electric rate increase application - cheyenne light, fuel & power

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BEFORE THE PUBLIC SERVICE COMMISSION

OF THE STATE OF WYOMING

APPLICATION OF CHEYENNE LIGHT, ) FUEL AND POWER COMPANY FOR ) AUTHORITY TO INCREASE ) DOCKET NO. 20003-__-ER-11 ITS ELECTRIC RATES ) (Record No.____)

)

APPLICATION OF CHEYENNE LIGHT, FUEL AND POWER COMPANY

Pursuant to the Wyoming Public Utilities Act, as amended, W.S. §§ 37-1-101, et seq.,

and Sections 104, 203(d), and 210 through 222 of the Procedural Rules and Special Regulations

of the Public Service Commission of Wyoming ("Commission"), Cheyenne Light, Fuel and

Power Company ("Cheyenne Light," "Applicant" or “Company”) hereby respectfully requests

authorization from the Commission to implement a change in its rates and charges for electric

service, and to implement other changes to its currently effective Electric Tariff - P.S.C. No. 10,

as reflected in the proposed tariffs as shown in Section 2 and more fully discussed below. In

support hereof, Cheyenne Light states as follows:

1. Applicant's exact legal name is Cheyenne Light, Fuel and Power Company, a

Wyoming corporation, with its principal place of business located at 108 West 18th Street,

Cheyenne, Wyoming, 82001. Cheyenne Light is a wholly-owned subsidiary of Black Hills

Corporation, which operates as a “holding company” under the Public Utility Holding

Company Act of 2005.

2. Applicant is a public utility, as defined by W.S. § 37-1-101(vi), providing

electric service in certain areas in the State of Wyoming, and is subject to the jurisdiction of the

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Commission. Applicant serves approximately 39,600 electric customers in Wyoming.

3. Pursuant to applicable Wyoming law and Commission rules, Cheyenne Light

hereby requests authority to increase its retail electric utility service rates in Wyoming by

$5,907,945 annually.

4. By this Application, Cheyenne Light seeks authorization to place into effect

revised rates, charges and tariffs for electric service provided to customers in its service area in

Wyoming. In the event the Commission exercises its authority pursuant to W.S. § 37-3-106(c)

to suspend the effectiveness of the rates, charges and tariffs proposed herein pending a

Commission investigation and/or hearing, Applicant respectfully requests that the rates, charges

and tariffs ultimately approved by the Commission be placed into effect for service on April 1,

2012. Cheyenne Light requests that a change in rates be approved in order to permit Cheyenne

Light to earn its requested rate of return, as detailed in the testimony and exhibits accompanying

this Application.

5. Applicant's present rates for electric service were placed into effect on January 1,

2008, which was the date of Cheyenne Light’s last general electric rate proceeding before the

Commission, Docket No. 20003-90-ER-07. Applicant’s present rates for electric service are

inadequate and not remunerative in that they have not and will not produce, after proper

consideration of applicable expenses, a fair return on the capital necessarily invested by

Applicant in providing safe and reliable electric service. Applicant proposes herein to increase

its overall annual electric services revenues from rates in the amount of $5,907,945, based upon

an analysis of the revenue requirement for the 12 months ending August 31, 2011.

6. The proposed rates include revisions to the Power Cost Adjustment (“PCA”) that

is presently in place. The revision of the PCA is in the public interest because it provides

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incentive for Cheyenne Light to operate efficiently and keep costs low, permits gradual increases

or decreases to rates based on actual costs and provides the Company with the ability to continue

to provide reliable and safe service to our customers.

7. The Company intends to file in the first quarter of 2012 a request that the Federal

Energy Regulatory Commission (FERC) approve proposed changes to the provisions of the

Generation Dispatch and Energy Management Agreement between Cheyenne Light and Black

Hills Power, Inc. (“Black Hills Power”) dated February 23, 2007 (the “GDEMA”). The GDEMA

sets forth the agreement by which Cheyenne Light sells all of its surplus energy to Black Hills

Power (the Put). The Company intends to request FERC approval of a proposed change to the Put

arrangement contained in the GDEMA whereby the proposed pricing mechanism for the Put will

be based on a market price. The Company will request in the FERC filing that the effective date

of the proposed pricing mechanism be concurrent with the effective date of the rates proposed in

this rate case. Prior to the FERC filing, the Company is willing to discuss the proposed Put

pricing mechanism with this Commission at a hearing or public meeting called by the

Commission, and the Company requests that this Commission support the Company’s FERC

filing.

8. Applicant requests approval to establish a major maintenance account and

consistent with the rules of FASB 71, establish a regulatory liability for plant maintenance. This

account will spread the costs of plant overhauls over a set period, resulting in a normalized

annual expense each year.

9. In further support of this Application, Applicant is submitting herewith the direct

testimony and exhibits of the following witnesses:

Mark Stege, Vice President of Operations for Cheyenne Light, will provide an overview

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of Cheyenne Light’s electric operations, discuss the driving issues underlying the requested

increase, discuss the Company’s workforce planning initiative, and provide a brief overview of

this Application.

Kyle D. White, Vice President of Regulatory and Resource Planning for Black Hills

Corporation, will provide support for the key components of the rate application presented by

Cheyenne Light.

Christopher J. Kilpatrick, Director of Rates and Resource Planning for Black Hills

Corporation, will present the Applicant’s revenue requirement model, discuss rate base,

adjustments and additional changes to the revenue requirement, present the proposed revisions to

the PCA, and summarize the revenue requirement model and tariff changes.

Charles R. Gray, Senior Regulatory Analyst, Regulatory Department of Black Hills

Corporation, will provide a proof of test year revenues and billing determinants for Cheyenne

Light.

Andy Butcher, Director of Generation Dispatch and Power Marketing for Black Hills

Power, Inc., will provide a description of GDEMA and the proposed changes to the provisions

under the GDEMA by which Cheyenne Light sells all of its surplus energy to Black Hills Power.

Laura Patterson, Director of Compensation and Benefits for Black Hills Corporation,

will describe the general compensation and benefits program for Black Hills Corporation

employees, and particularly the employees of Cheyenne Light, and explain why those

programs and their associated costs are reasonable and necessary to attract, motivate and

retain well qualified and competent employees to support Cheyenne Light and other Black

Hills Corporation affiliates and subsidiaries.

Jennifer Landis, Director of Organizational Development for Black Hills Corporation,

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will describe and support the Company’s strategic workforce planning process, and support

recovery of employee expenses.

Brian G. Iverson, Vice President and Treasurer of Black Hills Corporation, will certify

the books and records of Cheyenne Light, and will describe the financial integrity of Cheyenne

Light, and its capital structure and cost of debt, and proposes a 10.9 percent return on equity.

Dr. William E. Avera, FINCAP, Inc., will testify concerning the Applicant’s return on

equity. He will also review the operation of Cheyenne Light and provide support for the

Applicant’s requested 10.9 percent return on equity and for the Applicant’s requested capital

structure.

10. Cheyenne Light is seeking a 10.9 percent return on common equity, equating to an

8.70 percent return on rate base, as is discussed in more detail in the testimony of Brian G.

Iverson and Dr. William Avera. Applicant's actual rate of return on rate base without

adjustments was 8.49 percent during the test period of the twelve months ended August 31, 2011.

11. As discussed in direct testimony, there are several factors contributing to the

increase in the cost of service for Cheyenne Light’s electric customers. These factors include: a)

increased investment made in the electric plant infrastructure necessary to meet the system

requirements; b) general inflation that has occurred since the last rate case; and c) making a

necessary change to the existing GDEMA with Black Hills Power.

12. Section 1 consists of this Application and Appendix A, the Report of Tariff

Change, as required by Section 212 of the Commission's Procedural Rules and Special

Regulations.

13. Section 2 attached hereto contains the legislative and non-legislative versions of

Cheyenne Light’s proposed Rate Schedules. This section consists of:

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a. The proposed revised rate tariff sheets, P.S.C. No. 10, which contain the

proposed rates and charges; and

b. The comparison of the current tariffs to proposed new tariffs showing all of the

changes in legislative format, pursuant to Section 251 of the Commission's

Procedural Rules and Special Regulations. Strike-out markings indicate text that

has been deleted from the current tariff, and underscore markings indicate that

new text has been added to the proposed tariff.

14. Section 3 is a comparison of revenue under the Present Tariff Rates versus the

Proposed Tariff Rates.

15. Section 4 consists of the Revenue Requirement Model.

16. Section 5 consists of Work Papers to support the Revenue Requirement Model.

17. Section 6 includes the testimony and exhibits of the Cheyenne Light witnesses.

18. Contemporaneously with the filing of this Application for revisions in its electric

rates, Applicant is filing an application for revision of its gas rates (Docket No. 30005-___-GR-

11). Separate testimony has been presented for both cases.

19. The testimony, exhibits and accompanying documents establish that the requested

rates are just and reasonable, and meet all requirements of Wyoming law, and are in the public

interest.

20. Communications regarding this filing should be addressed to:

Mr. Mark Stege Vice President, Operations Cheyenne Light, Fuel and Power Company 1301 W. 24th Street Cheyenne, WY 82001

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Mr. Kyle D. White Vice-President – Resource Planning and Regulatory Affairs Black Hills Corporation 625 Ninth Street PO Box 1400 Rapid City, SD 57709 Mr. Christopher J. Kilpatrick Director of Rates and Resource Planning Black Hills Corporation 625 Ninth Street PO Box 1400 Rapid City, SD 57709 Ms. Glynda O. Gullickson Rahn Corporate Attorney Black Hills Corporation 625 Ninth Street PO Box 1400 Rapid City, SD 57709 Mr. Lee A. Magnuson Lynn, Jackson, Shultz & Lebrun, P.C. 110 North Minnesota Avenue, Suite 400 P.O. Box 2700 Sioux Falls, SD 57101-2700

WHEREFORE, Cheyenne Light respectfully requests that the Commission enter an order:

a) Approving electric service rates and charges which are sufficient to achieve

the proposed increase to the annual revenue requirement of $5,907,945;

b) Approving the revisions to the PCA;

c) Supporting the proposed revisions to the provisions of the GDEMA;

d) Approving the creation of a major maintenance account for steam plant

maintenance; and

e) Providing such other relief as the Commission deems necessary or

appropriate.

CHEYENNE LIGHT, FUEL & POWER COMPANYCHEYENNE, WYOMING

P.S.C. WYO No. 10

Date Issued

June 9, 2011 April 1, 2012

Date EffectiveChris Kilpatrick

Director of Resource Planning and Rates

April 30, 2010 December 1, 2011

Schedule Summation Sheet EighthSeventh Revised Sheet No. 6Page 1 of 11 Cancels SeventhSixth Revised Sheet No. 6

ELECTRIC RATES

RATE SCHEDULE SUMMATION SHEET

Rate Schedule

Sheet No. Type of Charge

Billing Units

Base Rate

Power Cost Adjustment

Total Rate

R 9 Residential Service

Service and Facility $12.00

12.76 $12.00

12.76

Energy Charge kWh 0.08921 0.0949 0.00588

0.09509 0.10078

C 15 Commercial Service


12.76 $12.00

12.76


0.10878 0.11528

SG 17 Secondary General Service


17.02 $16.00

17.02


0.04556 0.04808

Capacity Charge kW 18.65 19.83

18.65 19.83

PG 18 Primary General Service

Service and Facility $230.00 244.61

$230.00 244.61


0.04350 0.04588


17.15 18.24

STG 19

Substation Transformation General Service

Service and Facility $9,000.00 9,571.50

$9,000.00 9,571.50


0.04241 0.04468


14.00 14.89

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P.S.C. WYO No. 10

Date Issued April 1, 2011

April 1, 2012 Date EffectiveChris Kilpatrick


February 11, 2011 December 1, 2011

Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6APage 2 of 11 Cancels SixthFifth Revised Sheet No. 6A

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate

RAL 10 Residential Area Lights

On Existing Pole 100 Watt - HPS

Lamp/Mo $8.21

8.73 $8.21

8.73 Energy Charge * kWh 0.00588 0.00588

Requiring Pole/Overhead Feed -

100 Watt - HPS

Lamp/Mo $13.37

14.22 $13.37


Requiring Pole/Underground

Feed - 100 Watt - HPS

Lamp/Mo $18.75

19.94 $18.75


* The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6BPage 3 of 11 Cancels SixthFifth Revised Sheet No. 6B

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate

Power Cost Adjustment1

Total Rate

CAL 16 Commercial Area Lights On Existing Pole 100 Watts - HPS

Lamp/Mo. $8.21

8.73 $8.21

8.73 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS

Lamp/Mo. $14.12

15.02 $14.12


Lamp/Mo. $20.16

21.44 $20.16


Requiring Pole/ Overhead Feed

100 Watts - HPS

Lamp/Mo. $13.37

14.22 $13.37


Lamp/Mo. $19.27

20.49 $19.27


Lamp/Mo. $25.32

26.93 $25.32



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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6CPage 4 of 11 Cancels SixthFifth Revised Sheet No. 6C

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate

CAL 16 Commercial Area Lights

Requiring Pole/ Underground Feed

100 Watts - HPS

Lamp/Mo. $18.75 19.94

$18.75 19.94

Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS

Lamp/Mo. $23.39

24.88 $23.39


Lamp/Mo. $30.71

32.66 $30.71

32.66 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6DPage 5 of 11 Cancels SixthFifth Revised Sheet No. 6D

ELECTRIC RATES


Rate

Schedule Sheet No. Type of Charge

Billing Units Base Rate

Power Cost Adjustment1 Total Rate

SL 31 Street Lighting

Wood Pole Overhead Feed

100 Watts - HPS Lamp/Mo. $13.1213.95 $13.1213.95 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $18.7819.97 $18.7819.97 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $22.2223.63 $22.2223.63 Energy Charge * kWh 0.00588 0.00588

Wood Pole Underground Feed

100 Watts - HPS Lamp/Mo. $16.2417.27 $16.2417.27 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $21.9023.29 $21.9023.29 Energy Charge * kWh 0.00588 0.00588

Ornamental Pole Underground Feed

250 Watts - HPS Lamp/Mo. $31.2233.20 $31.2233.20 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $37.2839.65 $37.2839.65 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6EPage 6 of 11 Cancels SixthFifth Revised Sheet No. 6E

ELECTRIC RATES


Rate Schedule





19' Ornamental Pole Underground Feed

70 Watts - HPS Lamp/Mo. $12.6613.46 $12.6613.46 Energy Charge * kWh 0.00588 0.00588 100 Watts - HPS Lamp/Mo. $13.7914.67 $13.7914.67 Energy Charge * kWh 0.00588 0.00588

Traffic Signal Underground Feed

200 Watts - HPS Lamp/Mo. $10.4111.07 $10.4111.07 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $12.9913.81 $12.9913.81 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $19.0620.27 $19.0620.27 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6FPage 7 of 11 Cancels SixthFifth Revised Sheet No. 6F

ELECTRIC RATES


Rate Schedule




HL 32 Highway Lighting

Highway Lighting

200 Watts - HPS Lamp/Mo. $8.458.99 $8.458.99 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $10.4111.07 $10.4111.07 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $16.1317.15 $16.1317.15 Energy Charge * kWh 0.00588 0.00588

Underpass/ Understructure

150 Watts - HPS Lamp/Mo. $6.837.26 $6.837.26 Energy Charge * kWh 0.00588 0.00588

SLU 33 Street Lighting - Unincorporated Areas

Wood Pole/ Overhead Feed

100 Watts - HPS Lamp/Mo. $13.1213.95 $13.1213.95 Energy Charge * kWh 0.00588 0.00588

19' Ornamental Pole/ Underground Feed

100 Watts - HPS Lamp/Mo. $13.7914.67 $13.7914.67 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the highway lighting, street lighting -unincorporated areas, and pedestrian lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10





Rate Schedule Summation Sheet SeventhSixth Revised Sheet No. 6GPage 8 of 11 Cancels SixthFifth Revised Sheet No. 6G

ELECTRIC RATES


Rate Schedule




PL 34 Pedestrian Lighting

Pedestrian Lighting Fixtures

100 Watts - MH Lamp/Mo. $21.9423.33 $21.9423.33 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the highway lighting, street lighting -unincorporated areas, and pedestrian lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.

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P.S.C. WYO No. 10

Date Issued January 1, 2008



December 21, 2007 December 1, 2011

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Residential General Service Rate Schedule R First RevisedOriginal Sheet No. 9Page 1 of 1 Cancels Original Sheet No. 9

ELECTRIC RATES

RESIDENTIAL GENERAL SERVICE

SCHEDULE R APPLICABILITY

Applicable within all territory served to residential service. Not applicable to resale service. MONTHLY RATE

Service and Facility Charge: per Month....... .................................................................... $12.7612.00

Energy Charge: All kilowatt hours used, per kWh...... ............................................................................ 0.09490.08921

POWER COST ADJUSTMENT

The above schedule of charges shall be adjusted by the Power Cost Adjustment (PCA) commencing on Sheet No. 42.

When the billing period includes a change in the charges of an above referenced PCA tariff, the customer’s bill shall be prorated accordingly.

PAYMENT

Net monthly bills are due and payable twenty days from the date of the bill, and after that date the account becomes delinquent. A late payment charge of 1.5% on the current unpaid balance shall apply to delinquent accounts. If a bill is not paid, the Company shall have the right to suspend service, providing a ten day written or other required notice of such suspension has been given. When service is suspended for nonpayment of a bill, a reconnection service charge will apply.

RULES AND REGULATIONS

Service supplied under this schedule is subject to the terms and conditions set forth in the Company's Rules and Regulations on file with the Public Service Commission of Wyoming.


P.S.C. WYO No. 10





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Residential Outdoor Area Lighting Service Rate Schedule RAL First RevisedOriginal Sheet No. 10Page 1 of 3 Cancels Original Sheet No. 10

ELECTRIC RATES

RESIDENTIAL OUTDOOR AREA LIGHTING SERVICE

SCHEDULE RAL

APPLICABILITY

Applicable within all territory served for outdoor area lighting of customer's residential property where such service can be provided directly from existing secondary distribution lines of the Company. Not applicable for lighting of public streets or highways.

MONTHLY RATE REF. NO. High Pressure Sodium Lamps, Burning Dusk to Dawn: Lighting unit mounted on existing Company-owned pole: 9,500 lumen lamps, 100 watts, per lamp, per month ....................................................................................................WR040 $8.218.73 Lighting unit requiring installation of a pole and one span of overhead secondary feed wire: 9,500 lumen lamps, 100 watts, per lamp, per month. ...................................................................................................WR050 13.3714.22 Lighting unit requiring installation of a pole and underground cable: 9,500 lumen lamps, 100 watts, per lamp, per month. ...................................................................................................WR060 18.7519.94 POWER COST ADJUSTMENT



CONTRACT PERIOD

Contracts under this schedule with lighting units mounted on existing Company-owned poles shall be for a minimum period of two (2) years. Service for lighting units requiring the installation of a pole shall be by written agreement for a minimum period of ten (10) years. Where service is no longer required after the minimum period, the service may be terminated upon three (3) days’ notice.

(Continued on Sheet No. 10A)


P.S.C. WYO No. 10





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Commercial Service Rate Schedule C First RevisedOriginal Sheet No. 15Page 1 of 1 Cancels Original Sheet No. 15

ELECTRIC RATES

COMMERCIAL SERVICE

SCHEDULE C

APPLICABILITY

Applicable within all territory served to customers whose demands are less than 25 kW for lighting and power service supplied at secondary distribution voltage. Not applicable to standby, auxiliary or resale service.

MONTHLY RATE Service and Facility Charge: per Month..................................................................... $ 12.7612.00 Energy Charge: All kilowatt hours used, per kWh............................................................................... 0.10940.10290 POWER COST ADJUSTMENT



PAYMENT





P.S.C. WYO No. 10





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Commercial Outdoor Area Lighting Service Rate Schedule CAL First RevisedOriginal Sheet No. 16Page 1 of 3 Cancels Original Sheet No. 16

ELECTRIC RATES

COMMERCIAL OUTDOOR AREA LIGHTING SERVICE

SCHEDULE CAL

APPLICABILITY

Applicable within all territory served for outdoor area lighting of customer's property where such service can be provided directly from existing secondary distribution lines of the Company. Not applicable for lighting of public streets or highways.

MONTHLY RATE REF. NO. High Pressure Sodium Lamps, Burning Dusk to Dawn: Lighting unit mounted on existing Company-owned pole: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC040 ............. $ 8.218.73 27,500 lumen lamps, 250 watts, per lamp, per month......................WC043 ............. 14.1215.02 50,000 lumen lamps, 400 watts, per lamp, per month......................WC045 ............. 20.1621.44 Lighting unit requiring installation of a pole and one span of overhead secondary feed wire: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC050 ............. 13.3714.22 27,500 lumen lamps, 250 watts, per lamp, per month......................WC053 ............. 19.2720.49 50,000 lumen lamps, 400 watts, per lamp, per month......................WC055 ............. 25.3226.93 Lighting unit requiring installation of a pole and underground cable: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC060 ............. 18.7519.94 27,500 lumen lamps, 250 watts, per lamp, per month......................WC063 ............. 23.3924.88 50,000 lumen lamps, 400 watts, per lamp, per month......................WC065 ............. 30.7132.66 POWER COST ADJUSTMENT



CONTRACT PERIOD




P.S.C. WYO No. 10





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Secondary General Service Rate Schedule SG First RevisedOriginal Sheet No. 17Page 1 of 2 Cancels Original Sheet No. 17

ELECTRIC RATES

SECONDARY GENERAL SERVICE

SCHEDULE SG APPLICABILITY

Applicable within all territory served to lighting and power service supplied at secondary voltage. Not applicable to standby, auxiliary or resale service.

MONTHLY RATE Service and Facility Charge: per Month...................................................................................................................... $ 17.0216.00 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.0422 0.03968 Capacity Charge: All kilowatts of billing demand per kW ......................................................................... 19.8318.65 POWER COST ADJUSTMENT



PAYMENT


DETERMINATION OF BILLING DEMAND

Billing demand, determined by meter measurement, shall be the maximum fifteen minute integrated kilowatt demand used during the month, or as set forth in the Commercial and Industrial Rules and Regulations.



P.S.C. WYO No. 10





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Primary General Service Rate Schedule PG First RevisedOriginal Sheet No. 18Page 1 of 2 Cancels Original Sheet No. 18

ELECTRIC RATES

PRIMARY GENERAL SERVICE

SCHEDULE PG APPLICABILITY

Applicable within all territory served to lighting and power service supplied at primary voltage. Not applicable to standby, auxiliary, or resale service.

MONTHLY RATE Service and Facility Charge: per Month ................................................................................................................ $244.61230.00 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.04000.03762 Capacity Charge: All kilowatts of billing demand, per kW.................................. .................................... 18.2417.15 POWER COST ADJUSTMENT



PAYMENT






P.S.C. WYO No. 10



Director Resource Planning and Rates


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Substation Transformation General Service Rate Schedule STG First RevisedOriginal Sheet No. 19Page 1 of 2 Replaces Original Sheet No. 19

ELECTRIC RATES

SUBSTATION TRANSFORMATION GENERAL SERVICE

SCHEDULE STG APPLICABILITY

Applicable within all territory served to lighting and power service supplied at substation’s voltage. Not applicable to standby, auxiliary, or resale service.

MONTHLY RATE Service and Facility Charge: per Month ........................................................................ $9,571.509,000.00 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.03880.03653 System Capacity Charge: All kilowatts of billing demand, per kW.................................................................... $14.8914.00 POWER COST ADJUSTMENT



PAYMENT






P.S.C. WYO No. 10





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Street Lighting Service Rate Schedule SL First RevisedOriginal Sheet No. 31Page 1 of 2 Cancels Original Sheet No. 31

ELECTRIC RATES

STREET LIGHTING SERVICE

SCHEDULE SL APPLICABILITY

Applicable to the City of Cheyenne for street lighting service. MONTHLY RATE REF. NO.

WOOD POLE - OVERHEAD FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ..................................................................................... W030 ...... $ 13.1213.95 27,500 lumen lamps, 250 watts, per lamp, per month. .................................................................................... W040 ...... $ 18.7819.97 50,000 lumen lamps, 400 watts, per lamp, per month. .................................................................................... W050 ...... $ 22.2223.63

WOOD POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ..................................................................................... W070 ...... $ 16.2417.27 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... W080 ...... $ 21.9023.29

ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... W100 ...... $ 31.2233.20 50,000 lumen lamps, 400 watts, per lamp, per month ..................................................................................... W110 ...... $ 37.2839.65

19 FOOT POST TOP - ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 5,800 lumen lamps, 70 watts, per lamp, per month ......................................................................................... W118....... $ 12.6613.46 9,500 lumen lamps, 100 watts, per lamp, per month ......................................................................................... W120....... $ 13.7914.67

STREET LIGHTING SERVICE MOUNTED ON TRAFFIC SIGNAL FACILITIES - UNDERGROUND FEED:

High Pressure Sodium Lamps: 22,000 lumen lamps, 200 watts, per lamp, per month ......................................................................................... W140....... $ 10.4111.07 27,500 lumen lamps, 250 watts, per lamp, per month ......................................................................................... W150....... $ 12.9913.81 50,000 lumen lamps, 400 watts, per lamp, per month ......................................................................................... W160....... $ 19.0620.27



P.S.C. WYO No. 10





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Highway Lighting Service Rate Schedule HL First RevisedOriginal Sheet No. 32Page 1 of 1 Cancels Original Sheet No. 32

ELECTRIC RATES

HIGHWAY LIGHTING SERVICE

SCHEDULE HL APPLICABILITY

Applicable to the Wyoming Department of Transportation for highway lighting service. MONTHLY RATE REF. NO.

HIGHWAY LIGHTING: High Pressure Sodium Lamps: 22,000 lumen lamps, 200 watts, per lamp, per month ..................................................................................... WH030.... $8.458.99 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... WH040.... $10.4111.07 50,000 lumen lamps, 400 watts, per lamp, per month ..................................................................................... WH060.... $16.1317.15

UNDERPASS OR UNDERSTRUCTURE HIGHWAY LIGHTING: High Pressure Sodium Lamps: 16,000 lumen lamps, 150 watts, per lamp, per month: Burning Dusk to Dawn.................. ............................................... WH090 ... $6.837.26 PAYMENT








P.S.C. WYO No. 10





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Street Lighting Service – Unincorporated Areas Rate Schedule SLU First RevisedOriginal Sheet No. 33Page 1 of 3 Cancels Original Sheet No. 33

ELECTRIC RATES

STREET LIGHTING SERVICE - UNINCORPORATED AREAS

SCHEDULE SLU APPLICABILITY

Applicable within all territory served for street lighting service in such unincorporated areas in which there is no organization possessed of power to contract for such service. Not applicable to any other street lighting service.

MONTHLY RATE REF. NO.

WOOD POLE - OVERHEAD FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ...........................................................................WU010................ $ 13.1213.95

19 FOOT POST TOP - ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ...........................................................................WU020................ $ 13.7914.67 PAYMENT







P.S.C. WYO No. 10





I

Pedestrian Lighting Service Rate Schedule SL First RevisedOriginal Sheet No. 34Page 1 of 1 Cancels Original Sheet No. 34

ELECTRIC RATES

PEDESTRIAN LIGHTING SERVICE

SCHEDULE PL APPLICABILITY

Applicable to the City of Cheyenne for the Cheyenne Downtown Development Authority pedestrian lighting.

MONTHLY RATE REF. NO. PEDESTRIAN LIGHTING FIXTURES - UNDERGROUND FEED METAL HALIDE LAMPS:: TYPE I FIXTURE 1 - 7,800 lumen lamp, 100 watts, per Fixture, per month ........................................................................W200.................... $ 21.9423.33

The Company shall file to revise the rate under this service from time to time based upon the Company’s investment to provide service hereunder.

PAYMENT






Service supplied under this schedule is subject to the terms and conditions set forth in the Company’s Rules and Regulations on file with the Public Service Commission of Wyoming.






P.S.C. WYO No. 10

C C I C N N N

Power Cost Adjustment Fourth RevisedThird Revised Sheet No. 42Page 1 of 3 Cancels ThirdSecond Revised Sheet No. 42

POWER COST ADJUSTMENT APPLICABLE This Power Cost Adjustment (PCA) applies to all rate schedules for all classes of services authorized by the Wyoming Public Service Commission (Commission) and to all customers taking service pursuant to contract, rather than tariff, unless specifically exempted by order of the Commission. The PCA shall be calculated annually based on actual Delivered Power Costs for a twelve month periodthe previous calendar year as compared to the base year Delivered Power Costs, and shall include an over-or-under recovery from prior years’ adjustments through the Balancing Account. Cheyenne Light, Fuel and Power Company (Company) will make a PCA filing with the Commission annually. POWER COST ADJUSTMENT CALCULATION 1. System Delivered Power Costs $ 89,044,202 2. Sales for Resale $ 48,221,636 3. Retail Delivered Power Costs (line 1 – line 2) $ 40,832,566 4. Retail Energy Sales 1,019,094,498 kWh 5. Retail Delivered Power Cost per kWh (line 3 / line 4) $ 0.04007 / kWh 6. Base Retail Delivered Power Cost per kWh $ 0.03296 0.0433/ kWh 7. Difference (line 5 – line 6) $ 0.00711 / kWh 8. Total Change from Base (line 4 x line 7) $ 7,245,762 9. Delivered Power Costs to be Recovered / Refunded $ 5,933,474 10. Balancing Account (+ or -) $ 199,381 11. Power Cost Adjustment Amount (line 9 + line 10) $ 6,132,855 12. Projected Retail Energy Sales 1,043,767,653 kWh 13. Power Cost Adjustment (line 11 / line 12) $ 0.00588 / kWh SYSTEM DELIVERED POWER COSTS System Delivered Power Costs shall be the cost of generation fuel, purchased capacity and energy, transmission of electricity by others, and purchased emission allowances incurred by the Company. The System Delivered Power Costs shall be calculated on a calendar year basis. Coal purchased by the Company from an affiliate shall be priced in accordance with the methodology set forth in the Coal Supply Agreement dated February 7, 2007 and filed in Docket No. 20003-90-ER-07. The System Delivered Power Costs will also include any costs of new or existing governmental impositions for electric generation plant emissions, including but not limited to SO2 allowances, carbon taxes and/or carbon allowances, and other governmental initiatives related to electric generation plant emissions. Prior to including any new governmental impositions in the Delivered Energy Costs, the Company will make a filing with the Commission requesting approval of its plan to recover these new costs from Customers. SALES FOR RESALE Sales for Resale is the revenue received pursuant to the Company’s FERC approved tariffs and as listed under FERC account 447. These revenues also include sale of Renewable Energy Credits (RECs) net of the administrative fee, as well as net revenues from the Voluntary Renewable Energy Rider.






P.S.C. WYO No. 10

C I C C C C C C

Power Cost Adjustment First RevisedOriginal Sheet No. 42APage 2 of 3 Cancels Original Sheet No. 42A RETAIL ENERGY SALES Retail Energy Sales are the total retail energy sales (net of line losses) for all classes of service authorized by the Commission and the retail energy sales for all customers taking service pursuant to contract who are subject to the Power Cost Adjustment. The referenced sales are for the twelve month period.most recently completed calendar year. BASE RETAIL DELIVERED POWER COSTS The Base Retail Delivered Power Costs are established as $0.04330.03296 per kWh. This PCA base rate is derived by dividing the adjusted cost of generation fuel, purchased capacity and energy, transmission of electricity by others, and purchased emission allowances, by projected retail sales, as authorized by the Commission in the determination of overall revenues in Docket No. 20003-xx90-ER-1107. DELIVERED POWER COSTS TO BE RECOVERED/REFUNDED Delivered Power Costs to be Recovered / Refunded are equal to the Total Change from Base (line 8 in the Power Cost Adjustment Calculation) adjusted for a $1 million symmetrical dead band and subject to a tiered five percent sharing mechanismadjustment for costs outside the dead band. Line 9 of the Power Cost Adjustment Calculation is determined as follows:

(a) If the Total Change from Base is equal to or less than $2,500,0001,000,000 for the current period (either as an increase in costs or a decrease in costs), the total Change from Base is multiplied by 95%no change in rates occurs and the cost changes are absorbed or retained by the Company; or

(b) If the Total Change from Base is equal to or less than $5,000,000 but greater than $2,500,000more than $1,000,000 for the current period (either as an increase in costs or a decrease in costs), the amount greater than $2,500,000 is multiplied by 90 percent and then added to $2,375,000, the amount calculated in (a) above; or

(c) If the Total Change from Base is greater than $5,000,000 for the current period (either as an increase in costs or a decrease in costs), the amount greater than $5,000,000 is multiplied by 85 percent and then added to $4,625,000, the amount calculated for (a) and (b) above.$1,000,000 is subtracted from the Total Change from Base, and the result is multiplied by 95 percent.

This product is then the Delivered Power Cost to be Recovered from retail customers over the upcoming 12 months, or is the Delivered Power Cost to be Refunded to customers over the upcoming 12 months. BALANCING ACCOUNT This Balancing Account amount (line 10 of the Power Cost Adjustment Calculation) is derived by summing the Power Cost Adjustment Amount from the prior year’s filing less the actual amount recovered (or refunded) for the most recent twelve month period of April through Marchin the most recent calendar year through the PCA rate. The amount recovered (or refunded) through the PCA is the sum of the Retail Energy Sales for each month in the most recent twelve month period ending Marchcalendar year multiplied by the PCA rate in effect at the time, adjusted for prorations. This balance shall be recorded monthly. Interest shall accrue monthly on each end of month deferred balance whether the balance is positive or negative. The prior balancing account plus interest then becomes the beginning balancing account for the next month. The monthly interest rate shall be at a rate that is 1/12th of the annual interest rate established annually by the Commission pursuant to Section 241 of the Commission’s Procedural Rules and Special Regulations. The interest computation shall be symmetrical for either over collected or under collected amounts in the Balancing Account. POWER COST ADJUSTMENT AMOUNT The Power Cost Adjustment Amount is the amount which shall be refunded or charged to customers for Delivered Power Costs combined with the true-up of the PCA Balancing Account.






P.S.C. WYO No. 10

C C C C

Power Cost Adjustment First RevisedOriginal Sheet No. 42BPage 3 of 3 Cancels Original Sheet No. 42B PROJECTED RETAIL ENERGY SALES Projected Retail Energy Sales are the total retail kilowatt hours of retail sales for all classes of service authorized by the Commission and the retail energy sales for all customers taking service pursuant to contract who are subject to the Power Cost Adjustment for the period the PCA is anticipated to be in effect. Unless otherwise authorized by the Commission, a normal annual PCA period will run from JulyApril 1 through JuneMarch 301 of each calendar year. POWER COST ADJUSTMENT The Power Cost Adjustment on Line 13 shall be applied to all rate schedules for all classes of service authorized by the Commission. The credit will be applied on an equal per kWh basis for all classes of customers, unless the Commission finds an alternative manner of determining the bill credit or bill surcharge to be in the public interest. EFFECTIVE DATE The Power Cost Adjustment shall be effective, subject to approval by the Commission, for rates on and after JulyApril 1st of each year, or such other date as may be authorized by the Commission. In order to allow for a reasonable period of regulatory and public review, each annual Power Cost Adjustment application shall be filed no later than MayFebruary 15th for a requested effective date of prorated usage on and after JulyApril 1st. For periods where a later effective date is requested, the application with appropriate documentation shall be filed no later than 45 days prior to the requested effective date. No change in the PCA rate shall occur unless authorized by the Commission. INFORMATION TO BE FILED WITH THE COMMISSION Each annual Power Cost Adjustment application shall be accompanied by supporting data and documentation necessary to support the sales forecasts, actual costs, and other numbers that enter into the computation of the requested rate.


P.S.C. WYO No. 10

Schedule Summation Sheet Eighth Revised Sheet No. 6

Cancels Seventh Revised Sheet No. 6Page 1 of 11

ELECTRIC RATES


Rate


Billing Units

Base Rate


Total Rate

R 9 Residential Service Service and Facility $12.76 $12.76

Energy Charge kWh

0.0949 0.00588

0.10078

C 15 Commercial Service Service and Facility $12.76 $12.76

Energy Charge kWh

0.1094 0.00588

0.11528

SG 17 Secondary General Service Service and Facility $17.02 $17.02

Energy Charge kWh

0.0422 0.00588

0.04808

Capacity Charge kW

19.83

19.83

PG 18 Primary General Service Service and Facility $244.61 $244.61

Energy Charge kWh

0.0400 0.00588

0.04588

Capacity Charge kW

18.24

18.24

STG 19

Substation Transformation General Service

Service and Facility $9,571.50 $9,571.50

Energy Charge kWh

0.0388 0.00588 0.04468

Capacity Charge kW

14.89

14.89

Date Issued



December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6APage 2 of 11 Cancels Sixth Revised Sheet No. 6A

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate

RAL 10 Residential Area Lights

On Existing Pole 100 Watt - HPS

Lamp/Mo $8.73 $8.73 Energy Charge * kWh 0.00588 0.00588

Requiring Pole/Overhead Feed -

100 Watt - HPS Lamp/Mo $14.22 $14.22 Energy Charge * kWh 0.00588 0.00588

Requiring Pole/Underground

Feed - 100 Watt - HPS Lamp/Mo $19.94 $19.94 Energy Charge * kWh 0.00588 0.00588


Date Issued April 1, 2012 Date

EffectiveChris Kilpatrick Director of Resource Planning and

Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6B

Cancels Sixth Revised Sheet No. 6BPage 3 of 11

ELECTRIC RATES


Rate


Billing Units

Base Rate


Total Rate

CAL 16 Commercial Area Lights On Existing Pole 100 Watts - HPS Lamp/Mo. $8.73 $8.73 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $15.02 $15.02 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $21.44 $21.44 Energy Charge * kWh 0.00588 0.00588

Requiring Pole/ Overhead Feed

100 Watts - HPS Lamp/Mo. $14.22 $14.22 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $20.49 $20.49 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $26.93 $26.93 Energy Charge * kWh 0.00588 0.00588




Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6C

Cancels Sixth Revised Sheet No. 6CPage 4 of 11

ELECTRIC RATES


Rate


Billing Units

Base Rate


Total Rate

CAL 16 Commercial Area Lights

Requiring Pole/ Underground Feed

100 Watts - HPS Lamp/Mo. $19.94 $19.94 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $24.88 $24.88 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $32.66 $32.66 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.



Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6D

Cancels Sixth Revised Sheet No. 6DPage 5 of 11

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate


Wood Pole Overhead Feed


Wood Pole Underground Feed

100 Watts - HPS Lamp/Mo. $17.27 $17.27 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $23.29 $23.29 Energy Charge * kWh 0.00588 0.00588

Ornamental Pole Underground Feed

250 Watts - HPS Lamp/Mo. $33.20 $33.20 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $39.65 $39.65 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.



Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6E

Cancels Sixth Revised Sheet No. 6EPage 6 of 11

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate


19' Ornamental Pole Underground Feed

70 Watts - HPS Lamp/Mo. $13.46 $13.46 Energy Charge * kWh 0.00588 0.00588 100 Watts - HPS Lamp/Mo. $14.67 $14.67 Energy Charge * kWh 0.00588 0.00588

Traffic Signal Underground Feed

200 Watts - HPS Lamp/Mo. $11.07 $11.07 Energy Charge * kWh 0.00588 0.00588 250 Watts - HPS Lamp/Mo. $13.81 $13.81 Energy Charge * kWh 0.00588 0.00588 400 Watts - HPS Lamp/Mo. $20.27 $20.27 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the area lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.



Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6F

Cancels Sixth Revised Sheet No. 6FPage 7 of 11

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate

HL 32 Highway Lighting

Highway Lighting


Underpass/ Understructure

150 Watts - HPS Lamp/Mo. $7.26 $7.26 Energy Charge * kWh 0.00588 0.00588

SLU 33 Street Lighting - Unincorporated Areas

Wood Pole/ Overhead Feed

100 Watts - HPS Lamp/Mo. $13.95 $13.95 Energy Charge * kWh 0.00588 0.00588

19' Ornamental Pole/ Underground Feed

100 Watts - HPS Lamp/Mo. $14.67 $14.67 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the highway lighting, street lighting -unincorporated areas, and pedestrian lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.



Rates

December 1, 2011


P.S.C. WYO No. 10

Rate Schedule Summation Sheet Seventh Revised Sheet No. 6G

Cancels Sixth Revised Sheet No. 6GPage 8 of 11

ELECTRIC RATES


Rate Schedule


Billing Units

Base Rate


Total Rate

PL 34 Pedestrian Lighting

Pedestrian Lighting Fixtures

100 Watts - MH Lamp/Mo. $23.33 $23.33 Energy Charge * kWh 0.00588 0.00588 * The Power Cost Adjustment - Energy amount applicable to the highway lighting, street lighting -unincorporated areas, and pedestrian lighting rate schedules will vary monthly dependent upon the burning hours of the lighting units each month.



Rates

December 1, 2011


P.S.C. WYO No. 10

Residential General Service Rate Schedule R First Revised Sheet No. 9

Cancels Original Sheet No. 9Page 1 of 1

ELECTRIC RATES

RESIDENTIAL GENERAL SERVICE

SCHEDULE R APPLICABILITY

Applicable within all territory served to residential service. Not applicable to resale service. MONTHLY RATE

Service and Facility Charge: per Month....... .................................................................... $12.76

Energy Charge: All kilowatt hours used, per kWh...... ............................................................................ 0.0949




PAYMENT





EffectiveChris Kilpatrick Director of Resource Planning

and Rates

December 1, 2011


P.S.C. WYO No. 10

Residential Outdoor Area Lighting Service Rate Schedule RAL First Revised Sheet No. 10


ELECTRIC RATES

RESIDENTIAL OUTDOOR AREA LIGHTING SERVICE

SCHEDULE RAL

APPLICABILITY

Applicable within all territory served for outdoor area lighting of customer's residential property where such service can be provided directly from existing secondary distribution lines of the Company. Not applicable for lighting of public streets or highways.

MONTHLY RATE REF. NO. High Pressure Sodium Lamps, Burning Dusk to Dawn: Lighting unit mounted on existing Company-owned pole: 9,500 lumen lamps, 100 watts, per lamp, per month ....................................................................................................WR40 $8.73 Lighting unit requiring installation of a pole and one span of overhead secondary feed wire: 9,500 lumen lamps, 100 watts, per lamp, per month. ...................................................................................................WR50 14.22 Lighting unit requiring installation of a pole and underground cable: 9,500 lumen lamps, 100 watts, per lamp, per month. ...................................................................................................WR60 19.94 POWER COST ADJUSTMENT



CONTRACT PERIOD





and Rates

December 1, 2011


P.S.C. WYO No. 10

Commercial Service Rate Schedule C First Revised Sheet No. 15


ELECTRIC RATES

COMMERCIAL SERVICE

SCHEDULE C

APPLICABILITY

Applicable within all territory served to customers whose demands are less than 25 kW for lighting and power service supplied at secondary distribution voltage. Not applicable to standby, auxiliary or resale service.

MONTHLY RATE Service and Facility Charge: per Month..................................................................... $ 12.76 Energy Charge: All kilowatt hours used, per kWh............................................................................... 0.1094 POWER COST ADJUSTMENT



PAYMENT






and Rates

December 1, 2011


P.S.C. WYO No. 10

Commercial Outdoor Area Lighting Service Rate Schedule CAL First Revised Sheet No. 16


ELECTRIC RATES

COMMERCIAL OUTDOOR AREA LIGHTING SERVICE

SCHEDULE CAL

APPLICABILITY

Applicable within all territory served for outdoor area lighting of customer's property where such service can be provided directly from existing secondary distribution lines of the Company. Not applicable for lighting of public streets or highways.

MONTHLY RATE REF. NO. High Pressure Sodium Lamps, Burning Dusk to Dawn: Lighting unit mounted on existing Company-owned pole: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC40 ............... $ 8.73 27,500 lumen lamps, 250 watts, per lamp, per month......................WC43 ............... 15.02 50,000 lumen lamps, 400 watts, per lamp, per month......................WC45 ............... 21.44 Lighting unit requiring installation of a pole and one span of overhead secondary feed wire: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC50 ............... 14.22 27,500 lumen lamps, 250 watts, per lamp, per month......................WC53 ............... 20.49 50,000 lumen lamps, 400 watts, per lamp, per month......................WC55 ............... 26.93 Lighting unit requiring installation of a pole and underground cable: 9,500 lumen lamps, 100 watts, per lamp, per month......................WC60 ............... 19.94 27,500 lumen lamps, 250 watts, per lamp, per month......................WC63 ............... 24.88 50,000 lumen lamps, 400 watts, per lamp, per month......................WC65 ............... 32.66 POWER COST ADJUSTMENT



CONTRACT PERIOD





and Rates

December 1, 2011


P.S.C. WYO No. 10

Secondary General Service Rate Schedule SG First Revised Sheet No. 17


ELECTRIC RATES

SECONDARY GENERAL SERVICE

SCHEDULE SG APPLICABILITY

Applicable within all territory served to lighting and power service supplied at secondary voltage. Not applicable to standby, auxiliary or resale service.

MONTHLY RATE Service and Facility Charge: per Month...................................................................................................................... $ 17.02 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.0422 Capacity Charge: All kilowatts of billing demand per kW ......................................................................... 19.83 POWER COST ADJUSTMENT



PAYMENT







and Rates

December 1, 2011


P.S.C. WYO No. 10

Primary General Service Rate Schedule PG First Revised Sheet No. 18


ELECTRIC RATES

PRIMARY GENERAL SERVICE

SCHEDULE PG

APPLICABILITY

Applicable within all territory served to lighting and power service supplied at primary voltage. Not applicable to standby, auxiliary, or resale service.

MONTHLY RATE Service and Facility Charge: per Month ................................................................................................................ $244.61 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.0400 Capacity Charge: All kilowatts of billing demand, per kW.................................. .................................... 18.24 POWER COST ADJUSTMENT



PAYMENT







and Rates

December 1, 2011


P.S.C. WYO No. 10

Substation Transformation General Service Rate Schedule STG First Revised Sheet No. 19

Replaces Original Sheet No. 19Page 1 of 2

ELECTRIC RATES

SUBSTATION TRANSFORMATION GENERAL SERVICE

SCHEDULE STG

APPLICABILITY

Applicable within all territory served to lighting and power service supplied at substation’s voltage. Not applicable to standby, auxiliary, or resale service.

MONTHLY RATE Service and Facility Charge: per Month ........................................................................ $9,571.50 Energy Charge: All kilowatt hours used, per kWh.................................................................................. 0.0388 System Capacity Charge: All kilowatts of billing demand, per kW.................................................................... $14.89 POWER COST ADJUSTMENT



PAYMENT






EffectiveChris Kilpatrick Director Resource Planning

and Rates

December 1, 2011


P.S.C. WYO No. 10

Street Lighting Service Rate Schedule SL First Revised Sheet No. 31


ELECTRIC RATES

STREET LIGHTING SERVICE

SCHEDULE SL

APPLICABILITY

Applicable to the City of Cheyenne for street lighting service. MONTHLY RATE REF. NO.

WOOD POLE - OVERHEAD FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ..................................................................................... W030 ...... $ 13.95 27,500 lumen lamps, 250 watts, per lamp, per month. .................................................................................... W040 ...... $ 19.97 50,000 lumen lamps, 400 watts, per lamp, per month. .................................................................................... W050 ...... $ 23.63

WOOD POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ..................................................................................... W070 ...... $ 17.27 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... W080 ...... $ 23.29

ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... W100 ...... $ 33.20 50,000 lumen lamps, 400 watts, per lamp, per month ..................................................................................... W110 ...... $ 39.65

19 FOOT POST TOP - ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 5,800 lumen lamps, 70 watts, per lamp, per month ......................................................................................... W118....... $ 13.46 9,500 lumen lamps, 100 watts, per lamp, per month ......................................................................................... W120....... $ 14.67

STREET LIGHTING SERVICE MOUNTED ON TRAFFIC SIGNAL FACILITIES - UNDERGROUND FEED:

High Pressure Sodium Lamps: 22,000 lumen lamps, 200 watts, per lamp, per month ......................................................................................... W140....... $ 11.07 27,500 lumen lamps, 250 watts, per lamp, per month ......................................................................................... W150....... $ 13.81 50,000 lumen lamps, 400 watts, per lamp, per month ......................................................................................... W160....... $ 20.27




and Rates

December 1, 2011


P.S.C. WYO No. 10

Highway Lighting Service Rate Schedule HL First Revised Sheet No. 32




and Rates

December 1, 2011

ELECTRIC RATES

HIGHWAY LIGHTING SERVICE

SCHEDULE HL APPLICABILITY

Applicable to the Wyoming Department of Transportation for highway lighting service. MONTHLY RATE REF. NO.

HIGHWAY LIGHTING: High Pressure Sodium Lamps: 22,000 lumen lamps, 200 watts, per lamp, per month ..................................................................................... WH30...... $8.99 27,500 lumen lamps, 250 watts, per lamp, per month ..................................................................................... WH40...... $11.07 50,000 lumen lamps, 400 watts, per lamp, per month ..................................................................................... WH60...... $17.15

UNDERPASS OR UNDERSTRUCTURE HIGHWAY LIGHTING: High Pressure Sodium Lamps: 16,000 lumen lamps, 150 watts, per lamp, per month: Burning Dusk to Dawn.................. ............................................... WH90 ..... $7.26 PAYMENT








P.S.C. WYO No. 10

Street Lighting Service – Unincorporated Areas Rate Schedule SLU First Revised Sheet No. 33


ELECTRIC RATES

STREET LIGHTING SERVICE - UNINCORPORATED AREAS

SCHEDULE SLU APPLICABILITY

Applicable within all territory served for street lighting service in such unincorporated areas in which there is no organization possessed of power to contract for such service. Not applicable to any other street lighting service.

MONTHLY RATE REF. NO.

WOOD POLE - OVERHEAD FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ...........................................................................WU10.................. $ 13.95

19 FOOT POST TOP - ORNAMENTAL POLE - UNDERGROUND FEED: High Pressure Sodium Lamps: 9,500 lumen lamps, 100 watts, per lamp, per month ...........................................................................WU20.................. $ 14.67 PAYMENT








and Rates

December 1, 2011


P.S.C. WYO No. 10

Pedestrian Lighting Service Rate Schedule SL First Revised Sheet No. 34


ELECTRIC RATES

PEDESTRIAN LIGHTING SERVICE

SCHEDULE PL

APPLICABILITY

Applicable to the City of Cheyenne for the Cheyenne Downtown Development Authority pedestrian lighting.

MONTHLY RATE REF. NO. PEDESTRIAN LIGHTING FIXTURES - UNDERGROUND FEED METAL HALIDE LAMPS:: TYPE I FIXTURE 1 - 7,800 lumen lamp, 100 watts, per Fixture, per month ........................................................................W200.................... $ 23.33

The Company shall file to revise the rate under this service from time to time based upon the Company’s investment to provide service hereunder.

PAYMENT






Service supplied under this schedule is subject to the terms and conditions set forth in the Company’s Rules and Regulations on file with the Public Service Commission of Wyoming.



and Rates

December 1, 2011


P.S.C. WYO No. 10

Power Cost Adjustment Fourth Revised Sheet No. 42

Cancels Third Revised Sheet No. 42Page 1 of 3

POWER COST ADJUSTMENT APPLICABLE This Power Cost Adjustment (PCA) applies to all rate schedules for all classes of services authorized by the Wyoming Public Service Commission (Commission) and to all customers taking service pursuant to contract, rather than tariff, unless specifically exempted by order of the Commission. The PCA shall be calculated annually based on actual Delivered Power Costs for a twelve month period as compared to the base year Delivered Power Costs, and shall include an over-or-under recovery from prior years’ adjustments through the Balancing Account. Cheyenne Light, Fuel and Power Company (Company) will make a PCA filing with the Commission annually. POWER COST ADJUSTMENT CALCULATION 1. System Delivered Power Costs $______ 2. Sales for Resale $______ 3. Retail Delivered Power Costs (line 1 – line 2) $______ 4. Retail Energy Sales _______kWh 5. Retail Delivered Power Cost per kWh (line 3 / line 4) $ __ / kWh 6. Base Retail Delivered Power Cost per kWh $ 0.0433/ kWh 7. Difference (line 5 – line 6) $ ___ / kWh 8. Total Change from Base (line 4 x line 7) $_______ 9. Delivered Power Costs to be Recovered / Refunded $_______ 10. Balancing Account (+ or -) $_______ 11. Power Cost Adjustment Amount (line 9 + line 10) $_______ 12. Projected Retail Energy Sales _______ kWh 13. Power Cost Adjustment (line 11 / line 12) $ __/ kWh SYSTEM DELIVERED POWER COSTS System Delivered Power Costs shall be the cost of generation fuel, purchased capacity and energy, transmission of electricity by others, and purchased emission allowances incurred by the Company. The System Delivered Power Costs shall be calculated on a calendar year basis. Coal purchased by the Company from an affiliate shall be priced in accordance with the methodology set forth in the Coal Supply Agreement dated February 7, 2007 and filed in Docket No. 20003-90-ER-07. The System Delivered Power Costs will also include any costs of new or existing governmental impositions for electric generation plant emissions, including but not limited to SO2 allowances, carbon taxes and/or carbon allowances, and other governmental initiatives related to electric generation plant emissions. Prior to including any new governmental impositions in the Delivered Energy Costs, the Company will make a filing with the Commission requesting approval of its plan to recover these new costs from Customers. SALES FOR RESALE Sales for Resale is the revenue received pursuant to the Company’s FERC approved tariffs and as listed under FERC account 447. These revenues also include sale of Renewable Energy Credits (RECs) net of the administrative fee, as well as net revenues from the Voluntary Renewable Energy Rider.



and Rates

December 1, 2011


P.S.C. WYO No. 10

Power Cost Adjustment First Revised Sheet No. 42A

Cancels Original Sheet No. 42APage 2 of 3

RETAIL ENERGY SALES Retail Energy Sales are the total retail energy sales (net of line losses) for all classes of service authorized by the Commission and the retail energy sales for all customers taking service pursuant to contract who are subject to the Power Cost Adjustment. The referenced sales are for the twelve month period. BASE RETAIL DELIVERED POWER COSTS The Base Retail Delivered Power Costs are established as $0.0433 per kWh. This PCA base rate is derived by dividing the adjusted cost of generation fuel, purchased capacity and energy, transmission of electricity by others, and purchased emission allowances, by projected retail sales, as authorized by the Commission in the determination of overall revenues in Docket No. 20003-xx-ER-11. DELIVERED POWER COSTS TO BE RECOVERED/REFUNDED Delivered Power Costs to be Recovered / Refunded are equal to the Total Change from Base (line 8 in the Power Cost Adjustment Calculation) subject to a tiered sharing mechanism. Line 9 of the Power Cost Adjustment Calculation is determined as follows:

(a) If the Total Change from Base is equal to or less than $2,500,000 for the current period (either as an increase in costs or a decrease in costs), the total Change from Base is multiplied by 95%; or

(b) If the Total Change from Base is equal to or less than $5,000,000 but greater than $2,500,000 for the current period (either as an increase in costs or a decrease in costs), the amount greater than $2,500,000 is multiplied by 90 percent and then added to $2,375,000, the amount calculated in (a) above; or

(c) If the Total Change from Base is greater than $5,000,000 for the current period (either as an increase in costs or a decrease in costs), the amount greater than $5,000,000 is multiplied by 85 percent and then added to $4,625,000, the amount calculated for (a) and (b) above.

This product is then the Delivered Power Cost to be Recovered from retail customers over the upcoming 12 months, or is the Delivered Power Cost to be Refunded to customers over the upcoming 12 months. BALANCING ACCOUNT This Balancing Account amount (line 10 of the Power Cost Adjustment Calculation) is derived by summing the Power Cost Adjustment Amount from the prior year’s filing less the actual amount recovered (or refunded) for the most recent twelve month period of April through March. The amount recovered (or refunded) through the PCA is the sum of the Retail Energy Sales for each month in the most recent twelve month period ending March multiplied by the PCA rate in effect at the time, adjusted for prorations. This balance shall be recorded monthly. Interest shall accrue monthly on each end of month deferred balance whether the balance is positive or negative. The prior balancing account plus interest then becomes the beginning balancing account for the next month. The monthly interest rate shall be at a rate that is 1/12th of the annual interest rate established annually by the Commission pursuant to Section 241 of the Commission’s Procedural Rules and Special Regulations. The interest computation shall be symmetrical for either over collected or under collected amounts in the Balancing Account. POWER COST ADJUSTMENT AMOUNT The Power Cost Adjustment Amount is the amount which shall be refunded or charged to customers for Delivered Power Costs combined with the true-up of the PCA Balancing Account.



and Rates

December 1, 2011


P.S.C. WYO No. 10

Power Cost Adjustment First Revised Sheet No. 42B

Cancels Original Sheet No. 42BPage 3 of 3

PROJECTED RETAIL ENERGY SALES Projected Retail Energy Sales are the total retail kilowatt hours of retail sales for all classes of service authorized by the Commission and the retail energy sales for all customers taking service pursuant to contract who are subject to the Power Cost Adjustment for the period the PCA is anticipated to be in effect. Unless otherwise authorized by the Commission, a normal annual PCA period will run from July 1 through June 30 of each calendar year. POWER COST ADJUSTMENT The Power Cost Adjustment on Line 13 shall be applied to all rate schedules for all classes of service authorized by the Commission. The credit will be applied on an equal per kWh basis for all classes of customers, unless the Commission finds an alternative manner of determining the bill credit or bill surcharge to be in the public interest. EFFECTIVE DATE The Power Cost Adjustment shall be effective, subject to approval by the Commission, for rates on and after July 1st of each year, or such other date as may be authorized by the Commission. In order to allow for a reasonable period of regulatory and public review, each annual Power Cost Adjustment application shall be filed no later than May 15th for a requested effective date of prorated usage on and after July 1st. For periods where a later effective date is requested, the application with appropriate documentation shall be filed no later than 45 days prior to the requested effective date. No change in the PCA rate shall occur unless authorized by the Commission. INFORMATION TO BE FILED WITH THE COMMISSION Each annual Power Cost Adjustment application shall be accompanied by supporting data and documentation necessary to support the sales forecasts, actual costs, and other numbers that enter into the computation of the requested rate.



and Rates

December 1, 2011

Cheyenne Light, Fuel and Power Company Revenue Requirement Description

SUMMARY EXPLANATION OF STATEMENTS AND SCHEDULES

The following summary explanations of Statements and Schedules are intended as a general guide. They refer in some instances to both the electric and gas business segments (or divisions) to better explain the subject matter of the respective spreadsheets even though the spreadsheets themselves often contain information about only one or the other of the divisions but not both.


Section A Statement A Pages 1 and 2 – Balance Sheet – Total Company. This Statement shows the per books balance sheet as of August 31, 2011. It lists the specific assets and liabilities in each business segment, gas and electric, and identifies which accounts are considered common and therefore allocated on Schedule A-1. This Statement is organized by FERC account and is the starting point for the rate base calculation for each business segment. This Statement is identical in both the gas and electric filings. Statement A Page 3 – Rate Base Calculation – Electric. This Statement shows the calculation of the per books rate base for electric. This calculation is as of August 31, 2011 with the first column figures taken from Statement A Pages 1 and 2, Schedule D-1, and Statement F. The second column balances, representing the respective business segment’s allocation of common balances, is derived from Schedule A-1, Schedule D-1, and Statement E Page 1. The third column represents the total of each of the previous two columns. The per books rate base does not include any amounts listed in FERC account 107 – Construction Work in Progress or FERC account 105 – Future Use Plant. Cheyenne Light has also removed the transaction costs (organizational costs) incurred for Black Hills Corporation’s purchase of Cheyenne Light from Xcel Energy, in line 3 of this Statement as required under W.S. 37-1-105(b). Schedule A-1 – Balance Sheet Allocations for Common Business. This Schedule is used to allocate the common rate base assets and liabilities to each business segment, gas and electric. The allocation methods are described on the top of the page with descriptions of the origin of the allocation amounts. The allocations used for each line item are at the far right side of the page to show how the common allocation was made between gas and electric. The amounts on this page are used in Statement A Page 3 in the Common Allocation column to determine the rate base for the electric business. These allocations are also used throughout the model when common balance sheet items are allocated between the electric and gas business.


Section B

Statement B Page 1 – Income Statement – Total Company. This Statement shows the Income Statement for the twelve months ending August 31, 2011, with a breakout of revenues and expenses for gas, electric, and common business. The total amount in the common business column is then taken to Schedule B-1 to be allocated between gas and electric businesses. Statement B Page 2 – Income Statement – Electric. This Statement shows the business segment calculation of Operating Income for the twelve months ending August 31, 2011. The first column shows the amounts from Statement B Page 1 that are specifically identified with the electric business segment. The second column comes from Schedule B-1 which allocates the common business information between the two business segments, gas and electric. The amounts in the third column are the totals of the first two columns, which together determine each segment’s per books operating income for the twelve months ending August 31, 2011. Schedule B-1 – Income Statement Allocations for Common Business. This Schedule is used to allocate the common business expenses to each segment, gas and electric. The allocation methods are described on the top of the page with descriptions of the origin of the allocation amounts. The allocations used for each common line item are at the far right side of the page to show how the allocation was made between gas and electric. The amounts on this page are used in Statement B Page 2 in the common allocation column to develop the electric segment’s per books operating income. These allocations are also used throughout the model when common income statement items are allocated between the electric and gas business.


Section C

Statement C – Statement of Retained Earnings. This Statement shows the per books total company equity for the twelve months ending August 31, 2011. This Statement shows there have been no equity infusions taken from Cheyenne Light over the past twelve months and there have been $14.5 million in dividends.


Section D

Statement D Page 1 – Utility Plant in Service. This Statement shows a roll forward of property records from August 31, 2010, to August 31, 2011. The roll forward includes additions, retirements, transfers, and adjustments. This Statement does not include FERC Account 107 – Construction Work in Progress. Additional details of this roll forward by plant account can be found on Schedule D-1 which shows the same additions, retirements, transfers, and adjustments by electric FERC account. Statement D Page 2 – Adjusted Plant in Service for Rate Base. This Schedule shows a summary of plant in service for rate base calculations. The amounts in the first column plant in service, reconciles to Schedule D-1 and reconciles by function as of August 31, 2011. The second column amounts represent expected additions to rate base through the pro forma test year based on approved budgets as shown on Schedule D-2. Unexpensed rate case costs, which are referenced in Schedule H-5, are also included. The third column shows total adjusted plant in service for rate base calculations that are used in Statements M and N. Schedule D-1 – Utility Plant in Service. This Schedule shows, by electric plant account, the amounts used in Statement D-1 for the balances as of August 31, 2011. The amount shown for General Plant – Common Allocation (lines 53 - 64), reconciles to the calculation shown on Schedule A-1 (line 20-22) as of August 31, 2011, for the electric portion only. The amount shown for Acquisition Adjustment (line 81), reconciles to the amount shown on Schedule A-1 (line 26) and the amount shown for Other Utility Plant (lines 85 – 87), reconciles to the amount shown on Schedule A-1 (line 28) for the electric portion only. Schedule D-2 - Subsequent and Expected Additions and Retirements. This Schedule shows, by project description, the expected capital additions for the pro forma test year. These amounts are included as rate base on Statement D Page 2. The general plant additions are allocated to the electric business based on allocation (e) as calculated on Schedule A-1. The other utility plant additions are allocated to the electric business based on allocation (f) as calculated on Schedule A-1. Schedule D-3 – Acquisition Adjustment Annual Amortization. This Schedule provides the calculation of the annual amortization expense for the acquisition adjustment, as well as the accumulated amortization. The acquisition adjustment amortization calculations are based on a thirty year amortization period consistent with the Stipulation and Agreement filed October 18, 2007 – Docket No. 20003-90-07 (Record No. 11070). The accumulated amortization adjustment is reflected in Statement D Page 2 and the amortization expense is reflected in Statement J. Schedule D-4 – Policy of Capitalizing Interest and Other Overheads During Construction. This Schedule sets forth a description of the Company’s methods of capitalizing interest and overhead on construction projects.


Schedule D-5 – Policy of Continuing Property Records. This Schedule sets forth a description of the continuing property records maintained by the Company, including methods and procedures used to price retirements.


Section E

Statement E Page 1 – Accumulated Provision for Depreciation. This Statement is for electric only and shows the activity for the accumulated depreciation account by function for the twelve months ending August 31, 2011. The columns titled “Production”, “Transmission”, “Distribution”, “General”, and “Other Utility Plant – Electric” are specifically for electric assets. The “Common Allocation” and “Other Utility Plant – Common” columns are calculated from Schedule A-1 using allocators (e) and (f) respectively. The Summary includes:

(1) Starting Balance; (2) Utility Holdings Allocation;

(3) Annual Provision;

(4) Retirement;

(5) Removal Costs;

(6) Salvage;

(7) Transfers and Adjustments; and

(8) Ending Balance.

Statement E Page 2 – Adjusted Accumulated Provision for Depreciation. This Statement shows a calculation of accumulated depreciation, for electric only, to be used as a reduction to rate base. The first column is developed from Statement E Page 1, which is the per books accumulated depreciation for electric only as of August 31, 2011. The next column represents the depreciation of the subsequent additions and retirements for pro forma test year (Statement D Page 2) based on the respective depreciation rates provided in Statement J, divided by 2 to average changes that occur through the 12 month period. The third column is the sum of the first two columns and represents the adjusted accumulated depreciation. The adjusted accumulated depreciation amount is then used in Statements M and N. Schedule E-1 – Depreciation and Amortization Method. This Schedule includes a description of the Company’s methods and procedures for depreciating or amortizing plant. Schedule E-2 – Recording Accumulated Depreciation. This Schedule includes a description of the Company’s method of recording accumulated depreciation.


Section F

Statement F – Working Capital. This Statement is for electric only and is a summary page of working capital for the electric rate base. The cash working capital is based on a lead/lag study completed by Cheyenne Light for the twelve months ending August 31, 2011. The cash working capital amount is then adjusted based on the adjusted costs as shown in the lead/lag study found on Schedule F-3. The remaining items on this Statement are as of August 31, 2011, with the detail located on Schedule F-2. The adjusted balance for working capital is used for the calculations on Statements M and N. Schedule F-1 – Cash Working Capital Calculation. This Schedule shows the per books cash working capital requirements for electric only. These amounts are then updated with the pro forma adjustments on Schedule F-3. Lead/Lag Calculations: The Expense Per Day (column (b)) is calculated by dividing the per book recorded amounts (column (a)) by 365 days in a year. The Expense Per Day is then multiplied by the Expense Lead Days (column (c)) to determine the Expense Dollar Days (column (d)). The Expense Lead Days is a calculation of the time lag between services/goods received and the payment of such costs based on a selection of invoices specific to each expense category. For example, if the invoice for services provided for the month of April was paid on May 20th, the Expense Lead Days would be 35. The 35 days is calculated by taking April’s mid-service point of 15 days, since the service was for the entire month and adding the 20 days in May before the invoice was paid. The Revenue Lag Days is a calculation of the time lag between services rendered and the receipt of revenues for such services. The components of this calculation include average: 1) service month midpoint days, 2) meter reading to billing days, and 3) billing to collection days. Gross Cash Working Capital Requirement (Line 31) is calculated by multiplying the total Expense Per Day (Line 25 column (b)) by the Net Lead/Lag Days (Line 29). The Net Cash Working Capital Requirement (Line 33) is determined based on the Gross Cash Working Capital (Line 31) net of the calculated cash available from tax collections on behalf of other parties, Tax Collections Available (Line 32). Schedule F-2 – Components of Claimed Working Capital. This Schedule shows, for informational purposes only, the balance of materials and supplies, and prepaid expenses,


for each of the 12 months included in the test year. The common materials and supplies and prepaid expenses were allocated to electric on a monthly basis based on allocation (d) shown on Schedule A-1. Cheyenne Light will be receiving a spare transformer located in the Cheyenne area and this is included as an adjustment to supplies and materials. Schedule F-3 – Adjusted Cash Working Capital Calculation. This Schedule shows the computations, cross references and sources from which the data used in computing the adjusted cash working capital is derived. See Lead/Lag Calculation description included in Schedule F-1 narrative. Calculation of adjusted cash working capital based on adjusted expenses and adjusted revenues. Wyoming sales tax collections were also adjusted to reflect the increase in electric revenues.


Section G

Statement G – Cost of Capital. This Statement is the calculation of adjusted cost of capital. The capital structure is addressed in William Avera’s and Brian Iverson’s testimony. The adjusted rate of return on line 4 is used in Statement N to calculate the additional revenue needed to allow Cheyenne Light to earn a reasonable return on its investment. This amount is also referenced in Statement M. Schedule G-1 – Cost of Debt. This Schedule shows per book and pro forma weighted average cost of debt based upon the following data for each class and series of long term debt outstanding as of August 31, 2011 as well as the pro forma weighted average cost of debt based on projected changes to cost of debt.

(a) Title (b) Date of issuance (c) Date of maturity (d) Amount issued (e) Interest rate (f) Net proceeds amount (g) Per unit proceeds amount (h) Yield to maturity (i) Cost of money (j) Principal outstanding (k) Annual cost

Schedule G-2 – Cost of Preferred Stock. No preferred stock as of August 31, 2011. Schedule G–3 – Reacquisiton of Bonds or Preferred Stock. Cheyenne Light did not reacquire any bonds or preferred stock in the 18 months prior to filing.


Section H

Statement H- Operating Expenses. This Statement, by FERC account, details all the operation and maintenance expense amounts, going from the per books to the adjusted amount used in the cost of service. Each adjustment to the per books has its own column and is referenced to a Schedule that supports that adjustment. The adjusted operation and maintenance expenses are used in Statements M and N. A summary of the adjustment descriptions are listed below:

1. Distribution of Wages and Salaries 2. Employee Pension and Benefits Adjustment 3. Intercompany Black Hills Service Company Charges 4. Intercompany Black Hills Utility Holdings Charges 5. Outside Consulting Related to Rate Case 6. Listed Advertising Expense Reduction 7. Coal Pricing Adjustment 8. Generation Plant Overhaul Expenses 9. Generation Dispatch and Scheduling Cost Detail 10. Gillette Energy Complex Shared Facilities 11. Purchase Power and Sales for Resale

Schedule H-1 Page 1 – Per Books Distribution of Wages and Salaries. This Schedule shows, on a total Cheyenne Light company basis, the amount of wages and salaries attributable to operation and maintenance on a functional basis. A portion of the total common business wages and salaries are then allocated to electric on Schedule H-1 Page 2, based on allocators (d), (e), and (f) from Schedule B-1. Schedule H-1 Page 2 – Pro Forma Distribution of Wages and Salaries. This Schedule is for electric only and shows the total wages and salaries allocated from the common business to determine the total electric business wages and salaries, which is then used to calculate a pro forma wage increase. Column D calculates the additional personnel wages and salaries attributable to operation and maintenance. The overall wage increase includes increases from the approved union agreement and expected March 2012 increases in non-union wages, as well as other than standard payroll, such as overtime and standby pay. In addition, this reflects the two vacancies as of October 6, 2011 are filled and one incremental headcount is added as a result of the Strategic Workforce Planning initiative.


Schedule H-2 - Employee Pension and Benefits Adjustment. This Schedule adjusts the per books benefit costs to a pro forma benefit cost. These costs are allocated based on Schedule B-1 (Income Statement Allocations for Common Business) allocator (b). Schedule H-3 page 1 – Intercompany Charges from Black Hills Service Company – Total Company. This page shows a total company amount charged by Black Hills Service Company to Cheyenne Light for the twelve months ending August 31, 2011, along with the pro forma adjustment. The per books and pro forma adjusted amounts on this page are then allocated to the electric business on Schedule H-3 Page 2 based on the allocation factors in Schedule B-1. Schedule H-3 Page 2 - Intercompany Charges from Black Hills Service Company - Electric. This page is for the electric business only based on FERC account numbers. The allocation factors are shown next to each amount in the per books and pro forma adjusted columns. The total increase for the electric business is then shown in Statement H in column (d). Schedule H-4 Page 1 – Intercompany Charges from Black Hills Utility Holdings Company. This page shows a total company amount charged by Black Hills Utility Holdings Company to Cheyenne Light for the twelve months ending August 31, 2011, along with the pro forma adjustment. The per books and pro forma adjusted amounts on this page are then allocated to the electric business based on Schedule H-4 Page 2 based on the allocation factors in Schedule B-1. Schedule H-4 Page 2 – Intercompany Charges from Black Hills Utility Holdings Company. This page is for the electric business only based on FERC account. The allocation factors are shown next to each amount in the per books and pro forma adjusted columns. The total increase for the electric business is then shown in Statement H in column (e). Schedule H-5 – Outside Consulting Related to Rate Case. This Schedule is a listing of expected rate case expenditures. The total amount is allocated between gas and electric 50% - 50%. Of the total amount allocated to electric, one-half is going to expense with the remaining amount taken to Statement D Page 2 and included as rate base. Schedule H-6 – Listed Advertising Expense Accounts. This Schedule summarizes the advertising cost amounts by FERC account that have been removed from the per books expenses. The amount on line 7 column (f) has been removed from the cost of service on Statement H and shown in column (g). Schedule H-7 – Coal Price Adjustment. This Schedule compares the test year ending cost of coal by plant and then calculates the pro forma cost of coal by plant using a 2 year


average coal consumption and the projected 2012 price per ton of coal. The increase in the cost is adjusted on Statement H, column (h). Schedule H-8 – Generation Plant Overhaul Expenses. Cheyenne Light’s generation facility, Wygen II, has planned maintenance and overhaul schedules. This schedule normalizes these costs and the adjustment is shown on Statement H in column (i) Schedule H-9 – Generation Dispatch and Scheduling Cost Detail. This Schedule shows the calculation of generation dispatch and scheduling costs. Lines 2 – 13 show the total amount related to generation dispatch and scheduling for the pro forma test year. Total generation dispatch costs are then allocated based on a capacity allocation as shown on lines 15 – 57. The percent of capacity that is related to Cheyenne Light on line 61 is then multiplied by line 13 to determine the amount of expense to be charged to Cheyenne Light for generation dispatch on line 67. This amount is added to the cost of service in Statement H in column (j). Schedule H-10 – Gillette Energy Complex Shared Facilities. This Schedule provides the adjustment to Cheyenne Light’s per book rent for electric property revenue and per book production rent expenses for the Gillette Shared Facilities Agreement. Lines 23 – 53 provides the detail of Cheyenne Light’s share of the revenue and expense. These budget amounts are compared to the per books amounts to determine the adjustments. These adjustments are provided on Statement I Page 1 Line 13 and Schedule H column (k). Schedule H-11 – Purchase Power and Sales for Resale. This Schedule provides for the energy resource, either Black Hills Wyoming - Wygen I purchase agreement or Market Purchase Power, to be used to serve the additional load. These calculations provide an adjustment to Sales for Resale revenue on Statement I Page 1 and Purchase Power – Energy on Statement H.


Section I

Statement I Page 1 – Operating Revenue. This Statement is used to reconcile the per books revenue for the twelve months ending August 31, 2011, with pro forma adjustments to account for known and measurable adjustments. The adjusted total is used to determine the revenue requirement on Statement N. Statement I Page 2 – Operating Revenue By Customer Classification. This Statement shows the per books revenue and kWh sales by customer class as compared to the pro forma sales by customer class as calculated on Schedule I-1. Schedule I-1 – Pro Forma Operating Revenue Billing Determinants. This Schedule shows, by customer class, the pro forma adjusted billing determinants and the tariff rates in effect as of August 31, 2011 without the deferred portion of the Power Cost Adjustment. This schedule takes into account residential customer forecast and additional Primary and Secondary General load growth detailed on Schedule I-2. The billing determinants are then multiplied by the tariff rate to calculate the pro forma adjusted revenue by customer class. Schedule I-2 – Additional Load Growth. This Schedule details the assumptions for the primary and secondary general service additional load by customer.


Section J

Statement J – Depreciation, Amortization and Accretion Expense. This Statement is used to show the calculation of depreciation, amortization and accretion expense for the pro forma adjusted test year. The pro forma depreciation, amortization and accretion expense adjustment is determined by multiplying the depreciable plant in service by the functional class depreciation rate. The source for the functional class depreciation rate is the Depreciation Study completed by Black & Veatch completed in January 2007.


Section K

Statement K Page 1 – Computation of Federal Income Tax – Total Company. This Statement is a detailed reconciliation of the total Cheyenne Light federal income tax calculation for the twelve months ending August 31, 2011. It shows the permanent and temporary (timing) differences for Cheyenne Light on a separate company basis. Statement K Page 2 – Computation of Federal Income Tax – Electric. This Statement shows the electric business federal income tax calculation for the twelve months ending August 31, 2011. The common allocation is derived from Statement K Page 1 and allocated to the electric business based on the allocations next to each amount in the common allocation column. The total in the far right column on line 52 represents the tax adjusted per books amount of federal income tax expense for the twelve months ending August 31, 2011. Statement K Page 3 – Adjusted Federal Income Tax. This Statement is used to adjust federal income tax to a normalized amount based on the adjusted debt to equity structure and based on adjusted operating income projections. The adjusted operating income is determined using line 12 on Statement M from the Adjusted Total column. The pro forma interest expense is deducted using Schedule G-1, line 35, calculation for the electric business, in order to determine taxable income. Federal income tax is adjusted using the projected debt to equity structure as applied to the adjusted rate base, and calculating an imputed interest expense based on the expected actual cost of debt. This calculation is performed on Schedule K-1 and the adjustment is shown on line 9. Schedule K-1 – Interest Expense – Annualization Adjustment. This Schedule shows the calculation of implied debt expense based on the adjusted rate base, multiplied times the adjusted cost of debt. Based on this calculation, there would be more interest expense and therefore less taxable income. The decrease in federal income tax on line 15 is then used in Statement K Page 3 to reduce the adjusted federal income tax.


Section L

Statement L – Taxes Other Than Federal Income Tax. This Statement shows the calculation of Taxes Other than Income for only the electric business. The adjustments are based on the calculations provided on Schedule L-1. Schedule L-1 – Adjustments Other Than Federal Income Tax. This Schedule shows the adjustment for additional payroll taxes related to the payroll changes shown on Schedule H-1 Page 2. It also calculates the additional Cheyenne Light franchise fee due to the additional revenue as calculated on Statement N. Finally, it provides the calculation of the property tax adjustment based on property additions provided on Statement D Page 2.


Section M

Statement M – Overall Revenue Requirement. This Statement is a combination of the previous Statements and Schedules and is used to determine a per books operating income and an adjusted operating income. It is a one page summary of total rate base and total operating expenses. It also shows the level of additional revenue needed to get to the rate of return calculated on Statement G. The Additional Revenue Required column is developed from Statement N. Schedule M-1 – Other Rate Base Reduction Adjustment. This Schedule reflects current balances as of August 31, 2011, for the Deferred Income Tax Asset, Deferred Tax – Accelerated Depreciation, and Deferred Income Tax Liability accounts. Since these tax accounts are normally adjusted quarterly, those amounts adjusted to be in sync with the test year. This adjustment, along with the adjustment from Schedule M-2, is summarized on Statement M, line 24 (b). Schedule M-2 – Adjustment to Deferred Taxes – Accelerated Depreciation. This Schedule reflects an adjustment for deferred income taxes on the pro forma plant additions from Schedule D-2. This calculation is based on 50% bonus depreciation. This adjustment, along with the adjustment from Schedule M-1, is summarized on Statement M, line 24 (b).


Section N

Statement N – Revenue Requirement Analysis: This Statement is where the revenue requirement is calculated. This Statement brings in all the pro forma amounts from the previous Statements and Schedules. The first section of this Statement shows rate base by functional plant classification (Production, Transmission, Distribution, and General), along with the working capital and other rate base reductions to calculate the adjusted rate base The next section is the operation and maintenance expense amounts by functional classification (Production, Transmission, Distribution, and General). The next sections are as follows:

1) Depreciation Expense 2) Taxes Other Than Federal Income Tax 3) Other Operating Revenue 4) Revenue Under Existing Rates 5) Federal Income Taxes

The Net Revenue Requirement is calculated on page 5 of 5 on line number 299. This calculation is a summary of the previous 4 pages starting with pro forma rate base multiplied by the rate of return from Statement G to calculate the required return on rate base on line number 289. The return on rate based is summed with the next four lines, representing pro forma operation and maintenance expenses, depreciation/amortization/ accretion expense, taxes other than federal income tax and federal income tax referenced from above, to determine the total revenue requirement. The total revenue requirement on line 295 is then reduced by other operating revenue as shown on Statement I Page 1 lines 9 and 15 to determine the net revenue requirement. The net revenue requirement is then subtracted from the revenue under existing rates to determine the revenue deficiency before the tax adjustment on line 303. This amount is then multiplied by the federal tax gross up factor on line 307 to determine the tax adjusted revenue deficiency amount on line 305.


Section O

Statement O – Adjusted Class Cost of Service. This Schedule provides for the adjusted comparison of Cheyenne Light cost of service and revenue deficiency by rate class, along with the allocation factors.


Section P

Statement P – Power Cost Adjustment. This Statement shows the base rate calculation for the Power Cost Adjustment, including steam plant, purchase power, and transmission expense, adjusted by sales for resale. This base rate will be used in the annual filing for the Power Cost Adjustment. For additional information regarding this adjustment, see Chris Kilpatrick’s testimony.


Section Q

Statement Q – Description of Utility Operations. This Statement provides a description of the Company’s area and diversity of electric and gas operations.


Section R

Statement R – Purchases from Affiliated Companies: This Statement shows the coal price per ton calculation used in Schedule H-7. Schedule H-7 calculates the total dollar amount of coal costs based on plant operations.

• Statement R Page 1 - shows the calculation of the rate base amount and how it is allocated to the utilities BHP and Cheyenne Light.

• Statement R Page 2 - shows the total Wyodak Resources expenses and the amount allocated to the utilities BHP and Cheyenne Light.

• Statement R Page 3 - shows the total tons of coal to be sold by customer and develops the allocation percentages to the utilities BHP and Cheyenne Light which are used on page one and two.

• Statement R Page 4 - shows the calculation of total Federal Income Tax and the amount allocated the utilities BHP and Cheyenne Light.

• Statement R Page 5 - shows the calculation of the rate of return used to determine the amount earned on rate base.

• Statement R Page 6 - shows the calculation of the price per ton of coal to be charged the utilities BHP and Cheyenne Light.

Statement APage 1 of 3

Line FERC Electric Gas Common TotalNo. Description Acct No. Business Business Business Company

1 Utility Plant2 Utility Plant in Service 101 312,572,755$ 62,682,407$ 11,414,001$ 386,669,163$ 3 Future Use Plant 105 10,915 801 - 11,716 4 Completed Construction Not Classified 106 6,924,397 2,291,489 638,917 9,854,803 5 Plant Acquisition Adjustment 114 - - 4,942,723 4,942,723 6 Construction Work in Progress 107 4,062,499 1,628,734 388,656 6,079,890 7 Other Utility Plant 118 3,699,461 3,151,970 4,153,373 11,004,804 89 Gross Utility Plant 327,270,027 69,755,402 21,537,670 418,563,098

10 Accum. Prov. For Depreciation 108 (60,388,355) (22,514,921) (5,013,930) (87,917,206) 11 Res. for Depr. Other Utility Property 119 (2,960,276) (2,574,010) (2,734,935) (8,269,221) 12 Net Utility Plant 263,921,396 44,666,471 13,788,805 322,376,671 1314 Current and Accrued Assets15 Cash 131 - - 116,611 116,611 16 Restricted Cash 134 - - 3,582 3,582 17 Working Funds 135 - - 2,300 2,300 18 Accts Receivable - Net 142-145; 173, 174 10,464,104 1,190,620 12,372,413 24,027,136 19 Accts Rec Assoc Company 146 49,329 33,714 1,088,590 1,171,633 20 Material and Supplies 154-163 801,395 - 4,943,528 5,744,923 21 Gas Stored Underground 164 - 1,648,943 - 1,648,943 22 Prepayments 165 690,331 - 99,119 789,450 23 Total Current & Accrued Assets 12,005,159 2,873,278 18,626,143 33,504,579 2425 Deferred Debits26 Unamortized Debt Expense 181 - - 1,333,506 1,333,506 27 Preliminary Survey 183 835,847 - 76,416 912,263 28 Miscellaneous Debits 184 234,421 210,162 212,994 657,577 29 Regulatory Assets - Cost Adjustment 182 9,338,666 - - 9,338,666 30 Regulatory Assets - AFUDC 182 3,897,855 - - 3,897,855 31 Regulatory Assets - Pension/Retiree H.C. 182 - 2,144,989 2,144,989 32 Regulatory Assets - Other 182 207,483 78,287 4,868,002 5,153,772 33 Unrecognized Gas Cost 191 - 1,401,622 - 1,401,622 34 Unamortized Loss on Reacquired Bond 189 - - 489,663 489,663 35 Deferred IT - R&D Credit Carry Over 190 135,850 - - 135,850 36 Deferred ITC 190 128,877 131,161 260,037 37 Deferred Income Tax - Gas Costs 190 - (213,564) - (213,564) 38 Deferred Income Tax Asset 190 463,688 398,455 9,227,556 10,089,700 39 Total Deferred Debits 15,242,686 2,006,123 18,353,126 35,601,936 4041 Total Assets and Other Debits 291,169,241$ 49,545,871$ 50,768,074$ 391,483,187$

August 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYASSETS AND OTHER DEBITS - TOTAL COMPANY

For the Test Year Ended August 31, 2011


Line FERC Electric Gas Common TotalNo. Description Acct No. Business Business Business Company

1 Proprietary Capital2 Common Stock Issued 201 1$ 0$ -$ 1$ 3 Premium on Capital Stock 207 56,552,769 9,590,821 - 66,143,590 4 Other Paid in Capital 208 60,256,125 10,218,875 - 70,475,000 5 Unapprop. Retained Earnings 216 32,693,465 2,112,654 - 34,806,119 6 Total Proprietary Capital 149,502,360 21,922,350 - 171,424,710 78 Long Term Debt9 Bonds 221 110,000,000 - 17,000,000 127,000,000 10 Total Long Term Debt 110,000,000 - 17,000,000 127,000,000 1112 Current & Accrued Liability13 Notes Payable 224, 233 - - 6,831 6,831 14 Accounts Payable 228, 232 4,378,215 754,915 (1,388,383) 3,744,747 15 Asset Retirement Obligation 230 10,071 - 204,359 214,430 16 Accounts Payables Assoc Company 234 - - 8,634,617 8,634,617 17 Customer Deposits 235 120,000 - 1,362,659 1,482,659 18 Taxes Accrued 236 27,612 1,453 3,489,304 3,518,370 19 Interest Accrued - Customer Deposits 237 - - 13,635 13,635 20 Interest Accrued - Other 237 - - 2,104,386 2,104,386 21 Tax Collections Payable 241 - - 691,875 691,875 22 Misc. Current & Accrued Liab. 242, 245 262,984 - 910,791 1,173,775 23 Total Current & Accrued Liability 4,798,883 756,369 16,030,074 21,585,326 2425 Deferred Credits26 Customer Advance for Construction 252 33,488 - 3,630,752 3,664,240 27 Accrued Pension Liability 253 - - 1,818,002 1,818,002 28 Accrued Retiree Health Care 253 - - 4,717,453 4,717,453 29 Other Deferred Credits 253 154,676 27,234 4,835,955 5,017,866 30 Other Regulatory Liabilities 254 128,878 131,163 1,954,128 2,214,169 31 Accrued Deferred ITC 255 239,349 243,589 737 483,675 32 Unamortized Gain on Reaquired Debt 257 - - 971,126 971,126 33 Deferred Tax LT - Accel. Depr. - Other 282 34,709,937 8,336,241 1,085,211 44,131,389 34 Deferred Income Tax Liability 283 6,857,476 - 1,597,756 8,455,231 35 Total Deferred Credits 42,123,804 8,738,227 20,611,120 71,473,151 3637 Total Liabilities & Other Credits 306,425,046.60$ 31,416,945$ 53,641,194$ 391,483,187$

August 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYLIABILITIES AND OTHER CREDITS - TOTAL COMPANY



(Stmt. A Pg 1 and Pg 2) (Note 1, 2, 3)Line Electric Common Total ElectricNo. Description Business Allocation Rate Base

1 Utility Plant2 Utility Plant in Service 312,572,755$ 6,009,469$ (1) 318,582,224$ 3 Less: Transaction Costs - (1,172,378) (3) (1,172,378) 4 Completed Construction Not Classified 6,924,398 336,390 (1) 7,260,788 5 Plant Acquisition Adjustment - 2,934,495 (1) 2,934,495 6 Other Utility Plant 3,699,461 2,911,514 (1) 6,610,976 7 Gross Utility Plant 323,196,614 11,019,490 334,216,105 89 Accum. Prov. For Depreciation (60,388,355) (2,639,834) (2) (63,028,189)

10 Accum. Depr. for Other Utility Property (2,960,276) (1,917,189) (2) (4,877,465) 11 Net Utility Plant 259,847,983 6,462,467 266,310,450 1213 Current and Accrued Assets14 Material and Supplies 801,395 3,465,413 (2) 4,266,808 15 Prepayments 690,331 52,929 (2) 743,260 16 Total Current & Accrued Assets 1,491,726 3,518,342 5,010,068 1718 Cash Working Capital (Stmt. F) (1,874,684) - (1,874,684) 1920 Other Rate Base Additions / (Reductions)21 Regulatory Assets - AFUDC 3,897,855 - 3,897,855 22 Regulatory Assets - Pension/Retiree HC - 1,113,249 (2) 1,113,247 23 Deferred Income Tax Assets 463,688 6,087,729 (2) 6,551,415 24 Accrued Pension Liability - (943,543) (2) (943,545) 25 Accrued Retiree Health Care - (2,448,358) (2) (2,448,360) 26 Deferred Tax LT - Accel. Depr. - Other (34,709,937) (571,364) (2) (35,281,303) 27 Deferred Income Tax Liability (6,857,476) (228,154) (2) (7,085,632) 28 Other Regulatory Liabilities (128,878) (1,614,110) (2) (1,742,990) 29 Customer Advance for Construction (33,488) (1,938,822) (2) (1,972,312) 30 Customer Deposits (120,000) (727,660) (2) (847,662) 31 Interest Accrued - Customer Deposits - (7,281) (2) (7,283) 32 Total Other Rate Base Add. / (Reductions) (37,488,235) (1,278,314) (38,766,549) 3334 Total Electric Rate Base 221,976,791$ 8,702,495$ 230,679,286$ 3536 Note (1) Reference Schedule D-1 (Plant in Service - Electric).37 Note (2) Reference Schedule A-1 (Balance Sheet Allocations for Common Business).383940

Note (3) Organizational costs allocated between Electric and Gas Businesses utilizing Schedule A-1 (Balance SheetAllocations for Common Business) allocator (e). Total company organizational costs were $2,226,739.

CHEYENNE LIGHT, FUEL AND POWER COMPANY

August 31, 2011

RATE BASE CALCULATION - ELECTRICFor the Test Year Ended August 31, 2011

Schedule A-1Page 1 of 2

LineNo.

1 Allocation Components:23 Description Amount Percent4 Total Electric Revenue (Stmt. B) (Note 3) 105,942,801 75.8% (a) % of electric / gas revenue to total revenue 5 Total Gas Revenue (Stmt. B) 33,749,427 24.2%6 Total Electric Employees - (Note 1) 41.0 51.9% (b) % of electric / gas employees to total employees7 Total Gas Employees - (Note 1) 38.0 48.1%8 Gross Electric Plant in Service (Stmt A) 323,207,528 82.6% (c) % of electric / gas plant in service to total plant in service9 Gross Gas Plant in Service (Stmt. A) 68,126,667 17.4%

10 Total Electric Customers as of 8/31/2011 39,631 53.4% (d) % of electric / gas customers to total customers11 Total Gas Customers as of 8/31/2011 34,600 46.6%12 Blended Electric Employees / Customers (Avg. line 6 and line 10) 52.7% (e) % Based on Average Employees (b) and Customers (d)13 Blended Gas Employees / Customers (Avg. line 7 and line 11) 47.4%14 Blended Revenue (a), Employees (b) & Plant (c) 70.1% (f) % Based on Average of (a), (b) and (c).15 Blended Revenue (a), Employees (b) & Plant (c) 29.9%16 (Note 2) (Note 2)17 (Stmt. A) Allocated Allocated 18 FERC Common Electric Gas19 Description Acct No. Balance Balance Business 20 Utility Plant in Service 101 11,414,001$ 6,009,472$ (e) 5,404,529$ (e)2122 Organizational Costs 101 (2,226,739) (1,172,378) (e) (1,054,361) (e)2324 Completed Not Classified - Common 106 638,917 336,390 (e) 302,527 (e)2526 Plant Acquisition Adjustment (Note 4) 114 4,942,723 2,934,495 2,008,228 2728 Other Utility Plant 118 4,153,373 2,911,514 (f) 1,241,858 (f)2930 Accum Depr. - Common 108 (5,013,930) (2,639,834) (e) (2,374,096) (e)3132 Accum Depr. - Other Utility Property 119 (2,734,935) (1,917,189) (f) (817,745) (f)3334 Materials and Supplies 154-163 4,943,528 3,465,413 (f) 1,478,115 (f)3536 Prepayments 165 99,119 52,929 (d) 46,189 (d)3738 Regulatory Assets - Pension/Retiree H.C. 182 2,144,989 1,113,249 (b) 1,031,740 (b)3940 Deferred Tax ST - Bad Debt Reserve 190 820,129 621,658 (a) 198,471 (a) 41 Deferred Tax ST - Vacation Pay 190 117,854 61,166 (b) 56,688 (b)42 Deferred Tax ST - Employee Insurance Group 190 21,275 11,042 (b) 10,233 (b)43 Deferred Tax ST - Worker's Compensation 190 7,392 3,836 (b) 3,556 (b)44 Deferred Tax LT - Retiree Health Care 190 1,950,685 1,012,405 (b) 938,279 (b)45 Deferred Tax LT - Pension FAS 87 190 568,930 295,275 (b) 273,655 (b)46 Deferred Tax LT - Debt Premium 190 385,826 318,692 (c) 67,134 (c)47 Deferred Tax LT - FAS 143 (ARO) 190 16,268 13,437 (c) 2,831 (c)48 Deferred Tax LT - LT Disability 190 176,850 91,785 (b) 85,065 (b)49 Deferred Tax LT - NOL Carry forward 190 3,268,435 2,699,727 (c) 568,708 (c)50 Deferred Tax LT - Pension (AOCI) 190 65,500 33,995 (b) 31,506 (b)51 Deferred Tax LT - Retiree Health (AOCI) 190 1,681,844 872,877 (b) 808,967 (b)52 Deferred Tax LT - Other 190 73,943 51,834 (f) 22,109 (f)53 Sub total Deferred Income Tax Asset 9,154,930 6,087,729 3,067,202 54 Deferred Tax LT - ITC - Other 190 267 221 (c) 46 (c)55 Deferred Tax LT - FAS 109 - Other 190 72,225 59,658 (c) 12,567 (c)56 Deferred Tax LT - FAS 109 - ITC - Other 190 133 110 (c) 23 (c)57 Total Deferred Income Tax Asset 9,227,556 6,147,718 3,079,838 5859 Customer Deposits 235 (1,362,659) (727,660) (d) (634,999) (d) 6061 Interest Accrued - Customer Deposits 237 (13,635) (7,281) (d) (6,354) (d) 6263 Customer Advances for Construction 252 (3,630,752) (1,938,822) (d) (1,691,930) (d) 6465 Accrued Pension Liability 253 (1,818,002) (943,543) (b) (874,459) (b)66 Accrued Retiree Healthcare 253 (4,717,453) (2,448,358) (b) (2,269,095) (b)6768 Regulatory Liabilities - Other 254 (206,784) (170,804) (c) (35,980) (c)69 Regulatory Liability - Retiree Healthcare 254 (1,681,844) (1,389,203) (c) (292,641) (c)70 Regulatory Liability - Pension 254 (65,500) (54,103) (c) (11,397) (c)

CHEYENNE LIGHT, FUEL AND POWER COMPANYBalance Sheet Allocations for Common Business


Schedule A-1Page 2 of 2

LineNo.

1 Allocation Components:23 Description Amount Percent4 Total Electric Revenue (Stmt. B) (Note 3) 105,942,801 75.8% (a) % of electric / gas revenue to total revenue 5 Total Gas Revenue (Stmt. B) 33,749,427 24.2%6 Total Electric Employees - (Note 1) 41.0 51.9% (b) % of electric / gas employees to total employees7 Total Gas Employees - (Note 1) 38.0 48.1%8 Gross Electric Plant in Service (Stmt A) 323,207,528 82.6% (c) % of electric / gas plant in service to total plant in service9 Gross Gas Plant in Service (Stmt. A) 68,126,667 17.4%

10 Total Electric Customers as of 8/31/2011 39,631 53.4% (d) % of electric / gas customers to total customers11 Total Gas Customers as of 8/31/2011 34,600 46.6%12 Blended Electric Employees / Customers (Avg. line 6 and line 10) 52.7% (e) % Based on Average Employees (b) and Customers (d)13 Blended Gas Employees / Customers (Avg. line 7 and line 11) 47.4%14 Blended Revenue (a), Employees (b) & Plant (c) 70.1% (f) % Based on Average of (a), (b) and (c).15 Blended Revenue (a), Employees (b) & Plant (c) 29.9%16 (Note 2) (Note 2)17 (Stmt. A) Allocated Allocated 18 FERC Common Electric Gas19 Description Acct No. Balance Balance Business

CHEYENNE LIGHT, FUEL AND POWER COMPANYBalance Sheet Allocations for Common Business


71 (1,954,128) (1,614,110) (340,018) 7273 Accrued Deferred ITC 255 (737) (609) (c) (128) (c)7475 Deferred Tax LT - Accel. Depr. - Other 282 (1,085,211) (571,364) (f) (513,847) (f)7677 Deferred Income Tax Liability - Other 283 (276,215) (228,154) (c) (48,061) (c)78 Deferred Income Tax Liability - Derivatives OCI 283 (1,321,541) (1,091,593) (c) (229,948) (c)79 Total Deferred Income Tax Liability (1,597,756) (1,319,747) (278,009) 8081 Total 11,335,644$ 7,610,296$ 3,725,347$ 8283 Note (1) Employee counts as of August 31, 2011. Common employee counts were allocated based on (d) or 8-31-2011 gross distribution plant as 84 provided in Schedule D-1 in the electric and gas rate cases.85 Note (2) Common business times the allocation factor designated in the column. Balance sheet allocations are utilized throughout the model, 86 all balance sheet allocations in model reference back to the percentages listed above based on the letter in parenthesis.90 Note (3) The Revenue Allocator was adjusted by eliminating the revenue recorded for the Basin transmission agreement of $25.9M.87 Note (4) Plant Acquisition Adjustment was allocated based on the Blended Revenue (a), Employees (b) & Plant (c) allocator approved88 in Dockets 30005-112-GR-07 and 20003-90-ER-07 - (59.37% electric and 40.63% gas). This is more reflective of the electric and gas business at the89 time of acquisition.

Statement BPage 1 of 2

Line FERC Electric Gas Common Total No. Description Acct No. Business Business Business Company

1 Electric Sales 440-447 129,223,445$ -$ -$ 129,223,445$ 2 Gas Sales 480-482 - 32,974,816 - 32,974,816 3 Other Electric Revenue 450-457, 407 2,654,715 - - 2,654,715 4 Other Gas Revenue 487-495 - 774,611 - 774,611 5 Total Revenue 131,878,161 33,749,427 - 165,627,588 67 Fuel 501 7,321,549 - - 7,321,549 8 Purchased Power 555-558 61,614,228 - - 61,614,228 9 Production Expense (Excludes Fuel) 500, 502-554 6,013,329 - - 6,013,329

10 Transmission 560-573 7,227,152 - - 7,227,152 11 Purchased Gas 803-813 - 19,343,533 - 19,343,533 12 Distribution Expense 580-598 2,836,806 - - 2,836,806 13 Gas Distribution/Trans. Expense 835, 856-894 - 3,089,276 - 3,089,276 14 Customer Accounting Expense 901-905 233,353 119,953 1,586,178 1,939,484 15 Customer Service Expense 907-912 366,694 33,946 830,498 1,231,139 16 Administrative & General Expense 920-935 645,520 45,863 9,134,000 9,825,383 17 Total O&M 86,258,632 22,632,572 11,550,675 120,441,880 1819 Depreciation Expense 403 8,395,488 1,463,247 1,447,887 11,306,621 20 Amortization 404 - - - - 21 Taxes Other than Income 408 882,146 320,538 1,676,933 2,879,617 22 Accretion Expense 411 9,296 - - 9,296 23 Total Depr & Taxes Other than Income 9,286,930 1,783,785 3,124,819 14,195,534 2425 Net Operating Income 36,332,599 9,333,070 (14,675,495) 30,990,174 2627 Non-Operating Income (& Expense) 415-417, 421-426 (13,765) (1,445) (39,050) (54,259) 28 Interest (Expense) 427-431 - - (8,047,249) (8,047,249) 29 AFUDC - Debt & Equity 419, 432 197,972 16,824 569,949 784,745 30 Non-Operating (Expense) 184,208 15,379 (7,516,350) (7,316,763) 3132 Income Before Tax 36,516,807 9,348,449 (22,191,845) 23,673,411 33 - 34 Federal Income Taxes 409-411 (7,454,636) (602,981) - (8,057,616) 3536 Net Utility Income 29,062,171$ 8,745,468$ (22,191,845)$ 15,615,795$

Twelve Months Ended August 31, 2011

STATEMENT OF INCOME FOR THE 12 MONTHS ENDED - TOTAL COMPANYCHEYENNE LIGHT, FUEL AND POWER COMPANY


Statement BPage 2 of 2

(Stmt. B) (Sched. B-1)Line Electric Common TotalNo. Description Business Allocation Electric

1 Electric Sales 129,223,445$ -$ 129,223,445$ 2 Gas Sales - - - 3 Other Electric Revenue 2,654,715 - 2,654,715 4 Other Gas Revenue - - - 5 Total Revenue 131,878,161 - 131,878,161 67 Fuel 7,321,549 - 7,321,549 8 Purchased Power 61,614,228 - 61,614,228 9 Production Expenses 6,013,329 - 6,013,329

10 Transmission 7,227,152 - 7,227,152 11 Purchased Gas - - - 12 Electric Trans / Distribution Expense 2,836,806 - 2,836,806 13 Gas Distribution Expense - - - 14 Customer Accounting Expense 233,353 847,018 1,080,371 15 Customer Service Expense 366,694 443,486 810,180 16 Administrative & General Expense 645,520 6,403,440 7,048,960 17 Total Operation & Maintenance Expense 86,258,632 7,693,944 93,952,576 1819 Depreciation Expense 8,395,488 762,312 9,157,800 20 Accretion Expense 9,296 - 9,296 21 Taxes Other than Income 882,146 1,364,039 2,246,185 22 Total Depr & Taxes Other than Income 9,286,930 2,126,351 11,413,281 2324 Net Operating Income 36,332,599$ (9,820,295)$ 26,512,304$

Twelve Months Ended August 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYNET OPERATING INCOME - ELECTRIC


Schedule B-1Page 1 of 1

LineNo.1 Allocation Components:23 Description Amount Percent4 Total Electric Revenue (Stmt. B) (Note 3) 105,942,801 75.8% (a) % of electric / gas revenue to total revenue5 Total Gas Revenue (Stmt. B) 33,749,427 24.2%6 Total Electric Employees (Note 1) 41.0 51.9% (b) % of electric / gas employees to total employees7 Total Gas Employees (Note 1) 38.0 48.1%8 Gross Electric Plant in Service (Stmt A) 323,207,528 82.6% (c) % of electric / gas plant in service to total plant in service9 Gross Gas Plant in Service (Stmt. A) 68,126,667 17.4%

10 Average Electric Customers for the 12 Months ended 8.31.11 39,631 53.4% (d) % of electric / gas customers to total customers11 Average Gas Customers for the 12 Months ended 8.31.11 34,600 46.6%12 Blended Electric Employees / Customers 52.7% (e) % Based on Average Employees (b) and Customers (d)13 Blended Gas Employees / Customers 47.4%14 Blended Revenue (a), Employees (b) & Plant (c) 70.1% (f) % Based on Average of (a), (b) and (c).15 Blended Revenue (a), Employees (b) & Plant (c) 29.9%161718 (Stmt. B) (Note 2) (Note 2)19 FERC Common Electric Gas 20 Description Acct No. Balance Business Business21 Supervision - Customer Accounting Expense 901 309,807$ 165,437$ (d) 144,370$ (d)22 Meter Reading - Customer Accounting Expense 902 197,905 105,681 (d) 92,224 (d)23 Customer Records and Collections Expense 903 888,404 474,407 (d) 413,996 (d)24 Uncollectible Account Expense 904 (408) (218) (d) (190) (d)25 Miscellaneous Expense - Customer Accounting 905 190,470 101,711 (d) 88,759 (d)26 Total Customer Accounting Expense 1,586,178 847,018 739,159 2728 Supervision - Customer Service Expense 907 800,866 427,662 (d) 373,204 (d)29 Customer Assistance Expenses 908 15,773 8,423 (d) 7,350 (d)30 Informational & Instructional Advertising Expense 909 11,731 6,264 (d) 5,467 (d)31 Miscellaneous Customer Service & Information Expense 910 1,779 950 (d) 829 (d)32 Sales Demonstrating and Selling 912 350 187 (d) 163 (d)33 Total Customer Service Expense 830,498 443,486 387,013 3435 Administrative & General Salaries/Overhead Offset 920 4,872,734 3,415,787 (f) 1,456,948 (f)36 Office Supplies Expense 921 1,220,179 855,346 (f) 364,834 (f)37 Administrative Expense- Trans. Credit 922 (11,433) (8,014) (f) (3,418) (f)38 Outside Services Employed 923 821,823 576,098 (f) 245,725 (f)39 Property Insurance Expense 924 250,051 206,542 (c) 43,509 (c)40 Injuries & Damages Expense 925 582,160 480,864 (c) 101,296 (c)41 Employee Pension & Benefit Expense 926 20,230 10,499 (b) 9,731 (b)42 Regulatory Commission Expense 928 282,740 214,317 (a) 68,423 (a)43 Advertising Expense 930 187,801 100,285 (d) 87,515 (d)44 Miscellaneous General Expense 930 255,465 179,081 (f) 76,384 (f)45 Rents Expense/AP Discounts 931 167,485 117,407 (f) 50,078 (f)46 General Plant Maintenance Expense 935 484,764 255,228 (e) 229,536 (e)47 Total Administrative & General Expense 9,134,000 6,403,440 2,730,561 4849 Depreciation Expense 403 1,447,887 762,312 (e) 685,574 (e)5051 Property Taxes 408 1,608,175 1,328,353 (c) 279,822 (c)52 SUTA 408 73,623 38,211 (b) 35,413 (b)53 FUTA 408 9,818 5,096 (b) 4,723 (b)54 FICA 408 964,699 500,679 (b) 464,020 (b)55 Payroll Loading and Other 408 (979,383) (508,300) (b) (471,083) (b)56 Total Taxes Other than Income 1,676,933 1,364,039 312,895 5758 Total 14,675,495$ 9,820,295$ 4,855,202$ 5960 Note (1) Employee counts as of August 31, 2011. Common employee counts were allocated based on (d) or 8-31-2011 gross distribution plant provided. 61 in Schedule D-1 of the electric and gas rate cases.62 Note (2) Common business times the allocation factor designated in the column. Income statement allocations are utilized throughout the model, all 63 income statement allocations in model reference back to the percentages listed above based on the letter in the parenthesis.64 Note (3) The Revenue Allocator was adjusted by eliminating the revenue recorded for the Basin transmission agreement of $25.9M.

CHEYENNE LIGHT, FUEL AND POWER COMPANYIncome Statement Allocations for Common Business


Statement CPage 1 of 1

Line FERC Total No. Description Acct No. Company

1 Balance at Beginning of Period 201-216 170,308,915$ 2 Net Income 216 15,615,795 3 Dividends from Subsidiary - 4 Total Before Deductions 185,924,710 56 Dividends Paid/Declared and Other (14,500,000) 78 Balance at End of Period 201-216 171,424,710$

STATEMENT OF RETAINED EARNINGS - TOTAL COMPANYCHEYENNE LIGHT, FUEL AND POWER COMPANY


Statement DPage 1 of 2

(a) (b) (b) (d) (e)(a) + (b) + (c ) + (d)

(Sched. D-1) (Sched. D-1) (Sched. D-1) (Sched. D-1) (Note 1)Line FERC Balance at Transfers and Balance atNo. Acct No. Description Aug 31, 2010 Additions Retirements Adjustments Aug 31, 2011

1 Electric Plant in Service2 101 Steam Production 181,081,679$ 4,077,673$ (2,999,317)$ -$ 182,160,035$ 3 101 Transmission 4,813,166 13,017 - - 4,826,183 4 101 Distribution 122,707,393 7,107,417 (6,790,918) (97,151) 122,926,741 5 101 General 2,632,740 27,056 - - 2,659,796 6 Total Electric Plant 311,234,978 11,225,163 (9,790,235) (97,151) 312,572,755 78 105 Future Use Land 10,913 - - - 10,913 910 106 Steam Production 3,444,733 (3,783,041) - 754,503 416,195 11 106 Transmission 9,267 382,277 - 951,509 1,343,052 12 106 Distribution 1,377,354 3,372,928 - - 4,750,282 13 106 General - Electric 1,957,575 163,306 - (1,706,012) 414,869 1415 Total Electric Plant in Service 318,034,820$ 11,360,633$ (9,790,235)$ (97,151)$ 319,508,067$ 1617 Gas Plant in Service18 101 Transmission 73,939$ 13$ (73,952)$ -$ -$ 19 101 Distribution Plant 58,995,353 3,167,472 (655,996) (29,610) 61,477,219 20 101 General 868,913 336,275 - - 1,205,188 21 Total Gas Plant 59,938,205 3,503,760 (729,948) (29,610) 62,682,407 2223 105 Future Use Mains 801 - - - 801 2425 106 Transmission 489,583 (374,872) - (114,712) - 26 106 Distribution 343,305 1,748,219 - 114,712 2,206,235 27 106 General - Gas 310,881 (225,627) 85,254 2829 Total Gas Plant in Service 61,082,775$ 4,651,480$ (729,948)$ (29,610)$ 64,974,697$ 3031 General Plant in Service32 101 General Plant in Service (Note 2) 10,909,635$ 586,315$ (81,949)$ -$ 11,414,001$ 3334 106 General 239,899 399,018 - - 638,917 3536 114 Acquisition Adjustment 4,630,443 312,280 - - 4,942,723 3738 118 Other Utility Plant 3,298,539 7,706,265 - - 11,004,804 3940 Total General Plant 19,078,516$ 9,003,878$ (81,949)$ -$ 28,000,445$ 41424344 Note (1) Balance at August 31, 2011 is the sum of August 31, 2010 balance plus additions, retirements, transfers and adjustments for the twelve months45 ended August 31, 2011. All Electric Plant detail is located on Schedule D-1, Gas Plant detail is located in the gas filing Schedule D-1.4647

CHEYENNE LIGHT, FUEL AND POWER COMPANYUTILITY PLANT IN SERVICE - TOTAL COMPANY


Note (2) Utility plant in service includes organization costs, these costs are not included in rate base. General plant in service is from the Electric and Gas Schedule D-1.

Statement DPage 2 of 2

(a) (b) (c)(a) + (b)

(Sched. D-1)Per Books (Note 1) AdjustedPlant in Subsequent Plant in

Line FERC Service for Additions & Service forNo. Acct No. Description Rate Base Retirements Rate Base1 101 Steam Production Plant 182,160,034$ -$ 182,160,034$ 2 101 Transmission Plant 4,826,184 - 4,826,184 3 101 Distribution Plant 122,926,742 - 122,926,742 4 101 General Plant - Electric (Note 3) 2,659,795 87,500 2,747,295 5 101 General Plant - Common Allocation (Note 2) 4,837,091 - 4,837,091 6 Total Electric Plant in Service 317,409,846 87,500 317,497,346 78 106 Steam Generation 416,195 4,058,114 4,474,309 9 106 Transmission 1,343,052 5,944,346 7,287,398

10 106 Distribution 4,750,282 11,298,389 16,048,671 11 106 General - Electric 414,869 - 414,869 12 106 General - Common Allocation 336,390 1,171,682 1,508,072 13 Total Electric Plant Not Classified 7,260,788 22,472,530 29,733,319 1415 114 Acquisition Adjustment (Note 4) 2,934,495 (358,661) 2,575,835 1617 118 Other Utility Plant 6,610,975 472,499 7,083,474 1819 Total Electric Plant 334,216,105$ 22,673,868$ 356,889,973$ 202122232425 Note (4) Reference Schedule D-3 for net acquisition adjustment balance as of August 31, 2011.

Note (3) Unexpensed rate case costs referenced in Schedule H-5.

CHEYENNE LIGHT, FUEL AND POWER COMPANYADJUSTED PLANT IN SERVICE FOR RATE BASE - ELECTRIC

For the Pro Forma Test Year Ended August 31, 2011

Note (2) Rate base plant in service does not include organization costs.

Note (1) Subsequent additions and retirements references Schedule D-2. Schedule D-2 includes projected property additions and retirements fromthe pro forma test year.

Schedule D-1Page 1 of 2

(a) (b) (c ) (d) (e)(a) + (b) + (c ) + (d)

Line Account Balance at Transfers and Balance atNo. Number Electric Plant in Service Aug 31, 2010 Additions Retirements Adjustments Aug 31, 2011

1 STEAM PLANT23 311 Structures and Improvements 8,281,714$ 173,550$ -$ -$ 8,455,264$ 4 312 Boiler Plant Equipment 93,487,954 1,083,927 (222,938) - 94,348,943 5 314 Turbo generator Units 70,176,440 1,216,500 (1,417,638) - 69,975,302 6 315 Accessory Electric Equipment 9,050,944 1,587,544 (1,358,741) - 9,279,747 7 316 Miscellaneous Power Plant Equipment 84,627 16,151 - - 100,778 8 Total Steam Plant 181,081,679 4,077,673 (2,999,317) - 182,160,034 9

10 TRANSMISSION PLANT1112 350 Land 1,173,555$ 3,000$ -$ -$ 1,176,555$ 13 350 Land Rights 103,990 - - - 103,990 14 352 Structures and Improvements 69,462 - - - 69,462 15 353 Station Equipment 1,374,577 10,017 - - 1,384,594 16 354 Tower and Fixtures 364,188 - - - 364,188 17 355 Poles and Fixtures 842,018 - - - 842,018 18 356 Overhead Conductors and Devices 885,377 - - - 885,377 19 Total Transmission Plant 4,813,166 13,017 - - 4,826,184 2021 DISTRIBUTION PLANT2223 303 Miscellaneous Intangible Plant 168,500$ -$ -$ -$ 168,500$ 24 360 Land 86,926 - - - 86,926 25 360 Land Rights 48,509 49,638 - - 98,147 26 361 Structures and Improvements 514,405 20,387 - - 534,793 27 362 Station Equipment 13,258,382 308,836 (106,766) - 13,460,453 28 364 Poles, Towers, and Fixtures 18,299,583 807,541 (246,668) (48,009) 18,812,447 29 365 Overhead Conductors and Devices 18,080,292 1,374,626 (144,295) (1,570,588) 17,740,035 30 366 Underground Conduit 5,818,877 219,413 (1,167) (2,700) 6,034,424 31 367 Underground Conductors and Devices 26,427,168 2,233,490 (120,298) (27,648) 28,512,712 32 368 Line Transformers 14,622,480 760,754 (127,156) 1,551,725 16,807,803 33 369 Services 12,666,471 550,977 (68,053) (69) 13,149,327 34 370 Meters 2,803,032 273,053 (2,247,559) - 828,526 35 3701 Meters - ERT 3,725,212 - (3,720,250) - 4,962 36 371 Installations on Customers' Premises 1,105,990 83,727 (2,143) - 1,187,574 37 373 Street Lighting and Signal Systems 5,081,566 424,973 (6,564) 138 5,500,113 38 Total Distribution Plant 122,707,393 7,107,417 (6,790,918) (97,151) 122,926,742 3940 GENERAL PLANT4142 391 Office Furniture and Equipment 311,421$ 2,371$ -$ -$ 313,792$ 43 392 Transportation Equipment 1,365,497 - - - 1,365,497 44 393 Stores Equipment 9,706 - - - 9,706 45 394 Tools, Shop and Garage Equipment 537,298 24,685 - - 561,983 46 395 Laboratory Equipment 35,126 - - - 35,126 47 396 Power Operated Equipment 197,495 - - - 197,495 48 397 Communication Equipment 176,196 - - - 176,196 49 Total General Plant 2,632,740 27,056 - - 2,659,795 5051 GENERAL PLANT - COMMON ALLOCATION (Note 2)5253 301 Organization (Note 1) 1,172,378$ -$ -$ (1,172,378)$ -$ 54 389 Land 32,840 - - - 32,840 55 390 Structures and Improvements 1,293,629 185,907 - - 1,479,536 56 391 Office Furniture and Equipment 653,649 35,619 - - 689,268 57 392 Transportation Equipment 973,893 21,067 - - 994,960 58 393 Stores Equipment 64,167 - - - 64,167 59 394 Tools, Shop and Garage Equipment 479,349 13,723 - - 493,072 60 395 Laboratory Equipment 438 - - - 438 61 396 Power Operated Equipment 216,144 28,177 (43,146) - 201,175 62 397 Communication Equipment 837,502 24,201 - - 861,703 63 398 Miscellaneous Equipment 19,932 - - - 19,932 64 Total General Plant - Allocation 5,743,922 308,694 (43,146) (1,172,378) 4,837,091

CHEYENNE LIGHT, FUEL AND POWER COMPANYRate Base Plant in Service - Electric



(a) (b) (c ) (d) (e)(a) + (b) + (c ) + (d)

Line Account Balance at Transfers and Balance atNo. Number Electric Plant in Service Aug 31, 2010 Additions Retirements Adjustments Aug 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYRate Base Plant in Service - Electric


6566 PLANT HELD FOR FUTURE USE6768 360 Distribution - Land Owned in Fee (Note 5) 10,913 10,913 6970 COMPLETED CONSTRUCTION NOT CLASSIFIED7172 106 Steam Generation 3,444,733$ (3,783,041)$ -$ 754,503$ 416,195$ 73 106 Transmission 9,267 382,277 - 951,509 1,343,052 74 106 Distribution 1,377,354 3,372,928 - - 4,750,282 75 106 General - Electric 1,957,575 163,306 - (1,706,012) 414,869 76 106 General - Common Allocation (Note 2) 126,307 210,083 - - 336,390 77 Total Completed Constr. Not Classified 6,915,235 345,553 - - 7,260,788 7879 PLANT ACQUISITION ADJUSTMENT8081 114 Acquisition Adjustment (Note 3) 2,749,094$ 185,401$ -$ -$ 2,934,495$ 8283 OTHER UTILITY PLANT (Note 4)8485 118 Other Utility Plant - Electric 1,108,863$ 2,590,598$ -$ -$ 3,699,461 86 118 Other Utility Plant - Common 872,687 2,038,828 - - 2,911,514 87 Total Other Utility Plant 1,981,549 4,629,426 - - 6,610,975 8889 TOTAL ELECTRIC PLANT IN SERVICE 328,635,691$ 16,694,237$ (9,833,381)$ (1,269,529)$ 334,227,017$ 9091929394 Note (3) Plant Acquisition Adjustment was allocated based on the Blended Revenue (a), Employees (b) & Plant (c) allocator approved95 in Dockets 30005-112-GR-07 and 20003-90-ER-07 - (59.37% electric and 40.63% gas). This is more reflective of the electric and gas business at the96 time of acquisition. A change to the acquisition adjustment occurred in the test year. The prior owners of CLFP under went a federal tax audit that was97 recently completed. This resulted in a change to the NOL carry forward and the associated deferred tax asset that was acquired in the CLFP transaction. 9899 Note (5) Plant held for Future Use is not included in rate base.

Note (4) Other Utility Plant allocation based on Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (f).

Note (1) Transactional costs incurred during the acquisition of Cheyenne Light from Xcel Energy by Black Hills Corporation are included as part of plant in service but arenot included as part of rate base.Note (2) General Plant allocation based on Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (e).


LineNo. Project Description Amount

1 Electric Steam Production Plant2 Electric Steam Projects < $100,000 1,135,785$ 3 Chemical Treatment Area Enclosure 1,041,188 4 CSR Catalyst Replacement 603,550 5 Backup Battery Replacement 130,000 6 Iron Carbonate Injection System 300,000 7 Redundant Coal Conveying System 221,038 8 Turbine Packing & Replacement 523,553 9 Economizer Outlet Screen Replacement 103,000

10 Total Electric Steam Production Plant 4,058,114$ 111213 Electric Transmission Plant14 Electric Transmission Projects < $100,000 30,553$ 15 Skyline /Archer 115 kV - cross bars and line raising 106,455 16 SCADA Replacement Upgrade 120,000 17 Replace Happy Jack Breaker #262 120,797 18 Skyline/Archer 115 kV line - line dampners 228,985 19 East Business Park Substation 5,050,868 20 South Cheyenne 230/115 kV Substation 286,688 21 Total Electric Transmission Plant 5,944,346$ 222324 Electric Distribution Plant25 Electric Distribution Projects < $100,000 3,225,484$ 26 Swan Development - addition/distribution loop 1,031,322 27 Relocation - Converse Right of Way 235,618 28 Happy Jack Sub-Replace 115 kV Oil Circuit Breaker 213,340 29 Crow Creek Relay Upgrades 100,469 30 Distribution Project Engineering Costs 244,052 31 Happy Jack Reconductor 240,506 32 Polo Ranch Reconductor 117,917 33 East Business Park 1,575,147 34 Skyline Feeder 1,072,900 35 Replace OH Spacer Cable 200,000 36 Auto Throw Over (ATO) Upgrade for VA Hospital 175,000 37 Underground service and meter enclosures 328,182 38 Replace Distribution 427,595 39 Underground Replacement Program 467,357 40 Distribution Feeder Work 773,658 41 Electric Transformer Blanket 869,842 42 Total Electric Distribution Plant 11,298,389$ 43

CHEYENNE LIGHT, FUEL AND POWER COMPANYSubsequent and Expected Additions - Electric



LineNo. Project Description Amount

CHEYENNE LIGHT, FUEL AND POWER COMPANYSubsequent and Expected Additions - Electric


4445 General Plant - Common Allocation (Note 1)46 General Plant Projects < $100,000 619,212$ (e)47 General Plant Facilities/Structure 244,043$ (e)48 Vehicle Replacement 251,562$ (e)49 7 Core Systems Unification 56,865$ (e)50 Total General Plant - Allocated to Electric 1,171,682$ 5152 Other Utility Plant (Note 2)53 Service Company - Information Technology and Other 472,499 (f)54 Total Other Utility Plant 472,499 555657 Total Electric Plant Additions 22,945,029$ 5859606162

Note (2) Other Utility Plant allocated between Electric and Gas business utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (f).

Note (1) General Plant - Common Allocation allocated between Electric and Gas business utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (e).


LineNo. Description Reference Amount

1 Acquisition Adjustment Balance Schedule D-1 Line 81 (e) 2,934,495$ 23 Amortization Period Docket No. 20003-90-ER-7 (Note 1) 30 Years45 Annual Amortization Amount Line 1 ÷ Line 3 97,817$ 6789 Amortized Period - 1/1/2008 - 8/31/2011 Docket No. 20003-90-ER-07 (Note 1) 3.67 Years1011 Accumulated Amortization as of 8/31/2011 Line 5 x Line 9 358,661$ 1213 Net Acquisition Adjustment Line 1 - Line 11 2,575,835$ 141516 Note 1 - Reference Stipulation and Agreement Dated October 18, 2007, paragraph 11 for Docket No. 20003-90-ER-07.

CHEYENNE LIGHT, FUEL AND POWER COMPANYAcquisition Adjustment Annual Amortization - Electric



LineNo. Policy Description

123456

Interest is charged monthly on construction projects on all electric property classified as work in progressnot completed or in service, provided that construction has not been halted for an extended period oftime.

Overhead costs related to construction projects are capitalized in accordance with Electric Plantinstructions of the FERC Uniform System of Accounts.

CHEYENNE LIGHT, FUEL AND POWER COMPANYPolicy of Capitalizing Interest and Other Overheads During Construction




1 Power Plants:234567 Transmission Plant:89

1011121314151617 Distribution Plant:18192021222324252627 General Plant:2829303132 Retirement Units:33

CHEYENNE LIGHT, FUEL AND POWER COMPANYPolicy of Continuing Property Records

Each unit of general plant is separately identified and the records are maintained exactly like the powerplant records explained earlier for land and buildings. All other general plant is recorded utilizing avintage year accounting method (AR15) per FERC guidelines.

The Company uses retirement units that conform to FERC guidelines.

The records for distribution land, buildings, substations, transformer, and meters are maintained exactlylike the power plant records outlined above.

The units in the mass distribution accounts are maintained by county by year installed. The originalinstalled cost of these units is the average installed cost in the county for that year. When a unit isretired, the county is determined from the work order and the installed cost based on the oldest unit inservice is removed from the records of the Company. If the unit is reusable, the salvage value is bookedat average unit prices for that item.


A record exactly like the power plant record is maintained for each transmission substation. This recordincludes land, buildings and equipment.

A record for each transmission line is maintained. The original installed cost of units are an average oflike units within the line (e.g. all wood poles of the same age would have the same original installed costof the line). When a unit is retired, it is handled in the same manner as described above for power plants.If the unit is reusable the salvage value is booked at the average unit price for that item.

Each power plant is unitized in accordance with FERC rules and regulations. A record of original cost,age and description is maintained for each unit by plant location. When a unit is retired, the originalinstalled cost of that unit is removed from the records of the Company. If the unit is reusable or has avalue, the salvage is booked at market value.

Statement EPage 1 of 2

(a) (b) (c) (d) (e) (f) (g) (h)(a) + (b) + (c) +(d) + (e) + (f) + (g)

(Note 1) (Note 2)Line Common Other Utility Other Utility No. Description Production Transmission Distribution General Allocation Plant - Electric Plant - Common TOTAL

1 Balance August 31, 2010 13,116,174$ 2,033,899$ 45,383,729$ 869,888$ 2,258,583$ 707,843$ 458,426$ 64,828,542$ 23 Utility Holdings Allocation - - - - - 1,893,200 1,226,110 3,119,310 45 Add: Depreciation Exp 4,736,076 129,505 3,465,955 308,833 395,321 275,997 178,746 9,490,433 6 Less: Retirements Closed (2,999,317) - (6,787,296) - (43,146) - - (9,829,759) 7 Cost of Removal Closed (243,056) (154) (49,472) - (61) - - (292,743) 89 Add: Salvage Closed - - 33,266 - 12,060 - - 45,326

10 Add: Transfers & Adjustments 215,610 101,346 273,456 (200,088) 17,077 83,237 53,907 544,545 1112 Balance August 31, 2011 14,825,487$ 2,264,596$ 42,319,638$ 978,633$ 2,639,834$ 2,960,276$ 1,917,189$ 67,905,654$ 131415 Note (2) Other Utility Plant - Common is allocated between Electric and Gas business utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (f).

CHEYENNE LIGHT, FUEL AND POWER COMPANYACCUMULATED PROVISION FOR DEPRECIATION - ELECTRIC


Note (1) Common Allocation allocated between Electric and Gas business utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (e).

Statement EPage 2 of 2

(a) (b) (c)(a) + (b)

(Stmt. E) Note (2)Per Books Depreciation Expense Adjusted

Line Accumulated for Subsequent AccumulatedNo. Description Depreciation Additions/Retirements Depreciation1 Steam Production 14,825,487$ 53,050$ 14,878,537$ 23 Transmission 2,264,596 69,549 2,334,145$ 45 Distribution 42,319,638 159,872 42,479,510$ 67 Electric General 978,633 - 978,633$ 89 Common General (Note 1) 2,639,834 46,984 2,686,819$

1011 Other Utility Plant 4,877,465 18,947 4,896,413$ 1213 Total Adjusted Plant in Service 67,905,654$ 348,402$ 68,254,056$ 1415 Note (1) Common General allocated between Electric and Gas business utilizing Schedule A-1 16 (Balance Sheet Allocations for Common Business ) allocator (e).17 Note (2) Includes depreciation expenses for subsequent additions and retirements18 (Stmt D Pg 2) for the pro forma test year based on depreciation rates 19 provided in Stmt J, divided by two to average changes that occur throughout the 12 month20 period.

CHEYENNE LIGHT, FUEL AND POWER COMPANYADJUSTED ACCUMULATED PROVISION FOR DEPRECIATION - ELECTRIC


Schedule E-1Page 1 of 1


123456789

1011

There have been no changes in depreciation methods and procedures for the test year ended August 31,2011.

CHEYENNE LIGHT, FUEL AND POWER COMPANYDepreciation and Amortization Method - Total Company


The Company's depreciation expense rates are based on a depreciation study completed by Black &Veatch Consulting Engineers of Kansas City, Missouri, in January 2007. The study was performed inaccordance with standard industry practices. The study was completed using Company data throughSeptember 30, 2006. Specific depreciation expense rates are calculated for each FERC property accountand are applied to a twelve-month average of the property account investments to calculate annualdepreciation expense. See Statement J for calculation of depreciation expense for the test year based onthese rates. A more recent depreciation study was not completed as there was no new generation added.

Schedule E-2Page 1 of 1


123

Accumulated depreciation balances shown on Statement E for each functional classification are the resultof journal entries recorded monthly to reflect depreciation expense, retirements, cost of removal andsalvage.

CHEYENNE LIGHT, FUEL AND POWER COMPANYRecording Accumulated Depreciation - Total Company


Statement FPage 1 of 1

Line (Notes 1, 2) (Notes 2, 3) AdjustedNo. Description Reference Per Books Adjustments Balance

1 Cash Working Capital Sched. F-1 Ln 33 (b) (1,874,684)$ (1) (188,546)$ (3) (2,063,230) 23 Materials and Supplies Sched. F-2 Ln 25 (a) 4,266,808 (2) 958,839 (2) 5,225,647 45 Prepaid Expenses Sched. F-2 Ln 25 (b) 743,261 (2) - 743,261 67 Total Working Capital - Electric 3,135,385$ 770,293$ 3,905,678$ 89 Note (1) Reference Schedule F-1 for the lead lag study results.

10 Note (2) Reference Schedule F-2 for the past twelve month history and utilizing the August 31, 2011 balance11 and the adjustment for the 2012 purchase of the spare transformer.12 Note (3) Reference Schedule F-3 which utilizes the lead lag results including adjustments to cash working capital.

CHEYENNE LIGHT, FUEL AND POWER COMPANYWORKING CAPITAL - ELECTRIC


Schedule F-1Page 1 of 1

(a) (b) (c) (d)(a) ÷ 365 (b) x (c)

Line Per Expense Expense ExpenseNo. Description Reference Books Per Day Lead Days Dollar Days12 Coal Stmt. H Ln 3 (a) 7,196,754$ 19,717$ 35.2 694,038$ 3 Purchased Power and Transmission Stmt. H Lns 24 + 25 +36 (a) 68,234,828 186,945 31.2 5,832,684 4 Net Payroll Sched. H-1 Pg 2 Ln 27 (c) 1,647,343 4,513 14.0 63,182 5 Service/Holdings Company Charges Sched H-3 Pg 2 Ln 17 (a) + H-4 Pg 2 Ln 29 (a) 6,748,905 18,490 45.6 843,144 6 Other O & M 10,124,746 27,739 45.6 1,264,898 7 Total O & M 93,952,576 257,404 8,697,9468910 Property Tax Statement L Line 9 (a) 1,328,353 3,639 517.5 1,883,18311 Unemployment - State - (SUTA) Statement L Line 6 (a) 38,211 105 75.6 7,93812 Unemployment - Federal - (FUTA) Statement L Line 3 (a) 5,096 14 75.6 1,05813 FICA Statement L Line 2 (a) 500,679 1,372 15.0 20,58014 Wyoming Electric Franchise Fees Statement L Line 10 (a) 893,877 2,449 20.2 49,470 15 Total Taxes Other Than Income 2,766,216 7,579 1,962,229161718 Depreciation Expense Stmt. B Pg 2 Line 19 9,157,800 25,090 19 Total Depreciation 9,157,800 25,090 2021 Federal Income Taxes Stmt. K Pg 2 Line 52 6,929,471 18,985 38.5 730,9232223 Interest Expense on Long Term Debt Sched. G-1 Line 9 6,538,288 17,913 91.3 1,635,4572425 TOTAL 326,971 13,026,555 2627 Revenue Lag Days 36.028 Expense Lead Days Line 25 (d) ÷ Line 25 (b) 39.829 Net Days Line 27 - Line 28 (3.8)3031 Gross Cash Working Capital Requirement Line 25 (b) x Line 29 (a) (1,255,599) 32 Less: Tax Collections Available Line 40 (d) (619,085) 33 Net Cash Working Capital Requirement Line 31 + Line 32 (1,874,684)$ 3435 TAX COLLECTIONS AVAILABLE36 FICA Taxes (Employee Contribution) 97,593$ 267$ 15.0 4,005$ 37 Federal Withholding Tax 477,689 1,309 15.0 19,635 38 Wyoming Sales Tax 4,044,565 11,081 45.6 505,515 39 Wyoming Franchise Fees - Customer Paid 1,625,156 4,452 20.2 89,930 40 TOTAL 6,245,003$ 17,109$ 619,085$

DEPRECIATION

OPERATIONS & MAINTENANCE

TAXES OTHER THAN INCOME

CHEYENNE LIGHT, FUEL AND POWER COMPANYCash Working Capital Calculation - Electric



(a) (b)

(Note 1) (Note 1)Materials Prepaid

Line and Supplies ExpensesNo. (Accts. 154, 156, 163) (Acct. 165)

1 2010 August 3,271,054$ (f) 176,425$ (d)23 2010 September 3,249,804 (f) 38,747 (d)45 2010 October 3,233,503 (f) 146,525 (d)67 2010 November 3,276,324 (f) 136,323 (d)89 2010 December 3,211,148 (f) 116,754 (d)

1011 2011 January 3,548,452 (f) 104,061 (d)1213 2011 February 3,609,059 (f) 91,368 (d)1415 2011 March 3,625,778 (f) 632,778 (d)1617 2011 April 3,934,129 (f) 601,278 (d)1819 2011 May 3,629,480 (f) 671,307 (d)2021 2011 June 4,344,278 (f) 797,609 (d)2223 2011 July 4,140,307 (f) 780,941 (d)2425 2011 August 4,266,808 (f) 743,261 (d)2627 2012 Spare Transformer (Note 2) 958,839 2829 Adjusted Balance 5,225,647$ 743,261$ 303132333435 Note (2) A critical spare transformer for the system in Cheyenne will be received in 2012.

Note (1) Common Materials & Supplies and Prepaid Expenses allocated between Electric and Gasbusiness utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator (d).

Month Ending

CHEYENNE LIGHT, FUEL AND POWER COMPANYComponents of Claimed Working Capital - Electric



(a) (b) (c) (d)(a) ÷ 365 (b) x (c)

Line Adjusted Expense Expense ExpenseNo. Description Reference Total Per Day Lead Days Dollar Days12 Coal Stmt. H Ln 3 (m) 8,890,889$ 24,359$ 35.2 857,437$ 3 Purchased Power and Transmission Stmt. H Lns 24 + 25 +36 (m) 69,262,994 189,762 31.2 5,920,574 4 Net Payroll Sched. H-1 Pg 2 Ln 27 (d) 1,947,594 5,336 14.0 74,704 5 Service/Holding Company Charges Sched H-3 Pg 2 Ln 17 (b) + H-4 Pg 2 Ln 29 (b) 7,538,156 20,652 45.6 941,731 6 Other O & M 10,382,728 28,446 45.6 1,297,138 7 Total O & M 98,022,362 268,555 9,091,584 8910 Property Tax Statement L Line 9 (c) 1,547,317 4,239 517.5 2,193,683 11 Unemployment - State - (SUTA) Statement L Line 6 (c) 38,737 106 75.6 8,014 12 Unemployment - Federal - (FUTA) Statement L Line 3 (c) 5,622 15 75.6 1,134 13 FICA Statement L Line 2 (c) 523,648 1,435 15.0 21,525 14 Wyoming Electric Franchise Fees Statement L Line 10 (c) 989,574 2,711 20.2 54,762 15 Total Taxes Other Than Income 3,104,899 8,506 2,279,118 161718 Depreciation Expense Stmt. J Line 23 (e) 10,360,770 28,386 1920 Federal Income Taxes Stmt. K Pg 3 Line 11 5,766,541 15,799 38.5 608,262 2122 Interest Expense on Long Term Debt Sched. G-1 Line 35 6,399,746 17,534 91.3 1,600,854 2324 TOTAL 338,780 13,579,818 2526 Revenue Lag Days 36.027 Expense Lead Days Line 24 (d) ÷ Line 24 (b) 40.128 Net Days Line 26 - Line 27 (4.1)2930 Gross Cash Working Capital Requirement Line 24 (b) x Line 28 (a) (1,388,998) 31 Less: Tax Collections Available Line 39 (d) (674,232) 32 Net Cash Working Capital Requirement Line 30 + Line 31 (2,063,230) 3334 TAX COLLECTIONS AVAILABLE35 FICA Taxes (Employee Contribution) Note 1 115,380$ 316 15.0 4,740$ 36 Federal Withholding Tax Note 1 564,754 1,547 15.0 23,20537 Wyoming Sales Tax Note 2 4,399,042 12,052 45.6 549,81238 Wyoming Franchise Fees - Customer Paid Note 2 1,743,315 4,776 20.2 96,47539 TOTAL 6,822,491$ 18,691 674,232$ 4041 Note (1) Adjusted tax amounts based on per books tax as a percentage of total O & M wages times adjusted O & M wages.42 Note (2) Adjusted tax amounts based on revenue requirement (Statement M Ln 2 (d)) multiplied by tax/fee rate plus per books amount on Sched. F-1.

TAXES OTHER THAN INCOME

DEPRECIATION AND ACCRETION

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdjusted Cash Working Capital Calculation - ElectricFor the Pro Forma Test Year Ended August 31, 2011

OPERATIONS & MAINTENANCE

Statement GPage 1 of 1

(a) (b) (c) (d)(b) x (c)

Line No. Description Reference Amount

Percent of Total Cost

Weighted Cost

1 Pro Forma:2 Long-Term Debt 46.00% 6.10% 2.81%3 Common Equity 54.00% 10.90% 5.89%4 100.00% 8.70%567 Per Books:8 Long-Term Debt Schedule G-1 Line 31 (j). 127,000,000$ 42.56%9

10 Common Equity Components:11 Common Stock Issued Stmt. A Page 2 Ln 2 1$ 12 Other Paid-In Capital Stmt. A Page 2 Ln 3 66,143,590 13 Investment from Holding Company Stmt. A Page 2 Ln 4 70,475,000 14 Retained Earnings Stmt. A Page 2 Ln 5 34,806,119 15 Common Equity 171,424,710$ 57.44%1617 Total 298,424,710$ 100.00%

CHEYENNE LIGHT, FUEL AND POWER COMPANYCOST OF CAPITAL - PRO FORMA - TOTAL COMPANY


Schedule G-1Page 1 of 1

(a) (b) (c ) (d) (e) (f) (g) (h) (i) (j) (k)(f) ÷ (d) (h) ÷ (g)

Line No. Title Issue Maturity Amount Issued

Interest Rate

Net Proceeds Amount Per Unit

Yield to Maturity

Cost of Money

Principal Outstanding Annual Cost

1 Series 2007 11/20/2007 11/20/2037 110,000,000 6.67% 109,077,306 0.9916 6.67% 6.73% 110,000,000 7,411,569 2 Series 2009A (Note 1) 9/3/2009 3/1/2027 10,000,000 2.42% 9,641,844 0.9642 2.42% 2.51% 10,000,000 283,278 3 Series 2009B (Note 1) 9/3/2009 9/1/2021 7,000,000 2.42% 6,749,290 0.9642 2.42% 2.51% 7,000,000 220,756 45 Total Long-Term Debt (Note 2) 127,000,000$ 7,915,603$ 67 Average Cost of Corporate Bonds 6.23%89 Electric = 6,538,288$ Gas = 1,377,315$

1011 Note (1) The Series 2009A and 2009B Bonds are variable rate. The rate shown is the average variable weekly interest rate for the twelve months ended August 31, 2011, which includes 12 the Letter of Credit and Remarketing Fee.13 Note (2) Annual cost of the Series 2009 A and B bonds are allocated between Electric and Gas businesses based on Schedule A (Balance Sheet Allocations for Common Business) 14 allocator (c). 1516171819202122 (a) (b) (c ) (d) (e) (f) (g) (h) (i) (j) (k)23 (f) ÷ (d) (h) ÷(g)24 Amount Interest Net Proceeds Yield to Cost of Principal Annual 25 Title Issue Maturity Issued Rate Amount Per Unit Maturity Money Outstanding Cost2627 Series 2007 11/20/2007 11/20/2037 110,000,000 6.67% 109,077,306 0.9916 6.67% 6.73% 110,000,000 7,431,950 28 Series 2009A (Note 1) 9/3/2009 3/1/2027 10,000,000 1.42% 9,641,844 0.9642 1.42% 1.47% 10,000,000 168,691 29 Series 2009B (Note 1) 9/3/2009 9/1/2021 7,000,000 1.42% 6,749,290 0.9642 1.42% 1.47% 7,000,000 147,235 3031 Total Long-Term Debt (Note 2) 127,000,000$ 7,747,876$ 3233 Average Cost of Corporate Bonds 6.10%3435 The amounts between Gas and Electric is as follows: Electric = 6,399,746$ Gas = 1,348,130$ 3635 Note (1) The Series 2009A and 2009B Bonds are variable rate. The rate shown is the average variable weekly interest rate for the pro forma test year, which includes 36 the adjusted Letter of Credit and Remarketing Fee.37 Note (2) Annual cost of the Series 2009 A and B bonds are allocated between Electric and Gas businesses based on Schedule A (Balance Sheet Allocations for Common Business) 38 allocator (c).

COST OF DEBT - PRO FORMA - TOTAL COMPANYFor the Pro Forma Test Year Ended August 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYCOST OF DEBT - TOTAL COMPANY




No preferred stock as of August 31, 2011

CHEYENNE LIGHT, FUEL AND POWER COMPANYCost of Preferred Stock - Total CompanyFor the Test Year Ended August 31, 2011


Cheyenne Light, Fuel & Power did not reacquire any bonds or preferred stock in the 18 months prior to filing.

CHEYENNE LIGHT, FUEL AND POWER COMPANYReacquisition of Bonds or Preferred Stock - Total Company

For the 18 Month Period Prior to Filing

Statement HPage 1 of 6

(a) (b) (c) (d) (e) (f) (g)Line FERCNo. Account Description Per Books Sched. H-1 Sched. H-2 Sched. H-3 Sched. H-4 Sched. H-5 Sched. H-6

1 Steam Production Operation2 500 Supervision & Engineering 665,621 - - - - - - 3 501 Fuel on System Steam 7,196,754 - - - - - - 4 501.01 Fuel Handling/Other 124,795 - - - - - - 5 502 Steam Expense 1,437,055 - - - - - - 6 505 Electric Expense 412,517 - - - - - - 7 506 Miscellaneous 100,700 - - - - - - 8 507 Rents 1,185,822 - - - - - - 9 509 Allowances (13,141) - - - - - -

10 Total Steam Production Operation 11,110,122 - - - - - - 1112 Steam Production Maintenance13 510 Supervision & Engineering 420,077 - - - - - - 14 511 Structures 354,985 - - - - - - 15 512 Boilers 1,220,128 - - - - - - 16 513 Electric Plant 210,922 - - - - - - 17 514 Miscellaneous Plant 18,645 - - - - - - 18 Total Steam Production Maintenance 2,224,756 - - - - - - 1920 Total Steam Production Expense 13,334,878 - - - - - - 212223 Other Power Supply24 555 Purchased Power - Energy 47,148,786 - - - - - - 25 555 Purchased Power - Capacity 14,030,080 - - - - - - 26 556 Sys Control and Load Dispatch 434,692 - - - - - - 27 557 Purchased Power - Deferred 52 - - - - - - 28 558 Reserve Capacity Agreement 618 - - - - - - 29 Total Other Power Supply 61,614,228 - - - - - - 3031 Total Production Expenses 74,949,106 - - - - - - 3233 Transmission Operations34 560 Supervision & Engineering 19,689 - - - - 35 561 Load Dispatch 149,628 - - 10,189 - - 36 565 Transmission of Electricity by Others 7,055,962 - - - - - - 37 566 Misc. Transmission 1,873 - - - - - - 38 Total Transmission Operations 7,227,152 - - - 10,189 - - 3940 Total Transmission Expenses 7,227,152 - - - 10,189 - -


Adjustments

CHEYENNE LIGHT, FUEL AND POWER COMPANYOPERATION AND MAINTENANCE EXPENSES - ELECTRIC


Line FERCNo. Account Description

1 Steam Production Operation2 500 Supervision & Engineering3 501 Fuel on System Steam4 501.01 Fuel Handling/Other5 502 Steam Expense6 505 Electric Expense7 506 Miscellaneous8 507 Rents9 509 Allowances

10 Total Steam Production Operation1112 Steam Production Maintenance13 510 Supervision & Engineering14 511 Structures15 512 Boilers16 513 Electric Plant17 514 Miscellaneous Plant18 Total Steam Production Maintenance1920 Total Steam Production Expense212223 Other Power Supply24 555 Purchased Power - Energy25 555 Purchased Power - Capacity26 556 Sys Control and Load Dispatch27 557 Purchased Power - Deferred28 558 Reserve Capacity Agreement29 Total Other Power Supply3031 Total Production Expenses3233 Transmission Operations34 560 Supervision & Engineering35 561 Load Dispatch36 565 Transmission of Electricity by Others37 566 Misc. Transmission38 Total Transmission Operations3940 Total Transmission Expenses

(h) (i) (j) (k) (l) (m)Adjusted

Sched. H-7 Sched. H-8 Sched. H-9 Sched. H-10 Sched. H-11 Total

- - - - - 665,621 1,694,136 - - - - 8,890,889

- - - - - 124,795 - - - - - 1,437,055 - - - - - 412,517 - - - - - 100,700 - - - (167,901) - 1,017,921 - - (13,141)

1,694,136 - - (167,901) - 12,636,357

- - - - - 420,077 - - - - - 354,985 - 129,824 - - - 1,349,952 - - - - - 210,922 - - - - - 18,645 - 129,824 - - - 2,354,580

1,694,136 129,824 - (167,901) - 14,990,936

- - - - 886,575 48,035,361 - - - - 141,591 14,171,671 - - 72,200 - - 506,892 - - - - - 52 - - - - - 618 - - 72,200 - 1,028,166 62,714,594

1,694,136 129,824 72,200 (167,901) 1,028,166 77,705,530

- - - - - 19,689 - - - - - 159,817 - - - - - 7,055,962 - - - - - 1,873 - - - - - 7,237,341

- - - - - 7,237,341

Adjustments






Adjustments


4142 Distribution Operations43 580 Supervision 348,753 - - (15,634) - - 44 581 Load Dispatch 153,010 - - - - - - 45 582 Station Equipment 21,569 - - - - - - 46 583 Overhead Lines 274,336 - - - - - - 47 584 Underground Lines 144,882 - - - - - - 48 585 Street Lighting 18,347 - - - - - - 49 586 Metering 312,121 - - - - - - 50 587 Customer Installations 29,010 - - - - - - 51 588 Miscellaneous 328,073 - - - - - - 52 589 Dist Ops Rents 39,484 - - - - - - 53 Total Distribution Operations 1,669,585 - - - (15,634) - - 5455 Distribution Maintenance56 590 Supervision 219,830 167,143 - - - - - 57 592 Station Equipment 20,211 - - - - - - 58 593 Overhead Lines 583,521 - - - - - - 59 594 Underground Lines 163,123 - - - - - - 60 595 Transformers 148,922 - - - - - - 61 596 Street Lighting 31,342 - - - - - - 62 597 Metering - - - - - - - 63 598 Miscellaneous 272 - - - - - - 64 Total Distribution Maintenance 1,167,221 167,143 - - - - - 6566 Total Distribution Expenses 2,836,806 167,143 - - (15,634) - - 6768 Customer Accounting Expense69 901 Supervision 177,933 56,216 - - - - - 70 902 Meter Reading 111,993 - - - - - - 71 903 Customer Records and Collection Expense 525,342 - - - (859) - - 72 904 Uncollectible Accounts 124,488 - - - - - - 73 905 Miscellaneous 140,616 - - - (3,417) - - 74 Total Customer Accounting Expense 1,080,371 56,216 - - (4,276) - - 75


Line FERCNo. Account Description4142 Distribution Operations43 580 Supervision44 581 Load Dispatch45 582 Station Equipment46 583 Overhead Lines47 584 Underground Lines48 585 Street Lighting49 586 Metering50 587 Customer Installations51 588 Miscellaneous52 589 Dist Ops Rents53 Total Distribution Operations5455 Distribution Maintenance56 590 Supervision57 592 Station Equipment58 593 Overhead Lines59 594 Underground Lines60 595 Transformers61 596 Street Lighting62 597 Metering63 598 Miscellaneous64 Total Distribution Maintenance6566 Total Distribution Expenses6768 Customer Accounting Expense69 901 Supervision70 902 Meter Reading71 903 Customer Records and Collection Expense72 904 Uncollectible Accounts73 905 Miscellaneous74 Total Customer Accounting Expense75



Adjustments



- - - - - 333,119 - - - - - 153,010 - - - - - 21,569 - - - - - 274,336 - - - - - 144,882 - - - - - 18,347 - - - - - 312,121 - - - - - 29,010 - - - - - 328,073 - - - - - 39,484 - - - - - 1,653,951

- - - - - 386,973 - - - - - 20,211 - - - - - 583,521 - - - - - 163,123 - - - - - 148,922 - - - - - 31,342 - - - - - - - - - - - 272 - - - - - 1,334,364

- - - - - 2,988,315

- - - - - 234,149 - - - - - 111,993 - - - - - 524,483 - - - - - 124,488 - - - - - 137,199 - - - - - 1,132,311




Adjustments


76 Customer Service Expense77 907 Supervision 457,154 62,294 - - 30,696 - - 78 908 Customer Assistance 345,625 - - - 41,242 - (1,002) 79 909 Advertisement 6,264 - - - - - (1,323) 80 910 Misc. Customer Service 950 - - - - - - 81 912 Sales Demonstrating & Selling 187 - - - - - - 82 Total Customer Service Expense 810,180 62,294 - - 71,938 - (2,325) 8384 Total Customer Expenses 1,890,551 118,511 - - 67,663 - (2,325) 8586 Administrative & General Expense87 920 Administrative Salaries 4,058,803 14,597 - 276,342 61,835 - - 88 921 Office Supplies & Expense 886,275 - - 68,959 60,149 - (213) 89 922 Admin. Exp Trans Credit (8,014) - - - - - - 90 923 Outside Services 730,502 - - 20,322 83,282 87,500 - 91 924 Property Insurance 206,542 - - (2,819) - - 92 925 Injuries and Damages 485,924 - - 15,559 (2,092) - - 93 926 Pensions & Benefits (282,092) - 221,145 52,646 - 94 928 Regulatory Commission 258,462 - - - - - - 95 930.1 General Advertising 100,917 - - - (82,167) 96 930.2 Miscellaneous General 225,407 - - 42,173 (8,138) (80) 97 931 Rents 117,407 - - 4,249 594 - - 98 935 Maintenance of General Plant 268,826 - - 21,710 32,262 - - 99 Total Administrative & General Expense 7,048,960 14,597 221,145 446,495 280,539 87,500 (82,460)

100101 Total Operating & Maintenance Expense 93,952,576 300,251 221,145 446,495 342,756 87,500 (84,785) 102103 Adjustment Explanations104 Schedule H-1 Distribution of Salaries and Wages 105 Schedule H-2 Employee Pension and Benefits Adjustment106 Schedule H-3 Intercompany Black Hills Service Company Charges107 Schedule H-4 Intercompany Black Hills Utility Holdings Charges108 Schedule H-5 Outside Consulting Related to Rate Case109 Schedule H-6 Listed Advertising Expense Accounts110 Schedule H-7 Coal Pricing Adjustment111 Schedule H-8 Generation Plant Overhaul Expenses112 Schedule H-9 Generation Dispatch and Scheduling Cost Detail113 Schedule H-10 Gillette Energy Complex Shared Facilities114 Schedule H-11 Purchase Power and Sales for Resale


Line FERCNo. Account Description76 Customer Service Expense77 907 Supervision78 908 Customer Assistance79 909 Advertisement80 910 Misc. Customer Service81 912 Sales Demonstrating & Selling82 Total Customer Service Expense8384 Total Customer Expenses8586 Administrative & General Expense87 920 Administrative Salaries88 921 Office Supplies & Expense89 922 Admin. Exp Trans Credit90 923 Outside Services91 924 Property Insurance92 925 Injuries and Damages93 926 Pensions & Benefits94 928 Regulatory Commission95 930.1 General Advertising96 930.2 Miscellaneous General97 931 Rents98 935 Maintenance of General Plant99 Total Administrative & General Expense

100101 Total Operating & Maintenance Expense 102103104105106107108109110111112113114



Adjustments



- - - - - 550,145 - - - - - 385,865 - - - - - 4,941 - - - - - 950 - - - - - 187 - - - - - 942,088

- - - - - 2,074,400

- - - - - 4,411,577 - - - - 1,015,170

- - - - - (8,014) - - - - - 921,606 - - - - - 203,723 - - - - - 499,391 - - - - - (8,301) - - - - - 258,462 - - - - - 18,751 - - - - - 259,362 - - - - - 122,250 - - - - - 322,798 - - - - - 8,016,775

1,694,136 129,824 72,200 (167,901) 1,028,166 98,022,362

Schedule H-1 Distribution of Salaries and Wages Schedule H-2 Employee Pension and Benefits AdjustmentSchedule H-3 Intercompany Black Hills Utility Holdings ChargesSchedule H-4 Listed Advertising Expense AccountsSchedule H-5 Outside Consulting Related to Rate CaseSchedule H-6 Listed Advertising Expense AccountsSchedule H-7 Coal Pricing AdjustmentSchedule H-8 Generation Plant Overhaul ExpensesSchedule H-9 Generation Dispatch and Scheduling Cost DetailSchedule H-10 Gillette Energy Complex Shared FacilitiesSchedule H-11 Purchase Power and Sales for Resale

Schedule H-1Page 1 of 2

(a) (b) (c) (d)(a) + (b) + (c)

Line Electric GasNo. Operations Operations Common Total

1 OPERATION2 Production -$ -$ -$ -$ 3 Transmission - - - - 4 Distribution 440,168 983,715 - 1,423,883 5 Customer Accounts - - 579,737 579,737 6 Customer Service & Information - - 642,419 642,419 7 Administrative & General - - 104,408 104,408 8 Total Operation 440,168 983,715 1,326,564 2,750,447 9

10 MAINTENANCE11 Production - - - - 12 Distribution 480,282 172,135 - 652,417 13 Administrative & General - - 2,036 2,036 14 Total Maintenance 480,282 172,135 2,036 654,453 1516 Total Operation and Maintenance 920,450$ 1,155,850$ 1,328,600$ 3,404,900$ 1718 OPERATION AND MAINTENANCE SUMMARY19 Production -$ -$ -$ -$ 20 Transmission - - - - 21 Distribution 920,450 1,155,850 - 2,076,300 22 Customer Accounts - - 579,737 579,737 23 Customer Service & Information - - 642,419 642,419 24 Administrative & General - - 106,444 106,444 2526 TOTAL OPERATION AND MAINTENANCE 920,450$ 1,155,850$ 1,328,600$ 3,404,900$

Description

CHEYENNE LIGHT, FUEL AND POWER COMPANYDistribution of Operations and Maintenance Wages and Salaries - Total Company



(a) (b) (c) (d) (e)(a) + (b) (d) - (c)

(Sched. H-1 Pg 1) (Note 1) Per Book (Note 2) Total PayrollLine Electric Common Electric Annualized AnnualizationNo. Operations Allocation Total Payroll Adjustment

1 OPERATION2 Production (Note 3) -$ -$ -$ -$ -$ 3 Transmission (Note 3) - - - - - 4 Distribution 440,168 - 440,168 520,098 79,930 5 Customer Accounts - 309,580 (d) 309,580 365,796 56,216 6 Customer Service & Information - 343,052 (d) 343,052 405,346 62,294 7 Administrative & General - 73,190 (f) 73,190 87,591 14,401 8 Total Operation 440,168 725,821 1,165,989 1,378,831 212,842 9

10 MAINTENANCE11 Production (Note 3) - - - - - 12 Transmission (Note 3) - - - - - 13 Distribution 480,282 - 480,282 567,495 87,213 14 Administrative & General - 1,072 (e) 1,072 1,268 196 15 Total Maintenance 480,282 1,072 481,354 568,763 87,409 1617 Total Operation and Maintenance 920,450$ 726,893$ 1,647,343$ 1,947,594$ 300,251$ 1819 TOTAL OPERATION AND MAINTENANCE SUMMARY20 Production (Note 3) -$ -$ -$ -$ -$ 21 Transmission (Note 3) - - - - - 22 Distribution 920,450 - 920,450 1,087,593 167,143 23 Customer Accounts - 309,580 309,580 365,796 56,216 24 Customer Service & Information - 343,052 343,052 405,346 62,294 25 Administrative & General - 74,262 74,262 88,859 14,597 2627 TOTAL OPERATION AND MAINTENANCE 920,450$ 726,893$ 1,647,343$ 1,947,594$ 300,251$ 282930 Note (1) Common business wages and salaries were allocated between Electric and Gas operations utilizing Schedule B-1 (Income Statement 31 Allocations for Common Business) allocators (d), (e) and (f).323334353637 Note (3) The Operation and Maintenance Salaries and Wages for Production and Transmission are direct charges from Black Hills Power and are38 included in Statement H.

Note (2) The annualization reflects employee headcount and wage levels as of October 6, 2011. Wage levels are adjusted for merit and union increases during 2012, along with the addition of other than standard payroll such as overtime and standby pay. Additional personnel are included to fill two current vacancies. One for electric journey lineman and another for energy services engineer (common - allocated between electric and gas). In addition, this annualization reflects an additional electric journeyman line position as a result of the Strategic Workforce Planning initiative.

Description

CHEYENNE LIGHT, FUEL AND POWER COMPANYDistribution of Operation and Maintenance Wages and Salaries - Electric



(a) (b) (c)(b) - (a) (Note 1)

Line No.

FERC Account

No. Description Per BooksPro Forma Adjusted

Total Company Adjustment

Electric Adjustment

1 Pension and Benefits Plan:2 926 FAS 106 Retiree Healthcare 808,402$ 830,604$ $ 22,202 11,523$ 34 926 FAS 87 Pension Plan 474,860 537,160 62,300 32,334 56 926 Pooled Medical 804,553 921,406 116,853 60,647 78 401K Plan:9 926 Employer Match 401K 322,096 542,198 220,102 114,233

1011 Sharing Plan:12 926 Profit Sharing Plan 100,359 105,000 4,641 2,409 1314 Total Pension and Benefits Adjustment 2,510,270$ 2,936,368$ 426,098$ 221,145$ 1516 Note (1) The Electric allocation is based on Schedule B-1 (Income Statement Allocations for Common Business) allocator (b).

CHEYENNE LIGHT, FUEL AND POWER COMPANYEmployee Pension and Benefits AdjustmentFor the Test Year Ended August 31, 2011


(a) (b) (c)(Note 1) (b) - (a)

Line FERC Pro Forma Increase/No. Acct. No. Description Per Books Adjusted (Decrease)

1 920 Administrative and General Salaries 3,362,951$ 3,757,162$ 394,211$ 23 921 Office Supplies and Expenses 785,994 884,367 98,373 45 923 Outside Services Employed 719,808 748,798 28,990 67 924 Property Insurance 249,691 246,279 (3,412) 89 925 Injuries and Damages 469,007 487,844 18,837 1011 930.2 Miscellaneous General Expense 171,858 232,018 60,160 1213 931 Rents 151,115 157,177 6,062 1415 935 Maintenance of General Plant 313,382 354,617 41,235 1617 Total 6,223,806$ 6,868,262$ 644,456$ 18192021

CHEYENNE LIGHT, FUEL AND POWER COMPANYIntercompany Charges from Black Hills Corporation / Black Hills Service Company - Total Company


Note (1) These expenses are a combination of direct and indirect charges to Cheyenne Light from Black Hills Service Company without any additional fees. All costs are charged to Cheyenne Light as the costs are incurred by the Service Company. The allocation methods for indirect charges are described in the Cost Allocation Manual.


(a) (b) (c)(Note 1) (Note 1) (b) - (a)

Line FERC (Sched. H-3 Pg 1 (a)) (Sched. H-3 Pg 1 (b)) Increase/No. Acct. No. Description Per Books Adjusted (Decrease)

1 920 Administrative and General Salaries 2,357,429$ (f) 2,633,771$ (f) 276,342$ 23 921 Office Supplies and Expenses 550,982 (f) 619,941 (f) 68,959 45 923 Outside Services Employed 504,585 (f) 524,907 (f) 20,322 67 924 Property Insurance 206,245 (c) 203,426 (c) (2,819) 89 925 Injuries and Damages 387,400 (c) 402,959 (c) 15,559

1011 930.2 Miscellaneous General Expense 120,472 (f) 162,645 (f) 42,173 1213 931 Rents 105,932 (f) 110,181 (f) 4,249 1415 935 Maintenance of General Plant 164,996 (e) 186,706 (e) 21,710 1617 Total 4,398,041$ 4,844,536$ 446,495$ 181920

Note (1) Electric allocation of Black Hills Corporation / Black Hills Service Company charges to Cheyenne Light. Allocation based onSchedule B-1 (Income Statement Allocations for Common Business) allocators (b), (c), (e), and (f).

CHEYENNE LIGHT, FUEL AND POWER COMPANYIntercompany Charges from Black Hills Corporation / Black Hills Service Company - Electric


Schedule H-4 Page 1 of 2

(a) (b) (c)(Note 1) (b) - (a)

Line FERC Pro Forma Increase/No. Acct. No. Description Per Books Adjusted (Decrease)

1 561 Electric - Load Dispatch 145,558 155,747 10,189 23 580 Electric - Distribution Supervision 100,519 84,885 (15,634) 45 903 Customer Records and Collection Expense 572,995 571,387 (1,608) 67 905 Customer Accounting - Supervision 49,123 42,724 (6,399) 89 907 Customer Service - Supervision 46,368 103,852 57,484

1011 908 Customer Assistance 12,525 89,757 77,232 1213 920 Administrative and General Salaries 1,888,937 1,977,147 88,210 1415 921 Office Supplies and Expenses 287,649 373,454 85,805 1617 923 Outside Services Employed 148,292 267,096 118,804 1819 925 Injuries and Damages 46,666 44,133 (2,533) 2021 926 Employee Pensions and Benefits (97,345) 4,092 101,437 2223 930.2 Miscellaneous General Expense 58,739 47,130 (11,609) 2425 931 Rents 11,524 12,372 848 2627 935 Maintenance of General Plant 140,758 202,035 61,277 2829 Total 3,412,308$ 3,975,811$ 563,503$ 3031323334

CHEYENNE LIGHT, FUEL AND POWER COMPANYIntercompany Charges from Black Hills Corporation / Black Hills Utility Holdings - Total Company


Note (1) These expenses are a combination of direct and indirect charges to Cheyenne Light from Black Hills Utilities Holdings without any additional fees. All costs are charged to Cheyenne Light as the costs are incurred by Utilities Holdings. The allocation methods for indirect charges are described in the Cost Allocation Manual.


(a) (b) (c)(Note 1) (Note 1) (b) - (a)

Line FERC (Sched. H-4 Pg 1 (a)) (Sched. H-4 Pg 1 (b)) Increase/No. Acct. No. Description Per Books Adjusted (Decrease)

1 561 Electric - Load Dispatch 145,558 155,747 10,189 23 580 Electric - Distribution Supervision 100,519 84,885 (15,634) 45 903 Customer Records and Collection Expense 305,979 (d) 305,121 (d) (859) 67 905 Customer Accounting - Supervision 26,232 (d) 22,815 (d) (3,417) 89 907 Customer Service - Supervision 24,761 (d) 55,457 (d) 30,696

1011 908 Customer Assistance 6,688 (d) 47,930 (d) 41,242 1213 920 Administrative and General Salaries 1,324,145 (f) 1,385,980 (f) 61,835 1415 921 Office Supplies and Expenses 201,642 (f) 261,791 (f) 60,149 1617 923 Outside Services Employed 103,953 (f) 187,234 (f) 83,282 1819 925 Injuries and Damages 38,546 (c) 36,454 (c) (2,092) 2021 926 Employee Pensions and Benefits (50,522) (b) 2,124 (b) 52,646 2223 930.2 Miscellaneous General Expense 41,176 (f) 33,038 (f) (8,138) 2425 931 Rents 8,078 (f) 8,673 (f) 594 2627 935 Maintenance of General Plant 74,109 (e) 106,371 (e) 32,262 2829 Total 2,350,864$ 2,693,620$ 342,756$ 30313233

CHEYENNE LIGHT, FUEL AND POWER COMPANYIntercompany Charges from Black Hills Corporation / Black Hills Utility Holdings - Electric


Note (1) Electric allocation of Black Hills Corporation / Black Hills Utility Holdings charges to Cheyenne Light. Allocation based on Schedule B-1 (Income Statement Allocations for Common Business) allocator (b), (c), (d), (e), and (f). Schedule H-4 Pg 1 amount multiplied by allocationfactor.


(Note 1) (Note 1)Line Total Electric GasNo. Description Amount Business Business12 Capital Structure 30,000 15,000 15,000 3 Legal 300,000 150,000 150,000 4 Miscellaneous 20,000 10,000 10,000 56 Total 350,000$ 175,000$ 175,000$ 78 Costs Spread Over 2 Years:9 Total Outside Consulting line 6 175,000$ 175,000$

1011 Pro Forma Expense line 9 ÷ 2 87,500$ 87,500$ 121314

CHEYENNE LIGHT, FUEL AND POWER COMPANYOutside Consulting Related to Rate Case - Total Company


Note (1) Outside Consulting Costs allocated between Electric and Gas Businesses 50%-50%.


(a) (b) (c) (d) (e) (f) (g)(c) x allocator (c) x allocator (a) + (d) (b) + (e)

(Note 1) (Note 1)

Line No.FERC

Account No. Account Description Electric Gas Common

Electric - Common

Allocation

Gas- Common

AllocationElectric

AdjustmentGas

Adjustment

1 908 Customer Assistance 1,002$ -$ -$ -$ (d) -$ (d) 1,002$ -$ 2 909 Informational & Instructional Advertising - - 2,477 1,323 (d) 1,154 (d) 1,323 1,154 3 912 Sales Demonstrating - 771 - - (d) - (d) - 771 4 921 Office Supplies & Expense - - 304 213 (f) 91 (f) 213 91 5 930.1 General Advertising 632 - 152,687 81,535 (d) 71,152 (d) 82,167 71,152 6 930.2 Miscellaneous General - - 114 80 (f) 34 (f) 80 34 7 Total Non-Allowable 1,634$ 771$ 155,582$ 83,151$ 72,431$ 84,785$ 73,202$ 89

1011

CHEYENNE LIGHT, FUEL AND POWER COMPANYListed Advertising Expense Accounts - Total Company


Note (1) Expenses allocated between Electric and Gas businesses utilizing Schedule B-1 (Income Statement Allocations for Common Business) allocators (d) and (f).


Price Per Ton for 2012: 16.05$ (see Stmt R Page 6 Line 1)

(a) (b) (c) (d) (e) (f) (g)(a) x (b) (line 17) (d) x (e) (f) - (c)

Average Per F/SLine Tons Price Per Total Tons Price Per Total TotalNo Plant Consumed Ton Cost Consumed Ton Cost Increase

1 Wygen II 535,025 13.45$ 7,196,754$ 553,950 16.05$ 8,890,889$ 1,694,136$ 23456789

10 (h) (i) (j) (k)11 (h) + (i) (j) ÷ 212 2009 20101314 Tons Tons 2 year15 Plant Consumed Consumed Totals Average1617 Wygen II 560,705 547,194 1,107,899 553,950

The pro forma tons consumed are the 2 calendar year averages for this calculation. The price per ton is developed from the projected capital and expenses from the Wyodak Resources Development Company calculated consistently with Statement R methodology.

CHEYENNE LIGHT, FUEL AND POWER COMPANYCoal Price Adjustment - Electric


12 Months ended 8/31/11 Pro Forma Amount


LineNo. Description Reference

1 Total Expense for Boiler Maintenance (FERC Account 512) Stmt H Line 15 (a) 1,220,128$ 23 Plus: Normalized Overhaul Maintenance Expense Line 13 129,824 45 Adjusted Boiler Maintenance Line 1 + Line 3 1,349,952$ 678 Schedule of Projected and Actual Planned Overhaul Costs for Steam Plants9

1011 Wygen II Overhaul Expense (projected in 2016) 1,038,590$ 12 Normalization Period 8 13 Wygen II Annual Overhaul Expense Line 11 / Line 12 129,824$

CHEYENNE LIGHT, FUEL AND POWER COMPANYGENERATION PLANT OVERHAUL EXPENSES



Line No. Description Reference Total Cost

1 Costs Related to Generation Dispatch and Scheduling Note 12 Labor 1,416,367$ 3 Labor Overhead 1,019,784 4 Materials and Supplies 6,780 5 Other Non-Inventory Supplies 5,025 6 Consulting Services 395,620 7 Meals & Entertainment 3,100 8 Lodging 147,370 9 Total Costs Related to Generation Dispatch and Scheduling 2,994,046$

1011 Power Plant Capacity - Black Hills Power (MW) Note 212 Ben French 25.00 13 Ben French Diesels 10.00 14 Ben French CT's 100.00 15 Lange CT 40.00 16 Neil Simpson I 21.80 17 Neil Simpson II 91.00 18 Neil Simpson CT 40.00 19 Osage Note 320 Colstrip Long-Term Purchase 50.00 21 Happy Jack Long- Term Purchase 15.00 22 Silver Sage Long- Term Purchase 20.00 23 Wygen III 52% 57.20 24 Wyodak 20% 72.40 25 Total Power Plant Capacity - Black Hills Power (MW) 542.40 2627 Power Plant Capacity - Cheyenne Light (MW) Note 228 Wygen II 95.00 29 Wygen I (Purchase Power Agreement) 60.00 30 CT II (Purchase Power Agreement) 40.00 31 Happy Jack Long- Term Purchase 15.00 32 Silver Sage Long- Term Purchase 10.00 33 Total Power Plant Capacity - Cheyenne Light (MW) 220.00 3435 Power Plant Capacity - Black Hills/Colorado Electric Note 236 WN Clark #1 & #2 41.10 37 Pueblo Diesels 10.00 38 Pueblo NG #5 9.30 39 Pueblo NG #6 18.80 40 Rocky Ford Diesels 10.00 41 Airport Diesels 10.00 42 LMS 100 #1 90.00 43 LMS 100 #2 90.00 44 LMS 6000 #1 (Purchase Power Agreement) 100.00 45 LMS 6000 #2 (Purchase Power Agreement) 100.00 46 Total Power Plant Capacity - Black Hills/Colorado Electric (MW) 479.20

CHEYENNE LIGHT, FUEL AND POWER COMPANYGeneration Dispatch and Scheduling Cost Detail - Electric



Line No. Description Reference Total Cost

CHEYENNE LIGHT, FUEL AND POWER COMPANYGeneration Dispatch and Scheduling Cost Detail - Electric


4748 Power Plant Capacity - MDU, City of Gillette, and Other 49 Wygen III (48%) 52.80 50 Wygen I 5.00 51 Total Power Plant Capacity - MDU, City of Gillette, and Other (MW) 57.80 5253 Total Capacity to be Managed 1,299 5455 Black Hills Power Percent of Capacity 41.74%5657 Cheyenne Light Percent of Capacity 16.93%5859 Black Hills/Colorado Electric Utility Percent of Capacity 36.88%6061 MDU, City of Gillette, and Other Capacity 4.45%6263 Amount to be Charged to Cheyenne Light 506,892$ 6465 Amount per Book - Cheyenne Light Fuel and Power Stmt. H Ln 26 (a) 434,692 6667 Adjustment - Cheyenne Light Fuel and Power 72,200$ 68697071727374

Note (3) Osage was suspended October 1, 2010 due to the availability of more economical generation alternatives. Therefore, the plant capacity is not included in the allocation.

Note (1) Total generation dispatch and scheduling costs obtained from Black Hills Power Generation Dispatch andScheduling department's approved budget. Note (2) Costs from Black Hills Power Generation Dispatch and Scheduling are allocated based on the generationassets' load ratio.


Line No. Description Reference Amounts

1 Cheyenne Light's Share of Allocated Costs:23 Per Books - Shared Facilities Costs (FERC Account 507 - Production Rent) 945,822$ 45 2011 Budget:6 Pool 1 - Shared by all plants Line 26 x Line 36 251,677$ 7 Pool 3 - Wygen II and III Line 27 x Line 37 482,072$ 8 Pool 4 - Wygen I, II and III and Neil Simpson I and II Line 28 x Line 38 28,320$ 9 Pool 5 - Combustion Turbine I and II, and Wygen I, II and III Line 29 x Line 39 15,852$

10 Total 777,921$ 1112 Shared Facilities O&M Expense Adjustment (Statement H Line 8 (k)) Line 3 - Line 10 (167,901)$ 1314 Cheyenne Light's Share of Allocated Revenues:1516 Per Books - Shared Facilities Revenue (FERC Account 454 - Rent from Electric Property) 1,395,021$ 1718 2011 Budget with anticipated 2012 adjustment for spare transformer located in Gillette Line 53 1,135,441$ 1920 Shared Facilities Revenue Adjustment (Statement I Page 1 Line 14 (b)) Line 16 - Line 18 (259,580)$ 212223 Gillette Energy Complex Shared Facilities - 2011 Budget Detail2425 Gillette Energy Complex Facility Pool Descriptions: Costs26 Pool 1 - All plants shared facilities and water systems 1,289,645$ 27 Pool 3 - Wygen II and III 1,040,260 28 Pool 4 - Wygen I, II and III and Neil Simpson I and II 121,270 29 Pool 5 - Combustion Turbine I and II, and Wygen I, II and III 62,575 30 Total Costs 2,513,750$ 3132 (a) (b) (c)33 (a) x (b) = (c)34 Pool Wygen II Cheyenne Light35 Gillette Energy Complex Facility - Cost Allocators (Note 1): Net Capacity Net Capacity Allocator36 Pool 1 - Shared by all plants 486.8 95 19.52%37 Pool 3 - Shared by Wygen II and III Plants 205 95 46.34%38 Pool 4 - Shared by Wygen and Neil Simpson Plants 406.8 95 23.35%39 Pool 5 - Combustion Turbine and Wygen Plants 375 95 25.33%404142 Gillette Energy Complex Shared Facilities - Annual Revenue Requirement: Reference Cheyenne Light43 Facilities 1,092,064 44 Fuel Handling 5,385,012 45 Water Systems 333,852 46 Spare Transformer (Note 2) 801,395 47 Chemical Systems 2,189,306 48 Air Systems 336,238 49 10,137,866 5051 Rate of Return Line 49 x Stmt. G Ln 4 881,994 52 Depreciation - 40 years Line 49 ÷ 40 253,447 53 Calculated Revenue Requirement on Shared Assets Line 51 + Line 52 1,135,441 5455 Note 1: Pool 2 includes assets shared between plants other than Wygen II. Therefore, no costs are allocated to Cheyenne Light. 56 Note 2: Inclusion of the Cheyenne Light's spare transformer located in Gillette is a 2012 adjustment.

CHEYENNE LIGHT, FUEL AND POWER COMPANYGillette Energy Complex Shared Facilities - ElectricFor the Pro Forma Test Year Ended August 31, 2011


LineNo. Description Reference MWh1 (a)2 Additional Load Growth Assumptions: Schedule I-2 Ln 89 ÷ 1000 50,36334 (b) (c) (d) (e)5 (Note 1) (a) x (b) (Note 2) (c) x (d)6 Resource: Percent MWh Rate Adjustment78 Wygen I (Note 3) 80% 40,291 24.986$ 1,006,706$ 9

10 Purchased Power (Note 4) 20% 10,073 50.00$ 503,634$ 111213 Wygen I Capacity (60 MW) Charge Adjustment: Reference1415 2012 - Wygen I Pro Forma Capacity Rate per KW (Note 5) 12.92$ 1617 Pro Forma - Wygen I Capacity Charge Line 15 x 60000 x 12 9,304,718 1819 Per Books - Wygen I Capacity Charge 9,211,680 2021 Adjustment Line 17-Line 19 93,038$ 2223 CT2 Capacity (40 MW) Charge Adjustment:2425 2012 - CT2 Pro Forma Capacity Rate per KW (Note 5) 10.12$ 2627 Pro Forma - CT2 Capacity Charge Line 25 x 40000 x 12 4,855,753 2829 Per Books - CT2 Capacity Charge 4,807,200 3031 Adjustment Line 27-Line 29 48,553$ 323334 Wygen I Energy Charge Adjustment:3536 2012 - Wygen I Pro Forma Energy Rate per MWh (Note 6) 24.986$ 3738 Pro Forma - Wygen I Energy Charge Line 36 x 519,653 (test year MWh) 12,984,069 3940 Per Books - Wygen I Energy Charge 12,601,128 4142 Adjustment Line 38 - Line 40 382,941$ 4344454647484950515253545556575859

CHEYENNE LIGHT, FUEL AND POWER COMPANYPurchased Power and Sales for Resale - Electric


Note 6 - Energy rate will escalate by the change in the US Consumer Price index (CPI), Midwest City Size D, all items as published by the US Bureau of Statistics for the month of December from the previous year per the approved contract with Black Hills Wyoming. This rate represents the 2011 rate multiplied by the 5 year average of the % index change or 1.0227%.

Note 1 - The Company estimates that 80% of the additional load will be served by the Wygen I BHW PPA and 20% will be served through market purchased power.Note 2 - Wygen I rate of $25.47 is actual test year contract price. Purchased Power rate of $50.00 is based on expected peak market pricing.Note 3 - The impact to using the Wygen I energy to serve additional load growth is a reduction to Sales for Resale - Statement I Pg 1Lline 9.Note 4 - The impact to using Purchased Power energy to serve additional load growth is an increase to Purchased Power costs - Statement H Ln 24 (l).Note 5 - Capacity rate will escalate by the change in the US Consumer Price Index (CPI), US Average, all items less energy as published by the Bureau of Labor Statistics for the month of December from the previous year less one percentage point per the approved contract with Black Hills Wyoming. These rates represents the 2011 rate multiplied by the 5 year average of the % index change less 1% or 1.0101%.

Statement IPage 1 of 2

(a) (b) (c)(a) + (b)

Line Per AdjustedNo. Operating Revenue Books Adjustments Total

1 Sales of Electricity23 Retail4 Cheyenne Light - Retail Revenue 89,136,490$ 3,661,771$ (1) 92,798,261$ 5 Power Cost Adjustment Revenue 7,807,868 7,807,868 6 Total Sales of Electricity 96,944,358 3,661,771 100,606,129 78 Other Operating Revenue9 Sale for Resale 32,478,154 (1,006,706) (2) 31,471,448

10 Unbilled Revenue (199,067) - (199,067) 11 Late Payment Charges 182,021 - 182,021 12 Miscellaneous Service Revenues 175,844 - 175,844 13 Rents 1,397,661 (161,567) (3) 1,236,095 14 Transmission 744,281 - 744,281 15 Other Revenue 154,906 - 154,906 16 Total Other Operating Revenue 34,933,802 (1,168,273) 33,765,529 1718 Total Operating Revenue 131,878,160$ 1,486,792$ 134,371,658$ 192021 Note (1) Retail Revenue adjustments due to additional load growth provided in Statement I Page 2.22 Note (2) Reduction due to additional load growth served with Wygen I energy - Schedule H-11.23 Note (3) Reduction to Gillette Energy Complex Shared Facilities Agreement revenues - Schedule H-10 24 including an adjustment to account for a correction for pole attachment revenue.

CHEYENNE LIGHT, FUEL AND POWER COMPANYPRO FORMA ADJUSTED OPERATING REVENUE - ELECTRIC


Statement IPage 2 of 2

(a) (b) (c) (d) (e) (f)(c) - (a) (d) - (b)

Pro Forma AdjustedLine Energy Billing Energy Billing Energy BillingNo. Sales - kWh Revenue - $ Sales - kWh Revenue - $ Sales - kWh Revenue - $12 Residential (Excluding RAL) 261,717,340 28,307,833$ 262,483,610 28,421,591$ 766,270 113,758$ 34 Commercial (Excluding CAL) 47,727,881 5,393,821 47,727,881 5,393,821 - -$ 56 Secondary General 357,034,115 30,844,705 366,856,265 31,597,341 9,822,150 752,636$ 78 Primary General 194,881,628 13,365,077 235,422,908 16,160,454 40,541,280 2,795,377$ 9

10 Industrial 161,336,322 9,655,653 161,336,322 9,655,653 - -$ 1112 Lighting (Includes RAL and CAL) 5,912,087 1,569,401 5,912,087 1,569,401 - -$ 1314 Total Sales of Electricity 1,028,609,373 89,136,490 1,079,739,073 92,798,261$ 51,129,700 3,661,771$

Adjustment

CHEYENNE LIGHT, FUEL AND POWER COMPANYPRO FORMA ADJUSTED REVENUE BY CUSTOMER CLASSIFICATION - ELECTRIC


(Sched. I-1)

Per Books

Schedule I-1Page 1 of 2

LineNo. Adjusted Revenue

1 R - Residential Service2 Base Rate3 Service & Facility 416,560 Bills 12.00 / Month 4,998,720$ 4 Energy 262,483,610 kWh 0.08921 / kWh 23,416,1635 Voluntary Renewable Energy Rider 6,7086 28,421,591$ 78 C - Small Commercial Service9 Base Rate

10 Service & Facility 40,218 Bills 12.00 / Month 482,622$ 11 Energy 47,727,881 kWh 0.10290 / kWh 4,911,19912 5,393,821$ 1314 SG - Secondary General Service15 Base Rate16 Service & Facility 10,441 Bills 16.00 / Month 167,056$ 17 High Load Factor Credit (89,891) 18 System Capacity 909,539 kW 18.65 / kW-Mo 16,962,90219 Energy 366,856,265 kWh 0.03968 / kWh 14,557,27420 31,597,341$ 2122 PG - Primary General Service23 Base Rate24 Service & Facility 329 Bills 230.00 / Month 75,777$ 25 High Load Factor Credit (170,125) 26 Economic Development Rider (442,551) 27 System Capacity 456,747 kW 17.15 / kW-Mo 7,833,21128 Energy 235,422,908 kWh 0.03762 / kWh 8,864,14229 16,160,454$ 3031 TG - Transmission General Service32 Base Rate33 Service & Facility 24 Bills 9,000.00 / Month 216,000$ 34 High Load Factor Credit (221,265) 35 System Capacity 269,093 kW 14.00 / kW-Mo 3,767,30236 Energy 161,336,322 kWh 0.03653 / kWh 5,893,61637 9,655,653$ 38

Billing Units RateRate Schedule

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdjustment to Operating Revenue - Electric


(Note 1) (Note 2)


LineNo. Adjusted RevenueBilling Units RateRate Schedule

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdjustment to Operating Revenue - Electric


(Note 1) (Note 2)

38 Total Lighting Class39 Base Rate40 Monthly Rates 101,808 Units Various / Unit41 Energy 5,912,087 kWh Various / kWh 1,569,40642 1,569,406$ 43 Total Company Revenue4445 Base Rate46 Service & Facility 5,940,175$ 47 High Load Factor Credit (481,281)48 Economic Development Rider (442,551)49 Demand 28,563,41550 Energy 59,211,800 51 Voluntary Renewable Energy Rider 6,71452 Total 1,079,739,073 kWh 92,798,272$ 5354 Note (1) Billing units derived from adjusted load forecast. 55 Note (2) Current tariff rates and does not include the deferred power cost adjustment charge.


Pro FormaLine IncrementalNo. Revenue

1 Primary General Service - Customer A2 Assumptions:3 Load 4 MW4 Load Factor 80%5 Confidence Interval 90%6 Base Rate:7 Service & Facility 12 Bills 230.00 / Month 2,760$ 8 High Load Factor Credit (15,768) 9 System Capacity 43,200 kW 17.15 / kW-Mo 740,880 10 Energy 25,228,800 kWh 0.03762 / kWh 949,10711 1,676,979$ 1213 Primary General Service - Customer B14 Assumptions:15 Load 4 MW16 Load Factor 60%17 Confidence Interval 70%18 Base Rate:19 Service & Facility 12 Bills 230.00 / Month 2,760$ 20 System Capacity 33,600 kW 17.15 / kW-Mo 576,240 21 Energy 14,716,800 kWh 0.03762 / kWh 553,64622 1,132,646$ 2324 Primary General Service - Customer C25 Assumptions:26 Load 427 Load Factor 80%28 Confidence Interval 80%29 Base Rate30 Service & Facility 12 Bills 230.00 / Month 2,760$ 31 High Load Factor Credit (14,016)$ 32 System Capacity 38,400 kW 17.15 / kW-Mo 658,56033 Energy 22,425,600 kWh 0.03762 / kWh 843,65134 1,490,955$ 3536 Subtotal Primary General Servic 62,371,200 4,300,5803738 Secondary General Service - Customer A39 Assumptions:40 Load 1.541 Load Factor 70%42 Confidence Interval 70%43 Base Rate44 Service & Facility 12 Bills 16.00 / Month 192$ 45 System Capacity 12,600 kW 18.65 / kW-Mo 234,99046 Energy 6,438,600 kWh 0.03968 / kWh 255,48447 490,666$ 48

Billing Units Current RateRate Schedule

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdditional Load Growth - Electric


Load Assumptions/


Pro FormaLine IncrementalNo. RevenueBilling Units Current RateRate Schedule

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdditional Load Growth - Electric


Load Assumptions/

49 Secondary General Service - Customer B50 Assumptions:51 Load 1.052 Load Factor 60%53 Confidence Interval 70%54 Base Rate55 Service & Facility 12 Bills 16.00 / Month 192$ 56 System Capacity 8,400 kW 18.65 / kW-Mo 156,66057 Energy 3,679,200 kWh 0.03968 / kWh 145,99158 302,843$ 5960 Secondary General Service - Customer C61 Assumptions:62 Load 0.563 Load Factor 80%64 Confidence Interval 90%65 Base Rate66 Service & Facility 12 Bills 16.00 / Month 192$ 67 High Load Factor Credit (1,971) 68 System Capacity 5,400 kW 18.65 / kW-Mo 100,71069 Energy 3,153,600 kWh 0.03968 / kWh 125,13570 224,066$ 7172 Secondary General Service - Customer D73 Assumptions:74 Load 0.5075 Load Factor 70%76 Confidence Interval 60%77 Base Rate78 Service & Facility 12 Bills 16.00 / Month 192$ 79 System Capacity 3,600 kW 18.65 / kW-Mo 67,14080 Energy 1,839,600 kWh 0.03968 / kWh 72,99581 140,327$ 8283 Subtotal Secondary General Ser 15,111,000 1,157,9028485 Grand Total 77,482,200 kWh 5,458,482$ 8687 PG Timing Factor of 65% 40,541,280 2,795,37788 SG Timing Factor of 65% 9,822,150 752,63689 Timing Factor of New Load at 65% 50,363,430 3,548,013$

Statement JPage 1 of 1

(a) (b) (c) (d) (e)(a) - (b) (c) x (d)

(Stmt. D Pg 2) (Note 1) FunctionalAdjusted Less: Non- Class

Line Plant in Depreciable Depreciable Depreciation TotalNo. Description Service Items Plant Rate Expense

1 311 Structure & Improvements 8,455,264 - 8,455,264 2.77% 234,211 2 312 Boiler Plant Equipment 94,348,943 - 94,348,943 2.77% 2,613,466 3 314 Turbo Generator Equipment 69,975,302 - 69,975,302 2.39% 1,672,410 4 315 Accessory Electric Equipment 9,279,747 - 9,279,747 2.50% 231,994 5 316 Misc. Power Equipment 100,778 - 100,778 5.72% 5,765 6 106 Steam Generation 4,474,309 - 4,474,309 2.72% 121,701 7 Total Steam Production 186,634,343 - 186,634,343 2.61% 4,879,546 89 Transmission 12,113,582 1,176,555 10,937,027 2.34% 255,926

1011 Distribution 138,975,413 255,426 138,719,987 2.83% 3,925,776 1213 Electric General 3,162,164 87,500 3,074,664 3.84% 118,067 1415 Common General (Note 2) 7,517,541 1,205,218 6,312,323 8.02% 506,248 1617 Acquisition Adjustment (Note 3) - - 97,817 1819 Other Utility Plant 7,083,474 - 7,083,474 8.02% 568,095 2021 Accretion 9,296 2223 Total Adjusted Plant / Expense 355,486,517$ 2,724,699$ 352,761,818$ 10,360,770$ 2425 Per Book Depreciation, Amortization and Accretion Expense 9,167,096$ 2627 Adjustment to Depreciation Expense 1,193,675$ 2829 Note (1) Non-depreciable items from Schedule D-1 include: land, intangible plant, organization costs and rate case costs.30 Note (2) Common General includes organization costs from Schedule D-1.31 Note (3) Reference Schedule D-3 for the annual amortization amount for the Acquisition Adjustment.

CHEYENNE LIGHT, FUEL AND POWER COMPANYDEPRECIATION, AMORTIZATION AND ACCRETION EXPENSE - ELECTRIC


Statement KPage 1 of 3

Line Total Company Electric Gas Common No. Description Per Books Business Business Business1 Operating Income Before Federal Income Taxes (Stmt. B) 30,990,174$ 36,332,599$ 9,333,070$ (14,675,495)$ 2 Add Interest Income / (Expense) (Stmt. B) (7,262,504) 197,972 16,824 (7,477,300) 3 Subtotal 23,727,670 36,530,571 9,349,894 (22,152,795) 45 Tax Adjustments - Permanent Differences6 Meals & Entertainment 9,491 - - 9,491 7 Officer Restricted Stock 262 - - 262 8 Lobbying 19 - - 19 9 Equity AFUDC (249,676) (249,676) - - 10 PEP Life - Cash Surrender Value (5,942) - - (5,942) 11 Retiree Health Care Subsidiary (65) - - (65) 12 Total Permanent Differences (245,911) (249,676) - 3,765 1314 Tax Adjustments - Temporary Differences15 Employee Group Insurance 1,558 - - 1,558 16 Pension (14,211) - - (14,211) 17 Retiree Healthcare 116,241 - - 116,241 18 Vacation (86,155) - - (86,155) 19 Deferred Costs (3,519,622) (2,492,257) (1,027,365) - 20 Disability Liability (3,118) - - (3,118) 21 Insurance Reserve Liability (32) - - (32) 22 OCI Derivative Interest Swap 142,933 - - 142,933 23 FAS 143 ARO 3,099 - - 3,099 24 Bonus 119,586 - - 119,586 25 Line Extension Deposits (42,525) (2,071) (40,454) - 26 Reacquired Bond Loss 14,173 - - 14,173 27 Unamortized Bond Premium (26,247) - - (26,247) 28 Workman's Compensation (6,650) - - (6,650) 29 Contributions in Aid of Construction 689,829 504,599 185,230 - 30 Cost of Removal (168,742) (141,880) (26,862) - 31 Depreciation (26,982,161) (22,568,800) (3,189,932) (1,223,429) 33 Facts and Circumstances (55,835) (87,444) 31,609 - 34 Unit of Property (206,274) (144,392) (61,882) - 35 Repair Allowance (184,099) (184,099) - - 36 Prepaid Expenses (2,077) - - (2,077) 37 Bad Debt Reserve 145,133 - - 145,133 38 Total Temporary Differences (30,065,196) (25,116,344) (4,129,656) (819,196) 3940 Taxable Income Before Net Operating Loss (6,583,437) 11,164,552 5,220,238 (22,968,226) 41 Net Operating Loss 6,583,437 (11,164,552) (5,220,238) 22,968,226 42 Taxable Income - - - - 4344 Current Federal Income Tax @ 35% - - - - 45 Tax Return True Up to Current Income Taxes (3,705,755) 291,470 (790,787) (3,206,438) 4647 Deferred Income Tax (-Temp. Diff. - Net Oper. Loss) x 35% 8,218,616 12,698,313 3,272,463 (7,752,159) 48 Tax Return True Up to Deferred Taxes 3,553,479 (291,470) 790,787 3,054,162 49 Investment Tax Credit Amortization (54,993) (38,385) (16,278) (330) 50 Excess Deferred Tax Amortization (30,667) - - (30,667) 5152 Total Federal Income Tax $7,980,680 $12,659,928 $3,256,185 ($7,935,432)5354 Tax Savings Due to Consolidation55 There will be no tax savings as a result of filing a consolidated tax return for the test year ended August 31, 2011.5657 Abnormalities for Test Period58 None.


For the Test Year Ended August 31, 2011COMPUTATION OF FEDERAL INCOME TAX - TOTAL COMPANY


(Stmt. K Page 1) (Note 1)Line Electric Common Total No. Business Allocation Electric

1 Operating Income Before Federal Income Taxes 36,332,599$ (9,820,295) $26,512,3042 Add Interest Income / (Expense) 197,972 (6,176,250) (c) (5,978,277) 3 Subtotal 36,530,571 (15,996,545) 20,534,027 45 Tax Adjustments - Permanent Differences6 Meals & Entertainment - 4,926 (b) 4,926 7 Officer Restricted Stock - 136 (b) 136 8 Lobbying - 10 (b) 10 9 Equity AFUDC (249,676) - (b) (249,676) 10 PEP Life - Cash Surrender Value - (3,084) (b) (3,084) 11 Retiree Health Care Subsidiary - (34) (b) (34) 12 Total Permanent Differences (249,676) 1,954 (247,722) 1314 Tax Adjustments - Temporary Differences15 Employee Group Insurance - 809 (b) 809 16 Pension - (7,376) (b) (7,376) 17 Retiree Healthcare - 60,329 (b) 60,329 18 Vacation - (44,714) (b) (44,714) 19 Deferred Costs (2,492,257) - (2,492,257) 20 Disability Liability - (1,618) (b) (1,618) 21 Insurance Reserve Liability - (17) (b) (17) 22 OCI Derivative Interest Swap - 118,063 (c) 118,063 23 FAS 143 ARO - 2,560 (c) 2,560 24 Bonus Compensation - 62,065 (b) 62,065 25 Line Extension Deposits (2,071) - (c) (2,071) 26 Reacquired Bond Loss - 11,707 (c) 11,707 27 Unamortized Bond Premium - (21,680) (c) (21,680) 28 Workman's Compensation - (3,451) (b) (3,451) 29 Contributions in Aid of Construction 504,599 - 504,599 30 Cost of Removal (141,880) - (141,880) 31 Depreciation (22,568,800) (1,010,552) (c) (23,579,352) 3233 Facts and Circumstances (87,444) - (87,444) 34 Unit of Property (144,392) - (144,392) 35 Repair Allowance (184,099) - (184,099) 36 Prepaid Expenses - (1,574) (a) (1,574) 37 Bad Debt Reserve - 77,501 (d) 77,501 38 Total Temporary Differences (25,116,344) (757,950) (25,874,294) 3940 Taxable Income Before Net Operating Loss 11,164,552 (16,752,540) (5,587,989) 41 Net Operating Loss (11,164,552) 16,752,540 5,587,989 42 Taxable Income - - - 4344 Current Federal Income Tax @ 35% - - - 45 Tax Return True Up to Current Income Taxes 291,470 (2,247,713) (1,956,243) 4647 Deferred Income Tax (-Temp. Diff. - Net Oper. Loss) x 35% 12,698,313 (5,598,107) 7,100,206 48 Tax Return True Up to Deferred Taxes (291,470) 2,140,968 1,849,498 49 Investment Tax Credit Amortization (38,385) (273) (c) (38,658) 50 Excess Deferred Tax Amortization - (25,331) (c) (25,331) 5152 Total Federal Income Tax $12,659,928 ($5,730,456) 6,929,471$ 535455

Note (1) Common business (Stmt. K Page 1) allocated between Electric and Gas businesses utilizing Schedule B-1 (IncomeStatement Allocations for Common Business) allocator designated in column.

CHEYENNE LIGHT, FUEL AND POWER COMPANYCOMPUTATION OF FEDERAL INCOME TAX - ELECTRIC




1 Adjusted Operating Income before Federal Income Tax Stmt. M Line 12 column c 23,403,658$ 23 Adjusted Interest Expense Sched. G-1 Line 35 (f) 6,399,746 45 Taxable Income line 1 - line 3 17,003,912 67 Federal Income Tax @ 35% line 5 x 35% 5,951,369 89 Interest Expense Sync Sched. K-1 Line 15 (184,828)

1011 Adjusted Federal Income Tax Expense line 7 + line 9 5,766,541$ 1213 Per Books Federal Income Tax Stmt. K Pg 2 Line 52 6,929,471$ 1415 Adjustment to Federal Income Tax line 11 - line 13 (1,162,930)$ 161717 Interest expense adjustment is used since the adjusted interest expense tax effect is reflected on Line 9.

Current federal income tax per books is calculated on a separate return base at the statutory rate of 35%.

CHEYENNE LIGHT, FUEL AND POWER COMPANYADJUSTED FEDERAL INCOME TAX - ELECTRICFor the Pro Forma Test Year Ended August 31, 2011

Schedule K-1Page 1 of 1


1 Total Adjusted Rate Base Stmt. M Line 26 (c) 246,865,347$ 23 Adjusted Debt Portion of Cost of Capital Stmt. G Line 2 (b) 46.00%45 Adjusted Rate Base x Debt Portion Cost of Capital line 1 x line 3 113,558,060 67 Weighted Debt Cost Sched. G-1 Line 33 (k) 6.10%89 Calculated Adjusted Interest Expense line 5 x line 7 6,927,825$

1011 Adjusted Interest Expense Sched. G-1 Line 35 (f) 6,399,746$ 1213 Variance line 9 - line 11 528,079$ 1415 Federal Income Tax - 35% (Addition to FIT) line 13 x 35% (184,828)$

CHEYENNE LIGHT, FUEL AND POWER COMPANYInterest Expense - Annualization Adjustment - ElectricFor the Pro Forma Test Year Ended August 31, 2011

Statement LPage 1 of 1

(a) (b) (c)(a) + (b)

(Note 1)(Sched. B-1) (Sched. L-1)

Line Per Pro Forma AdjustedNo. Reference Books Adjustments Total

1 Federal Taxes2 FICA Tax Sched. B-1 Ln 54 500,679$ 22,969$ 523,648$ 3 Unemployment Tax Sched. B-1 Ln 53 5,096 526 5,622 45 State Taxes6 Unemployment Tax Sched. B-1 Ln 52 38,211 526 38,737 78 Local Taxes9 Property Sched. B-1 Ln 51 1,328,353 218,964 1,547,317

10 City Franchise Fees Company Books 893,877 95,697 989,574 1112 TOTIT - Payroll Loading & Other (520,031) - (520,031) 1314 Total Other Taxes 2,246,185$ 338,682$ 2,584,868$ 1516 Note (1) Pro forma adjustments do not include allocated Black Hills Service Company17 or Black Hills Utility Holdings costs. These costs are shown on Schedule H-3 and18 H-4.

CHEYENNE LIGHT, FUEL AND POWER COMPANYTAXES OTHER THAN FEDERAL INCOME TAX - ELECTRIC


Description

Schedule L-1Page 1 of 1

Line No. Description Reference Amount

1 FICA Tax Adjustment2 Net O&M Payroll Changes Sched H-1 Pg 2 Ln 27 (e) 300,251$ 3 FICA Tax Rate 7.65%45 Adjustment to FICA Tax line 2 x line 3 22,969$ 67 Unemployment Tax Adjustment8 O&M Payroll Changes Sched H-1 Pg 2 Ln 27 (e) 300,251$ 9 Estimated Blended Tax Rate 0.35%1011 Adjustment to Unemployment Tax line 8 x line 9 1,051$ 1213 Federal Adjustment line 11 ÷ 2 526$ 14 State Adjustment line 11 ÷ 2 526$ 1516 Franchise Fees17 Net Change in Revenue Stmt. I Pg 1 Ln 4 (b) + Stmt. M Ln 2 (d) 9,569,716$ 18 Franchise Fee Rate Franchise Agreements 1%1920 Adjustment to Franchise Fees line 16 x line 17 95,697$ 2122 Property Tax Adjustment2324 Subsequent/Expected Additions/Retirements Sched. D-2 Line 57 22,945,029$ 2526 Effective Blended Tax Rate 0.9543%2728 Total Property Tax Adjustment line 24 x line 26 218,964$

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdjustments Other than Federal Income Tax - ElectricFor the Pro Forma Test Year Ended August 31, 2011

Statement MPage 1 of 1

(a) (b) (c) (d) (e)Additional Adjusted

Line Per Pro Forma Adjusted Revenue Rate ofNo. Description Reference Books Adjustments Total Required Return1 Operating Revenue2 Sales of Electricity Stmt I Pg 1 Ln 7 96,944,358$ 3,661,771$ 100,606,129$ 5,907,945$ 106,514,074$ 3 Other Operating Revenue Stmt I Pg 1 Ln 17 34,933,802 (1,168,273) 33,765,529 - 33,765,529 4 Total Operating Revenue 131,878,160 2,493,498 134,371,658 5,907,945 140,279,603 56 Operating Expenses7 Operation and Maintenance Stmt H Ln 101 93,952,576 4,069,786 98,022,362 - 98,022,362 8 Depreciation Stmt J Ln 25 (e) 9,167,096 1,193,675 10,360,770 - 10,360,770 9 Taxes Other Than Income Tax Stmt L Ln 14 2,246,185 338,682 2,584,868 - 2,584,868 10 Total Operating Expenses 105,365,857 5,602,143 110,968,000 - 110,968,000 1112 Operating Income Before Tax 26,512,303 (3,108,645) 23,403,658 5,907,945 29,311,603 1314 Federal Income Tax Stmt K Pg 2 Ln 52 6,929,471 (1,162,930) (1) 5,766,541 2,067,777 7,834,318 1516 Return (Operating Income) 19,582,832$ 17,637,117$ 21,477,285$ 1718 Rate of Return 8.49% 7.14% 8.70%1920 Rate Base21 Plant in Service Stmt D Pg 2 Ln 19 334,216,105 22,673,868 356,889,973 356,889,973 22 Accumulated Depreciation Stmt E Pg 2 Ln 13 (67,905,654) (348,402) (68,254,056) (68,254,056) 23 Working Capital Stmt F Ln 7 3,135,385 770,293 3,905,678 3,905,678 24 Other Rate Base Reductions Stmt. A Pg 3 Ln 32 (38,766,549) (6,909,699) (2) (45,676,248) (45,676,248) 2526 Total Rate Base 230,679,287$ 16,186,060$ 246,865,347$ 246,865,347$ 2728 Note (1) - Reference Statement K Page 3 for adjustment to Federal Income Tax 29 Note (2) - Reference Schedules M-1 and M-2 for adjustments to Other Rate Base Reductions

CHEYENNE LIGHT, FUEL AND POWER COMPANYOVERALL REVENUE REQUIREMENT - ELECTRIC


Schedule M-1Page 1 of 1

(a) (b) (c) (d) (e) (f) (g)(a) + (b) Note 1 (d) + ((f) x allocator)Adjusted

Line FERC Total Company Pro Froma Other Rate Base Electric Gas Common TotalNo. Account Description Per Books Adjustment Reductions Business Business Business Electric

1 190175 DT1000 - VACATION 117,854 (90,463) 27,391 - - 27,391 (b) 14,216 2 190175 DT1010 - BAD DEBT RESERVE 820,129 143,797 963,926 - - 963,926 (a) 730,656 3 190175 DT1020 - EE GROUP INSURANCE 21,275 1,636 22,911 - - 22,911 (b) 11,891 4 190175 DT1050 - WORKERS COMP 7,392 (7,392) (0) - - - - 5 190520 DT2020 - RETIREE HEALTHCARE 1,950,685 122,053 2,072,738 - - 2,072,738 (b) 1,075,751 6 190520 DT2065 - PENSION (AOCI) 65,500 0 65,500 65,500 (b) 33,995 7 190520 DT3040 - RETIREE HEALTH (AOCI) 1,681,844 (0) 1,681,844 1,681,844 (b) 872,877 8 190520 DT3060 - FAS 143 (ARO) 16,268 3,254 19,522 - 19,522 (c) 16,125 9 190520 DT3075 - LINE EXTENSION DEP ELEC 463,688 (2,174) 461,514 461,514 461,514

10 190520 DT3076 - LINE EXTENSION DEP GAS 398,455 (42,477) 355,978 355,978 - 11 190520 DT3090 - PENSION FAS 87 568,930 46,192 615,122 615,122 (b) 319,248 12 190520 DT4000 - DEBT PREMIUM 385,826 (27,559) 358,267 358,267 (c) 295,929 13 190520 DT4010 - LT DISABILITY 176,850 (2,067) 174,784 174,784 (b) 90,713 14 190520 DT4135 - INSURANCE RESERVE - (33) (33) (33) (f) (23) 15 190520 DT4165 - NOL CARRYFORWARD 3,268,435 (2,359,743) 908,692 908,692 - 16 190520 DT4285 - ROLLOVER ADJUSTMENT 73,943 (115,343) (41,400) (41,400) (f) (29,021) 17 Total Account 190 10,017,074 (2,330,319) 7,686,755 461,514 1,264,670 5,960,572 3,893,870 1819 282100 DT4062 - ACCELERATED DEPRECIATION ELEC (34,709,937) (747,288) (35,457,225) (34,766,767) (34,766,767) 20 282100 DT4063 - ACCELERATED DEPRECIATION GAS (8,336,241) 42,153 (8,294,088) (8,984,546) - 21 282100 DT4064 - ACCELERATED DEPRECIATION OTHER (1,085,211) (23,352) (1,108,563) (1,108,563) (e) (583,658) 22 Total Account 282 (44,131,389) (728,487) (44,859,876) (34,766,767) (8,984,546) (1,108,563) (35,350,426) 2324 283005 DT1067 - ST DEFERRED COSTS (2,959,620) (330,704) (3,290,324) (3,290,324) (3,290,324) 25 283005 DT4040 - PREPAID EXPENSES (71,927) (2,181) (74,109) (74,109) (c) (61,214) 26 283440 DT1030 - BONUS (11,825) 125,566 113,741 113,741 (c) 93,950 27 283440 DT2093 - FAS 109 AFUDC (1,350,845) (0) (1,350,845) (1,350,845) (1,350,845) 28 283440 DT4065 - FAS 109 EQUITY AFUDC (2,547,011) (0) (2,547,011) (2,547,011) (2,547,011) 29 283534 DT4070 - REQUIRED BOND LOSS (192,463) 11,161 (181,302) (181,302) (c) (149,755) 30 Total Account 283 (7,133,692) (196,158) (7,329,850) (7,188,180) - (141,670) (7,305,199) 3132 (41,248,006)$ (3,254,964)$ (44,502,971)$ (41,493,433)$ (7,719,876)$ # 4,710,339$ (38,761,756)$ 3334 Per Books - Electric (Statement A Page 3 lines 23, 26, and 27):35 190 Deferred Income Tax Assets 6,551,415 36 282 Deferred Tax LT - Accel. Depr. - Other (35,281,303) 37 283 Deferred Income Tax Liability (7,085,632) 38 (35,815,519) 3940 Adjustement Other Rate Base Reductions (2,946,237) 4142 Note (1) Common business allocated between Electric and Gas businesses utilizing Schedule A-1 (Balance Sheet Allocations for Common Business) allocator designated by column.

CHEYENNE LIGHT FUEL & POWEROTHER RATE BASE REDUCTIONS

FOR THE TEST YEAR ENDED AUGUST 31, 2011

Adjusted Balance Assignment

Schedule M-2Page 1 of 1

(a) (b) (c) (d) (e) (f) (g)(Stmt. J) 1st Year Tax (a) x (c) (b) - (d) (e) x (f)

Line (Sched. D-2) Book Depreciation TaxNo. Capital Additions Amount Depreciation Rate Depreciation Difference Tax Rate Deferred Tax

1 Steam Plant 4,058,114$ 106,099$ 51.88% 2,105,350$ (1,999,251)$ 35% (699,738)$ 2 Transmission 5,944,346 139,098 52.50% 3,120,782 (2,981,684) 35% (1,043,590) 3 Electric Distribution 11,298,389 319,744 52.50% 5,931,654 (5,611,910) 35% (1,964,168) 4 General Plant - Comm Alloc 1,171,682 93,969 52.50% 615,133 (521,164) 35% (182,407) 5 Other Utility Plant - Comm Alloc 472,499 37,894 52.50% 248,062 (210,168) 35% (73,559) 67 Total 22,945,029$ 696,805$ 12,020,981$ (11,324,176)$ (3,963,462)$

CHEYENNE LIGHT, FUEL AND POWER COMPANYAdjustment to Deferred Taxes - Electric


Statement NPage 1 of 5

Line Pro FormaNo. Description Reference Per Books Reference Adjusted 1 Plant in Service23 Production Plant4 Steam Production Plant 182,160,034$ 182,160,034$ 56 Subtotal - Steam Plant 182,160,034 182,160,034 78 Unclassified Steam Plant Plus Additions 416,195 4,474,309 9

10 Total Unclassified Steam Plant 416,195 4,474,309 1112 Total Production Plant Sched. D-1 Lns 8 (e) + 72 (e) 182,576,229 Stmt D Pg 2 Lns 1 (c) + 8 (c) 186,634,343 1314 Transmission Plant15 Lines16 Power Pool Service 3,441,590 3,441,590 1718 Total Lines 3,441,590 3,441,590 19 Substations20 Power Pool Service 1,384,594 1,384,594 2122 Total Substations 1,384,594 1,384,594 23 Total Lines And Substations 4,826,184 4,826,184 2425 Subtotal - Trans. Plant 4,826,184 4,826,184 2627 Unclassified Transmission Plant Plus Additions 1,343,052 7,287,398 2829 Total Unclassified Trans. Plant 1,343,052 7,287,398 3031 Total Transmission Plant Sched. D-1 Lns 19 (e) + 73 (e) 6,169,236 Stmt D Pg 2 Lns 2 (c) + 9 (c) 12,113,582 3233 Distribution Plant34 Miscellaneous Intangible Plant 168,500 168,500 35 Land and Land Rights 185,073 185,073 36 Structures and Improvements 534,793 534,793 37 Station Equipment 13,460,453 13,460,453 38 Poles, Towers & Fixtures - Primary 18,812,447 18,812,447 39 Overhead Conductors & Devices - Primary 17,740,035 17,740,035 4041 Subtotal - O.H. Lines 50,901,301 50,901,301 4243 Underground Conduit 6,034,424 6,034,424 44 U.G. Conductors & Devices 28,512,712 28,512,712 4546 Subtotal - U.G. Lines 34,547,136 34,547,136 4748 Line Transformers 16,807,803 16,807,803 49 Services 13,149,327 13,149,327 50 Meters 828,526 828,526 51 Meters - ERT 4,962 4,962 52 Installations on Cust. Premises 1,187,574 1,187,574 53 Street Lighting and Signal Systems 5,500,113 5,500,113 5455 Subtotal - Equipment 37,478,305 37,478,305 5657 Subtotal - Dist. Plant 122,926,742 122,926,742 5859 Unclassified Dist. Plant Plus Additions 4,750,282 16,048,671 6061 Total Unclassified Dist. Plant 4,750,282 16,048,671 6263 Total Distribution Plant Sched. D-1 Lns 38 (e) + 74 (e) 127,677,024 Stmt D Pg 2 Lns 3 (c) + 10 (c) 138,975,413 6465 Total Trans. and Dist. Plant 133,846,260 151,088,995 66

CHEYENNE LIGHT, FUEL AND POWER COMPANYPER BOOKS AND PRO FORMA ADJUSTED REVENUE REQUIREMENT ANALYSIS - ELECTRIC



Line Pro FormaNo. Description Reference Per Books Reference Adjusted



67 General Plant68 Classified Plant Sched. D-1 Lns 49 (e) + 74 (e) 7,496,886 Stmt D Pg 2 Lns 4 (a) + 5 (a) 7,496,886 69 Unclassified General Plant Sched. D-1 Lns 75 (e) + 76 (e) 751,259 Stmt D Pg 2 Lns 11 (c) + 12 (c) 1,922,941 70 Plant Acquisition Adj Sched. D-1 Ln 81(e) 2,934,495 Stmt D Pg 2 Ln 15 (c) 2,575,835 71 Unexpensed Rate Case Costs - Stmt D Pg 2 Lns 4 (b) 87,500 72 Other Utility Plant Sched. D-1 Ln 87 (e) 6,610,975 Stmt D Pg 2 Ln 17 (b) 7,083,474 7374 Total General Plant 17,793,615 19,166,635 7576 Total Plant in Service Lns 12 + 31 + 63 + 74 334,216,105 Lns 12 + 31 + 63 + 74 356,889,973 7778 Accumulated Depreciation79 Production 14,825,487 14,878,537 80 Transmission 2,264,596 2,334,145 81 Distribution 42,319,638 42,479,510 82 General 3,618,467 3,665,452 83 Other Utility Plant 4,877,465 4,896,413 8485 Total Accumulated Depreciation Stmt. E Pg 1 Ln 12 (h) 67,905,654 Stmt. E Pg 2 Ln 13 (c) 68,254,056 8687 Net Plant Ln 76 - Ln 85 266,310,451 Ln 76 - Ln 85 288,635,917 8889 Working Capital90 Cash Working Capital Allowance (1,874,684) (2,063,230) 91 Materials and Supplies 4,266,808 5,225,647 92 Prepayments 743,261 743,261 9394 Total Working Capital Stmt F Ln 7 (a) 3,135,385 Stmt. F Ln 7 (b) 3,905,678 9596 Other Rate Base Deductions Stmt. A Ln 32 38,766,549 Stmt. M Ln 24 (b) 45,676,248 9798 Total Other Rate Base Deductions 38,766,549 45,676,248 99

100 Total Rate Base Ln 87 + Ln 94 - Ln 98 230,679,288$ Ln 87 + Ln 94 - Ln 98 246,865,347$ 101102 Operation and Maintenance Expense103104 Production Expense105 Operation106 Steam Power Generation107 Fuel 7,321,549$ 9,015,684$ 108 Rents 1,185,822 1,017,921 109 Other 2,602,751 2,602,751 110 Other Power Supply111 Purchased Power - Capacity 14,030,080 14,171,671 112 Purchased Power - Energy 47,148,786 48,035,361 113 System Control and Load Dispatch 434,692 506,892 114 Other 670 670 115116 Total Production Operation 72,724,351 75,350,951 117118 Maintenance119 Steam Power Generation 2,224,756 2,354,580 120121 Total Production Maintenance 2,224,756 2,354,580 122123 Total Production O&M Stmt. H Ln 31 (a) 74,949,106 Stmt. H Ln 31 (m) 77,705,530 124





125 Transmission Expense126 Operation127 Load Dispatching 149,628 159,817 128 Transmission Expense 7,055,962 7,055,962 129 Other 1,873 1,873 130131 Subtotal Trans. Operation 7,207,463 7,217,652 132133 Supervision and Engineering 19,689 19,689 134135 Total Transmission Operation 7,227,152 7,237,341 136137 Maintenance - - 138139 Subtotal Trans. Maintenance - - 140141 Total Transmission O&M Stmt. H Ln 40 (a) 7,227,152 Stmt. H Ln 40 (m) 7,237,341 142143 Distribution Expense144 Operation145 Load Dispatching 153,010 153,010 146 Station Expenses 21,569 21,569 147 Overhead Line Expenses 274,336 274,336 148 Underground Line Expenses 144,882 144,882 149 Street Lighting and Sig. Exp. 18,347 18,347 150 Meter Expenses 312,121 312,121 151 Cust. Install. Expenses 29,010 29,010 152 Dist Ops Rents 39,484 39,484 153154 Subtotal Dist. Operation 992,759 992,759 155 Supervision and Operation 348,753 333,119 156 Misc. Dist. Expenses 328,073 328,073 157158 Total Distribution Operation 1,669,585 1,653,951 159160 Maintenance161 Station Equipment 20,211 20,211 162 Overhead Lines 583,521 583,521 163 Underground Lines 163,123 163,123 164 Line Transformers 148,922 148,922 165 Street Light. & Signal System 31,342 31,342 166 Meters - - 167 Misc. Dist. Plant 272 272 168169 Subtotal Dist. Maintenance 947,392 947,392 170 Supervision and Engineering 219,830 386,973 171172 Total Distribution Maintenance 1,167,221 1,334,364 173174 Total Distribution O&M Stmt. H Ln 66 (a) 2,836,806 Stmt. H Ln 66 (m) 2,988,315 175176 Total Trans. & Dist. O&M 10,063,959 10,225,657 177178 Computer Services179 Accounts 901 Through 905 1,080,371 1,132,311 180181 Total Comp. Exp. & Cust. Acct. Stmt. H Ln 74 (a) 1,080,371 Stmt. H Ln 74 (m) 1,132,311 182183 Customer Service & Information184 Accounts 907 Through 910 810,180 942,088 185186 Total Customer Service and Info. Stmt. H Ln 82 (a) 810,180 Stmt. H Ln 82 (m) 942,088 187188 Subtotal O&M Expense Lns 123+141+174+181+186 86,903,616$ Lns 123+141+174+181+186 90,005,587$ 189190 Supervised O&M Expense 10,160,747 10,708,317





191192 Administrative and General Exp.193 Operation194 Property Insurance 206,542$ 203,723$ 195 Regulatory Comm. Exp. 258,462 258,462 196 Other A&G Expense 6,315,130 7,231,792 197198 Total A&G Operation 6,780,134 7,693,977 199 Maintenance200 General Plant 268,826 322,798 201202 Total A&G Expenses Stmt. H Ln 99 (a) 7,048,960 Stmt. H Ln 99 (m) 8,016,775 203204 Total O&M Expenses Ln 188 + Ln 202 93,952,576 Ln 188 + Ln 202 98,022,362 205206 Total O&M Exp. Less Purch. Pwr. Ln 204 - Lns 111 thru 114 32,338,347 Ln 204 - Lns 111 thru 114 35,307,768 207208 Total O&M Exp. Less P. P. & Fuel Ln 206 - Ln 107 25,016,799 Ln 206 - Ln 107 26,292,083 209210211 Depreciation / Accretion Expense212 Production 4,736,076 4,879,546 213 Transmission 129,505 255,926 214 Distribution 3,465,955 3,925,776 215 General 1,027,492 624,315 216 Other Utility Plant 454,743 568,095 217 Acquisition Adjustment - 97,817 218 Accretion 9,296 9,296 219220 Total Depreciation / Accretion Expense Stmt. J Ln 25 (e) 9,167,096 Stmt. J Ln 23 (e) 10,360,770 221222 Taxes Other Than Income223 Property Taxes 1,328,353 1,547,317 224 Payroll Taxes 500,679 523,648 225 Unemployment - Federal 5,096 5,622 226 Unemployment - State 38,211 38,737 227 Wyoming Franchise Fees 893,877 989,574 228 Payroll Loading and Other (520,031) (520,031) 229230 Total Taxes Other Than Income Stmt. L Ln 14 (a) 2,246,185 Stmt. Ln 14 (c) 2,584,868 231232 Total Oper. Exp. Before Inc. Tax Ln 204+ Ln 220 + Ln 230 105,365,857$ Ln 204+ Ln 220 + Ln 230 110,968,000$ 233234 Other Operating Revenue235 Sales for Resale 32,478,154$ 31,471,448$ 236 Unbilled Revenue (199,067) (199,067) 237 Acct. 450 - Late Payment Charges 182,021 182,021 238 Acct. 451 - Misc. Service Revenues 175,844 175,844 239 Acct. 454 & 456 - Rent from Elec. Prop. & Other 1,397,661 1,236,095 240 Other 899,188 899,188 241242 Total Other Operating Revenue Stmt. I Pg 1 Ln 17 (a) 34,933,802 Stmt. I Pg 1 Ln 17 (c) 33,765,529 243244 Revenue Under Existing Rates245 Revenue from Firm Sales 89,136,490 92,798,261 246 PCA Revenue 7,807,868 7,807,868 247 Other Operating Revenue 34,933,802 33,765,529 248249 Total Operating Revenue Stmt. I Pg 1 Ln 19 (a) 131,878,160 Stmt. I Pg 1 Ln 19 (c) 134,371,658 250 Oper. Expense Before Income Tax 105,365,857 110,968,000 251252 Oper. Income Before Income Tax Ln 249 - Ln 232 26,512,304 Ln 249 - Ln 232 23,403,658 253





254 Federal Income Tax Calculation255 Taxable Income 26,512,304 23,403,658 256 Federal Income Tax 6,929,471 5,951,369 257 Interest Expense Sync - (184,828) 258259 Total Federal Income Tax Stmt. K Pg 2 Ln52 6,929,471 Stmt. K Pg 3 Ln 11 5,766,541 260261 Total Operating Expense Ln 232 + Ln 259 112,295,328 Ln 232 + Ln 259 116,734,541 262263 Return to equity pretax Ln 249 - Ln 261 19,582,832 Ln 249 - Ln 261 17,637,117 264 Rate Base Ln 100 230,679,288$ Ln 100 246,865,347$ 265 Rate of Return, Existing Rates Ln 263 ÷ Ln 264 8.49% Ln 263 ÷ Ln 264 7.14%266267 Return Under Current Rates268269 Revenue from Firm Sales Ln 245 96,944,358$ Ln 245 + Ln 246 100,606,129$ 270 Other Operating Revenue Ln 246 + Ln 247 42,741,670 Ln 247 33,765,529 271272 Total Operating Revenue Ln 269 + Ln 270 139,686,028 Ln 269 + Ln 270 134,371,658 273274 Operation and Maintenance Expense Ln 204 93,952,576 Ln 204 98,022,362 275 Depreciation and Amortization Expense Ln 220 9,167,096 Ln 220 10,360,770 276 Taxes Other than Income Tax Ln 230 2,246,185 Ln 230 2,584,868 277 Federal Income Tax - Existing Rates Ln 259 6,929,471 Ln 259 5,766,541 278279 Total Operating Expenses Lns 274 + 275 + 276 + 277 112,295,328 Lns 274 + 275 + 276 + 277 116,734,541 280281 Return Ln 272 - Ln 279 27,390,700 Ln 272 - Ln 279 17,637,117 282 Rate Base Ln 264 230,679,288 Ln 264 246,865,347 283 Rate of Return, Current Rates Ln 281 ÷ Ln 282 11.87% Ln 281 ÷ Ln 282 7.14%284285 Revenue Requirement and Current Deficiency286287 Rate Base Ln 282 246,865,347$ 288 Rate of Return Stmt. G Ln 4 (d) 8.70%289 Return Ln 287 x Ln 288 21,477,285 290 Operation and Maintenance Expenses Ln 204 98,022,362 291 Depreciation and Amortization Expense Ln 220 10,360,770 292 Taxes Other than Income Tax Ln 230 2,584,868 293 Federal Income Tax - Existing Rates Ln 259 5,766,541 294295 Total Revenue Requirement Lns 289 thru 293 138,211,826 296 Less: Other Operating Revenue Ln 242 33,765,529 297298299 Net Revenue Requirement Ln 295 - Ln 296 104,446,297 300301 Revenue Under Existing Rates Ln 245 + Ln 246 100,606,129 302 Revenue Deficiency303 Amount before tax adjustment Ln 299 - Ln 301 (3,840,168) 304 Tax Adjusted Amount Needed (line 302 x line 306) Ln 303 x Ln 307 (5,907,945)$ 305 Percent Increase/(Decrease) Ln 310 ÷ Ln 301 5.87%306307 Tax Multiplier (1/(1-.35)) Federal Tax Rate at 35% 1.53846

Statement OPage 1 of 10

Ref. No. Description

Allocation Factor Total Electric Residential Commercial

Secondary General

Primary General

Transmission General Lighting

Energy Input (MWH) See WP-2 1 1,075,844 262,950 44,579 360,329 229,155 173,020 5,811 Production Capacity (kW) See WP-3 2 167,908 49,745 8,866 57,765 29,318 21,235 979 Reserved for Future Use 3 - Reserved for Future Use 4 - Distribution - Secondary 5 117,355 49,745 8,866 57,765 - - 979 Customers-(Test Yearend #) 6 39,631 34,969 3,495 866 25 2 274 Customers - Weighted Services (multiplier) 7 5,052,836 3,771,407 380,485 857,111 43,833 - - Customers - Weighted Meters (multiplier) 8 8,054,319 6,605,485 662,833 498,790 214,712 72,500 - Weighted Bills 9 39,874 34,969 3,495 866 250 20 274 Lighting (count) 10 274 - - - - - 274 Customers - Excluding Lighting 11 39,357 34,969 3,495 866 25 2 - Total Production Plant (line 2006) 12 186,634,343 55,292,931 9,854,802 64,207,380 32,587,760 23,603,284 1,088,185 Total Transmission Plant (line 2023) 13 12,113,582 3,588,811 639,630 4,167,408 2,115,123 1,531,981 70,629 Total Distribution Plant (line 2044) 14 138,975,413 56,344,497 8,966,879 51,909,321 7,884,938 5,608,764 8,261,015 Total General Plant (line 2052) 15 19,166,635 8,301,627 1,154,320 5,291,048 2,359,266 1,725,107 335,266 Total Plant in Service (line 2053) 16 356,889,973 123,527,866 20,615,631 125,575,158 44,947,087 32,469,136 9,755,095 Total Rate Base (line 2069) 17 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876 Reserved for Future Use 18 - - - - - - - Total Transmission Lines (line 2011) 19 3,441,590 1,019,617 181,725 1,184,002 600,928 435,251 20,066 Total Substations (line 2015) 20 1,384,594 410,205 73,110 476,339 241,761 175,107 8,073 Subtotal Transmission Plant (line 2020) 21 4,826,184 1,429,822 254,836 1,660,341 842,688 610,358 28,139 Distribution Primary 22 167,908 49,745 8,866 57,765 29,318 21,235 979 Subtotal Overhead Lines (line 2032) 23 50,901,301 16,486,188 2,938,316 19,144,128 6,964,113 5,044,101 324,454 Subtotal Underground Lines (line 2035) 24 34,547,136 14,644,006 2,609,986 17,004,945 - - 288,199 Subtotal Distribution Plant (line 2041) 25 122,926,742 48,752,904 7,876,861 46,704,418 7,100,402 5,051,603 7,440,555 Total Production O&M (line 3020) 26 77,705,530 19,941,085 3,427,834 26,192,211 15,848,712 11,868,119 427,569 Total Operation & Maintenance (line 3090) 27 98,022,362 28,608,883 4,666,091 31,957,780 18,344,798 13,675,947 768,863 Supervised O & M Expense (line 3080) 28 10,667,630 4,626,118 642,449 2,941,430 1,311,790 959,251 186,591 Subtotal Trans. Operation (line 3027) 29 7,217,652 2,138,326 381,112 2,483,072 1,260,256 912,803 42,083 Reserved for Future Use 30 - - - - - - - Distribution Operation Subtotal (line 3052) 31 953,275 457,964 61,686 253,882 76,337 52,074 51,332 Distribution Maintenance Subtotal (line 3066) 32 947,392 333,691 59,471 387,462 74,723 54,121 37,923 Prod., Trans., & Distr. O&M Less Fuel & Purchased Powe 33 16,708,471 5,207,260 888,488 5,684,901 2,723,731 1,982,629 221,461 Residential & Commercial ERT Meters 35 16,468 14,794 1,473 201 - - - Revised for Future Use 36 - - - - - - - Transformers (NCP) 37 117,355 49,745 8,866 57,765 - - 979 Firm Revenues 39 89,136,490 28,301,120 5,393,815 30,844,705 13,365,077 9,655,653 1,576,120 Residential & Commercial Revenue 40 33,694,935 28,301,120 5,393,815 - - - - Dist. Land and Land Rights 44 185,073 54,830 9,772 63,670 32,315 23,406 1,079 Dist. Structures 45 534,793 158,440 28,239 183,984 93,379 67,634 3,118 Dist. Station Equipment 46 13,460,453 3,987,840 710,749 4,630,768 2,350,296 1,702,317 78,482 Dist. Poles, Towers, and Fixtures 47 18,812,447 6,297,062 1,122,319 7,312,289 2,294,758 1,662,091 123,929 Dist. Overhead Conductors and Devices 48 17,740,035 5,938,095 1,058,341 6,895,448 2,163,944 1,567,343 116,864 Dist. Underground Conduit 49 6,034,424 2,557,901 455,892 2,970,291 - - 50,340 Dist. Underground Conductor 50 28,512,712 12,086,105 2,154,094 14,034,654 - - 237,859 Dist. Line Transformers 51 16,807,803 7,124,572 1,269,805 8,273,212 - - 140,214 Dist. Services 52 13,149,327 9,814,580 990,161 2,230,516 114,070 - - Dist. Meters 53 833,488 683,558 68,592 51,616 22,219 7,503 - Dist. Installations on Customer Premises 54 1,187,574 - - - - - 1,187,574 Dist. Street Lighting 55 5,500,113 - - - - - 5,500,113

CHEYENNE LIGHT, FUEL AND POWER COMPANYADJUSTED CLASS COST OF SERVICE - ELECTRIC

For the Pro Forma Test Year August 31, 2011




Secondary General

Primary General




Energy Input (MWH) See WP-2 1 100% 24.44% 4.14% 33.49% 21.30% 16.08% 0.54%Production Capacity (kW) See WP-3 2 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Reserved for Future Use 3 0% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Reserved for Future Use 4 0% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Distribution - Secondary 5 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Customers-(Test Yearend #) 6 100% 88.24% 8.82% 2.19% 0.06% 0.01% 0.69%Customers - Weighted Services (multiplier) 7 100% 74.64% 7.53% 16.96% 0.87% 0.00% 0.00%Customers - Weighted Meters (multiplier) 8 100% 82.01% 8.23% 6.19% 2.67% 0.90% 0.00%Weighted Bills 9 100% 87.70% 8.77% 2.17% 0.63% 0.05% 0.69%Lighting (count) 10 100% 0.00% 0.00% 0.00% 0.00% 0.00% 100.00%Customers - Excluding Lighting 11 100% 88.85% 8.88% 2.20% 0.06% 0.01% 0.00%Total Production Plant (line 2006) 12 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Total Transmission Plant (line 2023) 13 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Total Distribution Plant (line 2044) 14 100% 40.54% 6.45% 37.35% 5.67% 4.04% 5.94%Total General Plant (line 2052) 15 100% 43.31% 6.02% 27.61% 12.31% 9.00% 1.75%Total Plant in Service (line 2053) 16 100% 34.61% 5.78% 35.19% 12.59% 9.10% 2.73%Total Rate Base (line 2069) 17 100% 33.67% 5.69% 35.14% 13.42% 9.70% 2.38%Reserved for Future Use 18 0% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Total Transmission Lines (line 2011) 19 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Total Substations (line 2015) 20 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Subtotal Transmission Plant (line 2020) 21 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Distribution Primary 22 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Subtotal Overhead Lines (line 2032) 23 100% 32.39% 5.77% 37.61% 13.68% 9.91% 0.64%Subtotal Underground Lines (line 2035) 24 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Subtotal Distribution Plant (line 2041) 25 100% 39.66% 6.41% 37.99% 5.78% 4.11% 6.05%Total Production O&M (line 3020) 26 100% 25.66% 4.41% 33.71% 20.40% 15.27% 0.55%Total Operation & Maintenance (line 3090) 27 100% 29.19% 4.76% 32.60% 18.71% 13.95% 0.78%Supervised O & M Expense (line 3080) 28 100% 43.37% 6.02% 27.57% 12.30% 8.99% 1.75%Subtotal Trans. Operation (line 3027) 29 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Reserved for Future Use 30 0% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Distribution Operation Subtotal (line 3052) 31 100% 48.04% 6.47% 26.63% 8.01% 5.46% 5.38%Distribution Maintenance Subtotal (line 3066) 32 100% 35.22% 6.28% 40.90% 7.89% 5.71% 4.00%Prod., Trans., & Distr. O&M Less Fuel & Purchased Powe 33 100% 31.17% 5.32% 34.02% 16.30% 11.87% 1.33%Residential & Commercial ERT Meters 35 100% 89.83% 8.94% 1.22% 0.00% 0.00% 0.00%Revised for Future Use 36 0% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Transformers (NCP) 37 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Firm Revenues 39 100% 31.75% 6.05% 34.60% 14.99% 10.83% 1.77%Residential & Commercial Revenue 40 100% 83.99% 16.01% 0.00% 0.00% 0.00% 0.00%Dist. Land and Land Rights 44 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Dist. Structures 45 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Dist. Station Equipment 46 100% 29.63% 5.28% 34.40% 17.46% 12.65% 0.58%Dist. Poles, Towers, and Fixtures 47 100% 33.47% 5.97% 38.87% 12.20% 8.84% 0.66%Dist. Overhead Conductors and Devices 48 100% 33.47% 5.97% 38.87% 12.20% 8.84% 0.66%Dist. Underground Conduit 49 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Dist. Underground Conductor 50 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Dist. Line Transformers 51 100% 42.39% 7.55% 49.22% 0.00% 0.00% 0.83%Dist. Services 52 100% 74.64% 7.53% 16.96% 0.87% 0.00% 0.00%Dist. Meters 53 100% 82.01% 8.23% 6.19% 2.67% 0.90% 0.00%Dist. Installations on Customer Premises 54 100% 0.00% 0.00% 0.00% 0.00% 0.00% 100.00%Dist. Street Lighting 55 100% 0.00% 0.00% 0.00% 0.00% 0.00% 100.00%




Secondary General

Primary General




2001 Plant in Service

2002 Production Plant2003 Steam Production Plant 2 182,160,034 53,967,356 9,618,546 62,668,094 31,806,512 23,037,427 1,062,098 2004 Other Production Plant 2 - - - - - - - 2005 Unclassified Steam Production Plant 2 4,474,309 1,325,574 236,256 1,539,286 781,248 565,857 26,088 2006 CWIP Production & CT Plant 2 - - - - - - -

2006 Total Adjusted Production Plant CAT01 186,634,343 55,292,931 9,854,802 64,207,380 32,587,760 23,603,284 1,088,185

2007 Transmission Plant2008 Lines2009 Power Pool Service 2 3,441,590 1,019,617 181,725 1,184,002 600,928 435,251 20,066 2010 Direct To Jurisdiction 36 - - - - - - -

2011 Total Lines CAT02 3,441,590 1,019,617 181,725 1,184,002 600,928 435,251 20,066 2012 Substations2013 Power Pool Service 2 1,384,594 410,205 73,110 476,339 241,761 175,107 8,073 2014 CUS Plant 36 - - - - - - -

2015 Total Substations CAT03 1,384,594 410,205 73,110 476,339 241,761 175,107 8,073 2016 Total Lines And Substations TOTAL01 4,826,184 1,429,822 254,836 1,660,341 842,688 610,358 28,139

2017 Other Transmission Plant2018 Power Pool Service 36 - - - - - - -

2019 Total Other Trans. Plant CAT04 - - - - - - -

2020 Subtotal - Trans. Plant TOTAL02 4,826,184 1,429,822 254,836 1,660,341 842,688 610,358 28,139

2021 Unclassified Trans. Plant plus Additions 2 7,287,398 2,158,990 384,794 2,507,067 1,272,435 921,623 42,490

2022 Total Unclassified Trans. Plant CAT05 7,287,398 2,158,990 384,794 2,507,067 1,272,435 921,623 42,490

2023 Total Adjusted Transmission Plant TOTAL03 12,113,582 3,588,811 639,630 4,167,408 2,115,123 1,531,981 70,629

2024 Distribution Plant Miscellaneous Intangible Plant 2 168,500 49,920 8,897 57,969 29,421 21,310 982

2025 Land and Land Rights 2 185,073 54,830 9,772 63,670 32,315 23,406 1,079 2026 Structures and Improvements 2 534,793 158,440 28,239 183,984 93,379 67,634 3,118 2027 Station Equipment 2 13,460,453 3,987,840 710,749 4,630,768 2,350,296 1,702,317 78,482 2028 Poles, Towers & Fixtures - Primary 22 13,142,375 3,893,605 693,953 4,521,341 2,294,758 1,662,091 76,628 2029 Poles, Towers & Fixtures - Secondary 5 5,670,072 2,403,457 428,366 2,790,948 - - 47,301 2030 Overhead Conductors & Devices - Primary 22 12,393,188 3,671,649 654,394 4,263,600 2,163,944 1,567,343 72,259 2031 Overhead Conductors & Devices - Secondary 5 5,346,847 2,266,447 403,946 2,631,849 - - 44,605

2032 Subtotal - O.H. Lines CAT06 50,901,301 16,486,188 2,938,316 19,144,128 6,964,113 5,044,101 324,454

2033 Underground Conduit 5 6,034,424 2,557,901 455,892 2,970,291 - - 50,340 2034 U.G. Conductors & Devices 5 28,512,712 12,086,105 2,154,094 14,034,654 - - 237,859

2035 Subtotal - U.G. Lines CAT07 34,547,136 14,644,006 2,609,986 17,004,945 - - 288,199




Secondary General

Primary General




2036 Line Transformers 37 16,807,803 7,124,572 1,269,805 8,273,212 - - 140,214 2037 Services 7 13,149,327 9,814,580 990,161 2,230,516 114,070 - - 2038 Meters 8 833,488 683,558 68,592 51,616 22,219 7,503 - 2039 Installations on Cust. Premises 10 1,187,574 - - - - - 1,187,574 2040 Street Lighting and Signal Systems 10 5,500,113 - - - - - 5,500,113

Subtotal - Equipment CAT08 37,478,305 17,622,710 2,328,558 10,555,344 136,289 7,503 6,827,901

2041 Subtotal - Dist. Plant TOTAL04 122,926,742 48,752,904 7,876,861 46,704,418 7,100,402 5,051,603 7,440,555

2042 Unclassified Dist. Plant Plus Additions 25 13,554,966 5,375,917 868,571 5,150,033 782,952 557,033 820,460 2042.1 Unclassified Dist. Plant - AMI Meters 11 2,493,705 2,215,676 221,447 54,871 1,584 127 -

2043 Total Unclassified Dist. Plant CAT09 16,048,671 7,591,593 1,090,018 5,204,904 784,536 557,160 820,460

2044 Total Adjusted Distribution Plant TOTAL05 138,975,413 56,344,497 8,966,879 51,909,321 7,884,938 5,608,764 8,261,015

2045 Total Trans. and Dist. Plant TOTAL06 151,088,995 59,933,308 9,606,509 56,076,729 10,000,060 7,140,745 8,331,644

2046 General Plant2047 Classified Plant 28 7,496,886 3,251,095 451,494 2,067,148 921,886 674,133 131,130 2048 Unclassified General Plant 28 1,922,941 833,901 115,808 530,220 236,463 172,914 33,635 2049 Plant Acquisition Adj 28 2,575,835 1,117,035 155,128 710,246 316,748 231,623 45,055 2050 Unexpense Rate Case Costs 39 87,500 27,782 5,295 30,278 13,120 9,478 1,547 2051 Other Utility Plant 28 7,083,474 3,071,815 426,597 1,953,156 871,049 636,958 123,899

2052 Total Adjusted General Plant CAT10 19,166,635 8,301,627 1,154,320 5,291,048 2,359,266 1,725,107 335,266

2053 Total Adjusted Plant in Service TOTAL07 356,889,973 123,527,866 20,615,631 125,575,158 44,947,087 32,469,136 9,755,095

2054 Accumulated Depreciation2055 Production 12 14,878,537 4,407,966 785,627 5,118,628 2,597,904 1,881,660 86,750 2056 Transmission 13 2,334,145 691,522 123,249 803,010 407,559 295,195 13,609 2057 Distribution 14 42,479,510 17,222,375 2,740,835 15,866,710 2,410,126 1,714,386 2,525,079 2058 General 15 3,665,452 1,587,614 220,754 1,011,867 451,189 329,912 64,117 2059 Other Utility Plant 15 4,896,413 2,120,779 294,889 1,351,680 602,711 440,705 85,649

2060 Total Accumulated Depreciation CAT11 68,254,056 26,030,255 4,165,354 24,151,895 6,469,490 4,661,857 2,775,204

2061 Net Plant TOTAL08 288,635,917 97,497,611 16,450,278 101,423,262 38,477,597 27,807,279 6,979,891

2062 Working Capital2063 Cash Working Capital Allowance 27 (2,063,230) (602,176) (98,215) (672,666) (386,132) (287,859) (16,183) 2064 Materials and Supplies 16 5,225,647 1,808,717 301,858 1,838,694 658,123 475,419 142,836 2065 Prepayments 27 743,261 216,929 35,381 242,322 139,101 103,699 5,830

2066 Total Working Capital CAT13 3,905,678 1,423,470 239,024 1,408,351 411,092 291,259 132,482

2067 Other Rate Base Deductions 16 45,676,248 15,809,605 2,638,473 16,071,626 5,752,513 4,155,534 1,248,497

2068 Total Other Rate Base Deductions CAT14 45,676,248 15,809,605 2,638,473 16,071,626 5,752,513 4,155,534 1,248,497

2069 Total Rate Base TOTAL09 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876




Secondary General

Primary General




3001 Operation and Maintenance Expense

3002 Production Expense3003 Operation3004 Steam Power Generation3005 Fuel 1 9,015,684 2,203,548 373,577 3,019,594 1,920,343 1,449,926 48,697 3006 Rents 2 1,017,921 301,573 53,749 350,193 177,737 128,734 5,935 3007 Other 2 2,602,751 771,100 137,432 895,418 454,460 329,165 15,176 3008 Other Power Generation3009 Fuel 1 - - - - - - - 3010 Other 2 - - - - - - - 3011 Other Power Supply3012 Purchased Power - Capacity 2 14,171,671 4,198,548 748,303 4,875,447 2,474,480 1,792,264 82,629 3013 Purchased Power - Energy 1 48,035,361 11,740,455 1,990,408 16,088,330 10,231,542 7,725,170 259,455 3014 System Cont. & Load Dispatch 2 507,562 150,372 26,801 174,615 88,624 64,190 2,959

3015 Total Production Operation CAT15 75,350,951 19,365,596 3,330,269 25,403,599 15,347,186 11,489,450 414,851

3016 Maintenance3017 Steam Power Generation 1 2,354,580 575,489 97,565 788,612 501,526 378,670 12,718 3018 Other Power Generation 2 - - - - - - -

3019 Total Production Maintenance CAT16 2,354,580 575,489 97,565 788,612 501,526 378,670 12,718

3020 Total Production O&M TOTAL10 77,705,530 19,941,085 3,427,834 26,192,211 15,848,712 11,868,119 427,569

3021 Transmission Expense3022 Operation3023 Load Dispatching 20 159,817 47,348 8,439 54,982 27,905 20,212 932 3024 Station Expenses 20 - - - - - - - 3025 Overhead Line Expenses 19 - - - - - - - 3026 Transmission Expense 21 7,057,835 2,090,978 372,673 2,428,091 1,232,351 892,591 41,151

3027 Subtotal Trans. Operation CAT17 7,217,652 2,138,326 381,112 2,483,072 1,260,256 912,803 42,083

3028 Supervision and Engineering 29 19,689 5,833 1,040 6,774 3,438 2,490 115 3029 Misc. Trans. Expenses 29 - - - - - - - 3030 Rents 21 - - - - - - -

3031 Total Transmission Operation CAT18 7,237,341 2,144,160 382,151 2,489,846 1,263,694 915,293 42,198

3032 Maintenance3033 Structures 20 - - - - - - - 3034 Station Equipment 20 - - - - - - - 3035 Overhead Lines 19 - - - - - - - 3036 Underground Lines 19 - - - - - - -

3037 Subtotal Trans. Maintenance CAT19 - - - - - - -

3038 Supervision and Engineering 30 - - - - - - - 3039 Misc. Trans. Plant 30 - - - - - - -

3040 Total Transmission Maint. CAT20 - - - - - - -

3041 Total Transmission O&M TOTAL11 7,237,341 2,144,160 382,151 2,489,846 1,263,694 915,293 42,198




Secondary General

Primary General




3042 Distribution Expense3043 Operation3044 Load Dispatching 2 153,010 45,331 8,079 52,640 26,717 19,351 892 3045 Station Expenses 2 21,569 6,390 1,139 7,420 3,766 2,728 126 3046 Overhead Line Expenses 23 274,336 88,854 15,836 103,179 37,534 27,186 1,749 3047 Transformer Setting 51 - - - - - - - 3048 Underground Line Expenses 24 144,882 61,413 10,946 71,314 - - 1,209 3049 Street Lighting and Sig. Exp. 10 18,347 - - - - - 18,347 3050 Meter Expenses 53 312,121 255,976 25,686 19,329 8,321 2,810 - 3051 Cust. Install. Expenses 54 29,010 - - - - - 29,010

3052 Subtotal Dist. Operation CAT21 953,275 457,964 61,686 253,882 76,337 52,074 51,332 3053 Supervision and Operation 31 333,119 160,034 21,556 88,718 26,676 18,197 17,938 3054 Misc. Dist. Expenses 31 328,073 157,610 21,230 87,375 26,272 17,921 17,666 3055 Rents 31 39,484 18,969 2,555 10,516 3,162 2,157 2,126

3056 Total Distribution Operation CAT22 1,653,951 794,576 107,027 440,490 132,446 90,349 89,062

3057 Maintenance3058 Structures 45 - - - - - - - 3059 Station Equipment 46 20,211 5,988 1,067 6,953 3,529 2,556 118 3060 Overhead Lines 47 583,521 195,321 34,812 226,811 71,178 51,554 3,844 3061 Underground Lines 24 163,123 69,146 12,324 80,293 - - 1,361 3062 Line Transformers 51 148,922 63,126 11,251 73,303 - - 1,242 3063 Street Light. & Signal System 55 31,342 - - - - - 31,342 3064 Meters 53 - - - - - - - 3065 Misc. Dist. Plant 14 272 110 18 102 15 11 16

3066 Subtotal Dist. Maintenance CAT23 947,392 333,691 59,471 387,462 74,723 54,121 37,923 3067 Supervision and Engineering 32 386,973 136,300 24,292 158,263 30,521 22,107 15,490

3068 Total Distribution Maintenance CAT24 1,334,364 469,990 83,763 545,726 105,244 76,228 53,413

3069 Total Distribution O&M TOTAL12 2,988,315 1,264,566 190,790 986,216 237,690 166,577 142,476

3070 Total Trans. & Dist. O&M TOTAL13 10,225,657 3,408,726 572,941 3,476,062 1,501,385 1,081,870 184,673

3071 Customer Accounts Expenses3072 Computer Services 6 - - - - - - - 3073 Customer Accounts 6 - - - - - - - 3074 Accounts 901 Through 905 6 1,132,311 999,112 99,857 24,743 714 57 7,829

3075 Total Comp. Exp. & Cust. Acct. CAT25 1,132,311 999,112 99,857 24,743 714 57 7,829

3076 Customer Service & Informational Expenses3077 Accounts 907 Through 910 6 942,088 831,266 83,081 20,586 594 48 6,513

3078 Total Customer Service and Info. CAT26 942,088 831,266 83,081 20,586 594 48 6,513

3079 Subtotal O&M Expense TOTAL14 90,005,587 25,180,189 4,183,714 29,713,602 17,351,405 12,950,093 626,584

3080 Supervised O&M Expense TOTAL15 10,667,630 4,626,118 642,449 2,941,430 1,311,790 959,251 186,591




Secondary General

Primary General




3081 Administrative and General Exp.3082 Operation3083 Property Insurance 16 203,723 70,513 11,768 71,682 25,657 18,534 5,568 3084 Regulatory Comm. Exp. 39 258,462 82,062 15,640 89,438 38,754 27,998 4,570 3085 Other A&G Expense 28 7,231,792 3,136,134 435,529 1,994,052 889,288 650,295 126,493

3086 Total A&G Operation CAT27 7,693,977 3,288,710 462,937 2,155,172 953,699 696,827 136,632 3087 Maintenance3088 General Plant 28 322,798 139,985 19,440 89,007 39,694 29,027 5,646

3089 Total A&G Expenses CAT28 8,016,775 3,428,695 482,377 2,244,179 993,393 725,854 142,278

3090 Total O&M Expenses TOTAL16 98,022,362 28,608,883 4,666,091 31,957,780 18,344,798 13,675,947 768,863

3091 Total O&M Exp. Less Purch. Pwr. TOTAL17 35,307,768 12,519,508 1,900,580 10,819,388 5,550,151 4,094,322 423,819

3092 Total O&M Exp. Less P. P. & Fuel TOTAL18 26,292,084 10,315,960 1,527,003 7,799,793 3,629,809 2,644,397 375,122

3093 Depreciation / Amortization / Accretion Expense

3094 Production 12 4,879,546 1,445,631 257,653 1,678,699 852,005 617,107 28,451 3095 Transmission 13 255,926 75,822 13,514 88,046 44,687 32,367 1,492 3096 Distribution 14 3,925,776 1,591,619 253,296 1,466,334 222,734 158,436 233,357 3097 General 15 624,315 270,409 37,600 172,345 76,848 56,192 10,921 3098 Other Utility Plant 15 568,095 246,058 34,214 156,825 69,928 51,132 9,937 3099 Acquistion Adjustment 15 97,817 42,367 5,891 27,003 12,040 8,804 1,711 3100 Accretion 15 9,296 4,026 560 2,566 1,144 837 163

3101 Total Depreciation / Amortization / Accretion Expense CAT30 10,360,770 3,675,932 602,728 3,591,818 1,279,387 924,874 286,031

3102 Taxes Other Than Income3103 Property Taxes 16 1,547,317 535,562 89,380 544,438 194,871 140,772 42,294 3104 Payroll Taxes 33 523,648 163,197 27,845 178,166 85,362 62,136 6,941 3105 Unemployment - Federal 33 5,622 1,752 299 1,913 916 667 75 3106 Unemployment - State 33 38,737 12,073 2,060 13,180 6,315 4,597 513 3107 Wyoming Franchise Fees 39 989,641 314,214 59,885 342,455 148,386 107,202 17,499 3108 Payroll Loading and Other 33 (520,031) (162,070) (27,653) (176,936) (84,773) (61,707) (6,893)

3109 Total Taxes Other Than Income CAT31 2,584,935 864,728 151,816 903,216 351,078 253,667 60,429

3110 Total Oper. Exp. Before Inc. Tax TOTAL19 110,968,067 33,149,544 5,420,635 36,452,815 19,975,263 14,854,488 1,115,322

4001 Other Operating Revenue4002 Sales for Resale 1 31,471,448 7,692,023 1,304,061 10,540,632 6,703,425 5,061,319 169,988 4003 Unbilled Revenue 39 (199,067) (63,204) (12,046) (68,885) (29,848) (21,564) (3,520) 4004 Acct. 450 - Late Payment Charges 39 182,021 57,792 11,014 62,987 27,292 19,717 3,219 4005 Acct. 451 - Misc. Service Revenues 40 175,844 147,695 28,149 - - - - 4006 Acct. 454 & 456 - Rent from Elec. Prop. & Other 14 1,229,443 498,450 79,325 459,215 69,754 49,618 73,081 4007 Other 39 899,188 285,495 54,412 311,154 134,824 97,404 15,900

4008 Total Other Operating Revenue CAT32 33,758,878 8,618,252 1,464,915 11,305,102 6,905,447 5,206,495 258,667




Secondary General

Primary General




5001 Return Under Existing Rates5002 Revenue from Firm Sales 39 92,804,980 29,465,877 5,615,802 32,114,146 13,915,128 10,053,040 1,640,987 5003 PCA Revenue 1 7,807,868 1,908,343 323,529 2,615,064 1,663,078 1,255,681 42,173 5004 Other Operating Revenue 33,758,878 8,618,252 1,464,915 11,305,102 6,905,447 5,206,495 258,667

5005 Total Operating Revenue CAT33 134,371,726 39,992,472 7,404,246 46,034,312 22,483,653 16,515,216 1,941,827 5006 Oper. Expense Before Income Tax TOTAL19 110,968,067 33,149,544 5,420,635 36,452,815 19,975,263 14,854,488 1,115,322

5007 Oper. Income Before Income Tax TOTAL20 23,403,659 6,842,928 1,983,611 9,581,497 2,508,390 1,660,728 826,504

5001 Federal Income Tax Calculation5002 Tax Adjustments5003 Interest Expense 17 - - - - - - - 5004 State Income Tax 1 - - - - - - - 5005 Other Tax Adjustments 16 - - - - - - -

5006 Total Tax Adjustments CAT34 - - - - - - -

5007 Taxable Income TOTAL21 23,403,659 6,842,928 1,983,611 9,581,497 2,508,390 1,660,728 826,504 5008 Federal Income Tax 5,951,370 1,740,104 504,417 2,436,501 637,864 422,310 210,174 5009 Interest Expense Sync 16 (184,828) (63,973) (10,677) (65,034) (23,277) (16,815) (5,052) 5010 Less Inv. Tax Credit Amort. 16 - - - - - - -

5011 Total Federal Income Tax CAT35 5,766,542 1,676,131 493,740 2,371,467 614,587 405,495 205,122 5012 State Income Tax 1 - - - - - - -

5013 State Income Tax CAT36 - - - - - - -

5014 Total Operating Expense TOTAL22 116,734,609 34,825,674 5,914,375 38,824,282 20,589,850 15,259,983 1,320,444

5015 Return to equity pretax TOTAL23 17,637,117 5,166,798 1,489,871 7,210,030 1,893,803 1,255,233 621,383 5016 Rate Base TOTAL09 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876 5017 Rate of Return, Existing Rates 7.14% 6.22% 10.60% 8.31% 5.72% 5.24% 10.60%

6001 Proposed Revenue Increase

6002 Revenue Increase6003 Revenue Under Existing Rates 100,612,848 31,374,220 5,939,331 34,729,210 15,578,206 11,308,721 1,683,160 6004 Revenue Under Proposed Rates 106,520,794 34,549,449 5,527,873 35,249,346 17,099,811 12,582,271 1,512,044

6005 Proposed Revenue Increase 3,840,168 2,063,901 (267,448) 338,089 989,044 827,808 (111,225) 6006 Additional Revenue with Federal Income Tax 5,907,945 3,175,229 (411,459) 520,136 1,521,605 1,273,550 (171,116)




Secondary General

Primary General




6007 Return Under Proposed Rates

6008 Revenue from Firm Sales 106,520,794 34,549,449 5,527,873 35,249,346 17,099,811 12,582,271 1,512,044 6009 Other Operating Revenue 33,758,878 8,618,252 1,464,915 11,305,102 6,905,447 5,206,495 258,667

6010 Total Operating Revenue 140,279,671 43,167,701 6,992,787 46,554,449 24,005,258 17,788,766 1,770,711

6011 Operation and Maintenance Expense 98,022,362 28,608,883 4,666,091 31,957,780 18,344,798 13,675,947 768,863 6012 Depreciation and Amortization Expense 10,360,770 3,675,932 602,728 3,591,818 1,279,387 924,874 286,031 6013 Taxes Other than Income Tax 2,584,935 864,728 151,816 903,216 351,078 253,667 60,429 6014 Federal Income Tax - Existing Rates 5,766,542 1,676,131 493,740 2,371,467 614,587 405,495 205,122 6015 Federal Income Tax - Additional 2,067,777 1,111,328 (144,010) 182,047 532,561 445,742 (59,890) 6016 State Income Tax - - - - - - -

6017 Total Operating Expenses 118,802,386 35,937,002 5,770,365 39,006,330 21,122,410 15,705,725 1,260,554

6018 Return 21,477,285 7,230,698 1,222,422 7,548,119 2,882,847 2,083,041 510,157 6019 Rate Base 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876 6020 Rate of Return, Proposed Rates 8.70% 8.70% 8.70% 8.70% 8.70% 8.70% 8.70%

7001 Return Under Current Rates

7002 Revenue from Firm Sales 100,612,848 31,374,220 5,939,331 34,729,210 15,578,206 11,308,721 1,683,160 7003 Other Operating Revenue 33,758,878 8,618,252 1,464,915 11,305,102 6,905,447 5,206,495 258,667

7004 Total Operating Revenue 134,371,726 39,992,472 7,404,246 46,034,312 22,483,653 16,515,216 1,941,827

7005 Operation and Maintenance Expense 98,022,362 28,608,883 4,666,091 31,957,780 18,344,798 13,675,947 768,863 7006 Depreciation and Amortization Expense 10,360,770 3,675,932 602,728 3,591,818 1,279,387 924,874 286,031 7007 Taxes Other than Income Tax 2,584,935 864,728 151,816 903,216 351,078 253,667 60,429 7008 Federal Income Tax - Existing Rates 5,766,542 1,676,131 493,740 2,371,467 614,587 405,495 205,122 7009 State Income Tax - - - - - - -

7010 Total Operating Expenses 116,734,609 34,825,674 5,914,375 38,824,282 20,589,850 15,259,983 1,320,444

7011 Return 17,637,117 5,166,798 1,489,871 7,210,030 1,893,803 1,255,233 621,383 7012 Rate Base 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876 7013 Rate of Return, Current Rates 7.14% 6.22% 10.60% 8.31% 5.72% 5.24% 10.60%




Secondary General

Primary General




8001 Cost of Service and Revenue Deficiency

8002 Rate Base 246,865,347 83,111,476 14,050,828 86,759,987 33,136,176 23,943,003 5,863,876 8003 Rate of Return 8.70% 8.70% 8.70% 8.70% 8.70% 8.70% 8.70%8004 Return 21,477,285 7,230,698 1,222,422 7,548,119 2,882,847 2,083,041 510,157 8005 Operation and Maintenance Expenses 98,022,362 28,608,883 4,666,091 31,957,780 18,344,798 13,675,947 768,863 8006 Depreciation and Amortization Expense 10,360,770 3,675,932 602,728 3,591,818 1,279,387 924,874 286,031 8007 Taxes Other than Income Tax 2,584,935 864,728 151,816 903,216 351,078 253,667 60,429 8008 Federal Income Tax - Existing Rates 5,766,542 1,676,131 493,740 2,371,467 614,587 405,495 205,122 8009 State Income Tax - - - - - - -

8010 Total Cost of Service 138,211,894 42,056,373 7,136,798 46,372,401 23,472,697 17,343,024 1,830,601 8011 Less: Other Operating Revenue 33,758,878 8,618,252 1,464,915 11,305,102 6,905,447 5,206,495 258,667

8012 Net Cost of Service 104,453,017 33,438,121 5,671,883 35,067,299 16,567,250 12,136,530 1,571,934

8013 Revenue Under Existing Rates 100,612,848 31,374,220 5,939,331 34,729,210 15,578,206 11,308,721 1,683,160 8014 Revenue Deficiency8015 Amount before tax adjustment (3,840,168) (2,063,901) 267,448 (338,089) (989,044) (827,808) 111,225 8016 Tax Adjusted Amount Needed (5,907,945) (3,175,229) 411,459 (520,136) (1,521,605) (1,273,550) 171,116 8017 Percent Increase/(Decrease) 5.87% 10.12% -6.93% 1.50% 9.77% 11.26% -10.17%

tax multiplier (1/(1-.35)) Federal Tax Rate at 35% 1.53846 1.53846 1.53846 1.53846 1.53846 1.53846 1.53846

9000 Service and Facility Cost Analysis:9001 Ref. No. 2036, 2037, 2038 and 2042.1 net of accum depr. * Ref. No. 8003 1,198,320 154,031 640,900 8,328 461 9002 Depreciation Ref. No. 9017 * Stmt J Line 11 561,426 72,165 300,269 3,902 216 9003 Taxes Other than Income Tax (Percent of total) 138,875 18,780 76,322 1,088 51 9004 Operating Expenses9005 Meter Expense Ref. No. 3050 and 3064 255,976 125,543 44,072 9,035 2,867 9006 Distribution Salaries Ref. No. 3053 and 3067 * Ref. No 9015 104,339 13,039 50,483 1,001 56 9007 Other Costs (Ref. No 3046, 3048, 3054, 3060, and 3061 * Ref. No 9015 201,522 27,060 116,298 2,362 135 9008 Customer Service Ref. No. 3075 and 3078 1,830,377 182,938 45,329 1,309 105 9009 Admin and General Costs * Ref. No 9019 528,167 57,265 182,112 2,956 139 9010 (Tax Adjustment Ref. No 9001* Tax Multiplier) Less 9001 645,247 82,939 345,099 4,484 248

Total Servie and Facility Cost 5,464,250 733,761 1,800,884 34,466 4,278

Number of Bills on Exhibit CRG-E2, Line 4, 24, 44, 58, and 72 415,785 40,182 10,429 315 24 Monthly Facility Charge Calculation 13.14 18.26 172.68 109.41 178.25

9011 Accum Depr. Ratio Calc9012 Total Accum Depr for Distribution Only Ref. No. 2057 17,222,375 2,740,835 15,866,710 2,410,126 1,714,386 9013 Total Distribution Plant in Service Ref. No. 2044 56,344,497 8,966,879 51,909,321 7,884,938 5,608,764 9014 Overall Percent in Accum Depr 30.57% 30.57% 30.57% 30.57% 30.57%9015 Distribution Plant Ratio (Ref. No. 9017/9013) 35.21% 28.44% 20.44% 1.75% 0.14%9016 Taxes Other than Income Taxes Ratio9017 Distribution Plant in Service Ref. No. 2036, 2037, 2038 and 2042.1 19,838,386 2,550,006 10,610,215 137,873 7,629 9018 Total Plant in Service Ref. No. 2053 123,527,866 20,615,631 125,575,158 44,947,087 32,469,136 9019 Percent of Distribution Plant to Taxes Other than Inc. Taxes 16.06% 12.37% 8.45% 0.31% 0.02%

Statement PPage 1 of 1

Line FERCNo. Description Account Reference Amount

1 Steam Plant Fuel Expense 501 Stmt. H Ln 3 (m) 8,890,889$ 2 Steam Fuel Handling 501 Stmt. H Ln 4 (m) 124,795 3 Steam Plant Allowances Expense 509 Stmt. H Ln 9 (m) (13,141) 45 Base Cost for Steam Plant Expense line 1 + line 2 + line 3 9,002,543$ 67 Purchase Power - Energy 555 Stmt. H Ln 24 (m) 48,035,361 8 Purchase Power - Capacity 555 Stmt. H Ln 25 (m) 14,171,671 9

10 Base Purchase Power Expense line 7 + line 8 62,207,032 1112 Transmission 556 Stmt. H Ln 36 (m) 7,055,962 1314 System Delivered Power Costs line 5 + line 10 + line 12 78,265,537 1516 Sales for Resale 447 Stmt. I Pg 1 Ln 9 (c) 31,471,448$ 1718 Retail Delivered Power Costs line 14 - line 16 46,794,089$ 1920 Annual Retail Energy Sales - kWh Stmt. I Pg 2 Ln 14 (c) 1,079,739,073 2122 Base Unit Cost for Steam Plant line 18 ÷ line 20 0.0433$


For the Pro Forma Test Year Ended August 31, 2011DERIVATION OF BASE UNIT COST FOR POWER COST ADJUSTMENT

Statement QPage 1 of 1

LineNo. Description

123456789

10111213141516171819202122232425262728293031

Cheyenne Light purchases natural gas from independent suppliers. The natural gas supplies are delivered to the respectivedelivery systems through a combination of transportation agreements with interstate pipelines and deliveries by suppliersdirectly to certain transportation customers. The balance of the quantities required to meet firm peak day sales obligationsare primarily purchased at Cheyenne Light's city gate meter station and a small amount is received directly from wellheadsources.

CHEYENNE LIGHT, FUEL AND POWER COMPANYDESCRIPTION OF UTILITY OPERATIONS - TOTAL COMPANY


Cheyenne Light, Fuel and Power Company (Cheyenne Light) was acquired by Black Hills Corporation in January 2005.This combination electric and natural gas utility serves approximately 39,630 electric and 34,600 natural gas customers inCheyenne, Wyoming and part of Laramie County, Wyoming. Cheyenne Light has approximately 79 current employeeswith 3 open positions, and owns a business office, warehouse and garage facilities located in Cheyenne, Wyoming.

Cheyenne Light has a contract for 40 megawatts of energy and capacity from the Gillette CT (combustion turbine) and 60megawatts of base-load energy and capacity from the Wygen I coal-fired power plant. These contracts are with anunregulated wholesale subsidiary of Black Hills Corporation.

Cheyenne Light's electric system has a peak load of 181 megawatts and an average system load of approximately 128megawatts. Cheyenne's system serves electric customers with annual sales of approximately 1,028,609 megawatt hours.Cheyenne Light has approximately 1,088 miles of electric distribution lines and 25 miles of electric transmission lines.

Wygen II, located in Gillette, Wyoming, is Cheyenne Light's generating facility. This plant was included in rate base beginning January 1, 2008 and has 95 MW net capacity to provide base load energy. This facility is located near Black Hills Corporations' Wyodak coal mine.

Cheyenne Light's natural gas distribution system serves natural gas customers with annual sales and transportation of approximately 13.7 million dekatherms (dTh). Sales to commercial and residential customers account for approximately 4.6 million dTh and transportation accounting for approximately 9.0 million dTh. Cheyenne Light also operates and maintains approximately 29 miles of high pressure gas transmission pipeline as classified by the Wyoming Department of Transportation and approximately 750 miles of distribution pipeline.

Statement RPage 1 of 6

2012(2)

Line No.

Applicable Sales to BHP/CLFP

1 Gross Mining Plant 109,866,196$

2 Accumulated Provision for Depreciation, Depletion and Amortization -- Mining Plant 54,353,152

3 Net Mining Plant (Line 1 less Line 2) 55,513,044$ 24,031,597$ (a)

4 Blending Facility 7,326,765

5 Accumulated Provision for Depreciation 6,317,958

6 Net Blending Facility (Line 4 less Line 5) 1,008,807 533,356 (b)

7 Processing Plant 18,935,517

8 Accumulated Provision for Depreciation 10,301,450

9 Net Processing Plant (Line 7 less Line 8) 8,634,067 3,737,688 (c)

10 Mining Investment for BHP/CLFP Sales* 425,000

11 Accumulated Provision for Depreciation* 425,000

12 Net Investment for Sales to BHP/CLFP (Line 10 less Line 11) - -

13 Net Mining and Processing Plant (Sum Lines 3, 6, 9, 12) 65,155,918 28,302,641

14 Unamortized Stripping Costs* - - (a)

15 Materials, Supplies and Prepayments* 5,549,859 2,402,534 (a)

16 Total Utility Type Investment Base (Sum Lines 13, 14, 15) 70,705,777$ 30,705,175$

17 (a) Percent Applicable to Mining (Part III, Line 6) 43.29%18 (b) Percent Applicable to Blending Facility (Part III, Line 9) 52.87%19 (c) Percent Applicable to Processing (Part III, Line 11) 43.29%

20 * from Input page

Total Company

(1)

Statement R - Part IWyodak Resources Development Corporation

Computation of Utility Type Investment Basefor Total Sales to Black Hills Power and Cheyenne Light, Fuel and Power Company

for the 12 Months ended December 31, 2012


(1) (2) (3)

Line No. Total Company

Applicable Sales to BHP

Ownership & CLFP

Adjusted

1 Receipts from Coal Sales* 64,510,213$ 33,136,819$ 33,136,819$ 2 Operating Expenses:3 Mining Expenses (from Schedule B) 28,607,895 12,384,358 (a) 12,384,3584 Royalties* 8,063,777 4,142,102 (e) 4,142,1024a Royalty tax from prior year activity5 Production Tax* 3,066,758 1,575,295 (e) 1,575,2955a Production tax from prior year activity6 Severance Tax* 3,577,885 1,837,844 (e) 1,837,844

6a Severance Tax from Prior Year activity7 Black Lung Tax* 2,039,116 1,047,428 (e) 1,047,4287a Black Lung tax from prior year activity8 Blending Facility Expenses (from Schedule B) 1,834,827 970,073 (b) 970,0739 Processing Expenses (from Schedule B) 1,390,284 601,854 (c) 601,85410 11,089,997 4,800,860 (a) 4,800,86011 Depreciation -- Blending Facility (from Schedule B) 193,485 102,296 (b) 102,29612 Depreciation -- Processing Plant (from Schedule B) 1,422,289 615,709 (c) 615,70913 Depreciation -- Investment for BHP/CLFP Sale* - - - 14 Federal Reclamation, FICA, and Unemployment* 2,066,048 894,392 (a) 894,39214a Fed Reclamation tax from prior year activity15 Property Taxes:16 Mining 446,534 193,305 (a) 193,30517 Blending Facility 29,778 15,744 (b) 15,74418 Processing 76,960 33,316 (c) 33,31619 Investment for BHP/CLFP Sale 1,727 1,727 1,7272021 Total Operating Expenses (before Taxes) 63,907,359 29,216,304 29,216,3042223 Federal Income Tax (from Part IV) 156,199 1,015,804 (d) 1,015,80524 Total Operating Expenses 64,063,558 30,232,108 30,232,10925 Net Mining Income 446,654 2,904,711 2,904,71026 Other non-mining income (net) 5,433,68727 Less: Interest on Long-term Debt* - 28 Net Income 5,880,341$ 2930 Utility Type Investment Base Applicable to Sales to BHP/CLFP (from Part I) 30,705,175 30,705,1753132 Utility Type Rate of Return Related to Sales to BHP/CLFP 9.46% 9.46%3334 Note: An "*" designates the column 1 amount comes from the Input page.3536 (a) Percent Applicable to Mining (Part III, Line 6) 43.29%37 (b) Percent Applicable to Blending Facility (Part III, Line 9) 52.87%38 (c) Percent Applicable to Processing (Part III, Line 11) 43.29%39 (d) Amount Applicable to BHP/CLFP (Part IV, Line 11) 1,015,80440 (e) Coal taxes calculated based on applicable sales to those subsidiaries

Depreciation and Depletion of Mining Plant (from Schedule B)

Statement R - Part IIWyodak Resources Development Corporation

Computation of Utility Type Investment Basefor Total Sales to Black Hills Power/Cheyenne Light Fuel & Power



Line No. TONS SOLD1 Total Coal Sold 4,769,809

2 Total Coal Sold - Wyodak Plant 2,137,131

3 Total Coal Sold - All Except Wyodak 2,632,678

4 Total Tons Sold - BHP Wyodak 427,426

5 Total Coal Sold - BHP Other/Wygen II/Wygen III 1,637,191

6 Percent Applicable to Mining ((Line 4+Line 5)/Line 1) 43.29%

7 Total Coal Sold by Blending Facility (BHP Other less NSII, Trucks, Wygen II & Wygen III) 1,116,942

8 Other Coal Sold by Blending Facility 995,487

9 Percent Applicable to Processing Blending Facility (Line 7/(Line 7+Line 8)) 52.87%

10 Total Coal Sold - Train Load Out -

11 Percent Applicable to Processing (Line 4+Line 5)/(Line 1-Line 10) 43.29%


Statement R - Part IIIWyodak Resources Development Corporation

Computation of Utility Type Investment Basefor Total Sales to Black Hills Power and Cheyenne Light Fuel & Power


Line No. Description Amount1 Total Federal Income Tax Applicable to Mining Income 156,199$

2 Income before Federal Income Tax:3 Net Income 446,6544 Plus Federal Income Tax 156,199

5 Mining Income Before Federal Income Tax 602,853

6 Unadjusted Receipts from Coal Sales (from Part II) 33,136,819

7 Total Operating Expenses (from Part II) 29,216,304

8 Income before Federal Income Tax Applicable to BHP/CLFP 3,920,5159 Federal Income Tax Rate (Line 4/Line 5) 25.91%

10 Federal Income Tax 1,015,804$


Statement R - Part IVWyodak Resources Development Corporation

Computation of Utility Type Investment Basefor Total Sales to Black Hills Power / Cheyenne Light Fuel & Power


Line No. AmountPercent of

Total CostWeighted

Cost

1 Long Term Debt 0 0% 0% 0%2 Common Equity 176,434,237 100% 9.46% 9.46%3 Total Capitalization 176,434,237$ 100% 9%456 Utility A-rated Bonds 5.46%7 Plus 400 Basis Points 4.00%8 Return on Equity 9.46%9

10 Weighted Cost of Equity 9.46%11 Weighted Cost of Debt 0.00%12 Weighted cost of Capital 9.46%


Statement R - Part VWyodak Resources Development Corporation



Line No. Amount

1 Price per Ton required to balance Affiliate Coal Adjustment to approximately 16.05$

2 Coal Receipts from BHP/CLFP 33,136,819$

3 Coal Receipts from BHP/CLFP as Adjusted (from Part II) 33,136,819$

4 Difference in Coal Receipts BHP/CLFP/MDU (Line 2 - Line 3) -

5 Annual Retail Energy Sales in South Dakota - MWH 1

6 Annual Total Energy Sales - MWH 1

7 Percent Applicable to South Dakota (Line 5/Line 6) 100.00%

8 Affiliate Coal Adjustment (Line 4 x Line 7) -$


Statement R - Part VIWyodak Resources Development Corporation


Workpaper 1Page 1 of 3

Line FERCNo. Account Description Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Total

1 Steam Production Operation:2 500 Supervision & Engineering 91,889 92,847 107,691 75,345 76,941 68,876 158,070 88,137 (200,756) 29,529 38,812 38,247 665,628 3 501 Fuel 324,402 497,254 507,237 302,990 598,230 545,240 756,366 587,397 778,519 1,040,106 690,478 693,327 7,321,546 4 502 Steam Expense 126,025 117,271 71,349 144,694 104,623 113,577 218,354 119,367 129,887 92,678 90,908 108,324 1,437,057 5 505 Electric Expense 23,766 23,862 30,052 30,263 36,534 32,990 43,291 30,065 58,522 32,855 27,014 43,304 412,518 6 506 Miscellaneous 2,851 3,137 627 4,732 2,977 5,095 8,270 4,908 52,756 2,844 6,875 5,628 100,700 7 507 Rents 126,802 126,802 106,802 146,802 64,827 104,827 84,827 84,827 84,827 84,827 84,827 84,827 1,185,824 8 509 Allowances - - - - (13,141) - - - - - - - (13,141) 9 Total Steam Production Operation 695,735 861,173 823,758 704,826 870,991 870,605 1,269,178 914,701 903,755 1,282,839 938,914 973,657 11,110,132

1011 Steam Production Maintenance:12 510 Supervision & Engineering 32,995 18,158 20,696 23,279 19,837 30,275 45,779 23,433 83,016 39,383 31,657 51,571 420,079 13 511 Structures 15,304 20,574 12,162 12,373 30,731 23,926 49,794 24,785 69,375 27,388 32,571 36,002 354,985 14 512 Boilers 100,183 69,172 84,217 188,401 76,515 108,899 139,082 76,315 123,037 69,217 58,714 126,375 1,220,127 15 513 Electric Plant 13,186 20,426 19,295 26,435 17,157 26,614 37,248 14,356 5,295 6,502 12,884 11,523 210,921 16 514 Miscellaneous Plant 923 1,108 873 520 744 3,114 2,084 1,060 2,680 1,432 1,733 2,376 18,647 17 Total Steam Production Maintenance 162,591 129,438 137,243 251,008 144,984 192,828 273,987 139,949 283,403 143,922 137,559 227,847 2,224,759 1819 Other Power Supply20 555 Purchased Power 2,868,233 6,518,634 6,440,310 6,499,246 7,119,806 6,315,600 5,148,949 4,175,090 4,010,714 3,844,834 4,208,970 4,028,479 61,178,865 21 556 System Control and Load Dispatching 34,020 34,000 34,012 34,012 43,970 43,223 43,205 43,353 43,407 10,856 43,226 27,409 434,693 22 557 Other Expenses - - 52 - - - - - - - - - 52 23 558 Reserve Capacity Agreement - 618 - - - - - - - - - - 618 24 Total Other Power Supply 2,902,253 6,553,252 6,474,374 6,533,258 7,163,776 6,358,823 5,192,154 4,218,443 4,054,121 3,855,690 4,252,196 4,055,888 61,614,228 2526 Total Production Expenses 3,760,579 7,543,863 7,435,375 7,489,092 8,179,751 7,422,256 6,735,319 5,273,093 5,241,279 5,282,451 5,328,669 5,257,392 74,949,119 2728 Gas Purchases29 803 Gas Transmission 158,246 227,796 235,053 235,326 238,187 236,504 204,999 152,818 (4,486) - - - 1,684,443 30 804 Purch Gas Commodity System 816,523 1,103,272 1,871,450 2,232,299 2,546,311 2,787,218 1,837,564 1,904,885 1,719,293 1,034,369 769,519 1,130,153 19,752,856 31 805 Deferred Gas Costs (196,781) (13,501) (365,563) (186,914) 18,386 (521,321) (283,484) (56,497) (465,786) (84,091) (60,026) (71,292) (2,286,870) 32 808 Gas To/From Commodity (353,932) (243,968) 443,056 574,671 711,281 286,744 309,154 (279,768) (153,492) (305,256) (335,006) (559,209) 94,275 33 813 Other Gas Supply Expenses 14,913 3,770 9,503 9,241 7,263 7,277 9,707 7,296 7,610 7,493 6,887 7,867 98,827 34 Total Gas Purchases 438,969 1,077,369 2,193,499 2,864,623 3,521,428 2,796,422 2,077,940 1,728,734 1,103,139 652,515 381,374 507,519 19,343,531 3536 Underground Storage Expense37 835 Maint. of Measuring & Reg. Station Equip. - - - - - - - - - 142 - - 142 38 Total Underground Storage Expense - - - - - - - - - 142 - - 142 3940 Electric Transmission Operations41 560 Supervision & Engineering 4,046 2,268 (668) 2,116 1,028 59 1,525 2,267 2,895 1,705 1,301 1,146 19,688 42 561 Load Dispatch 2,458 6,352 6,065 6,625 82,244 18,822 (62,364) 10,086 14,955 35,975 (2,618) 31,025 149,625 43 565 Transmission of Electricity by Others 595,636 583,963 553,831 550,346 543,544 552,506 610,676 558,509 551,846 595,741 556,675 802,690 7,055,963 44 566 Miscellaneous Transmission Expense - - - - - - 109 762 1,002 - - - 1,873 45 Total Electric Transmission Operations 602,140 592,583 559,228 559,087 626,816 571,387 549,946 571,624 570,698 633,421 555,358 834,861 7,227,149 4647 Gas Transmission Operations48 856 Trans Mains Expense - - - - - - - 23,617 (1,337) - 300 - 22,580 49 859 Other Trans Ops Expense - - - - - - - - 7,039 - - - 7,039 50 Total Gas Transmission Operations - - - - - - - 23,617 5,702 - 300 - 29,619 5152 Gas Transmission Maintenance53 863 Trans Maint of Mains - - - - - 54 - - - - - - 54 54 Total Gas Transmission Maintenance - - - - - 54 - - - - - - 54 5556 Total Transmission Expenses 602,140 592,583 559,228 559,087 626,816 571,441 549,946 595,241 576,400 633,421 555,658 834,861 7,256,822

CHEYENNE LIGHT, FUEL AND POWER COMPANYOperation and Maintenance Expense by Month - Total Company






5758 Electric Distribution Operations59 580 Supervision 30,119 17,688 31,023 23,274 22,056 28,647 61,838 34,046 36,930 20,546 15,754 26,831 348,752 60 581 Load Dispatch 6,908 6,155 7,640 10,369 10,275 15,100 23,747 13,781 15,987 10,355 13,062 19,632 153,011 61 582 Station Equipment - - 3,019 1,669 99 - 1,542 1,081 7,644 175 2,513 3,828 21,570 62 583 Overhead Lines 49,798 89,750 8,918 26,038 11,918 7,071 12,764 27,129 22,433 14,712 2,435 1,369 274,335 63 584 Underground Lines 15,164 8,601 14,904 12,116 3,136 6,082 9,520 11,649 6,424 20,542 16,007 20,737 144,882 64 585 Street Lighting 399 - 912 449 2,843 2,396 2,351 1,443 1,490 2,046 2,946 1,072 18,347 65 586 Metering 15,466 6,176 15,723 19,133 14,179 27,586 45,163 38,068 34,893 28,471 27,646 39,616 312,120 66 587 Customer Installations 1,555 1,591 2,371 2,844 1,892 5,140 3,060 1,014 2,020 2,786 1,840 2,897 29,010 67 588 Miscellaneous 14,727 36,263 35,629 47,530 28,808 59,466 (18,811) 29,625 68,374 (10,007) 28,168 8,300 328,072 68 589 Rents - - - - - - - - 39,374 - - 110 39,484 69 Total Electric Distribution Operations 134,136 166,224 120,139 143,422 95,206 151,488 141,174 157,836 235,569 89,626 110,371 124,392 1,669,583 7071 Electric Distribution Maintenance72 590 Supervision 21,015 2,701 11,066 25,286 13,379 37,232 27,787 15,233 15,263 14,354 14,390 22,124 219,830 73 592 Station Equipment 3,979 (954) 435 36 6,685 1,605 274 2,247 1,761 4,142 20,210 74 593 Overhead Lines 101,146 22,089 37,820 38,460 24,438 27,024 22,725 30,283 48,686 35,944 68,007 126,899 583,521 75 594 Underground Lines 13,492 17,806 17,436 33,332 9,604 4,466 4,935 11,523 8,511 11,242 7,376 23,401 163,124 76 595 Transformers 12,480 25,873 13,093 12,875 30,638 20,202 14,058 4,468 3,580 2,983 1,996 6,675 148,921 77 596 Street Lighting 676 983 2,550 1,574 3,202 1,567 699 1,032 1,256 13,328 284 4,190 31,341 78 598 Miscellaneous (39) - - - - - - - 38 274 - - 273 79 Total Electric Distribution Maintenance 152,749 68,498 82,400 111,563 81,261 90,491 76,889 64,144 77,608 80,372 93,814 187,431 1,167,220 8081 Total Electric Distribution Expenses 286,885 234,722 202,539 254,985 176,467 241,979 218,063 221,980 313,177 169,998 204,185 311,823 2,836,803 8283 Gas Distribution Operations84 870 Oper Suprv & Eng 63,094 7,063 41,030 59,993 37,928 40,438 60,046 40,483 44,147 38,403 20,830 55,715 509,170 85 874 Main & Service 115,227 62,148 42,417 63,168 20,492 79,052 140,616 32,895 35,809 182,893 61,016 100,050 935,783 86 875 M&R Station General 17,499 7,656 18,315 12,317 6,921 11,701 34,761 12,934 14,956 10,246 11,388 21,413 180,107 87 877 M&R Station City Gate 18,011 - - - - - - 527 - (527) - - 18,011 88 878 Meter & House Reg 19,564 29,139 47,766 72,960 50,650 21,293 37,741 31,750 33,016 13,461 4,473 5,154 366,967 89 879 Cust Inst Gratuitous/Non-Gratuitous 45,538 20,806 117,337 82,438 91,147 43,774 37,413 51,251 28,705 29,107 23,533 37,879 608,928 90 880 Other Expenses 15,915 55,735 37,374 44,875 (10,217) 42,695 (41,939) 23,188 29,853 (12,239) 4,452 (13,192) 176,500 91 Total Gas Distribution Operations 294,848 182,547 304,239 335,751 196,921 238,953 268,638 193,028 186,486 261,344 125,692 207,019 2,795,466 9293 Gas Distribution Maintenance94 885 Maint Suprv & Eng 22,618 5,687 14,769 23,471 12,223 11,997 18,013 10,199 8,883 8,387 9,161 18,890 164,298 95 887 Mains Maint (3,974) (214) 40 305 (1,520) - - 5,697 - - 7,282 21 7,637 96 888 Maintenance Compressor Station - 1,235 - - 58 - - 2 1,539 717 1,030 1,207 5,788 97 889 M&R Equipment General - - - - - - 4,739 88 364 - 3,054 - 8,245 98 890 M&R Equipment Industrial - - - - - - - - - - - - - 99 891 M&R Equipment City Gate - - - - - - - - - - - - -

100 892 Services Maint 24,297 1,623 7,873 8,630 6,124 12,226 18,860 22,083 15,893 6,733 8,906 15,081 148,329 101 893 Meter & House Reg Maint 73,249 (160,997) 15,212 2,569 553 1,374 4,504 2,573 (8,925) 4,652 (6,175) 459 (70,952) 102 894 Maintenance of Other Equipment - - 185 - - - - - 464 - - - 649 103 Total Gas Distribution Maintenance 116,190 (152,666) 38,079 34,975 17,438 25,597 46,116 40,642 18,218 20,489 23,258 35,658 263,994 104105 Total Gas Distribution Expense 411,038 29,881 342,318 370,726 214,359 264,550 314,754 233,670 204,704 281,833 148,950 242,677 3,059,460 106107 Customer Accounting Expense108 901 Supervision 20,503 11,675 26,952 36,101 19,460 22,399 40,593 25,244 19,692 28,687 35,507 39,996 326,809 109 902 Meter Reading 26,089 7,584 18,650 22,217 11,048 12,722 30,711 15,780 14,550 13,729 11,901 21,700 206,681 110 903 Customer Records and Collection 72,776 97,454 184,872 112,579 46,446 134,182 7,452 19,388 147,745 78,032 42,305 23,051 966,282 111 904 Uncollectible Accounts 29,592 - 30,000 20,000 21,000 19,000 10,000 5,000 34,746 13,504 13,021 13,566 209,429 112 905 Miscellaneous 22,492 10,020 10,038 14,665 18,808 17,534 26,758 17,988 26,110 18,975 15,937 30,958 230,283 113 Total Customer Accounting Expense 171,452 126,733 270,512 205,562 116,762 205,837 115,514 83,400 242,843 152,927 118,671 129,271 1,939,484





114115 Customer Service Expense116 907 Supervision 86,960 31,110 69,414 93,776 57,910 66,263 99,545 76,503 61,179 56,892 56,155 85,359 841,066 117 908 Customer Assistance 27,071 8,289 39,915 62,258 14,352 23,699 58,796 30,914 46,079 30,183 13,427 20,457 375,440 118 909 Advertisement - - 1,067 - 480 959 982 1,781 2,555 2,819 406 681 11,730 119 910 Miscellaneous Customer Service 262 - - - 35 - 4 - 922 125 95 334 1,777 120 Total Customer Service Expense 114,293 39,399 110,396 156,034 72,777 90,921 159,327 109,198 110,735 90,019 70,083 106,831 1,230,013 121122 Sales Expense:123 912 Demonstrating and Selling 53 297 - - - - - - 296 94 3 378 1,121 124 Total Sales Expense 53 297 - - - - - - 296 94 3 378 1,121 125126 Total Customer Expenses 285,798 166,429 380,908 361,596 189,539 296,758 274,841 192,598 353,874 243,040 188,757 236,480 3,170,618 127128 Administrative & General Expense129 920 Administrative Salaries 516,821 582,433 182,132 426,576 637,860 692,840 528,683 467,500 153,644 563,079 449,923 395,655 5,597,146 130 921 Office Supplies & Expense 119,508 81,173 99,804 98,826 96,596 88,011 69,609 97,588 172,983 127,991 103,797 117,740 1,273,626 131 922 Administrative Expenses (708) (292) (381) (1,455) (323) (660) (692) (196) (485) (556) (362) (5,322) (11,432) 132 923 Outside Services 131,379 21,341 86,990 146,080 42,062 99,052 (382) 106,856 108,176 72,656 127,820 38,802 980,832 133 924 Property Insurance 21,082 21,481 14,326 38,770 18,989 18,989 18,989 18,989 18,989 18,989 20,229 20,229 250,051 134 925 Injuries and Damages 47,038 44,459 61,095 70,058 53,306 41,931 40,628 57,463 70,783 43,373 51,746 45,228 627,108 135 926 Pensions & Benefits (193,675) 65,851 (27,108) (498,935) 161,132 (25,158) 19,079 54,974 (2,322) 8,585 69,549 (9,752) (377,780) 136 928 Regulatory Commission 40,551 40,551 40,551 40,551 32,015 32,015 32,015 32,015 32,015 (71,609) 23,380 52,833 326,883 137 930.1 General Advertising 3,099 9,076 9,414 29,055 14,586 4,565 33,054 23,690 18,631 23,148 3,975 16,141 188,434 138 930.2 Miscellaneous General 47,027 12,769 35,692 31,198 34,071 22,497 58,286 23,354 27,809 (17,232) 18,164 11,030 304,665 139 931 Rents 15,781 19,856 12,308 13,961 13,528 10,937 10,997 12,439 15,044 11,103 19,759 11,773 167,486 140 935 Maintenance of General Plant 57,571 48,600 32,705 51,665 37,296 34,190 39,080 41,384 39,815 42,121 35,577 38,362 498,366 141 Total Administrative & General Expense 805,474 947,298 547,528 446,350 1,141,118 1,019,209 849,346 936,056 655,082 821,648 923,557 732,719 9,825,385 142143 Total Operating & Maintenance Expense 6,590,883$ 10,592,145$ 11,661,395$ 12,346,459$ 14,049,478$ 12,612,615$ 11,020,209$ 9,181,372$ 8,447,655$ 8,085,048$ 7,731,150$ 8,123,471$ 120,441,880$


(1) (2) (3) (4) Estimated Losses‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗ System

Line Energy Percent EnergyNo. Customer Class Sales of Input Amount Input‗‗‗‗ ‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗

MWh % MWh MWh1 CLF&P Retail2 Residential 261,717.340 4.5952 12,606 274,323 25.7%3 Commercial 47,727.881 4.5952 2,299 50,027 4.7%4 Secondary General 357,034.115 4.5952 17,197 374,231 35.0%5 Primary General 194,881.628 3.5952 7,267 202,149 18.9%6 Transmission General 161,336.322 (0) 161,336 15.1%7 Lighting Service 5,912.087 4.5952 285 6,197 0.6%8 Total CLF&P Retail 1,028,609.373 39,654 1,068,263 100.0%

Test Year Ended August 31, 2011Energy Related Units of Service



(1) (2) (3) (4) (5) (6) (7) Calculated Class Demand Allocated

System ‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗ Class System AllocatedLine Energy Average Annual Load Maximum Excess Excess DemandNo. Customer Class Input Demand Factor Demand Demand Demand Responsibility Percent‗‗‗‗ ‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗‗‗‗‗ ‗‗‗‗‗‗‗‗

1 MWh kW % kW kW kW kW2 Table 1 (1)/8.76 (2)/(3) (4)-(2) Note (b) (2)+(6)3 CLF&P Retail4 Residential 274,323 31,315 40.35 77,608 46,293 26,081 57,396 31.71%5 Commercial 50,027 5,711 37.46 15,246 9,535 5,372 11,083 6.12%6 Secondary General 374,231 42,720 52.37 81,573 38,853 21,889 64,608 35.69%7 Primary General 202,149 23,076 78.64 29,344 6,268 3,531 26,607 14.70%8 Transmission General 161,336 18,417 85.54 21,530 3,113 1,754 20,171 11.14%9 Lighting Service 6,197 707 48.28 1,464 757 426 1,133 0.63%

10 Total CLF&P Retail 1,068,263 121,946 226,765 104,819 59,053 180,998 100.00%1112 Peak: 181,000 kW13 July 18, 201114 16:00

Capacity Related Units of ServiceTest Year Ended August 31, 2011


Direct Testimony Mark Stege

Before the Public Service Commission of the State of Wyoming

In the Matter of the Application of Cheyenne Light, Fuel and Power Company

For an Increase in Electric Rates

Docket No. 20003-___-ER-11 Record No. __________

December 1, 2011

Table of Contents

I. Introduction And Background ............................................................................................. 1

II. Purpose Of Testimony ......................................................................................................... 2

III. Cheyenne Light Company Overview................................................................................... 2

IV. Description Of Cheyenne Light’s Electric Business ........................................................... 2

V. Customer Service ................................................................................................................. 5

VI. Capital Additions ................................................................................................................. 6

VII. Generation Resources .......................................................................................................... 9

VIII. Cheyenne Light’s Workforce............................................................................................. 10

IX. Rate Case Overview........................................................................................................... 11

X. Introduction Of Witnesses ................................................................................................. 12

I. INTRODUCTION AND BACKGROUND 1

2

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Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.

A. Mark Stege, 108 West 18th Street, Cheyenne, Wyoming, 82001.

Q. BY WHOM ARE YOU EMPLOYED AND IN WHAT CAPACITY?

A. I am the Vice President of Operations for Cheyenne Light, Fuel and Power Company

(“Cheyenne Light” or “Company”).

Q. FOR WHOM ARE YOU TESTIFYING ON BEHALF OF TODAY?

A. I am testifying on behalf of Cheyenne Light.

Q. PLEASE DESCRIBE YOUR EDUCATIONAL AND BUSINESS BACKGROUND.

A. I graduated from the University of Wyoming with a B.S. in Geology and from the

University of Northern Colorado with a B.S. in Accounting. I am a licensed certified

public accountant in the States of Wyoming and Kansas.

I joined Black Hills Corporation in 1995 as an internal auditor and held various auditing

and accounting positions within Black Hills Corporation (including Director of

Accounting, Generation Assets) until June of 2005 when I accepted the position of

Director of Customer Service with Cheyenne Light. I was promoted to General Manager

in March of 2007 and held that position until I was promoted to my current position of

Vice President – Operations in July 2008.

Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS VICE PRESIDENT OF

OPERATIONS FOR CHEYENNE LIGHT.

A. My role as Vice President of Operations is to provide vision, leadership and strategic

direction for all areas of Cheyenne Light’s business operations including both natural gas

and electric utility service.

1

II. PURPOSE OF TESTIMONY 1

2

3

4

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Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?

A. My testimony will 1) provide an overview of Cheyenne Light’s electric operations; 2)

discuss the driving issues underlying the requested increase; 3) discuss the Company’s

workforce; and 4) provide a brief overview of this Application. I will also introduce the

Company’s other witnesses.

III. CHEYENNE LIGHT COMPANY OVERVIEW 7

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Q. PLEASE GIVE A BASIC OVERVIEW OF CHEYENNE LIGHT’S BUSINESS

OPERATIONS.

A. Cheyenne Light is a subsidiary of Black Hills Corporation that serves approximately

39,630 electric customers and 34,600 natural gas customers in the city of Cheyenne,

Wyoming and portions of Laramie County. These areas make up more than 1,200 square

miles of certificated territory with approximately 85,000 residents. The Company has

approximately 79 current employees with 3 current open positions and is further

supported by its parent, Black Hills Corporation, and affiliates. Cheyenne Light operates

and maintains approximately 1088 miles of electric distribution and 25 miles of electric

transmission line. Cheyenne Light also operates and maintains approximately 29 miles

of high pressure gas transmission pipeline as classified by the Wyoming Department of

Transportation, and approximately 750 miles of distribution pipeline.

IV. DESCRIPTION OF CHEYENNE LIGHT’S ELECTRIC BUSINESS 20

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Q. WHAT IS INVOLVED IN PROVIDING UTILITY SERVICE?

A. Cheyenne Light provides electric service via a system of transmission lines, distribution

lines, substations and other infrastructure in place in its territory. Not only does utility

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service involve the necessary infrastructure, it also includes the commodity (electricity)

and related support services such as billing, customer service and operation and

maintenance. Some support services are provided by Cheyenne Light employees and

others are provided by affiliates of Cheyenne Light including Black Hills Service

Company, LLC (“Service Company”) and Black Hills Utility Holdings, Inc. (“Utility

Holdings”). All of these services are included in base rates. Likewise, an allowed return

on investment in the assets used to provide utility service is included in base rates.

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Q. PLEASE DESCRIBE THE COMPANY’S OPERATIONS.

A. Cheyenne Light’s electric division is primarily engaged in the generation, purchase,

distribution and sale of electricity in its service territory. In addition to its distribution

and transmission lines, it also has 6 substations. This system, along with the transmission

service from Western Area Power Administration (“Western”), delivered to customers

over one million MWh during the test year ending August 31, 2011 to serve

approximately 39,630 retail electric customers.

Q. IS THE COMPANY ANTICIPATING GROWTH IN ITS SERVICE

TERRITORY?

A. Yes. Cheyenne Light is expecting greater customer demand for electricity due to the

recent and expected growth in the Cheyenne area. The increased loads in the short term

are projected to reach up to 16 MW to serve the customers who have confirmed plans or

are already under construction in the Cheyenne Light territory.

Q. DOES THIS FUTURE GROWTH HAVE ANY IMPACT ON THIS RATE CASE?

A. Yes, future growth may impact this rate case. The projected future growth is set forth on

Exhibit KDW-3. If the amount of load that materializes prior to rates going into effect is

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different than the Company has forecasted for this rate case, the Company’s revenue

requirement will increase or decrease accordingly as explained in the testimony of Kyle

White.

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Q. WHAT IS TYPICALLY INVOLVED IN THE OPERATION AND

MAINTENANCE OF CHEYENNE LIGHT’S SYSTEM USED TO SERVE

ELECTRIC CUSTOMERS?

A. Cheyenne Light operates and maintains its electrical system to provide safe, reliable

service to our customers. Included in the operations and maintenance of this system is

transmission and distribution pole and line inspection, substation inspection mandated by

NERC, tree trimming, line recloser, and regulator inspections, and line transformer

inspections. The system is also analyzed from an engineering perspective to provide for

substation breaker, line recloser, and line fuse coordination and updated as a maintenance

operation.

In addition to its electrical system, Cheyenne Light must perform ongoing maintenance to

Wygen II, its coal fired power plant located near Gillette, Wyoming. Wygen II is

operated by Cheyenne Light affiliate, Black Hills Power, under an Operation and

Maintenance Services Agreement dated February 7, 2007. The costs incurred to operate

and maintain Cheyenne Light’s electrical system and generation assets are included in

this rate case.

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V. CUSTOMER SERVICE 1

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Q. WHAT EMPHASIS DOES CHEYENNE LIGHT PLACE ON CUSTOMER

SERVICE SATISFACTION LEVELS?

A. Customer service has been and remains a very high priority for Cheyenne Light, and for

all employees within the Cheyenne Light utility. Company and departmental goals

include a customer satisfaction component.

Cheyenne Light recently had the opportunity to enhance and expand its customer service

model. As a result of its conversion to a new customer information system that is now

common to the regulated utilities of Black Hills Corporation, Cheyenne Light is able to

provide call center customer service support 24 hours a day, seven days a week. In

addition, business process initiatives have been put into place to improve customer

service as well as efficiencies. For example, electronic bill presentment, a new and

improved interactive response system (IVR) and additional payment options have been

added to improve and make it easier for customers to do business with us.

Q. DOES CHEYENNE LIGHT CONSISTENTLY MEASURE CUSTOMER

SERVICE AND SATISFACTION LEVELS?

A. Yes. An important indicator of customer satisfaction is the number of formal complaints

filed with the Wyoming Public Service Commission (the “Commission”). Set forth

below is a summary of Cheyenne Light gas and electric customer contacts and formal

complaints made to the Commission for the years 2009, 2010 and year to date 2011.

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Customer Contacts and Formal Complaints-Wyoming Commission 1

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2009 2010 2011 YTD

Contacts 5 8 7

Formal Complaints 0 0 0

Given the scope of our utility operations and the reliance of our customers on our

services, we believe the low number of Commission contacts and formal Commission

complaints speak well of Cheyenne Light’s focus on customer service.

Q. HOW DOES CHEYENNE LIGHT DEMONSTRATE ITS COMMITMENT TO

THE COMMUNITIES AND CUSTOMERS IT SERVES?

A. As a community partner, Cheyenne Light remains active in numerous civic and

community events through economic development initiatives, financial contributions, and

the involvement of its dedicated employees. Cheyenne Light has been involved in a

broad range of projects to improve its local communities, including active involvement in

local United Way campaigns, home weatherization initiatives in coordination with local

social service agencies and many other community initiatives across our service territory.

VI. CAPITAL ADDITIONS 16

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Q. PLEASE DESCRIBE THE MAJOR CAPITAL ADDITIONS MADE TO THE

COMPANY’S ELECTRIC AND GENERATION SYSTEM THAT ARE

INCLUDED IN THIS RATE CASE.

A. In the years 2008 through August of 2011, since the last filed rate case, Cheyenne Light

has made capital additions to its electric system totaling approximately $40.9 million,

including capital improvements to Wygen II. The 2008 additions included 1) a new

feeder circuit from the newly added transformer bank at Crow Creek substation to East

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Business Park to support the additional load and provide reliability and 2) a new feeder

extension to the Saddle Ridge Housing development. The 2009 additions included 1) a

new feeder extension from the Crow Creek substation to the Sun Valley housing area, 2)

a feeder tie from the Saddle Ridge area to the East Business Park area for increased

reliability and 3) the decommissioning of the Snyder Substation which involved the

conversion of a 41 block area of the downtown business area from 4 kV to 13 kV to retire

out-dated equipment that had been in service prior to the 1940’s and was no longer

serviceable, as well as to provide reliability to the downtown business district. The 2010

capital expenditures included Cheyenne Light’s portion of costs related to the Advanced

Meter Infrastructure (AMI) installation and new feeders east and south out of the Skyline

substation for reliability and voltage support in east Cheyenne. The 2011 expenditures

included the East Business Park substation, distribution infrastructure at the SWAN

Ranch Development, and new distribution infrastructure at the North Range Business

Park.

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Q. DID CHEYENNE LIGHT RECEIVE GRANT MONEY FOR PART OF THE AMI

DEPLOYMENT?

A. Yes. In 2009, Cheyenne Light was awarded a grant from the Department of Energy

(“DOE”) of approximately $5 million in matching grant funds to install the smart grid

system, which includes the AMI meters and a Meter Data Management System

(“MDMS”).

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Q. WHAT WAS THE TOTAL AMOUNT RECEIVED FROM THE DOE GRANT

FOR THE SMART GRID SYSTEM?

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A. To date, Cheyenne Light has received approximately $3.3 million in DOE grant money.

These funds have been used primarily for the AMI meters which have been deployed.

Cheyenne Light anticipates future expenditures for the smart grid system, primarily for

the MDMS which will also qualify for the DOE grant.

Q. WHAT ELECTRIC CAPITAL EXPENDITURES DOES CHEYENNE LIGHT

HAVE BUDGETED FOR SEPTEMBER 2011 THROUGH JUNE 2012?

A. Cheyenne Light has budgeted capital expenditures of approximately $23.0 million

between September 1, 2011 through June 30, 2012. This includes approximately $4

million in generation facility upgrades, of which $2.4 million relates to environmental

upgrades. Transmission additions total approximately $5.9 million. Distribution

additions total approximately $11.3 million and include three new feeder additions out of

the East Business Park substation, a new feeder addition out of Skyline substation for

reliability, and new feeder expansions in the SWAN Development. In addition,

Cheyenne Light has purchased a spare transformer to be delivered in 2012 to reduce the

risk of reliability issues on its system. Without a spare transformer, Cheyenne Light

could face a lengthy lead time of six to nine months to procure a new replacement

transformer from a manufacturer, used replacement if available or the time needed to

have a failed unit rewound.

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VII. GENERATION RESOURCES 1

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Q. WHAT GENERATING RESOURCES DOES CHEYENNE LIGHT ROUTINELY

UTILIZE TO SERVE ITS ELECTRIC CUSTOMERS?

A. Cheyenne Light owns a coal-fired plant commonly referred to as Wygen II. Wygen II

has a net capacity of approximately 90 MW and was commercially available in 2008. In

addition to this owned generation, Cheyenne Light has two power purchase agreements

(PPA) with its non-regulated affiliate, Black Hills Wyoming, LLC. Under those PPAs,

Cheyenne Light purchases power from Wygen I, a coal-fired plant, and “CT2”, a natural

gas-fired combustion turbine. This purchased capacity accounts for approximately 100

MW – 60 MW from Wygen I and 40 MW from CT2. Wygen I, Wygen II and CT2 are

all located near Gillette, Wyoming. In addition to the CT2 and Wygen I PPA’s,

Cheyenne Light utilizes 15 MW of wind-generated power from Happy Jack Windpower,

LLC and 10 MW of wind-generated power from Silver Sage Windpower LLC,

unaffiliated renewable energy generators.

Q. DOES THE COMPANY’S GENERATION RESOURCE MIX INCLUDE ANY

COSTS SET FORTH IN THE NOVEMBER 1, 2011 CERTIFICATE FOR PUBLIC

CONVENIENCE AND NECESSITY (CPCN) FILING?

A. No, this rate case application does not include any costs attributable to the November 1,

2011 CPCN application or the new gas fired generation resources proposed in that

application.

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VIII. CHEYENNE LIGHT’S WORKFORCE 1

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Q. PLEASE DESCRIBE CHEYENNE LIGHT’S CURRENT WORKFORCE.

A. As stated above, Cheyenne Light currently employs 79 people with 3 current open

positions. In addition, employees of Service Company and Utility Holdings perform

specific functions for Cheyenne Light.

Q. DO YOU FORESEE ANY CHANGES TO CHEYENNE LIGHT’S WORKFORCE

IN THE NEAR TERM?

A. Yes. The average age of Cheyenne Light employees is 48.6 years. Over the next 5-7

years up to 28% of Cheyenne Light’s current workforce will reach the age of 62, which

has been the historical average age of retirement at Cheyenne Light and its parent, Black

Hills Corporation. In addition, Cheyenne Light may actually have a number of employee

retirements prior to age 62 as a result of the Company’s pension program, which applies

to approximately 28 gas and electric union employees. The pension program allows for

full retirement when an employee’s age plus years of service equal 95 or higher. If these

eligible employees do retire when eligible, Cheyenne Light’s workforce turnover will

actually be higher than anticipated, creating additional stresses to business operations.

Q. DOES THIS CAUSE ANY CONCERN?

A. Absolutely. Our people are our best assets. A talent shortage within our organization

impairs our ability to provide safe, reliable service to our customers. The impending

retirements are a concern not only from a headcount perspective, but from a knowledge

and experience standpoint. Over the next 5-7 years, 390 years of utility work experience

will be expected to retire from Cheyenne Light. As I stated earlier, that is 28% of our

current workforce, but represents 36% of total years of experience. Just within the critical

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role of line mechanics, we have two employees with a combined 43 years of experience

that could retire within 5 years. Cheyenne Light is at risk of losing invaluable

organizational knowledge and customer relationships. Many of our critical roles have up

to a 3 year time to full competence. It could be a full 3 years before an employee is able

to safely perform his/her duties unsupervised. Not having replacements ready for our

retiring employees could put Cheyenne Light at risk by placing undue strain on our

remaining employees who must train replacements as well as complete their own duties.

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Q. WHAT STEPS HAS THE COMPANY TAKEN TO ADDRESS THIS CONCERN?

A. As discussed in the testimony of Jennifer Landis, Cheyenne Light has been involved in a

strategic workforce planning process that evaluates workforce demographics, tenure,

experience and skill capabilities as well as industry trends and risks. As a result of this

process, the Company is currently seeking to add 1 additional line mechanic (included in

the revenue requirement of this electric rate case) and 1 additional gas technician

(included in the revenue requirement of the Company’s 2011 gas rate case) due to

impending retirements and additional business needs. These positions are in addition to

the 3 currently open positions. Through the strategic workforce planning process, the

Company will continue to evaluate and plan its workforce to provide safe and reliable

service to its customers.

IX. RATE CASE OVERVIEW 19

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Q. WHAT IS THE PRIMARY REASON FOR THIS RATE CASE?

A. This rate case is simply driven by the necessary capital additions, continued operations

and maintenance and increased costs of services necessary to provide safe, reliable

service to our customers.

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Q. WHAT IS THE REQUESTED AMOUNT OF THE INCREASE IN ELECTRIC

BASE RATES?

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A. Cheyenne Light is seeking to increase its electric base rates to recover $5,907,945 million

in additional annual revenues, which, as discussed in the testimony of Kyle White, could

be adjusted if the projected load increases or decreases prior to the date that rates go into

effect. This increase is calculated based on Cheyenne Light’s pro forma revenue

requirement using a test year of the twelve months ending August 31, 2011.

Q. WHEN WAS THE LAST RATE CASE FOR CHEYENNE LIGHT?

A. Cheyenne Light’s most recent electric rate case was filed almost 5 years ago in February,

2007.

X. INTRODUCTION OF WITNESSES 11

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Q. PLEASE INTRODUCE CHEYENNE LIGHT’S OTHER WITNESSES IN THIS

PROCEEDING.

A. The other witnesses providing written direct testimony and exhibits, and the subject

matter of each, are listed below:

Kyle D. White, Vice President of Resource Planning and Regulatory Affairs

Mr. White will discuss Cheyenne Light’s parent company, Black Hills Corporation, and

Cheyenne Light’s affiliate agreements, as well as the treatment of forecasted electric load

in this application.

Chris Kilpatrick, Director of Resource Planning and Rates

Mr. Kilpatrick supports and explains the Company’s revenue requirement model,

discusses the test year rate base and income statement, describes the appropriate

adjustments to the test year rate base, revenues and operating expenses, including any

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known and measurable or contracted for adjustments, and supports the requested revenue

increase.

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Charlie Gray, Senior Regulatory Analyst

Mr. Gray provides the proof of test year revenues and billing determinants for Cheyenne

Light.

David A. (Andy) Butcher, Director of Generation Dispatch and Power Marketing

Mr. Butcher will discuss the Generation Dispatch and Energy Management Agreement

between Cheyenne Light and Black Hills Power, Inc. In addition, he will explain the

proposed changes to the sale of surplus energy to Black Hills Power under that

agreement.

Laura Patterson, Director of Compensation and Benefits

Ms. Patterson will describe the compensation and benefits philosophy of the Company.

Jennifer Landis, Director of Organizational Development

Ms. Landis will provide information on the Company’s strategic workforce planning

process.

Brian Iverson, Vice President, Treasurer

Mr. Iverson’s testimony will certify the books and records of Cheyenne Light and the use

of Federal Energy Regulatory Commission (“FERC”) uniform system of accounts. In

addition, Mr. Iverson will discuss the corporate finance philosophy of Cheyenne Light,

the proposed capital structure, long term debt and cost of equity and debt financing

activity.

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Dr. William E. Avera, President of FINCAP, Inc. 1

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Dr. Avera presents his independent assessment of the fair and reasonable rate of return on

equity for the Company and the Company’s requested capital structure.

Q. DOES THIS CONCLUDE YOUR TESTIMONY?

A. Yes, it does.

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Direct Testimony and Exhibits Kyle D. White




Docket No.20003-____-ER-11

Record No. _______

December 1, 2011

Table of Contents

I. Introduction And Background ............................................................................................ 1

II. Purpose Of Testimony ........................................................................................................ 2

III. Black Hills Corporation Overview ..................................................................................... 2

IV. Black Hills Corporation Growth......................................................................................... 3

V. Cheyenne Light Future Growth .......................................................................................... 5

VI. Affiliate Agreements........................................................................................................... 6

EXHIBITS

Exhibit KDW – E1 Black Hills Corporation Organizational Chart Exhibit KDW – E2 Black Hills Corporation Subsidiary List Exhibit KDW – E3 Schedule of Potential Future Load Growth Exhibit KDW – E4 Shared Facilities Agreement Exhibit KDW – E5 Coal Supply Agreement

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I. INTRODUCTION AND BACKGROUND


A. Kyle D. White, 625 Ninth Street, P. O. Box 1400, Rapid City, South Dakota.


A. I am Vice President of Resource Planning and Regulatory Affairs for Black Hills

Corporation. My areas of responsibility include regulatory affairs and resource planning

for the regulated electric utility subsidiaries of Black Hills Corporation.


A. I am testifying on behalf of Cheyenne Light, Fuel and Power Company (“Cheyenne

Light” or “Company”).


A. I graduated with honors from the University of South Dakota in May of 1982 with a

Bachelor of Science degree in Business Administration, majoring in management. In

August of 1989 I graduated with a Masters degree in Business Administration, also from

the University of South Dakota. I have been employed by Black Hills in rate and

marketing related work since July of 1982 and have been in my present position since

February of 2011. In addition to on-the-job training, I have attended numerous seminars,

trade association meetings, and regulatory conferences covering a variety of utility-related

subjects.

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THIS COMMISSION?

A. Yes.

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II. PURPOSE OF TESTIMONY


A. My testimony will provide an overview of Black Hills Corporation’s subsidiary structure,

discuss how the projected future load growth in Cheyenne Light’s territory may impact the

Company’s revenue requirement and the impact of certain agreements that Cheyenne

Light has entered into with affiliates.

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III. BLACK HILLS CORPORATION OVERVIEW

Q. PLEASE GIVE A BASIC OVERVIEW OF BLACK HILLS CORPORATION’S

SUBSIDIARIES.

A. Black Hills Corporation is a diversified energy company that is headquartered in Rapid

City, South Dakota with a 128 year history. Black Hills Corporation operates as a

“holding company” under the Public Utility Holding Company Act of 2005. It operates

principally in the United States with two major business groups: 1) Utilities – which

deliver retail electric and natural gas service, and 2) Non-regulated Energy – which is

involved in various wholesale energy businesses.

Q. WHAT IS THE RELATIONSHIP BETWEEN BLACK HILLS CORPORATION

AND CHEYENNE LIGHT?

A. Cheyenne Light is a wholly-owned subsidiary of Black Hills Corporation. Cheyenne

Light is a component of Black Hills Corporation’s Utilities Business Segment. Attached

as Exhibit KDW-E1 is the organizational chart for Black Hills Corporation and its

subsidiaries. Attached as Exhibit KDW-E2 is the listing of subsidiaries and the

classification of those subsidiaries into the two major business groups - Utilities and Non-

regulated Energy.

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Q. WHAT OTHER UTILITIES ARE OWNED BY BLACK HILLS CORPORATION?

A. As shown on Exhibit KDW-E2, Cheyenne Light’s sister electric utilities include Black

Hills Power, which operates in western South Dakota, northeastern Wyoming and

southeastern Montana, and Black Hills/Colorado Electric Utility Company, which

operates in the Pueblo area of Colorado. In addition, Black Hills Corporation owns gas

utilities operating in Colorado, Nebraska, Iowa and Kansas.

Q. WHAT ARE THE COMPANIES INCLUDED IN THE NON-REGULATED

ENERGY GROUP OF BLACK HILLS CORPORATION?

A. Black Hills Corporation’s Non-regulated Energy businesses include: Wyodak Resources

Development Corporation, which is engaged in coal production and sales; Black Hills

Exploration and Production, Inc., which is engaged in oil and natural gas production;

Enserco Energy, Inc., which is engaged primarily in natural gas, coal, power and oil

marketing; and Black Hills Wyoming, LLC and its subsidiaries, which are engaged in

independent power production.

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IV. BLACK HILLS CORPORATION GROWTH

Q. PLEASE GIVE A GENERAL DESCRIPTION OF THE AQUILA, INC.

TRANSACTION.

A. Black Hills Corporation purchased the natural gas utility assets of Aquila, Inc. in

Nebraska, Kansas, Colorado and Iowa as well as the electric utility assets in Colorado on

July 14, 2008. The operating employees working for Aquila in those four states were

retained and have continued to operate the acquired assets.

Q. WHAT EFFECT DID THE AQUILA ASSET PURCHASE HAVE ON CHEYENNE

LIGHT CUSTOMERS?

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A. Due to significant planning and pre-acquisition efforts, the transition was seamless to both

customers at Black Hills Power and Cheyenne Light as well as the newly acquired

customers. Cheyenne Light continues to have a strong management team in place that is

responsible for its operational, customer service, and financial results.

The Aquila purchase has induced unification projects across the Utilities business group

that have provided benefits to Cheyenne Light customers. One of those benefits is

expanded customer service availability to Cheyenne Light customers which went into

effect in August 2009. The Aquila transaction also brought with it an opportunity to share

and deploy best practices in areas such as construction standards and materials, and

various operations and maintenance programs.

In addition to unification and best practice deployment, Cheyenne Light customers are

now served by a company that is part of a corporation that has increased its financial

strength. The Aquila purchase significantly reduced financial risks and contributed to

Black Hills Corporation maintaining its credit rating in the most turbulent credit market

this nation has experienced since the 1930s.

Q. DID SERVICES RECEIVED FROM BLACK HILLS CORPORATION OR ITS

SUBSIDIARIES CHANGE FOLLOWING THE AQUILA TRANSACTION?

A. Yes. Following the Aquila transaction, Cheyenne Light received services from Black

Hills Utility Holdings, Inc. (“Utility Holdings”) in addition to Black Hills Service

Company, LLC (“Service Company”). As discussed in the testimony of Chris Kilpatrick,

Cheyenne Light has entered into service agreements with each of these entities. Cost

allocation manuals explaining the methodology used to allocate costs between the various

subsidiaries are included as Exhibits CJK-E4 and CJK-E5 to Chris Kilpatrick’s testimony.

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V. CHEYENNE LIGHT FUTURE GROWTH

Q. IS CHEYENNE LIGHT EXPECTING FUTURE LOAD GROWTH?

A. Yes. As stated in the testimony of Mark Stege, Cheyenne Light is expecting up to 16 MW

of load growth prior to July 1, 2012.

Q. DOES THE EXPECTED LOAD GROWTH IMPACT THIS RATE CASE?

A. Yes, the expected load growth does impact this rate case. This load growth is currently

included as a pro forma adjustment to retail revenue. If this load growth materializes to

the extent that the Company has forecasted for this application, the revenue requirement

included in this rate case would remain the same. If the load growth materializes at either

a slower or faster rate than forecasted in this application, the revenue requirement will

increase or decrease accordingly.

Q. PLEASE PROVIDE DETAIL REGARDING THE FUTURE LOAD GROWTH.

A. As shown on Exhibit KDW-E3 and Schedule I-2, there are seven customers that the

Company is expecting to require service prior to July 1, 2012. This schedule sets forth the

assumptions that the Company currently has for load, load factor and confidence factor as

well as the base rate and projected revenue that the Company may recognize if this load

growth materializes. Primarily due to Cheyenne Light’s experience with past load

projections, as well as information received from each customer, the Company has utilized

a confidence factor and timing factor to reduce the projected revenue and expenses

associated with each customer. In a past proceeding, the Company included a forecasted

load projection in its revenue requirement that did not materialized to the degree projected.

By using a confidence factor and timing factor, the Company is attempting to predict the

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likelihood that this customer load will materialize and, if so, the accuracy of the load and

load factor assumptions.

If the loads associated with any given customer on Exhibit KDW-E3 have materialized or

are reasonably expected to materialize by the effective date of rates under this proceeding,

this Exhibit, including the confidence factor, timing factor, load and load factor, will be

updated and the revenue requirement model will reflect the updated revenue realized from

this load growth and its impact on this rate case. Where the load has not materialized by

the time rates under this proceeding are set, but the Company reasonably expects the load

to materialize by or shortly following the effective date of rates under this proceeding, the

Company will update this Exhibit, including the confidence factor, timing factor, load and

load factor, to reflect the most current information known at that date and update the

revenue requirement with those customer loads accordingly. Finally, where the load has

not materialized and is not expected to materialize by or shortly following the effective

date of rates under this proceeding, this Exhibit and the revenue requirement model will be

updated to remove the associated revenue and expenses.

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VI. AFFILIATE AGREEMENTS

Q. WHAT AFFILIATE AGREEMENTS IMPACT CHEYENNE LIGHT’S

REVENUES?

A. Cheyenne Light’s agreements with affiliates that have a material impact on its revenues

include two power purchase agreements, an agreement to share assets at a common

generation site, service agreements with holding companies and finally, a coal supply

agreement.

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Cheyenne Light has two power purchase agreements (PPA) with its non-regulated

affiliate, Black Hills Wyoming, LLC (“Black Hills Wyoming”). Under those PPA’s,

Cheyenne Light purchases power from Wygen I, a coal-fired plant and “CT2” a

combustion turbine.

In addition, Cheyenne Light has entered into a Shared Facilities Agreement dated August

5, 2009 with affiliate companies Black Hills Wyoming and Black Hills Power, Inc.

attached to this testimony as KDW-E4. The Shared Facilities Agreement is an agreement

amongst the entities owning generation at the Gillette Energy Complex (the “Complex”).

Cheyenne Light’s coal fired power plant, Wygen II, sits at the complex. The Shared

Facilities Agreement allows the parties to share the assets located at the Complex

necessary for their owned generation and also sets a fee structure for that use.

Historically, Cheyenne Light has received a net annual payment from Black Hills Power

and Black Hills Wyoming for the use of its assets at the Complex as a result of the Shared

Facilities Agreement.

Cheyenne Light has entered into service agreements with Service Company and Utility

Holdings. These agreements are attached to the testimony of Chris Kilpatrick as Exhibits

CJK-E2 and CJK-E3. Service Company provides support services, including

administrative and management, to all regulated and non-regulated business units of Black

Hills Corporation. Conversely, Utility Holdings provides services primarily related to

customer service, billing, engineering, transmission planning and information technology,

and provides those services only to the regulated business holdings of Black Hills

Corporation.

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Finally, Cheyenne Light has entered into a Coal Supply Agreement dated February 7,

2007 with Wyodak Resources Development Corporation (“Wyodak”), a non-regulated

affiliate, to provide coal to Wygen II. The Coal Supply Agreement is attached to this

testimony as Exhibit KDW-E5. The pricing for the Coal Supply Agreement is based on

what the Company refers to as ‘Statement R’ pricing because it has historically

corresponded to the Statement in the rate case application that details the coal price

calculation for coal purchased from the utility’s affiliate. Under this methodology,

Cheyenne Light’s coal costs are determined by calculating the amount that allows

Wyodak to recover its cost of service related to the coal sales to Cheyenne Light, plus a

return on investment. That return is the average interest rate for new, long-term A-rated

utility bonds issued during the calendar year for which the calculation is being made, plus

four hundred basis points. This is a utility type rate of return methodology. This

methodology has been presented and accepted by the Wyoming Public Service

Commission previously for both Black Hills Power and Cheyenne Light, including Docket

No. 20003-103-EP-09 (Cheyenne Light’s application to pass on its power cost adjustment

increase as contested by Frontier Oil). In addition, this pricing methodology has been

accepted by third parties with ownership interests at the Complex such as the City of

Gillette and Montana Dakota Utilities Co. This coal supply arrangement is beneficial to

Cheyenne Light for several reasons. Wygen II is a mine-mouth facility eliminating almost

all transportation costs, utilizes existing coal storage and has a coal conveyor shared with

Wygen III, a Black Hills Power majority owned coal fired power plant, to deliver coal

directly from the Wyodak Mine. In addition, the Coal Supply Agreement is a long term

supply agreement, providing coal to Wygen II for the life of the facility.

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Costs and revenue associated with the Shared Facilities Agreement, Black Hills Wyoming

PPA’s, service agreements and Coal Supply Agreement are included in Cheyenne Light’s

revenue requirement.

Q. HAS A STATEMENT R CALCULATION BEEN PREPARED FOR BLACK

HILLS POWER?

A. Yes, a forecast of the coal price for Cheyenne Light is provided as Statement R of the rate

application.

Q. WHAT IS THE FORECASTED COAL PRICE?

A. The forecasted coal price for 2012 is $16.05 per ton delivered to Wygen II. This amount

is higher than it has been in the recent past. The cause of this increase is due to a

combination of circumstances including longer coal conveyor distances resulting from the

location of the mining in relation to the site of generation and increased overburden. In

addition, increased operating costs such as drilling and blasting, equipment maintenance

and fuel are also contributing to this increase.

Q. ARE THERE ANY OTHER AFFILIATE ARRANGEMENTS THAT IMPACT

CHEYENNE LIGHT’S REVENUES?

A. Yes. While not exclusively amongst affiliates, Cheyenne Light recovers the costs of

supplying reactive power and voltage control services from Wygen II to the transmission

system owned and operated by Black Hills Power, Basin Electric Power Cooperative and

Powder River Energy Corporation commonly referred to as the Common Use System,

with which Wygen II is interconnected. Wygen II is interconnected to the Common Use

System pursuant to an interconnection agreement. Consistent with the terms of that

interconnection agreement, Cheyenne Light supplies reactive power to the Common Use

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System and is entitled to be compensated for that service by the Common Use System

transmission providers. Cheyenne Light’s reactive power revenue requirement is

calculated to reflect the portion of Wygen II’s fixed costs that are attributable to Wygen

II’s reactive power capability. This arrangement was filed with FERC on May 27, 2009 in

Docket No. ER09-1203-000 and approved June 29, 2009.


A. Yes, it does.

10

Exhibit KDW-E1

Black Hills Corporation Organizational Chart

Exhibit KDW-E2 Black Hills Corporation Subsidiary List

Black Hills Corporation Subsidiaries

Our subsidiaries are classified with two major business groups – Non-regulated Energy and Utilities.

Non-regulated Energy

Black Hills Non-regulated Holdings, LLC (“Black Hills Non-regulated Holdings”) Black Hills Electric Generation, LLC (“Black Hills Electric Generation”) Black Hills Exploration and Production, Inc. (“Black Hills Exploration &

Production”) Enserco Energy Inc. (“Enserco Energy”) Wyodak Resources Development Corp. (“Wyodak”)

Utilities Black Hills Power, Inc. (“Black Hills Power”) Black Hills Utility Holdings, Inc. (“Black Hills Utility Holdings”)

Black Hills/Colorado Electric Utility Company, LP (“Colorado Electric”) d/b/a Black Hills Energy

Black Hills/Colorado Gas Utility Company, LP (“Colorado Gas”) d/b/a Black Hills Energy

Black Hills/Iowa Gas Utility Company, LLC (“Iowa Gas”) d/b/a Black Hills Energy

Black Hills/Kansas Gas Utility Company, LLC (“Kansas Gas”) d/b/a Black Hills Energy

Black Hills/Nebraska Gas Utility Company, LLC (“Nebraska Gas”) d/b/a Black Hills Energy

Cheyenne Light, Fuel and Power Company ("Cheyenne Light, Fuel & Power" or “Cheyenne Light”)

http://www.enserco.com/

http://www.wyodak.com/

Pro Forma

Line Incremental

No. Revenue

1 Primary General Service - Customer A

2 Assumptions:

3 Load 4 MW

4 Load Factor 80%

5 Confidence Interval 90%

6 Base Rate:

7 Service & Facility 12 Bills 230.00 / Month 2,760$

8 High Load Factor Credit (15,768)

9 System Capacity 43,200 kW 17.15 / kW-Mo 740,880

10 Energy 25,228,800 kWh 0.03762 / kWh 949,107

11 1,676,979$

12

13 Primary General Service - Customer B

14 Assumptions:

15 Load 4 MW

16 Load Factor 60%


18 Base Rate:



21 Energy 14,716,800 kWh 0.03762 / kWh 553,646

22 1,132,646$

23

24 Primary General Service - Customer C

25 Assumptions:

26 Load 4

27 Load Factor 80%


29 Base Rate


31 High Load Factor Credit (14,016)$


33 Energy 22,425,600 kWh 0.03762 / kWh 843,651

34 1,490,955$

35

36 Subtotal Primary General Service 62,371,200 4,300,580

37

38 Secondary General Service - Customer A

39 Assumptions:

40 Load 1.5

41 Load Factor 70%


43 Base Rate

44 Service & Facility 12 Bills 16.00 / Month 192$


46 Energy 6,438,600 kWh 0.03968 / kWh 255,484

47 490,666$

48

Billing Units Current RateRate Schedule


Additional Load Growth - Electric


Load Assumptions/

pmh

Typewritten Text

Exhibit KDW-E3

pmh

Typewritten Text

Schedule I-2 Page 1 of 2

Schedule I-2

Page 2 of 2

Pro Forma

Line Incremental

No. RevenueBilling Units Current RateRate Schedule


Additional Load Growth - Electric


Load Assumptions/

49 Secondary General Service - Customer B

50 Assumptions:

51 Load 1.0

52 Load Factor 60%


54 Base Rate



57 Energy 3,679,200 kWh 0.03968 / kWh 145,991

58 302,843$

59

60 Secondary General Service - Customer C

61 Assumptions:

62 Load 0.5

63 Load Factor 80%


65 Base Rate


67 High Load Factor Credit (1,971)


69 Energy 3,153,600 kWh 0.03968 / kWh 125,135

70 224,066$

71

72 Secondary General Service - Customer D

73 Assumptions:

74 Load 0.50

75 Load Factor 70%


77 Base Rate



80 Energy 1,839,600 kWh 0.03968 / kWh 72,995

81 140,327$

82

83 Subtotal Secondary General Service 15,111,000 1,157,902

84

85 Grand Total 77,482,200 kWh 5,458,482$

pmh

Typewritten Text

Exhibit KDW-E4

pmh

Typewritten Text

Shared Facilities Agreement

pmh

Typewritten Text

pmh

Typewritten Text

pmh

Typewritten Text

pmh

Typewritten Text

COAL SUPPLY AGREEMENT

Dated February 7,2007

between

WYODAK RESOURCES DEVELOPMENTCORPORATION

and

CHEYENNE LIGHT, FUEL AND POWERCOMPANY

pmh

Typewritten Text

Exhibit KDW-E5

pmh

Typewritten Text

Coal Supply Agreement

pmh

Typewritten Text

pmh

Typewritten Text

pmh

Typewritten Text

pmh

Typewritten Text

2-7-07 (between Wyodak & CLFP)

pmh

Typewritten Text

TABLE OF CONTENTS

SECTION 1 TERM OF AGREEMENT.........................................................1

SECTION 2 REPRESENTATIONS OF SELLER.. .. .. .. .. . .. .. .. ...... .. .. .. .. .. .. .. .. .. .. ..1

SECTION 3 QUANTITIES OF COAL TO BE SOLD AN PURCHASED..............1

SECTION 4 PLACE OF DELIVERY AN SALE........................................ ....2

SECTION 5 QUALITY OF COAL. .......... ......... .......................... .......... ... ..2

SECTION 6 WEIGHING..... ...... ............ ............ .................. ................. ....4

SECTION 7 SAMPLING AND ANALYSIS. . ... . .. ...... . .. ...... . .. . .. . .................... .4

SECTION 8 DETERMINING COAL QUALITY.............................................4

SECTION 9 PURCHASE PRICE. . .. . .. . ..... . .. ...... . .. .... .......... ..... . .. . .. . .. . .... . .....4

SECTION 10 INOICES AN PAYMENTS............. ............................ ...... ....6

SECTION 11 NO RESTRICTION ON COAL RESERVES................... ............ ...6

SECTION 12 UNCONROLABLE FORCE.....................................................6

SECTION 13 INEMNIFICATION............................................................. 7

SECTION 14 NOTICES........................................................................... 7

SECTION 15 APLLICABLE LAW.... ...... . .. .... .. . .. ...... . .. . .. . ... .. . .. . ... . .. . .. . .. . ... .8

SECTION 16 AMENDMENT...................................................................8

SECTION 17 SUCCESSORS AND ASSIGNS...............................................8

SECTION 18 COMPLETE AGREEMENT..... .. . .. .... .. . ............ ..... . .. . .. . .. . .. . ....8

COAL SUPPLY AGREEMENT

COAL SUPPLY AGREEMENT ("this Agreement"), dated as of Februar 7, 2007 by andbetween WYODAK RESOURCES DEVELOPMENT CORP., a Delaware corporation("Seller"), and CHEYENNE LIGHT, FUEL AND POWER COMPANY, a Wyomingcorporation ("Buyer").

WHEREAS, Seller mines coal at a coal mine consisting of the existing Wyodak Mine(the "Mine") in Campbell County, Wyoming, pursuant to coal leases and coal propertiescontaining certain coal reserves (collectively, the "Coal Reserves");

WHEREAS, Buyer is constructing certain improvements which improvements wilconsist of a coal-fired steam electric generating facility having a name-plate rating ofapproximately 90 megawatts, known as Wygen #2 (the "Facility") located adjacent to the CoalReserves.

WHEREAS, the paries intend that Seller wil mine and deliver all of Buyer's coalrequirements for the Facility during the Term ofthis Agreement;

NOW, THEREFORE, Seller agrees to sell and deliver and Buyer agrees to accept andbuy coal, as hereinafter provided, upon the following terms and conditions:

SECTION 1. TERM OF AGREEMENT.

The term of this Agreement (the "Term") shall commence on the date hereof, and shallcontinue thr the life of the Facility or February 1st, 2057, uness terminated earlier pursuant tothe terms of this Agreement.

SECTION 2. REPRESENTATIONS OF SELLER

(a) Certain Representations. Waranties and Covenants of Seller. The source of the coalto be sold and purchased shall be the Coal Reserves. Seller represents and warants to Buyer that:

(1) The Coal Reserves contained approximately 285 milion tons of mineablecoal as of November 1 sI. 2006. Seller has sufficient uncommitted Coal Reserves to commitsufficient coal for the entire Term of this Agreement;

(2) Seller's title to the coal delivered to Buyer hereunder shall be good and

merchantable and its transfer lawful; such coal shall be free and clear of any lien or encumbrancecreated, or permitted to be created, by Seller, and Seller agrees to indemnify and hold Buyer freeand harless from any costs and expenses that Buyer might incur as a result of any such lien orencumbrance.

SECTION 3. QUANTITIES OF COAL TO BE SOLD AND PURCHASED.

(a) Seller agrees to sell and Buyer agrees to buy all of the coal which is necessary tofuel the Facility during the Term. Buyer may at any time increase or decrease the amount of thecoal to be delivered to the Facility at a rate necessar to properly fuel the Facility; provided,

however, that it is specifically understood and agreed that Buyer is not obligated to purchase anyminimum amount of coal from Seller. Without limiting the obligations herein, it is estimated thatthe maximum anual coal consumption of the Facility is 535,000 tons of coal which Sellerhereby agrees to dedicate to the Facility.

(b) If for any reason not constituting an uncontrollable force, as defined in Section

15, Seller fails to sell (or to make available for sale) to Buyer all the coal necessary to fuel theFacility during the Term, in accordance with the pricing, quality, and other terms ofthisAgreement, Buyer may, at its option, purchase coal necessary to fuel the Facility from suchalternative sources as the Buyer may select in its sole discretion (such coal, the "ReplacementCoal"); provided that, if the Buyer purchases such Replacement Coal, Seller shall reimburseBuyer for the difference between the costs incured by Buyer in connection with the purchase ofsuch Replacement Coal (which shall include, without limitation, costs of aranging for thepurchase, and the transporting and handling, of the Replacement Coal, and other costs associatedwith Buyer's use at the Facility of such Replacement Coal, if appropriate) and the costs thatwould have been otherwise incured in connection with the purchase, receipt and handling ofcoal delivered by the Seller pursuant to the terms of this Agreement.

(c) Buyer shall provide Seller with a written rollng 90-day forecast of estimated

quantities required prior to the 15th of each month. For example, on or before Januar 15, Buyershall provide a forecast for the months of Februar, March, and April, and on or before February15, Buyer shall provide a forecast for the months of March, April, and May. Seller shall invoiceBuyer based upon the forecast, and Seller shall make payment based upon the invoice, subject tosubsequent adjustment based upon actual quantities delivered, in accordance with the invoicingand payment provisions of Section 10 of this Agreement.

SECTION 4. PLACE OF DELIVERY AND SALE.

Delivery shall be made to Buyer at the diverter gates on the bottom of coal silo # 2, andcoal silo #3 also known as the Truck Load Out coal silo (the "Points of Delivery"). Title to thecoal delivered by Seller in fulfillment of its obligations under this Agreement, and all risk of lossthereupon shall pass to Buyer upon completion of weighing in accordance with Section 6 of thisAgreement. The Points of Delivery may be changed from time to time by mutual agreement ofthe paries. With respect to delays or interrption of deliveries caused by defects in delivery

systems not controlled by Seller, the obligation of seller shall be limited to providing promptnotice of, and request for repairs by the system owner/operator.

SECTION 5. QUALITY OF COAL.

The coal furnished hereunder shall be raw, ru-of-mine coal and substantially free ofmagnetic material and other foreign material impurities including, but not limited to, miningdebris, bone, slate, scrapped iron, steel, petroleum coke, earh, rock, pyrite, wood and blastingwire. The quality of coal delivered hereunder shall be determined from the coal samples takenby Seller pursuant to Section 7. Seller warants that the quality of coal as delivered shall bewithin the ranges as set forth below:

Coal Size-raw, pit run coal nominally sized to two-inch minus

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Proximate Analysis As Received Range (raw)

Moisture (%)Ash (%)Volatile Matter (%)Fixed Carbon (%)BTU per pound (as received)BTU per pound (MA)

24.00 to 34.004.00 to 10.00

28.09 to 36.9929.45 to 37.407400 to 8400 (Typical: 8000)

11100 to 12250

Ultimate Analysis

Carbon (%)Hydrogen (%)Nitrogen (%)Chlorine (%)Sulfur (%)Ibs.S02/MBTUAsh (%)Oxygen (dift (%)Moisture (%)

46.07 to 52.383.04 to 3.500.50 to 0.800.00 to 0.030.20 to 1.00 (Typical: 0.60)

0.51bs to 2.50 (Typical: 1.50)4.00 to 10.00

11.02 to 12.5424.00 to 34.00

Sulfur Forms

Pyritic Sulfur (%)Sulfate Sulfur (%)Organic Sulfur (%)

0.01 to 0.63

0.00 to 0.020.14 to 1.34

Fusion Temp. of Ash (degrees F) Reducing Oxidizing

2101/2180 2310/23902160/2180 2400/24302170/2205 2415/25002185/2215 2560/2630

Initial DeformationSoftening (H=W)Hemispherical (H=1/2W)Fluid

Notwthstanding the foregoing, if the Facility experiences significant performance or handlingdifficulties relative to coal quality, the paries shall cooperate in good faith to resolve suchdifficulties. Seller shall take all reasonable steps to meet any revised quality parameters mutuallyagreed upon, and wil promptly implement any other mutually accepted solution or parialsolution to such difficulties.

The Buyer's operator shall have the ability to blend coal from Silo #2 (Lower Seam Coal) asrequired to meet the air quality permit requirements, but shall utilize coal from Silo #3 ( UpperSeam Coal) as much as possible. Specifically, Buyer shall be limited to a maximum monthlyaverage of 50% Lower Seam CoaL.

For the puroses of this Agreement, "Lower Seam Coal" shall be defined as coal mined from thebottom 35% ofthe minable reserves, having a sulfer content between.20 and .55 percent."Upper Seam Coal" shall be defined as coal mined from the upper 65% of the minable reserves,having a sulfer content between .5 5 and 1.0 percent.

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SECTION 6. WEIGHING.

The weights of the coal delivered to Buyer shall be determined from weights taken byBuyer on Buyer's scales located at such places as the paries hereto may agree. The aggregateweights of such delivered coal shall be accepted as the quantity of coal delivered for whichinvoices are to be rendered and payments to be made. The accuracy of Buyer's scales shall beverified by a third pary monthly, and Seller shall have access to any and all calibration records,which shall be retained by Buyer for a minimum of thee years.

The percent weighted average of coal delivered from Silo #2 and Silo#3 will bedetermined based on a totalized value calculated by the Buyers control system.

SECTION 7. SAMPLING AND ANALYSIS.

Analysis of calorific value, ash, sulfu, moisture and, if requested by Buyer, ash softeningtemperatue, shall be made by Seller or at its direction for each day's deliveries of coaL. Analysisshall be performed in accordance with the latest methods approved by the American Society forTesting and Materials (ASTM) or such other methods as the paries may agree upon. Samplesshall be taken by Seller on a regular basis in accordance with ASTM standards utilizing samplingequipment provided by Seller. Seller shall, at Buyer's request, promptly provide Buyer with theresults of any analysis conducted pursuant to this Section 7 for coal in either Silo #2 or Silo #3.

SECTION 8. DETERMINING COAL QUALITY.

Within two business days after the end of each month, the weighted average coal qualitycontent, including BTU's per pound as received, percent Sulfu, and percent Ash of coaldelivered hereunder during such month shall be computed by Seller using the daily coaldelivered weight readings taken from the coal scales and control system silo 2 and 3 weightedaverages pursuant to Section 6 and from the analysis made by Seller from the daily compositecoal samples taken pursuant to Section 7. Seller shall, at Buyer's request, promptly provideBuyer with the results of Seller's computations made pursuant to this Section 8. For thepuroses of this section a "business day" shall be defined as Monday through Friday, with theexception of federal holidays.

SECTION 9. PURCHASE PRICE.

(a) The Purchase Price per ton of coal to be paid by Buyer to Seller for each ton ofcoal delivered under this Agreement, shall be in accordance with Statement R pricingmethodology, as defined herein, based upon the pro-rata tons sold under this Agreement ascompared to the tons mined by Seller on an anual basis, consistent with Seller's practices withrespect to sales to its other regulated affiliates.

"Statement R" pricing is the amount Buyer would pay that would allow Seller to earn anafter-tax rate ofretum on Seller's actual average per ton costs for coal sold under this Agreementthat is equal to the yield for Moody's A-Rated lO-Year Utility Bond Index during the calendaryear for which the calculation is being made, plus 400 basis points. Applicable costs for the

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puroses of computing Seller's average per ton costs include: direct mining costs, mobileequipment costs, overburden expense, processing costs (for on-site sales), other miningexpenses, administration and employment costs, governent impositions, employee fringebenefit costs, depreciation, depletion, and any other cost related to Seller's mining operations.Specifically excluded from this calculation are costs related to Seller's train load-out facility.

An example of the methodology utilized to determine Statement R pricing is attachedhereto as Exhibit A.

(b) Price Adjustment

(1) BTU Price Adjustment

The Purchase Price, as determined in Section 9(a) above, will be adjusted to reflect theactual, as received, weighted average calorific value of the coal delivered for the month, if suchvalue is less than 7400 Btu, based on the following formula:

CV adjustment = (C-7400) / 7400 Btu * P

Where CV equals the adjustment to the Base invoice price in dollars per ton (rounded to2 decimal places); where P equals the base price of the Base Coal applicable as determined inSection 9(a) above; and where C equals the weighted average (as received) Btus for the monthdelivered and sold as referenced in Section 4.

(An example of this calculation is included in Exhibit B)

(2) Sulfu Price Adjustment

If the weighted average sulfu dioxide ("S02") content of the coal delivered for themonth is greater than 2.50 lbs S02/MMBTU, the Purchase Price, as determined in Section 9(a)above, shall be further adjusted pursuant to the following formula:

SV = ((S02 - I.5Olbs S02/MMBTU)* C * E) / 1,000,000)*-1

Where SV equals the final invoice price adjustment concerning sulfu; where S02 equalsthe actual weighted average (as received) S02 content expressed to two decimal places oftheBase Coal delivered in such month; where C equals the weighted average (as received) BTUs perpound of the coal delivered in such month; where E equals the average price of S02 allowancesexpressed in $/ton of S02. The average price of S02 allowances are determined by the weightedaverage sum of the weekly S02 price indices published by Energy Argus (in either Air Daily,Coal Daily, or WeeklyPower Plays) during the calendar month of delivery.

(An example ofthis calculation is included in Exhibit B)

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SECTION 10. INVOICES AND PAYMENTS.

Seller shall invoice Buyer by delivering a hard copy invoice to Buyer by the fifthworking day of each month. The Purchase Price shall be based upon the Statement R valuesdetermined according to Seller's operations for the prior calendar year.

It is understood that some of the actual costs included in the Statement R calculationupon which the Purchase Price is based may not be known or determinable on the date bilingsare made for the coal for which such costs are incured. Retroactive adjustments and appropriatebilings and credit statements shall be made at such time that such costs become known anddeterminable, which is expected to occur by Januar 15th for the preceding calendar year. IfSeller fails to make an adjustment in bilings or notify Buyer in writing of the potential for anadjustment in bilings within two years from the date information is reasonably available toSeller to fully determine the actual amount of the adjustment, Seller shall be bared from makingthat adjustment. If Buyer fails to protest to Seller in writing within two years of a date wheninformation is reasonably available to Buyer to determine that an adjustment included in a bilingreceived prior to that date is incorrect, Buyer shall be bared from contesting that adjustmenteven if the adjustment was incorrect.

Buyer shall pay each invoice to Seller by the 20th day after receipt of each month. In theevent Buyer fails to pay the undisputed portion of any invoice when due, or in the event Sellerfails to issue an undisputed credit to Buyer in a timely maner, then Buyer or Seller, as the casemay be, shall pay interest on the undisputed amount until paid/credited at a per anum rate equalto the from time to time "prime rate" as published in The Wall Street J oumal plus two percent.

SECTION 11. NO RESTRICTION ON COAL RESERVES.

Except to the extent dedicated to Buyer herein, this Agreement shall not restrict Sellerfrom mining, sellng, using, committing, dedicating, mortgaging or encumbering in any manerthe Coal Reserves for any purose; provided, however, that no such sale, use, commitment,dedication, mortgage or encumbrance shall relieve, be construed to relieve, or operate as adefense to relieve the Seller of its obligations hereunder.

SECTION 12. UNCONTROLLABLE FORCE.

If, because of uncontrollable force, either par hereto is unable to cary out any par orall of its obligations under this Agreement, and if such pary promptly gives to the other paryhereof notice of such uncontrollable force, then the obligations of the pary giving such noticeshall be suspended to the extent made necessary by such uncontrollable force and during itscontinuance, provided the effect of such uncontrollable force is eliminated insofar as possiblewith all reasonable dispatch. The term "uncontrollable force" as used herein shall mean anycause beyond the control of the pary claiming such uncontrollable force and which, by theexercise of reasonable diligence, the pary is unable to overcome and shall include but not belimited to acts of God, acts of the public enemy, insurection, riot, strike, labor dispute, labor ormaterial shortage, fire, explosion, flood, breakdown of or damage to such par's plant,equipment or facilities, interrption of transportation, embargo, orders or injunctions of a federal,state or local court, agency or governental body having jurisdiction, acts of civil or militar

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authority, failure of equipment, or inability to obtain materials, supplies, or equipment fromothers because of similar causes. It shall be considered an uncontrollable force and shall relieveSeller from performing its obligations under this Agreement if valid state or federal legislation isenacted which prohibits the strip mining of the federal coal which has been leased by Seller.

SECTION 13. INDEMNIFICATION.

Each Pary shall indemnfy, defend and hold harless the other Pary and its successors,assigns, employees, contractors and agents from and against all damages, losses or expenses,claims or causes of action of every kind or character suffered or paid as a result of any and allclaims, demands, suits, penalties, causes of action, proceedings, judgments, administrative andjudicial orders and liabilities (including reasonable attorneys' fees incured in any litigation orotherwse), assessed, incured or sustained by or against such other pary and its successors,assigns, employees, contractors and agents with respect to or arising out of any breach by theindemnfying party of its waranties, representations, convenants or agreements hereunder,except to the extent that any such damages, losses or expenses, claims or causes of action are theresult of the gross negligence, wilful misconduct, or failure to comply with this Agreement bysuch indemnified pary.

SECTION 14. NOTICES.

(a) Unless otherwse expressly provided herein, all notices required to be given bythe provisions of this Agreement shall be deemed to be duly served if given in writing sent byUnited States mail, postage prepaid, or by telecopy or other electronic mail media and to theaddresses set forth below:

If to Seller:

Mailng Address:

Street Address:

Phone Number:Fax Number:

If to Buyer:

Mailing Address:

Street Address:

Wyodak Resources Development Corp.P.O. Box 1400Rapid City, SD 57709625 9th StreetRapid City, SD 57701Attn: Jim WiliamsVice President-General Manager(605) 721-1700(605) 721-2549

Cheyenne Light Fuel & PowerP.O. Box 1409Cheyenne, WY 820031301 West 24th StreetCheyenne, WY 82001Attn: Linn Evans

President-Retail Operations

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Phone Number:Fax Number:

(605) 721-1700(605) 721-2568

(b) A copy of all notices required to be given under this Section 17(a) shall also bedelivered to each Financing Pary pursuant to Section 20(b) hereof to the address to be providedby such Financing Pary.

SECTION 15. APPLICABLE LAW.

This Agreement shall be considered to have been entered into and shall be interpretedunder the laws of the State of Wyoming.

SECTION 16. AMENDMENT.

No provision of this Agreement may be amended, modified, supplemented or waivedexcept by an instruent in writing signed by Seller and Buyer.

SECTION 17. SUCCESSORS AND ASSIGNS.

(a) This Agreement and all the terms and provisions hereof shall be binding upon andinure to the benefit ofthe respective successors and assigns of the paries hereto.

(b) This Agreement and any interests, rights or obligations under this Agreement maynot be assigned by any par without the prior written consent ofthe other pary, which consentshall not be uneasonably withheld or delayed.

SECTION 18. COMPLETE AGREEMENT.

This Agreement constitutes the complete agreement of the paries.

IN WITNESS WHEREOF, the paries hereto have caused this Agreement to be dulyexecuted by their respective officers thereunto duly authorized as of the date first above written.

(Signature Page Follows)

-8-

WYODAK RESOURCES DEVELOPMENT CORP.

By ~;/~Attest: -M (7 ~

l n ~~CHEYENNE LIGHT, FUEL AND POWER COMPANY.

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EXHIBIT B

Exhibit BCoal Quality Adjustment Examples

Example 1 - Adjustment for Btu Content

Weighted average Btu delivered during the month was 7350 and the curent Statement Rpricing in effect for the said month was $ $7.90/ton - the price adjustment to be computed asfollows:

CV adjustment = (7350-7400)/7400*7.90

CV = ($0.05/ton) adjustment per ton to the base price of Base Coal, as determined inSection 9a above.

Example 2 - Adjustment for Sulfur Content

Weighted average S02 content delivered during the month was 2.55, the actual, asreceived, calorific value of the coal delivered for the month was 8,000, and the average monthlyS02 allowance in effect for the said month was $475.50/ton - the price adjustment to becomputed as follows:

SV adjustment = ((2.55-1.5) * 8000)*475.50) /1,000,000) *-1

SV = ($3.99/ton).

Anex D-l594510.2

Direct Testimony and Exhibits Christopher J. Kilpatrick




Docket No.20003-____-ER-11

Record No. _______

December 1, 2011

i

TABLE OF CONTENTS

I. Introduction & Qualifications.................................................................................... 1

II. Purpose Of Testimony .............................................................................................. 2

III. Revenue Requirement Model Overview ..................................................................... 2

IV. Rate Base ................................................................................................................ 5

V. Adjustments To The Operating Expenses ................................................................. 10

VI. Additional Changes To The Operating Expenses ....................................................... 15

VII. Cost Adjustment Clauses ........................................................................................ 18

VIII. Summary Of The Model ......................................................................................... 22

IX. Cost Allocations .................................................................................................... 23

X. Conclusion ............................................................................................................ 27

EXHIBITS

Exhibit CJK-E1..............................Power Cost Adjustment Example Calculations

Exhibit CJK-E2............................................Service Company Service Agreement

Exhibit CJK-E3.............................................. Utility Holdings Service Agreement

Exhibit CJK-E4.................... Cost Allocation Manual (CAM) – Service Company

Exhibit CJK-E5.......................Cost Allocation Manual (CAM) – Utility Holdings

ii

I. INTRODUCTION & QUALIFICATIONS 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22


A. My name is Christopher J. Kilpatrick, 625 Ninth Street, P.O. Box 1400, Rapid City,

South Dakota 57701.


A. I am currently employed as Director of Resource Planning and Rates for Black Hills

Corporation (“BHC”).

Q. FOR WHOM ARE YOU TESTIFYING ON BEHALF TODAY?


Light” or the “Company”).

Q: PLEASE DESCRIBE YOUR EDUCATIONAL AND BUSINESS BACKGROUND.

A. I am a graduate of Mount Marty College in Yankton, South Dakota, with a Bachelor of

Arts Degree in Accounting. I am a Certified Public Accountant (“CPA”), a member of

the American Institute of Certified Public Accountants and the South Dakota CPA

Society. My work experience includes working for two public accounting firms from

1994 through 1999. The first was Wohlenberg, Ritzman, and Co., located in Yankton,

South Dakota, and the second was Ketel Thorstenson, LLP, located in Rapid City, South

Dakota. I began my career with BHC in January 2000 in the internal audit department.

In August of 2003, I became the controller of Black Hills FiberCom until February 2005

when I accepted the position of Director of Accounting – Retail Operations. In August

2008, I was offered the position of Director of Rates. In 2011, I accepted an expanded

role and I am now responsible for both electric rates and resource planning.

1

Q. BRIEFLY DEFINE YOUR DUTIES AND RESPONSIBILITIES. 1

2

3

4

5

6

7

8

A. I am responsible for the resource planning and electric rates for Black Hills Corporation’s

electric utility subsidiaries. I review financial information and verify that the financial

reporting for each subsidiary is accurate and in accordance with the rules and regulations

of the Federal Energy Regulatory Commission (“FERC”). Additionally, I am responsible

for integrated resource planning for all the retail electric utility subsidiaries of BHC, which

include Black Hills Power, Inc. (“Black Hills Power”), Black Hills/Colorado Electric Utility

Company, LP (“Black Hills Energy”) and Cheyenne Light.


10

11

12

13

14

15

16

17

Q. WHAT IS THE PURPOSE OF YOUR DIRECT TESTIMONY?

A. The purpose of my testimony is to present and explain the Revenue Requirement Model

(the “Model”) that supports this rate case filing. The Model is presented in Volume 1 of

Cheyenne Light’s Application as Statements A through R, and supporting Schedules. In

my testimony, I describe the adjustments to certain utility costs, and I will support the

revenue requirement. In addition, I will describe the Company’s Cost Allocation

Manuals with Black Hills Service Company, LLC (“Service Company”) and Black Hills

Utility Holdings, Inc. (“Utility Holdings”).

III. REVENUE REQUIREMENT MODEL OVERVIEW 18

19

20

21

22

Q. PLEASE DESCRIBE YOUR ROLE IN PREPARING THE MODEL.

A. My role was to directly supervise the preparation of the per books and pro forma

information including the Statements, and supporting Schedules, in accordance with the

rules and regulations of the Public Service Commission of Wyoming (“Commission”).

2

Q. PLEASE DESCRIBE THE MODEL. 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

A. The Model develops Cheyenne Light’s revenue requirement and includes the calculation

of return on rate base. The Model develops the entire revenue requirement for Cheyenne

Light and it shows the revenue increase needed based on current rates as shown on

Statement M, column (d).

Q. WHAT HAS CHEYENNE LIGHT USED FOR A TEST YEAR IN THIS FILING?

A. Cheyenne Light is utilizing a twelve month test year based on historical data, ending

August 31, 2011 as adjusted with known and measurable adjustments.

Q. WHAT STATEMENTS HAVE YOU INCLUDED IN THIS FILING?

A. The following is a list of the Statements provided in the Application:

A. Balance Sheet

B. Income Statement

C. Statement of Retained Earnings

D. Utility Plant in Service

E. Accumulated Depreciation

F. Working Capital

G. Rate of Return

H. Operation and Maintenance Expense

I. Operating Revenues

J. Depreciation Expense

K. Income Taxes

L. Taxes Other Than Income

M. Overall Revenue Requirement

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N. Adjusted Revenue Requirement 1

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O. Adjusted Class Cost of Service

P. Power Cost Adjustment Calculation

Q. Description of Utility Operation

R. Purchases from Affiliated Companies

In front of each Statement is a summary overview of the information included.

Q. WHAT SCHEDULES HAVE BEEN INCLUDED IN THE FILING?

A. Schedules have been included, where applicable, to provide supporting documentation

and calculations for the Statements listed above.

Q. EXPLAIN HOW THE REVENUE REQUIREMENT WAS DEVELOPED.

A. The starting point to determine the revenue requirement is the per books financial

statements for the test year, kept and recorded in the normal course of business, in

compliance with FERC rules and regulations. Adjustments for known and measurable

items were then made to the per books financial statements to determine the pro forma

costs and revenue requirement.

Q. WHAT ADJUSTMENTS WILL BE MADE TO THE TEST YEAR?

A. Cheyenne Light is incorporating pro forma adjustments to the test year that are known

and measurable and relate to investments that will be used and useful prior to new rates

going into effect. Known and measurable adjustments to the per books financial

statements include: 1) additional rate base that will be used to serve customers at the time

the new rates go into effect; and 2) adjusting expenses for known increases.

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Q. PLEASE SUMMARIZE THE SIGNIFICANT ADJUSTMENTS THAT HAVE

BEEN MADE TO CHEYENNE LIGHT’S MODEL.

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A. Adjustments have been made for rate base in Statements D, E, and F and on Schedules

M-1 and M-2. Expense adjustments have been included in Statements H, J, K, and L.

Q. WHAT DATES DID THE COMPANY USE FOR PRO FORMA ADJUSTMENTS?

A. The Company used September 1, 2011 through June 30, 2012 for pro forma adjustments.

August 31, 2011 was the last day of the test year; therefore September 1, 2011 was the

first date of the pro forma period. The Company selected June 30, 2012 as the last day of

its pro forma adjustments based on the filing date of this rate case and the Wyoming

Public Service Commission’s ability to suspend rates under Wyoming Statute § 37-3-106.

The Company will update these pro forma adjustments to reflect the effective date of new

rates resulting from this proceeding.

IV. RATE BASE 13

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Q. PLEASE DESCRIBE RATE BASE.

A. Rate base is the value established by a regulatory authority, upon which a utility is

allowed to earn a specified rate of return as shown on Statement M. Rate base begins

with the amounts of all fixed asset accounts for Cheyenne Light as of August 31, 2011, as

shown on Statement D, Page 1, reduced by Accumulated Depreciation as shown on

Statement E, Page 1. Additional rate base is then added to reflect expected capital

additions from September 1, 2011 through the effective date of this rate case as shown on

Statement D, Page 2. Additional depreciation expense is also included, along with a

corresponding increase in accumulated depreciation, thereby decreasing rate base. Rate

base also includes a component of working capital as shown on Statement F. The final

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component of rate base is the other rate base reductions, such as deferred federal income

taxes as it relates to the timing difference of book depreciation and tax depreciation

expense. These amounts can be found on Schedules M-1 and M-2.

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A. WORKING CAPITAL 4

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Q. HOW WAS WORKING CAPITAL CALCULATED AND INCLUDED IN RATE

BASE?

A. Working Capital, as shown on Statement F, is comprised of four components. The first is

cash working capital as determined from a lead/lag study. The others are materials and

supplies and prepaid expenses using balances as of August 31, 2011, with known and

measurable adjustments. The final adjusted balance of $3,905,678, as shown on

Statement F, is included as part of rate base.

Q. DESCRIBE HOW THE CASH WORKING CAPITAL AMOUNT WAS

DETERMINED.

A. We prepared a per books and an as adjusted cash working capital (“CWC”) amount for

this rate case. The per books CWC is located on Schedule F-1 and the as adjusted CWC

is on Schedule F-3. The as adjusted CWC amount is used as a component of rate base.

The per books and as adjusted CWC amounts were determined by preparing a Lead/Lag

Study.

Q. HOW DOES A LEAD/LAG STUDY MEASURE THE AMOUNT OF CASH

REQUIRED FOR OPERATING EXPENSE?

A. A lead/lad study measures the difference between: (1) the time a service is rendered and

billed until the time revenues for that service are received (“lag”) and (2) the time that

services, materials, etc. are obtained/used and the time expenditures for those services are

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made (“lead”). The applicable lead period for each major category of expense is

compared to the revenue lag period. The difference between those periods, expressed in

days, multiplied by the average daily operating expense yields the amount of cash

working capital requirement.

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Q. HOW WAS THE EXPENSE LEAD DAYS CALCULATED ON SCHEDULE F-3?

A. The expense lead days were determined by compiling/analyzing a sample of the actual

data for the test year for each of the following categories:

• Payroll Expense

• Purchased Power and Transmission Expenses

• Purchased Fuel Expense

• Intercompany Payments Charges

• Taxes and Interest

• Other Operating and Maintenance Expense

The expense dollar days is a dollar amount calculated by taking the expense lead days

times the expenses for each expense category listed above. The expense lead days are the

actual days between when a service is received and when payment is made for those

services. To determine the expense lead days for each expense category, we reviewed a

sample of invoices paid from that category and determined the average number of days it

took to pay each of those invoices. The expense per day is calculated by taking the total

expense per category divided by the number of days in the year. Finally, that expense per

day for each category is multiplied by the expense lead days for that category to

determine the expense dollar days for each category. Line 24 of Schedule F-3 contains

the combined total of the expense dollar days and the combined total of the expense per

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day for all the expense categories. The total in column (d) was then divided by the total

in column (b), resulting in the expense lead days of 40.1 which is shown on line 27 of

Schedule F-3.

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Q. CAN YOU DESCRIBE HOW THE REVENUE LAG DAYS WERE

CALCULATED?

A. The midpoint of service for each revenue month during the test year was first determined

by dividing the total days of the year by 12 and then by 2. Then the amount of lag days

between when the meter is read and when the customer is billed was determined by using

the Company’s billing system and calculating that amount on a monthly basis. The

monthly results are then averaged to arrive at an annual average. Next, the average

number of days between billing and receipt of payment was determined. This was done

by using the Company’s billing system and calculating that amount on a monthly basis

and then averaging the monthly results to arrive at an annual average. Finally, the sum of

the results discussed above were added together to determine the total revenue lag days

of 36.

Q. WHAT WAS THE RESULT OF THE LEAD/LAG STUDY?

A. The results of the lead/lag study demonstrate that, in aggregate, customers have supplied

funds to the utility to pay for expenses prior to the utility paying for the same expenses.

As a result, a rate base reduction was included in the determination of total rate base.

Q. WHAT AMOUNT OF CASH WORKING CAPITAL WAS DETERMINED?

A. The final cash working capital adjusted balance developed from the lead/lag study is

($2,063,230). The adjusted balance of cash working capital is used as a component of

rate base.

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Q. EXPLAIN THE KNOWN AND MEASURABLE ADJUSTMENT MADE TO

MATERIALS AND SUPPLIES.

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A. A known and measurable adjustment has been made to materials and supplies for a spare

transformer that has been purchased and will be received in 2012. This is a spare

transformer for the system located in Cheyenne, WY. In case of a transformer failure, the

spare transformer will allow more timely restoration of service. Additional operational

details of the spare transformer are included in the testimony of Mark Stege.

B. OTHER RATE BASE REDUCTIONS 8

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Q. WHAT OTHER REDUCTIONS TO RATE BASE WERE MADE?

A. Deferred federal income taxes related primarily to accelerated depreciation, cash received

for customer deposits, advances for construction, and also pension related costs are

included as reductions to rate base, as shown on Statement A Page 3.

Q. ARE THESE OTHER REDUCTIONS TO RATE BASE CONSISTENT WITH

THE COMPANY’S LAST RATE CASE?

A. Yes, we used a consistent approach and accounts to reduce rate base.

Q. WHAT OTHER ADJUSTMENTS DID YOU MAKE TO REDUCE RATE BASE?

A. As shown on Statement E page 2, we also made an adjustment to reduce rate base for

additional accumulated depreciation expense. The adjustment increases accumulated

depreciation to reflect one half of the annual depreciation expense for the new assets

summarized on Statement D Page 2.

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Q. WERE PRO FORMA ADJUSTMENTS MADE TO OTHER RATE BASE

REDUCTIONS?

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A. Yes. Schedule M-1 provides for an adjustment that reflects current balances as of August

31, 2011 for the Deferred Income Tax Asset (190), Deferred Tax – Accelerated

Depreciation (282), and Deferred Income Tax Liability (283) accounts. Since these tax

accounts are normally updated on a quarterly basis, these amounts needed to be updated

to be in sync with the test year. Consistent with prior rate cases, an adjustment was been

made for deferred taxes related to the accelerated depreciation for the pro forma capital

additions to be placed in service prior to the effective date of the new rates resulting from

this rate case. The main difference from the last rate case is the 50% bonus depreciation

rates for 20 and 15 year tax assets that have been used in the calculation of this

adjustment as shown in Schedule M-2.

V. ADJUSTMENTS TO THE OPERATING EXPENSES 13

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Q. PLEASE DEFINE OPERATING EXPENSES.

A. Total operating expenses are costs incurred by the Company in order to supply electricity

to the customers of Cheyenne Light. In the development of the revenue requirement,

these operating costs are passed on to customers dollar for dollar; that is, without

Cheyenne Light earning any net income on those expenses. Expenses are reflected in the

following statements:

1) Statement H shows the operating and maintenance expenses using the detail cost

by FERC account.

2) Statement J is the calculation of depreciation expense.

3) Statement K shows the calculation of federal income tax expense.

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4) Statement L calculates taxes other than federal income taxes - such as federal

payroll taxes and property taxes.

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5) All these Statements are summarized on Statement M to show the per books and

the pro forma rate of return.

Q. PLEASE EXPLAIN THE ADJUSTMENTS FOR THE EXPENSES ON

STATEMENT H.

A. Several adjustments were made to the expense as shown on Statement H, columns (1) –

(11). Statement H starts with the per books information for the twelve months ending

August 31, 2011, by FERC account number. Each adjustment has a column on this page

and a supporting Schedule to show how the adjustment was determined.

Adjustment (b): The adjustment of $300,251 on Schedule H-1 represents the actual and

projected wage increases. These amounts are calculated using an average of union

negotiated wage increases and expected non-union wage increases, together with the

costs associated with open vacancies and additional employees needed for operations.

Refer to Laura Patterson’s testimony for further description of the compensation program

for Cheyenne Light employees and Jennifer Landis for the Strategic Workforce Planning.

Adjustment (c): Schedule H-2 represents the costs to provide retiree healthcare, the

pension plan expense based on the current actuarial report, medical costs for employees,

as well as, the Employer portion of the 401K and Profit Sharing Plans. These amounts

are compared to the test year expense and the difference is an increase to operating

expenses of $221,145.

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Adjustment (d): Schedule H-3 contains the corporate costs charged to Cheyenne Light

from Service Company for the twelve months ending August 31, 2011. The per books

amount is then updated for an increase of $446,495 to the operating expenses.

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Adjustment (e): Schedule H-4 contains the corporate costs charged to Cheyenne Light

from Utility Holdings for the twelve months ending August 31, 2011. The per books

amount is then updated for an increase of $342,756 to the operating expenses.

Adjustment (f): Schedule H-5 is a detailed listing of rate case expenses that are

expected to be incurred in this docket. The costs will be amortized into expenses over a

two year period with the unexpensed amount also included in rate base.

Adjustment (g): Schedule H-6 represents the removal of costs associated with

unallowable advertising.

Adjustment (h): Schedule H-7 provides for the pro forma adjustment for the price of

coal. This adjustment is based on the two year calendar average coal use by the Wygen II

plant. This average coal usage was used to determine the projected coal costs. The coal

price is based on Statement R pricing for 2012. This resulted in a $1,694,136 increase

from the test year. The testimony of Kyle White addresses the Statement R – Affiliate

Transaction coal pricing in further detail.

Adjustment (i): Schedule H-8 provides an adjustment for planned plant overhauls.

Cheyenne Light spends approximately $1,038,590 every six to eight years. Currently, the

next scheduled Wygen II major overhaul is in 2016. This adjustment is to expense a

portion of the plant overhaul cost each year based on the plant’s planned maintenance

cycle. The normalized overhaul expense and pro forma addition to expense is $129,824.

As set forth in the Application, Cheyenne Light is requesting approval to set up a major

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maintenance account that will meet the requirements of FASB 71 to establish a

regulatory liability. Basically, Wygen II will have an annual amount expensed and the

accounting offset will go to a regulatory liability. When the plant completes the major

maintenance, the actual costs will first be applied to the regulatory liability and then to

expense. When the actual costs are determined, this will become the basis for the next

regulatory liability to be incurred over the next eight years.

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Adjustment (j): Schedule H-9 provides for Cheyenne Light’s costs related to generation

dispatch and scheduling. These costs are in accordance with the Generation Dispatch and

Energy Agreement between Black Hills Power, Inc. and Cheyenne Light dated February

23, 2007 that has been filed with the Federal Energy Regulatory Commission. This

agreement allocates costs to the parties contracting for services based on total capacity of

each company. Based on the current Generation Dispatch and Scheduling budgeted

costs, the expense adjustment is $72,200.

Adjustment (k): Schedule H-10 shows Cheyenne Light’s pro forma adjustments for the

Gillette Energy Complex Shared Facilities Agreement based on 2011 budgeted expenses

and shared asset revenue requirements. Total 2011 expense budgets are provided along

with the calculation of Cheyenne Light’s share of these expenses based on pooled

expensed net capacity allocators. In addition, the revenue requirement calculation of the

shared assets owned by Cheyenne Light is provided with an adjustment for the spare

transformer in Gillette. These 2011 revenue and expense budget amounts are compared

to the per book amounts with the difference representing the adjustment. The testimony

of Kyle White provides further details regarding the Gillette Energy Complex Shared

Facilities Agreement.

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Adjustment (l): Schedule H-11 identifies the energy resource to be used to serve the

customer loads, shown on Exhibit KDW-E3 attached to the testimony of Kyle White and

Schedule I-2. The Company expects to update these assumptions to reflect the most

current information before the rates pursuant to this rate application are determined and

approved. The Model will be updated to incorporate this adjustment.

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With the load growth included in the Company’s revenue requirement as shown in

Schedule I-2, it is anticipated that the Black Hills Wyoming power purchase agreement

for 60 MW of capacity and associated energy from Wygen I generating facility (“BHW

PPA”) will be used to serve approximately 80% of the additional load and the remaining

20% will be served by market purchased power. The use of the Wygen I energy results

in a reduction to surplus energy sold to Black Hills Power by approximately $1,006,706

in accordance with the Generation Dispatch and Energy Management Agreement. This

amount is shown as a reduction to the revenue credit on Statement I page 1, line 6,

column (b). The 20% served by market purchased power represents approximately a

$503,634 increase in purchased power expenses. This amount is shown as an increase on

Statement H, line 24, column (l).

In addition, the capacity and energy rate escalations have been calculated in accordance

with the BHW PPA, as well as, the power purchase agreement that the Company

currently has in place with Black Hills Wyoming for “CT 2” a natural gas fired

combustion turbine and the resulting expense adjustment has been included in the pro

forma operating expense.

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VI. ADDITIONAL CHANGES TO THE OPERATING EXPENSES 1

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Q. WHAT ADDITIONAL ADJUSTMENTS DID YOU MAKE TO THE OPERATING

EXPENSES?

A. The depreciation expense was adjusted, as shown on Statement J, to account for the

capital additions that will be placed in service on or before the effective date of this rate

case. Depreciation rates established in the depreciation study completed in January 2007

were used to calculate the additional depreciation expense.

Q. HOW ARE THE DEPRECIATION, AMORTIZATION AND ACCRETION

ADJUSTMENTS CALCULATED ON STATEMENT J?

A. The depreciation adjustment is calculated by using the existing depreciation rates, as

determined by the last depreciation study, multiplied by the adjusted plant in service. In

addition to depreciation, the acquisition adjustment amortization and Asset Retirement

Obligation (ARO) accretion expenses are included. The adjusted expense is then

compared to the per books amount for the test year and the difference is recorded on

Statement M and N as the adjusted depreciation expense and an increase in accumulated

depreciation.

Q. HAS ANYTHING CHANGED ON STATEMENT J FROM THE LAST RATE

CASE?

A. Yes, line 19 for Other Utility Plant, represents common assets allocated from Service

Company and Utility Holdings. These companies hold common assets for the

corporation, such as computer networks, billing, and customer service systems and

software. These assets have been allocated in accordance with the Cost Allocation

Manuals.

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Q. IS THE COMPANY REQUESTING AN ADJUSTMENT REGARDING THE

AMORTIZATION EXPENSE RELATED TO THE PURCHASE OF CHEYENNE

LIGHT BY BLACK HILLS CORPORATION?

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A. Yes. In Section 11 of the Stipulation and Agreement filed October 18, 2007, between the

Company and the Office of Consumer Advocate of the Wyoming Public Service

Commission (“Stipulation”), which was approved by the Commission, the parties agreed

that an acquisition adjustment related to the purchase of Cheyenne Light by Black Hills

Corporation of $4,630,443 shall be included in rate base upon which Cheyenne Light

earns a return on the unamortized balance. It was further agreed in the Stipulation that

the acquisition adjustment would be amortized over thirty (30) years for regulatory

purposes beginning in 2008. Although the parties agreed in the Stipulation that for

purposes of the 2007 rate case, the annual expenses associated with the amortization will

not be recovered through rates, the parties further agreed that the issue of amortization

shall be further addressed in future cases. Accordingly, the Company is proposing that

the annual expense associated with this amortization be recovered through rates. See

Schedule D-3 for the calculation. Given the operating performance for the Company

over the past few years for customer service, reliability and community support, we

believe the inclusion of the amortization of the acquisition premium is appropriate.

Q. PLEASE EXPLAIN THE REMAINING CHANGES TO THE REVENUE

REQUIREMENT MODEL.

A. On Statement L, additional payroll taxes were calculated based on the known and

measurable adjustments described on Schedule H-1. The net payroll change was

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multiplied by the federal and state payroll tax rates to determine the adjustment of

$24,021 to payroll taxes as shown on Schedule L-1.

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Q. PLEASE EXPLAIN THE WYOMING FRANCHISE FEES.

A. The adjustment for the franchise fee is based on the pro-forma retail revenue adjustment

on Statement I Page 1 and the additional revenue requirement on Statement M multiplied

by the 1% franchise fee in accordance with Cheyenne Light’s franchise agreements

resulting in an additional cost of $95,764.

Q. HOW IS THE ADJUSTMENT FOR PROPERTY TAXES CALCULATED ON

STATEMENT L?

A. The adjustment for property taxes is calculated based on the new fixed asset additions, as

shown on Statement D Page 2 and multiplying the assessed value for the asset additions

by the effective blended tax ratio. The effective blended tax ratio was developed based

on projected tax levies for a normalized twelve month operating period. The total

property tax adjustment is $218,964 as shown on Schedule L-1.

Q. HOW IS THE FEDERAL INCOME TAX CALCULATED?

A. Federal income taxes are calculated based on the adjusted rate base amount on Statement

M and Statement G debt and equity ratios. The adjusted operating income before tax

amount found on Statement M, column (c), line 12 is then reduced by the adjusted

interest expense as provided on Schedule G-1. This taxable income is multiplied by the

federal income tax rate. This amount is adjusted for the interest expense annualization

adjustment found on Schedule K-1, line 15 for the adjusted federal income tax expense.

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Q. WHERE DO YOU GET THE PER BOOKS REVENUE ON STATEMENT I,

PAGE 2?

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A. The per books revenue is from the billing system for the customers of Cheyenne Light for

the test year ended August 31, 2011.

Q. WERE CHANGES MADE TO RETAIL REVENUE?

A. Yes. The testimony of Charles Gray discusses the residential customer forecast for the

test year. In addition, the revenue from rental of electric property is reduced to reflect the

Gillette Energy Complex Shared Facilities budget adjustment as shown on Schedule H-

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Q. ARE THERE ADDITIONAL CHANGES MADE TO RETAIL REVENUE

CURRENTLY INCLUDED IN THE REVENUE REQUIREMENT?

A. Yes. The testimony of Kyle White addresses the addition of projected electric service

load growth to revenue. Detailed assumptions for this additional electric service load

growth are provided on Schedule I-2 and Exhibit KDW-E3.

Q. EXPLAIN HOW STATEMENT N WAS PREPARED.

A. Statement N was prepared based on Cheyenne Light’s per book and pro forma

Statements and Schedules. Statement N shows the detailed calculations and overall

revenue requirement for the Model.

VII. COST ADJUSTMENT TARIFF 19

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Q. WHAT COST ADJUSTMENT CLAUSES ARE CURRENTLY IN EFFECT?

A. As Stipulated and Ordered for Docket No. 20003-90-ER-07 (Record No. 11070) the

Power Cost Adjustment (PCA) is the current cost adjustment tariff in effect. This cost

adjustment tariff applies to all rate schedules for all classes of services authorized by the

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Public Service Commission of Wyoming and to all customers taking service pursuant to

contract, rather than tariff, unless specifically exempted by order of the commission. The

PCA is calculated annually based on actual Delivered Power Costs for the previous

calendar year as compared to the base year Delivered Power Costs, and includes over-or-

under recovery from prior years’ adjustments through a Balancing Account.

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Q. IS CHEYENNE LIGHT PROPOSING ANY CHANGES TO ITS COST

ADJUSTMENT TARIFF?

A. Yes. Statement P establishes a new PCA base cost amount of $0.0433 per kWh,

determined by dividing the total adjusted retail delivered power costs by the adjusted

system energy sales. In addition, a revised sharing mechanism has been created to

address the risks and opportunities presented with the proposed change to the pricing of

the surplus energy sold to Black Hills Power under the Generation Dispatch and Energy

Management Agreement (also referred to as the Put). This revised sharing mechanism

will incent the Company to save power costs and allow customers to share in the first

dollar saved. Additional information regarding the proposed change to the Put pricing, is

provided in the testimony of David A. (Andy) Butcher. Finally, the revised PCA also

includes the anticipated sale of Renewable Energy Credits (RECs) from the Happy Jack

and Silver Sage Wind Farms. This revised PCA is pursuant to the innovative rate making

provisions of W.S. §37-2-121 and falls outside the requirements of Section 249 and 250.

Q. PLEASE DESCRIBE THE CHANGES IN THE SHARING MECHANISM AND

DEADBAND.

A. The proposed sharing mechanism provides for a reciprocal three tiered approach. More

specifically, the first tier will share power costs or savings 5% Cheyenne and 95%

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customer when power costs deviate less than +/- $2.5 million annually from base rates.

The second tier of power cost increase or savings between +/- $2.5 and $5 million

annually will be shared 10% Cheyenne Light and 90% customer. The third tier of power

cost increase or savings greater than +/- $5 million annually will be shared 15%

Cheyenne Light and 85% customer. A summary of this three tiered sharing mechanism is

provided below and example calculations are provided in Exhibit CJK-E1 to my

testimony. In addition, P.S.C. WYO No. 10 Electric Service Tariff Sheets Original Sheet

Nos. 42, 42A, and 42B have been updated to reflect this revised PCA.

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9 Power Cost Adjustment Sharing Mechanism Summary

Sharing Tier – Above or Below Base Customer Share Company Share Less than $2.5 million 95% 5% Over $2.5 million and up to $5 million 90% 10% Over $5 million 85% 15%

Consistent with this tiered sharing mechanism, the revised PCA eliminates the

symmetrical dead band.

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Q. WHY IS THE DEAD BAND ELIMINATED?

A By eliminating the dead band, customers share in the first dollar of any power cost

savings. By re-establishing the PCA base rate and changing the pricing of the surplus

energy with Black Hills Power, there are greater opportunities for future power cost

savings. Without the dead band and with the graduated sharing rates, Cheyenne Light is

incented to keep costs as low as possible.

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Q. HOW WILL SALES OF RECS BE ADDRESSED IN THE PCA? 1

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A. Revenue from the sales of renewable energy credits, less reasonable administration fees,

will be credited to the system delivered power costs. The administration fee represents

those costs incurred by the Company to track, market and sell renewable energy credits.

The sale of RECS is not currently addressed in the PCA since the Happy Jack and Silver

Sage Wind Farm power purchase agreements were executed subsequent to Cheyenne

Light’s last rate case in 2007. In addition, as of the last Cheyenne Light Power Cost

Adjustment filing on February 11, 2011, no RECs from Happy Jack or Silver Sage had

been sold. However, Cheyenne Light has been crediting the system delivered power

costs with the net revenues received from the Voluntary Renewable Energy Rider.

Q. HOW WILL THE PREVIOUS POWER COST ADJUSTMENT BE HANDLED

SINCE IT WILL NOT BE IN EFFECT FOR THE FULL TWELVE MONTHS

DURING 2012?

A. The only impact to the current PCA would be to prorate the dead band. For illustrative

purposes only and not representative of actual numbers, if new rates went into effect on

May 1, 2012, the $1,000,000 dead band would be prorated based on the historical

monthly sales volumes for January through April (335,000 average MWh’s) as compared

to the calendar year sales for the last three years (average 1,000,000 MWh’s). This

percentage (33.50%) would then be applied to the dead band and the result ($335,000)

would be the new dead band amount that would first be absorbed by the Company before

passing along any costs.

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Q. WHEN WOULD YOU FILE FOR THIS PARTIAL YEAR POWER COST

ADJUSTMENT?

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A. Cheyenne Light would plan to file for this partial year PCA under the normal filing

procedures as outlined in the tariff, or by February 15, 2013 for new rates effective April

1, 2013. This filing would only cover the costs under the previous PCA calculation. The

recovery of the costs will match the period of time the costs were incurred. The first

filing under the new PCA calculation, would happen approximately 45 days after the new

rates have been in effect for twelve months and the new PCA rate would go into effect 45

days after that filing.

VIII. SUMMARY OF THE MODEL 10

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Q. WHAT IS THE AMOUNT OF ADDITIONAL REVENUE REQUIRED BASED

ON THE MODEL?

A. The additional revenue amount needed, after the gross up for federal income tax, is

$5,907,945, as shown on Statement M.

Q. HAS THE COMPANY PREPARED A CLASS COST OF SERVICE STUDY?

A. Yes, as shown in Statement O, Cheyenne Light has developed a class cost of service

study. This has been developed consistent with the Company’s past rate case with

updates to the allocation factors. The capacity allocator (number 1) has been updated

based on the 2011 summer peak of 181 MW in July.

Q. DO YOU BELIEVE THIS IS THE BEST METHOD OF SPREADING THE

REVENUE REQUIREMENT BETWEEN CLASSES OF CUSTOMERS?

A. No, since we don’t have precise customer load data, I believe this is an estimate but not

the best answer. As stated in the testimony of Mark Stege, the Company anticipates that

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its smart grid system will be fully implemented prior to its next rate case application and

will provide the Company with improved information to complete a class cost of service

study.

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Q. HOW WILL THE REVENUE REQUIREMENT BE APPLIED TO THE RATE

CLASSES?

A. The additional revenue requirement is proposed to be applied as an across the board

increase to all rate classes, which is consistent with the last rate case.

IX. COST ALLOCATIONS 8

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Q. HOW ARE COMMON RATE BASE AND OPERATING EXPENSES

ALLOCATED BETWEEN THE GAS AND ELECTRIC BUSINESS?

A. Common rate base and operating expenses are allocated between the gas and electric

businesses based on the allocation factors and calculations described on Schedule A-1

and Schedule B-1. Six allocation factors are used to allocate common costs:

(a) Electric and Gas Revenues for the twelve months ending August 31, 2011

(b) Electric and Gas Employees as of August 31, 2011

(c) Gross Electric and Gas Plant in Service as of August 31, 2011

(d) Electric and Gas Customers as of August 31, 2011

(e) Blended Employees (b) and Customers (d)

(f) Blended Revenue (a), Employees (b), and Plant (c)

The blended electric/gas employees and customers factor percentage is the average of

factors (b) and (d). The blended electric/gas revenue, employees, and plant factor

percentage is the average of factors (a), (b), and (c).

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Q. WHAT OTHER COST ALLOCATIONS ARE INCLUDED IN THE RATE BASE

SET FORTH IN THIS TESTIMONY?

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A. Cheyenne Light obtains services from Black Hills Service Company and Black Hills

Utility Holdings. Services are obtained from Service Company through a Service

Agreement providing for support services. This avoids the duplication of these business

functions by each of the regulated and non-regulated business units of Black Hills

Corporation. By providing support services on a centralized basis, efficiencies are

created when compared to stand-alone business functions. Cheyenne Light also obtains

services primarily related to customer service, billing and information technology from

Utility Holdings through a Service Agreement. Cheyenne Light remains a separate

subsidiary of Black Hills Corporation and is not a subsidiary of Utility Holdings.

Q. ARE THESE SERVICES PROVIDED UNDER A WRITTEN AGREEMENT?

A, Yes, Cheyenne Light has Service Agreements with Service Company and Utility

Holdings. Both Service Company and Utility Holdings provide their services at cost to

Cheyenne Light and other Black Hills Corporation affiliates through direct charges and

indirect charges. Expenses for support services are charged to Cheyenne Light on a

monthly basis pursuant to the Service Agreements. A copy of the Service Company

Service Agreement is attached to my testimony as Exhibit CJK-E2. A copy of the Utility

Holdings Service Agreement is attached as Exhibit CJK-E3.

Q. DOES THE COST ALLOCATION MANUAL DESCRIBE THE

METHODOLOGIES USED FOR ALLOCATION?

A. Yes. The methodologies are described on pages 9-10 of the Service Company Cost

Allocation Manual (CAM) and pages 8-10 of the Utility Holdings CAM. The

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departments and services provided by Service Company and Utility Holdings are

different. The Service Company provides support services, including administrative and

management, to all regulated and non-regulated business units of Black Hills

Corporation. Conversely, Utility Holdings provides services primarily related to

customer service, billing, information technology, engineering and transmission planning

and provides those services only to the regulated business holdings of Black Hills

Corporation. In addition, Cheyenne Light does not receive services from every

department of the Service Company. A copy of the Service Company CAM is attached

as Exhibit CJK-E3. A copy of the Utility Holdings CAM is attached as Exhibit CJK-E4.

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Q. CAN YOU EXPLAIN THE DIFFERENCE BETWEEN DIRECT AND INDIRECT

CHARGES?

A. Yes. Direct charges are those costs specifically associated with providing support to an

identified subsidiary or group of identified subsidiaries. Indirect charges are those costs

that are not associated with an identified subsidiary, meaning they indirectly support all

subsidiaries or directly support the operation of the applicable service company. The

CAMs provide a more detailed explanation of the treatment of direct and indirect costs.

Q. HOW ARE THESE SERVICES BILLED TO BLACK HILLS CORPORATION’S

DIFFERENT SUBSIDIARIES?

A. The costs of services that can be directly assigned to a subsidiary are billed directly to

that business unit (the company that will be receiving the charges). This is true for all of

BHC’s subsidiaries. The indirect costs that are attributable to more than one business

unit are allocated based on a formula that is designed to result in fair and equitable

allocation of these costs. Indirect costs are allocated using one of several pre-defined

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allocation factors. All indirect costs of that department are then allocated using that

factor. When determining which allocation factor should be assigned to each cost center,

a factor was selected based on the specific cost driver of that department. For certain cost

centers, a specific cost driver may not be clearly identifiable or the driver may not be cost

efficient to compute on a continuing basis. In these instances, a three-pronged general

allocation factor is used, which is referred to as the blended ratio. In addition, some

departments utilize a “holding company blended ratio”. The difference between the

blended ratio and the holding company blended ratio is that the holding company blended

ratio allocates a percentage of costs to Utility Holdings.

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Q. DO THESE ALLOCATIONS OF INDIRECT COSTS RESULT IN A FAIR AND

EQUITABLE COST BEING BILLED TO CHEYENNE LIGHT?

A. Yes. The methods used by Service Company and Utility Holdings were established by

reviewing relevant cost factors and are consistent with industry practice in allocating

common costs. In addition, services that are identified to a specific project or company

are directly billed to that project or company. The combination of assigning direct costs

for identifiable expenses and allocation of indirect costs fairly and accurately represents

Cheyenne Light’s share of the costs of Service Company and Utility Holdings in the

provision of services to Cheyenne Light.

Q. ARE THERE ANY OTHER FACTORS AFFECTING THE COSTS CHARGED

BY EITHER THE SERVICE COMPANY OR UTILITY HOLDINGS?

A. Yes. The FERC and North American Electric Reliability Corporation (NERC)

requirements have increased the costs associated with the regulated reporting,

compliance, corporate governance, and outside services. Other factors that have and will

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continue to impact the costs of providing utility service include significant increases in

health care and other benefit costs. These costs continue to increase year to year and as

appropriate are directly charged or allocated to the affiliate receiving the benefit of the

services using the methodologies discussed above.

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Q. HAVE THE CAMS BEEN PROVIDED TO REGULATORY COMMISSIONS?

A. Yes. The Service Company CAM and the Utility Holdings CAM have been previously

provided to other Commissions in which Black Hills Corporation operates its regulated

utility businesses including this Commission with the Black Hills Power rate case filed in

2009.

Q. IS IT NORMAL PRACTICE FOR DIVERSIFIED UTILITIES TO USE CAMS

FOR COMMON BUSINESS COSTS?

A. Yes. The CAMs were designed to distribute support costs to subsidiaries.

X. CONCLUSION 13

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Q. DOES THE MODEL RESULT IN JUST AND REASONABLE REVENUE

REQUIREMENT?

A. Yes. The Model uses the per books financial statements for the test year ending August

31, 2011, which contains known and measurable adjustments. The effect is a straight-

forward application supporting the requested increase in base rates.


A. Yes, it does.

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Cheyenne Light Fuel and Power

Power Cost Adjustment Analysis

Line Example 1 Example 2

No.

1 Coal 9,000,000 9,000,000

2 Purchase Power 69,580,000 65,500,000

3 Transmission 7,000,000 10,000,000

4 Emission Allowances 12,000 250,000

5 System Delivered Power Costs 85,592,000 84,750,000

6 Sales for Resale (Included REC Sales) 33,000,000 48,211,636

7 Retail Delivered Power Cost 52,592,000 36,538,364

8 Annual Retail Energy Sales (kWh) 1,029,375,643 1,029,375,643

9 Energy Cost / kWh (Line 7/Line 8) 0.0511$ 0.0355$

10 Base Cost in Rate Case Filing 0.0433$ 0.0433$

11 Change from base (Line 9-Line 10) 0.0078$ (0.0078)$

12 Total Change (Line 8*Line 11) 8,029,130$ (8,029,130)$

13 Sharing Adjustment - Line 12 is > $0M and ≤ $2.5M - 5% CLFP: 95% Customer 2,375,000$ (2,375,000)$

14 Sharing Adjustment -Line 12 is > $2.5M and ≤ $5.0M - 10% CLFP: 90% Customer 2,250,000$ (2,250,000)$

15 Sharing Adjustment -Line 12 is > $5.0M - 15% CLFP: 85% Customer 2,574,761$ (2,574,761)$

16 Net Amont to (Refund)/Charge Customers (Line 13+Line14+Line 15) 7,199,761$ (7,199,761)$

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Exhibit CJK-E1 Power Cost Adjustment Example Calculations

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Exhibit CJK -E2 Service Company Service Agreement

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Exhibit CJK - E3 Utility Holdings Service Agreement

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Black Hills Service Company

Cost Allocation Manual

Effective Date: July 14, 2008

Amended: January 1, 2010

Amended: August 1, 2010

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Exhibit CJK-E4 Cost Allocation Manual (CAM) - Service Company

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Black Hills Service Company Cost Allocation Manual Table of Contents

1. Introduction 3

2. Service Company Organization 3

3. Direct and Indirect Costs 4

4. Transaction Coding 5

a. GLBU b. Operating Unit

c. Department

d. Account

e. Resources

f. Product

5. Timekeeping 8

6. Loadings 8 7. Allocation Factors 9

8. Changing Allocation Factors 9

9. Subsidiary Payments for Direct and Indirect Charges 10

10. Allocating Fixed Assets 10

Appendix 1 - BHSC Departments 12 Appendix 2 – Allocation Factors 17

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Introduction The purpose of this cost allocation manual is to document the allocation processes of Black Hills Service Company, from recording the original transaction through the allocation of costs to Black Hills Corporation subsidiaries. Various topics to be addressed include the organization of the Service Company, the recording of transactions, calculating and assigning allocation factors, and recording allocation transactions. Black Hills Service Company (the Service Company) was formed on December 30, 2004, and was fully implemented and operational as of January 1, 2006. The Service Company was formed as required by the Public Utility Holding Company Act of 1935, which was administered by the Securities and Exchange Commission (SEC). Service companies were required of all registered holding companies under this law. Service companies coordinate corporate support functions and distribute costs to registered holding company subsidiaries using pre-defined allocation methodologies that had to be approved by the SEC. Black Hills Corporation became a registered holding company at the end of 2004, and through a transition period and various amendments to the registered holding company filings, established the date of January 1, 2006 to fully implement the Service Company. In August of 2005, this law was repealed and replaced by the Public Utility Holding Company Act of 2005, which is administered by the Federal Energy Regulatory Commission (FERC). This new law was effective in February of 2006. Although certain administrative and reporting requirements changed as a result of the repeal, Black Hills Corporation did not change its implementation plan. The Service Company is a wholly owned subsidiary of Black Hills Corporation (the Holding Company), and is a separate legal entity. The majority of operations and all employees were transferred out of the Holding Company on the effective date of implementation. The only transactions that remain at the Holding Company are transactions pertaining to long-term debt and related deferred finance costs, corporate credit facility and related deferred finance costs, and the administration of money pool transactions for both the utility money pool and the non-utility money pool. In addition, as will be discussed in greater detail later, certain corporate costs are allocated directly to the Holding Company. The most notable of these types of costs are corporate development project costs.

Service Company Organization The Service Company is organized into operating departments based upon the services that those departments provide to Black Hills Corporation subsidiaries. A list of each department, as well as a brief description of the services they provide, is attached as Appendix 1.

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Direct Costs versus Indirect Costs A key issue in distributing Service Company costs is distinguishing between direct costs and indirect costs. The account coding will change depending on whether the cost is a direct or indirect cost. Below is a summary of each of these types of costs and examples of these costs. Direct costs are those costs that are specifically associated with an identified subsidiary or group of identified subsidiaries. This means that it is known exactly to which subsidiary or group of subsidiaries these costs relate. Here are some examples:

• A Payroll Processor is processing the payroll for Enserco. The labor costs incurred in processing payroll are specifically associated with an identified subsidiary. Therefore, this would be a direct cost.

• An Internal Auditor travels to Denver to complete audits for Enserco and Black Hills Exploration and Production. The time associated with completing the audits would be charged to each company based on the time worked for each specific company project. The travel expenses could either be coded to each company based on time worked or coded using a combination of spreading those charges equally and charging costs specifically to one of the companies each day worked. For example, one meal to Enserco, the next meal to BHEP, etc.

• The Human Resources department incurs costs to bring an employment candidate on-site to Gillette for an interview with Wyodak. These travel costs incurred in bringing the employee in for the interview are specifically associated with an identified subsidiary. Therefore, this would be a direct cost.

• A Help Desk technician orders a replacement computer monitor for an employee at Black Hills Power. This hardware cost incurred is specifically associated with an identified subsidiary. Therefore, this would be a direct cost.

Indirect costs are those costs that are not associated with an identified subsidiary. This means that the costs indirectly support all companies or directly support the operation of the Service Company. In other words, costs that would be directly charged to the Service Company using the definition and examples above would be classified as indirect costs. Here are some examples:

• A Payroll Processor attends training on year-end payroll updates. The labor costs incurred in attending this training are not specifically associated with an identified subsidiary. Therefore, this would be an indirect cost.

• The Internal Audit department is completing a BHC consolidated financial statement audit. Since all entities indirectly affect the financial statements of BHC consolidated, this charge would be considered an indirect cost.

• An Environmental representative wishes to take Paid-Time-Off (PTO). This charge can not be directly attributable to any specifically identified company; therefore, this charge would be considered an indirect cost.

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• A Help Desk technician orders a replacement computer monitor for an employee of the Service Company. This hardware cost incurred is specifically associated with the Service Company. Therefore, this would be an indirect cost.

It is important to consider two things when determining if a cost is a direct cost or an indirect cost: (1) Can the costs that are coded to a specific company or group of companies be substantiated; and (2) Can it be substantiated that a utility-based entity is not subsidizing the operations of non-utility based company with the time and expenses that have been charged to them. As can be seen from above, a certain level of judgment will be involved when deciding whether a particular cost should be directly charged or indirectly allocated. There are certain costs that will always be considered direct or indirect costs, no matter the circumstances. Below is a list of significant Service Company expenses that follow these rules: Always considered direct costs:

• Capitalized costs for non-BHSC projects (including capitalized labor) • Corporate development project costs • Retiree healthcare costs

Always considered indirect costs:

• PTO and Holiday labor (they are included as a component of overhead) • Corporate-wide bonuses and other similar methods of compensation that are

included as a component of overhead • Payroll taxes and 401(k) match expenses (they are included as components of

overhead) • Short or long-term disability expenses • Board of Directors’ fees and expenses • General Office rent • Depreciation • Directors’ and officers’ insurance • Investor relations expenses • Shareholder expenses • Intercompany interest expense and income

Transaction Coding

The Service Company uses an accounting software system to accumulate and distribute both direct costs and indirect costs. It is important to have costs properly classified as direct or indirect. Direct costs will be directly charged to the subsidiaries, while indirect costs will be allocated to the subsidiaries using pre-defined allocation factors. Below is a description of the coding.

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-- -- -- -- --

GLBU OpUnit Dept Acct Resource Product

General Ledger Business Unit (GLBU):

• Five (5) character numeric field. • The GLBU is used to identify the company that will be receiving the charges. • The GLBU is required on all accounting transactions. • The GLBU is auto-populated by default when the OpUnit is entered.

-- -- -- -- --


Operating Unit (OpUnit):

• Six (6) character numeric field. • The OpUnit field is used to identify the account code block as either a direct cost

or an indirect cost. • If the cost is a direct cost, the OpUnit field will be populated using the OpUnit

code for the company being directly charged. • If the cost is an indirect cost, the OpUnit field will be populated using the general

Service Company OpUnit 701600. Indirect costs also include costs directly related to the Service Company.

-- -- -- -- --


Department (Dept):

• Four (4) character numeric field. • The Dept field is used to identify where the cost(s) originated.

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• The Dept field is required on all income statement and capital transactions. • Every Dept is assigned to a GLBU.

-- -- -- -- --


Account (Acct) • Six (6) character numeric field. • The Account field is required on all accounting transactions. • All companies will use the same Chart of Accounts though some values will be

specific to certain companies.

-- -- -- -- --


Resource (PS Resc):

• Four (4) character numeric field. • A Resource is used to indentify types of costs. • The Resource field is required on all income statement and capital accounting

transactions.

-- -- -- -- --


Product (Prod):

• Three (3) character numeric field. • A Product code is used to identify business lines.

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Timekeeping All Service Company employees are required to complete a timesheet for each two week pay period. Timesheets of all employees must be approved by a supervisor. Employees must complete the code block, as previously discussed, for each time record. The timesheet will default the employees’ payroll department and resource. However, the employee is responsible for providing the remainder of the code block. Employees are encouraged to enter their time in one half hour increments, although they may use smaller increments if they so choose.

Loadings Certain benefits that are provided to employees become an inherent cost of labor. To account for these benefits and allow for them to be charged to the appropriate subsidiary, they become part of a loading rate that is added on to each payroll dollar. The loading rates are calculated at the beginning of the year based upon budgeted benefit expenses and budgeted labor and are reviewed monthly and updated as needed. These rates are loaded into the accounting system. Below is a list of components of the loading rates: General loadings:

• Compensated Absences: including PTO, Holiday, Jury duty, Funeral pay, United Way day and Annual Physical appointment.

• Payroll Taxes: including FICA, FUTA SUTA and city taxes • Employee Benefits: including health and medical, 401K match and fees,

Pension, Retiree healthcare and associated fees and Pension audit fees • Incentives: including Non-officer bonus plans, Restricted Stock and Stock Option

expense Supplemental loadings:

• Officer bonus plans • Long-term disability • Officer pension benefits

At the end of each month, loadings calculated on payroll using the loading rates must be true-ed up against actual employee benefit costs. The purpose for this true-up is due to the fact that the Service Company’s income statement must net to zero, meaning there can be no net income or net loss remaining at the Service Company. Loadings calculated on payroll are based on an estimated rate and budgeted benefits, so differences between actual benefits will be inherent to this process. The main reasons for the difference is the employee benefit costs differ from the budget payroll differs from budget or timing. After the difference is calculated and reviewed for reasonableness, it is recorded to a separate department, and indirectly allocated to Black Hills Corporation subsidiaries.

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Allocation Factors As previously stated, Service Company costs are either directly charged to a subsidiary, or indirectly allocated when the cost is not associated with a specific subsidiary. Indirect costs are allocated using one of several pre-defined allocation factors. Each department has been assigned one of these allocation factors. All indirect costs of that department are then allocated using that factor. When determining which allocation factor should be assigned to each cost center, a factor was selected based on the specific cost driver of that department. For instance, the expenses incurred by a Human Resources department are primarily related to their support of all company employees. In this example, the cost driver for the Human Resources department indirect costs is employees. Therefore, their indirect costs will be allocated based upon the Employee Ratio. For certain cost centers, a specific cost driver may not be clearly identifiable or the driver may not be cost efficient to compute on a continuing basis. In these instances, a three-pronged general allocation factor is used, which is referred to as the Blended Ratio. This ratio equally weights three different general ratios: Gross Margin, Asset Cost (limited to PP&E), and Payroll Dollars. These factors were chosen to be included in the Blended Ratio because they best allocate costs based on the diverse nature of BHC operations. In addition, some departments utilize a Holding Company Blended Ratio. The difference between the Blended Ratio and the Holding Company Blended Ratio is that the Holding Company Blended Ratio allocates a percentage of costs to BHC Holding Company. For example, the Corporate Governance department will allocate indirect costs using the Holding Company Blended Ratio because certain costs incurred, such as New York Stock Exchange fees and Board of Directors costs, relate to both the Holding Company and the subsidiary companies. One additional item to note is that health care costs are allocated differently due to the self-insurance pool. Black Hills Corporation has chosen to pool all health care costs and spread the risk amongst all subsidiaries equally. All medical costs of BHC are paid by the Service Company and allocated to subsidiaries based on employee counts. Appendix 2 includes a list of all allocation factors, including a brief description of the factor, the basis for the calculation of the factor, and the departments to which that factor has been assigned. Any asset factors and employee count factors are calculated as of period-end dates, while revenue and expense factors are calculated for twelve months ended as of period-end dates.

Changing Allocation Factors Allocation factors are set at the first of the year, based upon financial information from the prior year ending December 31st. Assets, utility assets, employee counts, and power generation capacity are based on values as of the previous period ending

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December 31st. Gross margin, utility gross margin, payroll dollars, and utility payroll dollars are based on values for the 12 months ended December 31st. Certain events may occur during the year that are deemed to be significant to Black Hills Corporation that will require corresponding adjustments made to the allocation factors. Examples of these types of events include acquisitions, divestitures, new generation, significant staffing changes or new, significant revenue streams. When these events occur, indirect allocation factors will be adjusted. When adjusting allocation factors, it is the policy of the Service Company to not recalculate all allocation factors. Rather, allocation factors will be adjusted with pro forma adjustments. For example, if an acquisition occurs during the middle of the year, pro forma values will be loaded. Asset values at the time of the acquisition would be used, as well as pro forma gross margin and payroll dollars for a 12 month period. It should be noted that estimations may be required, especially when significant additions or changes are expected as a result of the acquisition. It should also be noted that asset values, gross margin, and payroll dollars for the other companies will not be changed. However, the ratios will change because the base against which the ratios are calculated will change. Subsidiary companies would see decreased ratio values with acquisitions, and increased ratio values with divestitures. Changes will be effective as of the beginning of the month, and will apply to all transactions for the month. Any changes to indirect allocation factors are initiated by one member of the allocations staff and reviewed by the Financial Manager of the Service Company. Allocation factors loaded into the system are reviewed by someone other than who input the factors into the system.

Subsidiary Payment for Direct and Indirect Charges

It is the policy of the Service Company to insure payments are made by the subsidiary companies for direct and indirect charges. All payments for direct and indirect charges must be remitted to the Service Company by the end of the following month. Payment requests will be provided directly to the accounts payable departments of the subsidiary companies. The Service Company will monitor payments received during the month to insure that all subsidiary companies make payment in a timely manner.

Allocating Fixed Assets The Service Company maintains certain fixed assets that are used by and benefit multiple Black Hills Corporation subsidiaries. These fixed assets primarily consist of computer hardware and software that form the corporate-wide information technology network. Because these fixed assets support multiple Black Hills Corporation subsidiaries, they are allocated to the appropriate subsidiaries monthly as part of the

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month-end close process, along with the allocation of these assets’ accumulated depreciation. Allocated assets and accumulated depreciation are maintained in separate general ledger accounts at the subsidiary level so that they are not intermingled with regular subsidiary fixed assets, and for ease of reconciliation. The allocation factor used for fixed assets and accumulated depreciation is the Blended Ratio, except as otherwise noted. Depreciation expense is allocated using the same ratio as the asset.

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APPENDIX 1

BHSC DEPARTMENTS

Accounting Systems (4700) – Maintains the corporate wide accounting systems of Black Hills Corporation, most notably the general ledger and financial statement preparation systems. (Blended Ratio)

Accounts Payable (4701) – Processes payments to vendors and prepares 1099s and applicable documentation for the majority of Black Hills Corporation subsidiaries. (Blended Ratio)

Corporate Development (4702) – Facilitates the development of the corporate strategy, prepares strategic plans, and evaluates potential business opportunities. (HoldCo Blended Ratio)

Corporate Governance and Shareholder Services (4703) – Develops and enforces corporate governance policies and procedures in accordance with applicable laws and regulations. Provides oversight of compliance with Securities and Exchange Commission rules and regulations. Oversees the administrative duties to the Board of Directors. Provides various recordkeeping and administrative services related to shareholder services. Assists in the administration of equity-based compensation plans. (HoldCo Blended Ratio)

Tax (4704) – Prepares quarterly and annual tax provisions of all Black Hills Corporation subsidiaries. Maintains and reconciles all current and deferred income tax general ledger accounts. Prepares tax filings and ensures compliance with applicable laws and regulations. Oversees various tax planning projects. (Blended Ratio)

Credit and Risk (4705) – Provides risk management, risk evaluation, and risk analysis services. Provides support to the Executive Risk Committee. Evaluates contract risks. (Blended Ratio)

Legal - Corporate (4706) – Provides legal services related to labor and employment law, litigation, contracts, rates and regulation, Securities and Exchange Commission compliance, environmental matters, real estate and other legal matters. Oversees the hiring and administration of external counsel. Provides legal support to various corporate development projects. (Blended Ratio)

Environmental Services (4709) – Establishes policies and procedures for compliance with environmental laws and regulations. Researches emerging environmental issues and monitors compliance with environmental requirements. Oversees environmental clean-up projects. (Asset Ratio)

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Executive Management (4710) – Provides overall oversight of Black Hills Corporation subsidiaries. Provides the Board of Directors information for decision making purposes. (HoldCo Blended Ratio)

Safety (4711) – Develops and implements safety planning activities and provides employee safety education. Administers the corporate safety program. Assists with compliance with DOT, OSHA, and MSHA regulations. (Employee Ratio)

Finance and Treasury (4712) – Coordinates activities related to securities issuance, including maintaining relationships with financial institutions, cash management, debt compliance, investing activities and monitoring the capital markets. Oversees the administration of corporate pension and 401(k) plans. (HoldCo Blended Ratio)

Financial Reporting (4713) – Oversees the corporate consolidation of subsidiary financial statements. Prepares monthly internal financial reports for management. Prepares quarterly and annual financial reports to the Securities and Exchange Commission. Researches emerging accounting issues and assists with the compliance of new accounting rules and regulations. (HoldCo Blended Ratio)

Budget and Forecasting (4714) - Oversees the accumulation of subsidiary financial budgets and forecasts. Provides the consolidation of the corporate wide budget and forecast. Guides the preparation of strategic plans. (Blended Ratio)

General Accounting (4715) – Provides maintenance of accounting and financial reporting, researches emerging accounting issues, and assists in the compliance of all accounting rules and regulations. (Blended Ratio)

Accounting- Central Services (4716) – Maintains the accounting records for Black Hills Service Company and Black Hills Corporation. Provides oversight of Accounts Payable, Payroll, and Property Accounting departments. (Blended Ratio)

Accounting-Generation Services (4717) – Provides general ledger accounting to non-regulated generation facilities and accounting support to all generation facilities. (Generation Capacity Ratio)

Human Resources Corporate (4718) – Establishes and administers policies related to employment, compensation and benefits. Provides general HR support services. (Employee Ratio)

Human Resources Regulated (4720) – Administers policies related to employment, compensation and benefits for the regulated subsidiaries. Provides general HR support services to the regulated subsidiaries. (Employee Ratio)

Compensation and Benefits (4721) – Administers policies related to compensation and benefits. Oversees the self-insured medical benefits plans and provides support to the third party administrators of the plans. (Employee Ratio)

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Organization Development and Training (4722) – Provides technical and professional development training. Provides general HR support services. (Employee Ratio)

Insurance (4724) – Facilitates physical risk management strategies through the purchase and evaluation of various types of insurance coverage. Provides claims management services. (Blended Ratio)

Internal Audit (4725) – Reviews internal controls and procedures to ensure assets are safeguarded and transactions are properly authorized and recorded. Oversees the Sarbanes Oxley compliance efforts. (Blended Ratio)

Company Communications (4726) – Provides oversight to the corporate communications processes. Provides communications to investors and the financial community. Provides advertising and branding development for the companies within Black Hills Corporation. Responsible for media relations. Manages and tracks all contributions made on behalf of Black Hills and it subsidiaries, as well as Black Hills Corporation Foundation. Assists in the preparation of the annual report. (Blended Ratio)

Payroll (4727) – Processes payroll for all Black Hills Corporation subsidiaries including but not limited to time reporting, calculation of salaries and wages, payroll tax reporting and compliance reports. (Employee Ratio)

Power Delivery Management (4728) – Performs resource planning, power delivery management, strategic planning, and construction management for the corporation’s power generation assets. (Generation Capacity Ratio)

Property Accounting (4729) – Maintains the accounting records for property, plant and equipment for the majority of subsidiaries of the corporation. Assists in the compliance with regulatory accounting requirements as it relates to property. Prepares various operating and financial reporting for management. (Asset Ratio)

Records Management (4730) – Administers and maintains the records retention policies and procedures of the corporation. Manages and maintains the content management software. (Blended Ratio)

Supply Chain Management (4731) – Develops strategies and provides general oversight to Facilities, Contract Management, Strategic Sourcing, Fleet Services, Materials Management and Supplier Diversity departments. (Blended Ratio)

Contracts Management (4732) – Manages contracts, including drafting, negotiating and reviewing and interpreting contracts. (Blended Ratio)

Strategic Sourcing (4733) – Executes the procurement process including, purchasing activities, managing vendor relationships, and issue resolution and tracking and expediting orders. (Blended Ratio)

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Fleet Services (4734) – Manages fleet expense cards, fleet contracts, vehicle purchasing, replacement and disposal and licensing and registration. Manages vehicle maintenance schedules. (Blended Ratio)

Supplier Diversity (4735) – Develops new sources of supply for all types of products and services and promotes the inclusion of diverse suppliers into the supply chain bidding process. (Blended Ratio)

Facilities Management (4736) – Provides facility, construction, and real estate management services for corporate-wide facilities. Supports disaster recovery and business continuation planning. (Blended Ratio)

Utility Communications (4737) – Manage and create internal and external communications for the utility companies. Provides advertising and branding development for the utility companies within Black Hills Corporation. (Utility Blended Ratio)

Creative Services (4738) – Provides graphical support to internal and external communications, advertising and branding for the companies within Black Hills Corporation. Maintains logo standards. (Blended Ratio)

Federal Governmental Affairs (4739) – Monitors, reviews, and researches government legislation and acts as a liaison with legislators. Manages the company’s lobbying strategy. (Blended Ratio)

Regulatory Management (4740) - Manages all aspects of regulatory requirements and relationships. (Blended Ratio)

State Governmental Affairs (4741) – Monitors, reviews, and researches government legislation and acts as a liaison with legislators. Maintains relationships with local and state governmental bodies. (Blended Ratio)

Information Technology Administration (4742) – Provides guidance, governance, and strategic planning to the overall information technology operations. Provides liaison services between information technology departments and their business partners. (Blended Ratio)

Information Technology Business Applications Financial and HR Systems (4743) – Manages, maintains, and enhances the financial and human resource related business applications of the company. (Blended Ratio)

Information Technology Business Applications (4744) – Manages, maintains, and enhances business applications within the utility companies. (Utility Blended Ratio)

Information Technology Business Applications Web Service Support (4745) – Manages, maintains, and enhances the web-based service business applications of the company. (Blended Ratio)

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Information Technology Business Applications Wholesale and Enterprise Systems (4746) – Manages, maintains, and enhances the wholesale and enterprise-wide business applications of the company. (Blended Ratio)

Information Technology Infrastructure Services (4747) – Manages, maintains, and enhances data center operations, infrastructure servers, storage, system software, enterprise architecture, and corporate databases. (Blended Ratio)

Information Technology Communications (4748) – Manages and supports the data and voice communication needs for the company. Provides telecommunication expense management services. (Blended Ratio)

Information Technology User Services (4749) – Provides technology support services for the company, including field services, the help desk, and technology integration. (Blended Ratio)

Corporate Security (4750) – Manages and supports the systems that provide both information and physical security services for the company. (Blended Ratio)

Information Technology Compliance (4751) – Responsible for internal and external audit compliance, disaster recovery, change management and legal compliance related to technology. (Blended Ratio)

Materials Management (4752) – Manages inventory, obsolescence and scrap. Ensure availability of proper materials. Pull, restock and stage materials. (Blended Ratio)

Process Improvement (4753) - Helps identify solutions to improve work processes, maximize business performance and add value for customers and stakeholders. (Blended Ratio)

Generation Plant Operations (4754) – Operates and manages the new generation for BHCOE and BHCIPP. (Nameplate Generation Ratio)

Asset Blended (4793) – Records depreciation for the Service Company assets. (Blended Ratio)

Benefits Pooled (4794) – Records those benefit costs, primarily related to health and welfare, for all companies to be pooled and allocated to subsidiaries. (Employee Ratio)

Accounting Accruals (4795) – Records accrual of certain charges not related to specific departments or not significant enough to allocate to each department. (Blended Ratio)

Benefits Loading (4796) - Records overhead benefit costs loaded to labor costs (Blended Ratio)

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APPENDIX 2

ALLOCATION FACTORS Asset Cost Ratio – Based on the total cost of assets as of December 31 for the prior year, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. Assets are limited to property, plant, and equipment, and include construction or work in process. Assets are also reported at their FERC value, meaning that assets for the utility subsidiaries will not include any eliminations that are done to bring their FERC financial statements into compliance with GAAP. FERC requires that acquired fixed assets be recorded at their gross value with accumulated depreciation, while GAAP requires that acquired fixed assets be recorded at their net value. An elimination journal entry is used to eliminate the gross-up for preparation of GAAP financial statements, but this elimination journal entry is not factored into the calculation of the Asset Cost Ratio.

The Environmental Services and Property Accounting departments utilize this ratio, and it is a component in both the Blended Ratio and the Holding Company Blended Ratio.

Gross Margin Ratio – Based on the total gross margin for the prior year ending December 31, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. Gross margin is defined as revenue less cost of sales. Certain intercompany transaction may be excluded from gross margin if they would not have occurred if the revenue relationship was with a third party instead of a related party.

No departments utilize this ratio, but it is a component in both the Blended Ratio and the Holding Company Blended Ratio.

Payroll Dollars Ratio – Based on the total payroll dollars for the prior year ending December 31, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. Payroll dollars include all bonuses and compensation paid to employees, but do not include items that are only included on an employee’s W-2 for gross-up and income tax purposes, such as life insurance premiums over $50,000.

No departments utilize this ratio, but it is a component in both the Blended Ratio and the Holding Company Blended Ratio.

Blended Ratio – A composite ratio comprised of an average of the Asset Cost Ratio, the Payroll Dollars Ratio, and the Gross Margin Ratio. These factors are equally weighted. This factor is sometimes referred to as the general allocation factor.

Departments that utilize this ratio include Accounting Systems, Accounts Payable, Tax, Credit and Risk, General Accounting, Insurance, Internal Audit, Legal, Company Communications, Records Management, Supply Chain Management, Contract

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Management, Strategic Sourcing, Fleet Services, Supplier Diversity, Facilities, Creative Services, Federal Governmental Affairs, Regulatory Management, State Governmental Affairs, Information Technology Administration, Information Technology Business Applications Wholesale and Enterprise, Information Technology Business Applications Web Service Support, Information Technology Business Applications Financial and HR Systems, Information Technology Infrastructure Services, Information Technology Communications, Information Technology User Services, Corporate Security, Information Technology Compliance, Materials Management, Process Improvement, Central Services, Budgeting & Forecasting, Assets Blended, Accounting Accruals, Benefits, Retiree and BHSC portion of the Rapid City Plant Street Facility and Bellevue Data Center Facility.

Holding Company Blended Ratio – 5% of costs allocated to the Holding Company, with the remaining 95% of costs allocated using a composite ratio comprised of an average of the Asset Cost Ratio, the Payroll Dollars Ratio, and the Gross Margin Ratio. These factors are equally weighted.

Departments that utilize this ratio include Corporate Development, Corporate Governance and Shareholder Services, Executive Management, Finance and Treasury and Financial Reporting.

In addition, a portion of directors and officer’s insurance expense incurred through the Insurance cost center will be direct charged to the BHC Holding Company.

Employee Ratio – Based on the number of employees at the end of the prior year ending December 31, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries.

Departments that utilize this ratio include Payroll, Safety, Human Resources Corp., Human Resources Regulated, Compensation and Benefits, Organization Development, and Payroll. Health and welfare costs for BHC will be in a pool and allocated to subsidiaries based on the Employee Ratio.

Power Generation Capacity Ratio – Based on the total power generation capacity at the end of the prior year ending December 31, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. Power generation includes capacity in service and capacity under construction.

Departments that use this ratio include Power Delivery Management and Accounting-Generation Services. Utility Asset Cost Ratio – Based on the total cost of utility assets as of December 31 for the prior year, the numerator of which is for an applicable BHC utility subsidiary and the denominator of which is for all applicable BHC utility subsidiaries. Utility assets are limited to property, plant, and equipment, and include construction or work in process. Assets are also reported at their FERC value, meaning that assets for the utility

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subsidiaries will not include any eliminations that are done to bring their FERC financial statements into compliance with GAAP. FERC requires that acquired fixed assets be recorded at their gross value with accumulated depreciation, while GAAP requires that acquired fixed assets be recorded at their net value. An elimination journal entry is used to eliminate the gross-up for preparation of GAAP financial statements, but this elimination journal entry is not factored into the calculation of the Utility Asset Cost Ratio. No departments utilize this ratio, but it is a component in the Utility Blended Ratio Utility Gross Margin Ratio – Based on the total utility gross margin for the prior year ending December 31, the numerator of which is for an applicable BHC utility subsidiary and the denominator of which is for all applicable BHC utility subsidiaries. Utility gross margin is defined as revenue less cost of sales. Certain intercompany transaction may be excluded from utility gross margin if they would not have occurred if the revenue relationship was with a third party instead of a related party. No departments utilize this ratio, but it is a component in the Utility Blended Ratio. Utility Payroll Dollars Ratio – Based on the total utility payroll dollars for the prior year ending December 31, the numerator of which is for an applicable BHC utility subsidiary and the denominator of which is for all applicable BHC utility subsidiaries. Utility payroll dollars include all bonuses and compensation paid to employees, but do not include items that are only included on an employee’s W-2 for gross-up and income tax purposes, such as life insurance premiums over $50,000. No departments utilize this ratio, but it is a component in the Utility Blended Ratio. Utility Blended Ratio – A composite ratio comprised of an average of the Utility Asset Cost Ratio, the Utility Payroll Dollars Ratio, and the Utility Gross Margin Ratio. These factors are equally weighted. The Utility Communications and IT Business Applications departments utilize this ratio. Nameplate Generation Capacity Ratio – Based on the total Colorado Airport Project power generation capacity at the end of the prior year ending December 31, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. Nameplate generation includes capacity in service and capacity under construction at the Colorado Airport Project. The Generation Plant Operations department utilizes this ratio. Square Footage Ratio – The total square footage of a given facility, the numerator of which is for an applicable BHC subsidiary and the denominator of which is for all applicable BHC subsidiaries. The Rapid City Plant Street Facility operating unit utilizes this ratio.

______________________________________________________________________________

Black Hills Utility Holdings, Inc.

Cost Allocation Manual ______________________________________________________________________________

Effective Date: July 14, 2008

Amended: August 1, 2009

Amended: January 1, 2011

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Exhibit CJK-E5

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Cost Allocation Manual (CAM) - Utility Holdings

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Black Hills Utility Holdings, Inc. Cost Allocation Manual

Table of Contents

1. Introduction 3

2. BHUH Organization 3

3. Direct Costs versus Indirect Costs 3

4. Transaction Coding 4

a. General Ledger Business Unit

b. Operating Unit

c. Department

d. FERC Account

e. Product

f. Resource

g. Work Order

5. Timekeeping 7

6. Loadings 7

7. Allocation Ratios 8

8. Changing Allocation Ratios 8

9. Subsidiary Payment for Direct and Indirect Charges 9

10. Allocating Fixed Assets 9

11. Allocating Capitalized Inventory 10

10. Appendix 1 – BHUH Departments 11

11. Appendix 2 – Allocation Ratios 18

3

Introduction

The purpose of this cost allocation manual is to document the allocation processes of Black Hills

Utility Holdings, Inc. (“BHUH”), from recording the original transaction through the allocation

of costs to entities receiving services from BHUH. Various topics to be addressed include the

organization of BHUH, the recording of transactions, calculating and assigning allocation ratios,

and recording allocation transactions.

BHUH began formal operations in July 2008. The company was formed in anticipation of the

purchase of certain gas and electric utility operating companies from Aquila, Inc. BHUH is a

wholly owned subsidiary of Black Hills Corporation (“BHC”). BHUH is the parent company of

each of the five acquired Aquila operating companies. In addition, BHUH also holds certain

departments that support the operations of the five acquired Aquila operating companies and

other utility operating companies (Black Hills Power, Inc., Cheyenne Light, Fuel & Power

Company), together the “operating companies”. These costs are allocated to the operating

companies requesting service using formal cost allocation methodologies. Departments that

provide support services to the five acquired Aquila operating companies as well as other Black

Hills Corporation subsidiaries are held at Black Hills Service Company, LLC (“BHSC”). BHSC

cost allocation methodologies are discussed in a separate cost allocation manual.

BHUH Organization

BHUH is organized into departments based upon the services that those departments provide to

the operating companies. A list of each department, as well as a brief description of the services

they provide, is attached hereto as Appendix 1.

Direct Costs versus Indirect Costs

A key issue in distributing BHUH costs is distinguishing between direct costs and indirect costs.

The account coding will change depending on whether the cost is a direct or indirect cost. Below

is a summary of each of these types of costs and examples of these costs.

Direct costs are those costs that are specifically associated with an identified operating company

or group of identified operating companies. This means that it is known exactly to which

operating company or group of operating companies these costs relate. Here are some examples:

Advertising is prepared for a new energy efficiency campaign in the state of Nebraska.

The advertising costs incurred are specifically associated with an identified operating

company. Therefore, this would be a direct cost.

The Vice President of Utilities attends a meeting on the proposed budget for the state of

Iowa. The labor costs incurred in attending this meeting are specifically associated with

an identified operating company. Therefore, this would be a direct cost.

A trainer from Gas Engineering travels to various Black Hills Kansas Gas field offices to

conduct training. These travel costs are specifically associated with an identified

operating company. Therefore, this would be a direct cost.

4

Indirect costs are those costs that are not associated with an identified operating company. This

means that the costs indirectly support all companies or directly support the operation of BHUH.

In other words, costs that would be directly charged to BHUH using the definition and examples

above would be classified as indirect costs. Here are some examples:

Advertising is prepared for all customers to inform them of changes to electronic

payment processes. These advertising costs incurred apply to all operating companies.

Therefore, this would be an indirect cost.

The Vice President of Utilities attends a meeting to present the consolidated budget for

all gas utilities to the Board of Directors. The labor costs incurred in attending this

meeting are not specifically associated with an identified operating company. Therefore,

this would be an indirect cost.

A trainer from Gas Engineering travels to Rapid City to present a training program to

operating company executives. These travel costs are specifically associated with

BHUH. Therefore, this would be an indirect cost.

It is important when determining if a cost is a direct cost or an indirect cost to consider two

things: (1) Can the costs coded to a specific operating company or group of operating companies

be substantiated, and (2) Can it be substantiated that a utility-based subsidiary is not subsidizing

the operations of a non-utility based subsidiary with the time and expenses that have been

charged to them. As can be seen from above, a certain level of judgment will be involved when

deciding whether a particular cost should be directly charged or indirectly allocated.

There are certain costs that will always be considered direct or indirect costs, no matter the

circumstances. Below is a list of significant BHUHC expenses that follow these rules:

Always considered direct costs:

Capitalized costs for non-BHUHC projects (including capitalized labor)

Retiree healthcare costs

Always considered indirect costs:

PTO (Paid Time Off) and Holiday labor (they are included as a component of overhead)

Bonuses and other similar methods of compensation that are included as a component of

overhead

Payroll taxes and 401(k) match expenses (they are included as components of overhead)

Short or long-term disability expenses

General office rent

Depreciation

Intercompany interest expense and income related to the BHUHC balance payable or

receivable from the Utility Money Pool

Transaction Coding

BHC utilizes the PeopleSoft software system. PeopleSoft provides a variety of fields to create

account coding logic, or code block. The account coding string consists of seven fields. It is

5

important to understand the intended purpose of each field within the account coding string. In

addition, the system also handles the distribution of both direct and indirect costs to the operating

companies.

All transactions will use the account coding string listed below. The coding is comprised of

seven separate fields, each representing an important characteristic of the underlying transaction.

_______ -- _________ -- ___________ -- _________

GL BU OP UNIT DEPARTMENT ACCOUNT

________ -- _________ -- ___________

RESOURCE PRODUCT WORK ORDER

General Ledger Business Unit (“GLBU”):

Five (5) character numeric field.

The GLBU field is used to identify the company that will be receiving the charges, either

as a direct cost or an indirect cost.

The field is required to be populated on all accounting transactions

The will default based on the operating unit (Op Unit), as described below.

_______ -- _________ -- ___________ -- _________


________ -- ___________ -- _____________


Operating Unit (“Op Unit”):

Six (6) character numeric field.

The Op Unit field is used to identify the account code block as either a direct cost or an

indirect cost.

If the cost is a direct cost, the Op Unit field will be populated using the general Utility

Holding Op Unit 201900. Indirect costs also include costs directly related to the Utility

Holding Company.

The field will be populated using one of the BHUHC Op Units for indirect costs.

_______ -- _________ -- ___________ -- _________


________ -- ___________ -- ___________


6

Department:

Four (4) character numeric field

The department field is used to identify where the cost(s) originated

The department is required on all income statement and capital transactions

Every Dept is assigned to a GLBU

_______ -- _________ -- ___________ -- _________


_________ -- ___________ -- ____________


Account:

Six (6) character numeric field

The account field is required on all accounting transactions

All companies will use the same Chart of Accounts though some values will be specific to

certain companies.

_______ -- _________ -- ___________ -- _________


_________ -- ___________ -- ______________


Resource:

Four (4) character numeric field

Represents the type of cost that fall under a specific account

The resource field is required for all income statement and capital accounting transactions

_______ -- _________ -- ___________ -- _________


_________ -- ___________ -- ______________


Product:

Three (3) character numeric field

Identifies the product line

Examples of the product line include electric, gas, and non-regulated

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_______ -- _________ -- ___________ -- _________


_________ -- ___________ -- ___________


Work Order:

Eight (8) character numeric field

Represents the collection of costs to allow the monitoring of a job or group of tasks

The project field is required on all construction work in progress transactions

Generally used for capital projects, additionally used to track specific costs in Operations

and Maintenance

Timekeeping

All BHUH employees are required to complete a timesheet for each two week pay period,

whether they are an employee paid hourly or an employee paid a salary. Employee timesheets

are required to be approved by their supervisor.

Employees must complete the coding string, as previously discussed, for each time record. The

timesheet will default the employee’s department and resource. However, the employee is

responsible for providing the remainder of the code block. Employees are encouraged to enter

their time in one half hour increments, although they may use smaller increments if they so

choose.

Loadings

Certain benefits that are provided to employees become an inherent cost of labor. To account for

these benefits and allow for them to be charged to the appropriate subsidiary, they become part

of a loading rate that is added on to each payroll dollar (see below). A distinct resource is used

to track each specific loading.

The loading rates are calculated at the beginning of the year based upon budgeted benefit

expenses and budgeted labor and are reviewed and updated quarterly. These rates are loaded

into the accounting system and used for payroll processing throughout the year. Below is a list

of components of the loading rates:

General loadings:

Compensated Absences: including PTO (Paid Time Off), Holiday, Jury duty, Funeral

pay, United Way day and Annual Physical appointment.

Payroll Taxes: including FICA, FUTA SUTA and city taxes.

Employee Benefits: including health and medical, 401K match and fees, Pension,

Retiree healthcare and associated fees and Pension audit fees.

Incentives: including Non-officer bonus plans, Restricted Stock and Stock Option

expense.

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At the end of each month, loadings calculated on payroll using the loading rates must be trued-up

against actual employee benefit costs. The purpose for this true-up is due to the fact the BHUH

income statement must net to zero, meaning there can be no net income or net loss remaining at

BHUH. Loadings calculated on payroll are based on an estimated rate and budgeted benefits, so

differences between the actual benefits will be inherent to this process. The main reason for the

difference is the employee benefit costs differ from the budget, payroll differs from budget, or

timing. After the difference is calculated and reviewed for reasonableness, it is recorded to a

separate department and indirectly allocated to the operating companies.

Allocation Ratios

As previously stated, BHUH costs are either directly charged to an operating company, or

indirectly allocated when the cost is not associated with a specific operating company. Indirect

costs are allocated out using one of several pre-defined allocation ratios. Each department has

been assigned one of these allocation ratios. All indirect costs of that department are then

allocated using that ratio. When determining which allocation ratio should be assigned to each

department, a ratio was selected based on the specific cost driver of that department. For

instance, the expenses incurred by the Customer Service - Rapid City department are primarily

related to the support of all utility customers. In this example, the cost driver for the Customer

Service - Rapid City department indirect costs is the number of customers. Therefore, the

indirect costs will be allocated based upon the Customer Count Ratio.

For certain departments, a specific cost driver may not be clearly identifiable or the driver may

not be cost efficient to compute on a continuing basis. In these instances, a three-pronged

general allocation ratio is used. This ratio equally weights three different general ratios: Gross

Margin, Asset Cost, and Payroll Dollars. These ratios were chosen to be included in the General

Allocator Ratio because they best allocate costs based on the diverse nature of BHUH

operations.

A list of all allocation ratios, including a brief description of the ratio, the basis for the

calculation of the ratio, and the department to which that ratio has been assigned, is attached

hereto as Appendix 2.

Changing Allocation Ratios

Allocation ratios are set at the first of the year, based upon financial information from the prior

year ending December 31st. The ratios for Asset Cost and Customer Count are based on values

as of the previous period ending December 31st. The ratios for Gross Margin, Payroll Dollars,

and Net Energy Sales are based on values for the 12 months ended December 31st.

Certain events may occur during the year that are deemed to be significant to BHUH that will

require corresponding adjustments made to the allocation ratios. Examples of these types of

events include acquisitions, divestitures, new generation, significant staffing changes or new,

significant revenue streams.

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When these events occur, indirect allocation ratios will be adjusted. When adjusting allocation

ratios, it is the policy of BHUH to not recalculate all allocation ratios. Rather, allocation ratios

will be adjusted with pro forma changes. For example, if an acquisition occurs during the middle

of the year, pro forma values will be loaded. Asset values at the time of the acquisition would be

used, as well as pro forma gross margin and payroll dollars for a 12 month period. It should be

noted that estimations may be required, especially when significant additions or changes are

expected as a result of the acquisition.

It should also be noted that asset values, gross margin, and payroll dollars for the other

companies will not be changed. However, the ratios will change because the base against which

the ratios are calculated will change. Operating companies would normally see decreased ratio

values with acquisitions, and increased ratio values with divestitures. Changes will be effective

as of the beginning of the month, and will apply to all transactions for the month.

Any changes to indirect allocation ratios are initiated by one member of the allocations staff and

reviewed by another member of the allocations staff. All changes are documented in memo

format, with the supporting documentation maintained. Allocation ratios loaded into the system

are reviewed by someone other than who input the ratios into the system. Accounting calculates

the allocation ratios and provides ratios and calculations to Financial Managers and Regulatory

Departments for review.

Subsidiary Payment for Direct and Indirect Charges

It is the policy of BHUH to insure payments are made by the subsidiary companies for direct and

indirect charges. All payments for direct and indirect charges must be remitted to the BHUH by

the end of the following month. Payment requests will be provided directly to the accounts

payable departments of the subsidiary companies. BHUH will monitor payments received during

the month to insure that all subsidiary companies make payment in a timely manner.

Allocating Fixed Assets

BHUH maintains certain fixed assets that are used by and benefit all operating companies.

These fixed assets primarily consist of computer hardware and software and shared office

facilities. Because these fixed assets support all operating companies, they are allocated monthly

as part of the month-end close process, along with the allocation of these assets’ accumulated

depreciation. Construction or Work in Process balances are not allocated.

Allocated assets and accumulated depreciation are maintained in separate general ledger

accounts at the subsidiary level so they are not intermingled with regular subsidiary fixed assets,

and for ease of reconciliation.

The allocation ratio used to allocate assets and accumulated depreciation will vary depending on

the type of asset being allocated, and will be based on the function the asset is serving. For

instance, customer service software is allocated based on the Customer Count Ratio, while

general office space is allocated using the General Allocator Ratio.

10

Allocating Capitalized Inventory

The gas metershop is a BHUH department serving the gas utility operating companies. As gas

meters are purchased, they are recorded as capitalized inventory (charged to plant-in-service) by

BHUH, the meters are issued out of inventory to the specific operating company. All gas meter

investment and accumulated depreciation reserve is held at BHUH, at month-end, a manual

journal entry is prepared to allocate the plant balance of BHUH. The Customer Count Ratio is

used for this allocation.

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Appendix 1

BHUH Departments

Gas Supply Services Administration (2301)

Description: Provides for the development and execution of the gas supply portfolio plans for all

gas distribution operating companies. This plan includes purchasing strategies for the

commodity and optimization and procurement of pipeline capacity and services. (Customer

Count Ratio)

Computer Aided Dispatch CAD Assets (4247)

Description: The assets invested for the Computer Aided Dispatch system for Black Hills

Energy. This includes capitalized and centrally located hardware and software costs to service

multiple utilities. Depreciation expense on this group of assets is also charged from here.

(Customer Count Ratio)

FAME Assets (4251)

Description: The assets invested for the Facilitated Asset Mapping Enterprise system for Black

Hills Energy. This includes capitalized and centrally located hardware and software costs to

serve multiple utilities. Depreciation expense on this group of assets is also charged from here.


General Assets (4253)

Description: The assets of BHUH not specifically identified and charged to one of the other

asset investment departments for Black Hills Energy. Depreciation expense on this group of

assets is also charged from here. (Customer Count Ratio)

Work Management Assets (4257)

Description: The assets invested for the Work Management system for Black Hills Energy. This

includes capitalized and centrally located hardware and software costs to serve multiple utilities.

Depreciation expense on this group of assets is also charged from here. (Customer Count Ratio)

Regulated Generation Assets (4258)

Description: The assets for electric utilities specifically. This includes capitalized and centrally

located hardware and software costs to serve multiple electric utilities. Depreciation expense on

this group of assets is also charged from here. (Customer Count Ratio)

BHUH Benefits Loadings (4470)

Description: Utilized for charging out benefits, including medical costs, to the operating

companies. Provided that all labor is loaded with overhead loadings, only the residual charges

are allocated. (General Allocator Ratio)

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Retiree (4473)

Description: Provides for the collection of retiree health benefits for the former employees of

BHUH. (General Allocator Ratio)

BHUH Accounting Accruals (4474)

Description: Created to facilitate the accrual of certain charges not related to specific

departments. (General Allocator Ratio)

Blended Assets - All (4478)

Description: The assets invested and centrally located for gas and electric operating companies

where the General Ratio is determined to be the best form of allocation. Depreciation expense

on this group of assets is also charged from here. (General Allocator Ratio)

Blended Assets - Electric (4479)

Description: The assets invested and centrally located for electric operating companies where the

General Ratio is determined to be the best form of allocation. Depreciation expense on this

group of assets is also charged from here. (General Allocator Ratio)

Blended Assets - Gas (4480)

Description: The assets invested and centrally located for gas operating companies where the

General Ratio is determined to be the best form of allocation. Depreciation expense on this group

of assets is also charged from here. (General Allocator Ratio)

Blended Assets - Customers (4481)

Description: The assets invested and centrally located for gas and electric companies where the

Customer Ratio is determined to be the best form of allocation. Depreciation expense on this

group of assets is also charged from here. (Customer Count Ratio)

Blended Assets – Electric AMI (4482)

Description: The assets invested for BHUH electric utilities where the Customer Count Ratio is

determined to be the best form of allocation. Depreciation expense on this group of assets is also

charged from here. (Customer Count Ratio)

Transmission Planning (5107)

Description: Performs near and long-term (1-20 year) transmission planning to determine cost-

effective transmission additions needed to reliably serve projected customer load. Performs

studies in support of large customer requests and the FERC Tariff; and performs operational

studies for planned outages. Provides support in meeting compliance with NERC Standards; and

represents the corporation in regional and sub-regional planning groups. (Transmission Ratio)

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NERC Compliance (5108)

Description: Develops, coordinates and oversees the Electric Utilities Group’s compliance with

mandatory North American Electric Reliability Corporation (NERC) Reliability Standards,

which standards are enforceable through financial sanctions and are intended to ensure a reliable

Bulk Electric System. (Transmission Ratio)

FERC Tariff and Compliance (5109)

Description: Develops, coordinates, and oversees the Electric Utilities Group’s compliance with

the Federal Energy Regulatory Commission (FERC) requirements pertaining to electric

transmission; and administers the Company’s Open Access Transmission Tariff (OATT).

Administration of the Tariff, which outlines the “rules of the road” for transmission providers,

the rates we charge, and the procedures and timelines in addressing customer requests (new load,

new generators, or other requests to wheel power across the system). (Transmission Ratio)

Transmission and Distribution Reliability (5110)

Description: Operates the Company’s transmission and distribution systems on a 24/7 basis; and

plans and directs switching and outage restoration efforts for both emergency and planned

outages. Supervisory Control and Data Acquisition (SCADA) design, implementation, and

maintenance. (Transmission Ratio)

NERC Transmission and Tech Support (5111)

Description: Develops, coordinates and oversees the technical support piece of the Electric

Utilities Group’s compliance with mandatory North American Electric Reliability Corporation

(NERC) Reliability Standards, which standards are enforceable through financial sanctions and

are intended to ensure a reliable Bulk Electric System. (Transmission Ratio)

Transmission Services Management (5112)

Description: For all three electric utilities (BHP, CLFP and Colorado Electric), Transmission

Services directs the 24/7 Reliability Centers in Rapid City and Pueblo, Transmission Planning,

NERC Compliance, FERC Compliance, and Transmission Tariff Administration. (Transmission

Ratio)

Electric Engineering Services (5120)

Description: Engineering Services supports transmission and distribution activities within the

Electric Utilities group including engineering, distribution planning, T & D asset management,

metering, substation maintenance, GIS/drafting and outage management systems. (General

Allocator Ratio)

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Power Supply and Renewables (5121)

Description: Provides for the planning, development, and management of power supply and

renewable strategies for electric operating companies. (Net Energy Sales Ratio)

Electric Regulatory Services (5122)

Description: Supports and manages all electric regulatory filings, rate cases, and regulatory

issues. (General Allocator Ratio)

Gas Engineering Services (5254)

Description: Establishes and monitors network-wide gas standards and coordinate mapping

activities for all gas service states. (Customer Count Ratio)

GIS Support (5305)

Description: Researches, builds and implements work management solutions for the benefit of

electric and gas network operations. This department also supports STORMS, FAME and

network requests. (Customer Count Ratio)

Meter shop General (5490)

Description: Manages and provides gas measurement support to field operations located in gas

service states. (Customer Count Ratio)

Utility Margin Accounting (5666)

Description: Assists in the preparation of budgets for the operating companies. Prepares various

operating and financial reporting for utility management. Assists with the regulatory strategy for

the operating companies. (General Allocator Ratio)

Utility Financial Management (5668)

Description: Assists in the compliance with regulatory accounting requirements. Prepares

budgets, forecasts, and assists in the Strategic Planning of the operating companies. Prepares

various operating and financial reporting for utility management. Assists with the regulatory

strategy for the operating companies. (General Allocator Ratio)

Utility Accounting (5670)

Description: Assists in the compliance with regulatory accounting requirements. Assists in the

preparation of budgets for the operating companies. Prepares various operating and financial

reporting for utility management. Assists with the regulatory strategy for the operating

companies. (General Allocator Ratio)

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Customer Service Management (5674)

Description: Provides general direction and supervision of customer service activities.

Encourages the safe, efficient and economical use of the utilities services. (Customer Count

Ratio)

Utility Operations Management (5682)

Description: Provides guidance, direction and management to overall utility operations.

(General Allocator Ratio)

Utility Market Services (5688)

Description: Provides business and planning services, including marketing. Searches for

competitive business opportunities and energy solutions. (General Allocator Ratio)

Customer Service Center - Lincoln (5701)

Description: Answers and resolves customer inquiries for both regulated and non-regulated

customers. (Customer Count Ratio)

Customer Account Services - Omaha (5702)

Description: Assists customers with billing, payment and collection issues. (Customer Count

Ratio)

Customer Service Support - Rapid City (5703)

Description: Provides support to customer services areas through training, revenue assurance

analysis, quality analysis, business analysis and customer and community communication.


Customer Account Services – Rapid City (5704)

Description: Assists customers with billing, payment and collection issues. (Customer Count

Ratio)

Customer Service Center – Rapid City (5705)

Description: Answers and resolves customer inquiries for both regulated and non-regulated

customers. (Customer Count Ratio)

Large Volume Billing (5706)

Description: Manages and maintains regulated and non-regulated sales and billing of gas to

large volume customers. (Customer Count Ratio)

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Customer Service Center Support (5707)

Description: Provides direct support to the operations of the two customer service centers in

Lincoln and Rapid City. Provides analysis on employee staffing, monitoring service metrics,

projects, and planning. (Customer Count Ratio)

Bill Processing (5712)

Description: Prepares, assembles, inserts and distributes customer mailings for both regulated

and non-regulated customers. (Customer Count Ratio)

Field Resource Center - Lincoln (5715)

Description: Schedules and dispatches premise service activities to both regulated and non-

regulated customers. (Customer Count Ratio)

Field Resource Center - Rapid City (5717)

Description: Schedules and dispatches premise service activities to both regulated and non-

regulated customers. (Customer Count Ratio)

Service Guard Marketing (6005)

Description: Provides and manages product development for consumer marketing with the

primary focus on appliance options business for non-regulated customers. (Customer Count

Ratio)

Utility Service Management - (6183)

Description: Provides guidance to utility activities with emphasis on service support. (Customer

Count Ratio)

External Affairs – KS/CO Gas (6184)

Description: Works directly with customers in the areas of builder relations, economic

development and customer relations for the states of Kansas and Colorado. (Customer Count

Ratio)

Business Operations - KS/CO Gas (6198)

Description: Assists with the management of the gas transmission and distribution activities for

the states of Kansas and Colorado. (Customer Count Ratio)

Appliance Technical Training (6331)

Description: Designs and implements safety programs and incentives, incident investigation,

hazard identification and problem solving, and appliance repair technical skill training.


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Gas Regulatory Services (6372)

Description: Supports and manages all gas regulatory filings, rate cases, and regulatory issues.

(General Allocator Ratio)

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Appendix 2

Allocation Ratios

Any asset ratios and employee and customer count ratios are calculated as of period-end dates,

while revenue and expense ratios are calculated for twelve months ended as of period-end dates.

Asset Cost Ratio – Based on the total cost of assets as of December 31 for the prior year,

the numerator of which is for an applicable operating company and the denominator of

which is all applicable operating companies. Assets are also reported at their FERC

value, meaning that assets for the utility subsidiaries will not include any elimination that

are done to bring their FERC financial statements into compliance with GAAP. FERC

requires that acquired fixed assets be recorded at their gross value with accumulated

depreciation, while GAAP requires acquired fixed assets be recorded at their net value.

An elimination journal entry is used to eliminate the gross-up for preparation of GAAP

financial statements, but this elimination journal entry is not factored into the calculation

of the Asset Cost Ratio.

No departments utilize this ratio, but it is a component in the Blended Ratio.

Gross Margin Ratio – Based on the total gross margin for the prior year ending

December 31, the numerator of which is for an applicable operating company and the

denominator of which is for all applicable operating companies. Gross margin is defined

as revenue less cost of sales.


Payroll Dollar Ratio –Based on the total payroll dollars for the prior year ending


denominator of which is for all applicable operating companies. Payroll dollars include

all bonuses and compensation paid to employees, but do not include items that are only

included on an employee’s W-2 for gross-up and income tax purposes, such as life

insurance premiums of $50,000.


Blended Ratio – A composite ratio comprised of an average of the Asset Cost Ratio,

Payroll Dollar Ratio and the Gross Margin Ratio. These factors are equally weighted.

This factor is sometimes referred to as the general allocation factor.

Departments that utilize this ratio include BHUH benefits loading, retiree, BHUH

accounting accruals, all blended assets, electric blended assets, gas blended assets,

electric engineering services, electric regulatory services, utility margin accounting,

utility financial management, utility accounting, utility operations management, utility

market services, and gas regulatory services.

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Customer Count Ratio – Based on the number of customers at the end of the prior year

ending December 31, the numerator of which is for an applicable operating company and

the denominator of which is for all applicable operating companies.

Departments that utilize this ratio include gas supply services administration, computer

aided dispatch, FAME assets, general assets, work management assets, regulated

generation assets, customer blended assets, electric AMI blended assets, gas engineering

services, GIS support, general meter shop, customer service management, Lincoln

customer service center, Omaha customer account services, Rapid City customer service

support, Rapid City customer account services, Rapid City customer service center, large

volume billing, customer service center support, bill processing, Lincoln field resource

center, Rapid City field resource center, service guard marketing, utility service

management, KS/CO gas external affairs, KS/CO gas business operations, and appliance

technical training.

Net Energy Sales Ratio – Based on the net energy sales for the prior year ending


denominator of which is for all applicable operating companies.

The department that utilizes this ratio is power supply and renewables.

Transmission Ratio – Based on a simple average of a multiple of cross-sectional drivers

for the transmission function that includes customer counts, peak load, number of

substations, number of feeders, number of distribution and transmission miles, and

number of remote terminal units. The numerator of which is for an applicable operating

company and the denominator of which is for all applicable operating companies.

The departments that utilize this ratio include transmission planning, NERC compliance,

FERC tariff and compliance, transmission and distribution reliability, NERC

transmission and tech support, and transmission serviced management.

Direct Testimony and Exhibits Charles D. Gray





December 1, 2011

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Table of Contents

I. Introduction And Qualifications ......................................................................................1

II. Purpose Of Testimony And Exhibits ...............................................................................2

III. Test Year Actual Billing Determinants And Proof Of Test Year Revenue.....................3

IV. Pro Forma Revenue Adjustments ....................................................................................5

V. Adjusted Billing Determinants On Proposed Rates.........................................................8

Exhibits

• Exhibit CRG-E1, Test Year Actual Billing Determinants. • Exhibit CRG-E2, Pro Forma Billing Determinants on Proposed Rates.

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I. INTRODUCTION AND QUALIFICATIONS

Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 1

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A. My name is Charles R. Gray and my business address is 105 South Victoria Avenue,

Pueblo, Colorado.


A. I am employed by Black Hills Corporation in the Regulatory Department as a Senior

Regulatory Analyst.

Q. PLEASE BRIEFLY DESCRIBE YOUR DUTIES AND RESPONSIBILITIES AS

A SENIOR REGULATORY ANALYST FOR BLACK HILLS ENERGY.

A. I am responsible for gathering, researching and analyzing accounting, financial,

statistical, customer billing data and other information. I also prepare analyses, work

papers and other supporting documents for various filings with regulatory agencies and

reports, both internal and external. I also participate in the preparation of the cost of

service study and relate cost of service results to the development of product prices,

rates and tariffs.

Q. PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND

PROFESSIONAL EXPERIENCE.

A. I attended Central Missouri State University in Warrensburg, Missouri, from which I

received a Bachelor of Science-Education Degree. I also attended Longview

Community College in Kansas City, Missouri, from which I received an Associates of

Arts-Accounting Degree. In 1986 I began working for Missouri Public Service, a

division of Aquila, Inc. (“Aquila”), and held positions within the Accounting

Department. My responsibilities included direct responsibility for the monthly billing

of Missouri Public Service’s Large Volume billing accounts, as well as preparation of

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financial and regulatory reports, monthly accounting journal entries and budgeting. In

1995 I joined Aquila’s Regulatory Department as a Rates Analyst. I was promoted to

Senior Rates Analyst in 2000. Following the sale of certain Aquila electric and gas

properties to Black Hills Corporation, I accepted a position as Senior Regulatory

Analyst located in Pueblo, Colorado.

II. PURPOSE OF TESTIMONY AND EXHIBITS 6

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A. The purpose of my testimony is to provide a proof of test year electric revenue on the

current electric rate schedules for Cheyenne Light, Fuel and Power Company

(“Cheyenne Light”). I will provide two revenue adjustments to test year billing

determinants. I also will be providing the electric pro forma billing determinants priced

out on the proposed rates. I also will be updating the Cheyenne Light electric rate

schedule tariffs.

Q. DID YOU ALSO FILE TESTIMONY IN THE CHEYENNE LIGHT, FUEL AND

POWER GAS FILING?

A. Yes, I also provided similar testimony for the Company’s gas rate case filing.

Q. ARE YOU SPONSORING ANY EXHIBITS IN THIS PROCEEDING?

A. Yes. I am sponsoring the following Exhibits:

• Exhibit CRG-E1, Test Year Ended Actual Billing Determinants.

• Exhibit CRG-E2, Pro Forma Billing Determinants on Proposed Rates.

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III. TEST YEAR ACTUAL BILLING DETERMINANTS

AND PROOF OF TEST YEAR REVENUE

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Q. PLEASE EXPLAIN THE PURPOSE OF EXHIBIT CRG-E1.

A. The purpose of Exhibit CRG-E1 is to price out the billing determinants on existing

rates for the test year ended August 2011 by rate schedule. This process is necessary

for the proof of test year revenue on the existing rates. The Cheyenne Light electric

rate schedule revenue is normally classified as a customer service and facility charge,

capacity charge or energy charge. In addition to these normal billing charges, electric

revenues can also be generated by the power cost adjustment, high load factor incentive

credit, rate schedule minimum monthly charges, equipment rental fees and the

voluntary renewable energy rider.

Q. ARE THERE ANY BILLING CHARGES EXCLUDED FROM EXHIBIT

CRG-E1?

A. Yes. The revenue shown on Exhibit CRG-E1 does not include sales and franchise

taxes.

Q. PLEASE EXPLAIN HOW YOU DERIVED THE BILLING DETERMINANTS

SHOWN ON CRG-E1?

A. I compiled the test year billing determinants by rate identification (“rate ID”) from a

combination of Customer Information System (“CIS+”) monthly billing system reports

and from a download of individual customer billing records from CIS+ in a database

format. From these sources I cross checked the billing information for accuracy and

reliability and grouped the appropriate rate ID’s to the specific rate schedule.

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Q. DOES THE CIS+ BILLING SYSTEM ASSIGN ONLY ONE RATE ID NUMBER

FOR EACH TARIFF RATE SCHEDULE?

A. No. There can be multiple rate ID’s within the CIS+ billing system for a specific rate

schedule. The rate ID’s are used internally by the billing system to designate the proper

rate component values to apply to the billed usage during the bill calculation process.

As an example, Cheyenne Light has a Residential General Service tariff schedule but

the tariff schedule has two rate ID’s associated with it. The Residential Service rate

sheet schedule R uses rate ID WY609 for the regular residential service accounts and

WY675 for the net metered Residential Service accounts. In total, the CIS+ billing

system currently uses 11 rate ID’s for metered electrical service and another 7 rate ID’s

for the voluntary renewable energy rider, unmetered street lighting, highway/pedestrian

lighting and outdoor area lighting options available to customers.

Q. PLEASE DISCUSS THE FORMAT USED ON EXHIBIT CRG-E1.

A. The schedule lists separately each rate schedule by name. The test year billing

determinants are shown by type along with the charge per unit and the total test year

dollars billed by rate component. The various components are summed and shown in

total at the end of each rate section. For the unmetered street and outdoor area lighting

schedules, the schedule lists the number of services billed during the test year, the

unmetered usage billed and the revenue generated by the lighting schedule.

Q. DID YOUR ANALYSIS OF THE TEST YEAR BILLING DETERMINANTS

ALLOW YOU TO REACH ANY CONCLUSIONS CONCERNING BILLED

REVENUE?

A. My analysis allows me to conclude that billed revenues are accurately reflected in the

per-books revenue presented in the case filing support.

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IV. PRO FORMA REVENUE ADJUSTMENTS 1

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Q. ARE YOU RESPONSIBLE FOR ANY REVENUE ADJUSTMENTS?

A. Yes, I have calculated two revenue adjustments that have been incorporated into the

overall revenue requirement addressed in the testimony of Chris Kilpatrick. The

electric revenue adjustments were:

• Residential Customer Forecast (R-1)

• General Service Additional Load Growth (R-2)

Q. WHAT IS THE PURPOSE OF R-1 RESIDENTIAL CUSTOMER FORECAST?

A. Adjustment R-1 is a known and measurable adjustment to electric residential test year

revenues to achieve proper matching between test year revenues, expenses and

investment for the period of time in which the new rates become effective. This

adjustment is necessary to reflect the projected revenue of new residential customers

added to the Cheyenne Light system that were not on system either during the full test

year or are expected to be served after the test year.

Q. HOW WAS THE ADJUSTMENT CALCULATED?

A. I accomplished the adjustment through three calculations. The first calculation updated

the test year revenue to include a full year of billing for the new residential customers

that began service during the test year. By subtracting the number of residential

customers served at the beginning of the test year from the number of customers served

at the end of the test year I determined that the customer count had grown by 330

customers. I then calculated the revenue adjustment necessary to annualize the revenues

of these new customers. To calculate the required adjustment I assumed that one

twelfth of the customers were added each month and that their consumption of

electricity was equal to the average consumption of the other residential customers for

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that month. Next, I updated the pro forma test year for the new residential electric

customers added in September and October 2011 as known and measurable. My final

step in updating the residential customer revenues, to be consistent with the matching

principle, was to forecast the new customers and related revenues for the remaining

months of the next year following the close of the test year. For this calculation I

assumed that customer growth would continue at 28 new residential customers per

month and that these new customers would use the average an equal amount of

electricity as the current customers did in that month during the test year. The sum of

these calculations is presented in the table below and illustrates the impact of the

residential customer annualization and forecast pro forma adjustment on actual test year

residential sales.

kWh Sales Revenue

Test year Ended Aug. 31,2011 261,717,340 $ 28,301,119

Residential Customer Forecast Adj. 766,270 $ 113,758

Total Pro Forma Residential 262,483,610 $ 28,414,877

Q. WHAT IS THE PURPOSE OF R-2 GENERAL SERVICE ADDITIONAL LOAD

GROWTH ADJUSTMENT?

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A. Adjustment R-2 is a known and measurable adjustment to test year revenues. It is

necessary to reflect the projected yearly kWh consumption and annual billing demands

of four new General Service-Secondary customers and three new General Service-

Primary customers that potentially will be on line when the proposed electric rates are

implemented. All seven of the new customer loads are currently in the construction

process and are forecasted to be taking permanent electric service by the second half of

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2012. Cheyenne Light will provide updated load projections during the rate case

proceedings to reflect the most current information available regarding when these

loads will be on permanent service. In this initial application filing and based on prior

experience with customers’ estimates regarding the timing of their permanent service,

Cheyenne Light has discounted the new load estimates by thirty-five percent (35%).

These net sales and revenue projections are provided on Schedule I-2 of the revenue

requirement rate model. It is reasonable to consider these potential new loads and the

associated revenues as adjustments to test year revenues.

Q. PLEASE PROVIDE THE POTENTIAL IMPACT OF THE LARGE GENERAL

SERVICE-SECONDARY ADJUSTMENT?

A. The adjustment to General Service-Secondary resulted in increasing General Service-

Secondary test year billing determinants by 19,500 annual kW and 9,822,150 annual

kWh consumption for these four new customers. The projected monthly billing

demands and monthly energy sales were added to the test year billing determinants for

the General Service-Secondary section. This adjustment resulted in an increase to test

year base revenue of approximately $752,636 as shown on Schedule I-2 and Statement

I Page 2.

Q. PLEASE PROVIDE THE POTENTIAL IMPACT OF THE LARGE GENERAL

SERVICE-PRIMARY ADJUSTMENT?

A. In the same manner as previously explained, the adjustment to General Service-Primary

resulted in increasing General Service-Primary test year billing determinants by 74,880

annual kW and 40,541,280 annual kWh consumption for these three new customers.

This adjustment resulted in an increase to test year base revenue levels of

approximately $2,795,377 as shown on Schedule I-2 and Statement I Page 2.

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V. ADJUSTED BILLING DETERMINANTS ON PROPOSED RATES 1

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Q. PLEASE EXPLAIN THE PURPOSE OF EXHIBIT CRG-E2.

A. The purpose of Exhibit CRG-E2, Pro Forma Billing Determinants on Proposed Rates,

is to price out the pro forma billing determinants on the proposed rates. The pro forma

billing determinants provided in Exhibit CRG-E2 are also carried over to Section 3,

Revenue Comparison under Present and Proposed Rates provided in the application of

Cheyenne Light.

Q. DISCUSS THE PROCESS YOU USED IN DEVELOPING EXHIBIT CRG-E2.

A. I used Exhibit CRG-E1 as my starting point in creating Exhibit CRG-E2, using the

same billing determinants as provided in Exhibit CRG-E1. That is, I used the same

number of customer bills, same monthly billed kW demands and the same number and

allocation of kWh consumption by each individual rate schedule. I then included the

pro forma billing determinants for the residential customer forecast adjustment covered

in the previous section of my testimony. I also included the General Service Additional

Load Growth adjustment forecast billing determinants. To determine the revenue

requirement produced by the proposed rates, I used a CIS+ billing report listing all base

rate component values for every rate schedule and increased each base rate value by

6.35%, the proposed base rate revenue increase. Exhibit CRG-E2 then prices out the

pro forma billing determinants on the proposed rates and quantifies the effect of

increasing each base rate charge by 6.35%.

To illustrate the process of increasing the base rate charges by the 6.35%, the

Residential Service (WY609) proposed base rate charges are shown in the following

table.

Rate Schedule Residential Service

Current Rate Schedule-R

Proposed Rate Schedule-R

Change in Base Rates

Customer Charge $12.00 $12.76 6.33%

Energy Charge -kWh $0.08921 $0.0949 6.38%

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Q. WHY DO THE PROPOSED VALUES NOT EQUAL THE PROPOSED BASE

REVENUE INCREASE PERCENTAGE OF 6.35%?

A. It is due to rounding from the existing rate values.

Q. DID YOUR ANALYSIS OF THE PRO FORMA ADJUSTED BILLING

DETERMINANTS IN EXHIBIT CRG-E2 PRICED AT PROPOSED RATE

COMPONENT VALUES IN THE FILED PROPOSED RATE SCHEDULE

TARIFFS ALLOW YOU TO REACH ANY CONCLUSIONS CONCERNING

THE ADDITIONAL REVENUE REQUIREMENT REQUEST OF $5,907,945?

A. Yes. My analysis allows me to conclude that the Exhibit CRG-E2 pro forma billing

determinants priced out on the increased base rate charges provided in proposed rate

schedule tariffs will allow Cheyenne Light the opportunity to receive the allowed

revenue requirement level derived by the revenue requirement model sponsored by

Chris Kilpatrick.


A. Yes.

pmh

Typewritten Text

Exhibit CRG-E1

pmh

Typewritten Text

Exhibit CRG-E2

Direct Testimony and Exhibits David A. (Andy) Butcher





December 1, 2011

Table of Contents

I. Introduction And Background ............................................................................................. 1

II. Purpose Of Testimony ......................................................................................................... 2

III. Generation Dispatch Agreement.......................................................................................... 2

EXHIBITS

Exhibit DAB-E1 Generation Dispatch and Power Marketing Agreement Exhibit DAB-E2 Palo Verde Hub Peak Pricing Report

I. INTRODUCTION AND BACKGROUND 1

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A. My name is David A. (Andy) Butcher, 2828 Plant Street, Rapid City, South Dakota

57702-0385.


A. I am currently employed as the Director of Generation Dispatch and Power Marketing for

Black Hills Power (“Black Hills Power”).



Light”).


A. I am a graduate of DeVry University in Columbus, Ohio, with a Bachelor of Science in

Engineering. I am also a graduate from the United States Army Signal Officers Basic

course and a certified North American Reliability Corporation (NERC) operator at the

reliability level. My work experience includes serving as an Officer in the United States

Army from 1989 through 1993. I also worked four years for Honeywell DMC as an

energy conservation specialist and nearly seven years for American Municipal Power

(AMP) as the Manager of System Operations. I began my career with Black Hills Power

in September 2005 in the Generation Dispatch and Power Marketing department as a

Real Time Marketer. In March of 2008, I became the Manager of Generation Dispatch

and Power Marketing until August 2010 when I was promoted to the Director of the same

department.

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Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR OF

GENERATION DISPATCH AND POWER MARKETING.

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A. As the Director of Generation Dispatch and Power Marketing, I lead a group of 16

employees all with the ultimate goal of providing reliable low cost power for Black Hills

Power, Cheyenne Light, and Black Hills/Colorado Electric Utility Company, LLC (Black

Hills Colorado”). We provide generation dispatch and load following operations for

these utilities with a 24 hour 365 day operation center. I am also responsible for

providing energy marketing services for Black Hills Power, Black Hills Colorado and

Black Hills Wyoming, LLC (”Black Hills Wyoming”), Black Hills Corporation’s

unregulated, independent power producing subsidiary.


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A. My testimony will provide a description of the Generation Dispatch and Energy

Management Agreement dated February 23, 2007 (the “GDEMA”) attached hereto as

Exhibit DAB-E1 and proposed changes to the provisions under the GDEMA in which

Cheyenne Light sells all of its surplus energy to Black Hills Power known as the “Put”.

III. GENERATION DISPATCH AGREEMENT 17

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Q. PLEASE GIVE A BASIC OVERVIEW OF THE GDEMA.

A. The GDEMA between Black Hills Power and Cheyenne Light provides that Black Hills

Power will perform generation dispatch and energy management services to manage the

dispatch of Black Hills Power’s and Cheyenne Light’s generating resources on a system-

wide, least-cost basis. Under the GDEMA which has been approved by the Federal

Energy Regulatory Commission (FERC), Black Hills Power manages all of Cheyenne

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Light’s generation resources and power purchase agreements (PPA) in order to serve the

Cheyenne Light load reliably and as economically as possible. Black Hills Power will

purchase any energy needed to serve the Cheyenne Light load and price the purchases at

cost, without mark-up.

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In addition to the generation dispatch and energy management provisions, the GDEMA

states that during periods when Cheyenne Light has resources in excess of its load, Black

Hills Power will purchase the surplus energy.

Q. HOW DOES THE ‘PUT’ WORK?

A. Under the Put as it presently exists, Black Hills Power is required to take the energy that

Cheyenne Light has in excess of its load, even if the energy could be purchased from the

market at a lower cost. Black Hills Power purchases the surplus energy of Cheyenne

Light on an hourly basis. The price of this energy is equal to the variable cost under the

Wygen I PPA between Cheyenne Light and Black Hills Wyoming (the “BHW PPA”).

The Wygen I PPA was used as a price indicator because it contains a ‘must take’

provision. The Put effectively provided a pass through of the costs associated with the

BHW PPA to Black Hills Power and allowed Cheyenne Light to economically dispatch

its power supply resources without being constrained by the must take provision.

Q. ARE YOU PROPOSING CHANGES TO THE GDEMA?

A. Yes. The Company and Black Hills Power intend to request FERC approval of a

proposed change to the pricing of the Put arrangement contained in the GDEMA. The

proposed pricing mechanism for the Put is based on a market price.

3

Q. WHEN DO THE PARTIES INTEND TO REQUEST FERC APPROVAL OF THE

PROPOSED AMENDMENT TO THE GDEMA?

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A. Cheyenne Light and Black Hills Power intend to file with FERC an amendment to the

GDEMA in the first quarter of 2012 to incorporate the proposed pricing mechanism. The

Company will request in the FERC filing that the effective date of the proposed pricing

mechanism be concurrent with the effective date of the rates proposed under this rate

case. Prior to the FERC filing, the Company is willing to discuss the proposed pricing

mechanism with the Public Service Commission of Wyoming (“Commission”) at a

hearing or public meeting called by the Commission.

Q. WHY ARE YOU PROPOSING CHANGES TO THE PUT AT THIS TIME?

A. As stated above, the pricing of the Put is currently based on the BHW PPA and is split

into an energy and capacity charge. However, due to the BHW PPA contract extension

filed with the FERC on July 30, 2009 (Docket No. ER09-1524-000), this pricing will

change to a one-price mechanism in 2013. The Put is considered energy without the

capacity component. Following the revised pricing mechanism in the BHW PPA in

2013, it will no longer be an accurate price indicator for the Put. Black Hills Power

would be required to buy Cheyenne Light’s surplus energy with a combined price for

energy and capacity, thus paying for capacity for a non-firm energy product.

Black Hills Power and Cheyenne Light agree that the pricing of the Put should reflect

market pricing. The change to the BHW PPA makes this change necessary prior to 2013.

Q. WHAT AFFECT WILL THESE CHANGES HAVE ON CHEYENNE LIGHT?

A. Cheyenne Light will be selling to Black Hills Power non-firm Put energy at market

prices. Therefore, there may be some instances in which the selling price is lower than

4

the price set forth in the BHW PPA. Cheyenne Light will no longer have a guarantee that

the sale of energy to Black Hills Power will cover all of its costs to purchase energy

under the BHW PPA. However, Cheyenne Light will also have an opportunity to sell the

surplus energy at market which could be higher than the price of the surplus energy

purchased under the BHW PPA resulting in a net gain to Cheyenne Light.

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Q. WHY IS CHEYENNE LIGHT AGREEABLE TO THIS MODIFICATION AND

WHAT IS THE PROJECTED FINANCIAL IMPACT TO CHEYENNE LIGHT’S

CUSTOMERS DUE TO THE PROPOSED MODIFICATION TO THE PUT?

A. Cheyenne Light is agreeable to this modification for two primary reasons: 1) With this

modification to the Put, Cheyenne Light will receive the market price. When market

price exceeds the price of energy under the Wygen I PPA, Cheyenne Light and its

customers will benefit; and 2) Cheyenne Light does not have the resources to dispatch its

own system. As stated above, the pricing change to the Wygen I PPA results in an unfair

price indicator for the Put, which would lead Black Hills Power to request termination of

the agreement. The GDEMA allows either party to terminate upon six months notice.

The Company currently forecasts that Cheyenne Light’s customers will financially

benefit from the proposed modification to the Put in 2012. Even if there is not a benefit to

customers, the forecasted financial impact to Cheyenne Light, if any, is outweighed by its

need for the services included in the GDEMA.

5

Q. HOW WILL THE COMPANY GENERALLY DETERMINE THE MARKET

PRICE FOR THE SURPLUS POWER THAT WILL BE SOLD BY CHEYENNE

LIGHT TO BLACK HILLS POWER?

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A. There is no readily available published market price for energy produced by the Wygen

generation facilities located near Gillette, Wyoming. Therefore, the Company believes

that the market price for this power can best be determined by using the daily published

day ahead average market price for energy at the Palo Verde hub, adjusted by an amount

that historically is the differential between the Palo Verde hub price and the Rockies hub

(Colorado West) price. The Palo Verde hub is a liquid trading hub with a published price

for the sale of both on-peak and off-peak day ahead energy at the hub of the four corners

of the states of Arizona, Utah, Colorado and New Mexico. The Palo Verde hub is a

better determinant of price for the Wygen generation facilities than, for example, the Mid

C hub, because the Palo Verde hub is closer to the Rockies territory. The Rockies hub

does not publish its prices. The historical differential between the Palo Verde price and

the Rockies hub - Colorado West (where Cheyenne Light is located) will best reflect the

difference in pricing between Cheyenne Light and the Palo Verde hub price.

Q. PLEASE DESCRIBE THE EXACT MANNER THAT THE COMPANY WILL

USE TO DETERMINE THE MARKET PRICE FOR THE SURPLUS POWER

THAT WILL BE SOLD BY CHEYENNE LIGHT TO BLACK HILLS POWER.

A. The Company will use the monthly forecast published by Ventyx, which is based on a

historical analysis, to calculate on a monthly basis the differential between the Palo Verde

hub price and the Rockies hub (Colorado West) price on both an on-peak (the “On-peak

Monthly Differential”) and off-peak basis (the “Off-peak Monthly Differential”). “On-

6

peak” and “off-peak” will be as defined by NERC. The daily market price for the surplus

power sold by Cheyenne Light to Black Hills Power, Inc. shall be the Palo Verde day

ahead average price for on-peak or off-peak, plus or minus the calculated applicable On-

peak Monthly Differential or the Off-peak Monthly Differential.

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Q. PLEASE PROVIDE AN EXAMPLE OF HOW THE MARKET PRICE FOR

SURPLUS POWER WILL BE DETERMINED.

A. I will use a historical price in this example and will assume that on October 14, 2011,

Cheyenne Light is selling on-peak surplus power to Black Hills Power, Inc. In addition, I

calculated that the On-peak Monthly Differential for October 2011 is minus $2.49 per

MWh. Attached as Exhibit DAB-E2 is a copy from the ICE website showing the Palo

Verde Peak price report information from October 3, 2011 to November 16, 2011. This

Exhibit reflects that on October 13, 2011, the day ahead average price (the price for

October 14, 2011 on-peak energy) for Palo Verde Peak is $35.29. Therefore, the market

price for the October 14, 2011 on-peak power sold by Cheyenne Light to Black Hills

Power, Inc. is calculated for October 13, 2011, to be $32.80 as follows:

$35.29 Palo Verde day ahead price on October 13, 2011 for peak power

(02.49) On-peak Monthly Differential 17

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$32.80 Market price for Cheyenne Light’s sale of October 14, 2011 peak

power to Black Hills Power


A. Yes, it does.

7

GENERATION DISPATCH AND ENERGY MANAGEMENT AGREEMENT

BETWEEN

BLACK HILLS POWER, INC.

AND

CHEYENNE LIGHT, FUEL & POWER COMPANY

Dated: February 23, 2007

pmh

Typewritten Text

Exhibit DAB-E1

pmh

Typewritten Text

Generation Dispatch and Energy Management Agreement

pmh

Typewritten Text

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Typewritten Text

Black Hills Power, Inc. Electric Rate Schedule FERC No. 34

Original Sheet No. 2

Cheyenne Light, Fuel and Power Company Electric Rate Schedule FERC No. 1

Issued by: Steven J. Helmers Senior Vice President and General Counsel Issued on: February 23, 2007

Effective Date: _________


TABLE OF CONTENTS

ARTICLE 1 PAGE NO. TERM OF AGREEMENT…………………………………………. 4 ARTICLE II DEFINITIONS ……………………………………………………. 4 ARTICLE III AGENT …………………………………………………………… 8 ARTICLE IV MUTUAL OBLIGATIONS ……………………………………… 11 ARTICLE V SURPLUS ENERGY …………………………………………….. 11 ARTICLE VI GENERAL ……………………………………………………….. 11







BETWEEN BLACK HILLS POWER, INC.

AND CHEYENNE LIGHT, FUEL & POWER COMPANY

This Generation Dispatch and Energy Management Agreement (“Agreement”) is

made and entered into this 23 day of February, 2007, by and between Black Hills Power,

Inc. (“Black Hills Power”), a South Dakota corporation, and Cheyenne Light, Fuel &

Power Company (“Cheyenne Light”), a Wyoming corporation, referred to collectively as

“Parties” and singularly as “Party”.

WHEREAS, the Parties enter into this Agreement in order to achieve a greater

realization of economic benefits for their respective customers through the coordination

of generation and/or purchasing of wholesale Energy; and

WHEREAS, the Parties can achieve these economic benefits through a single

integrated and centrally dispatched system, and through coordination of their electric

supply activities, including planning, construction, operation, and maintenance of their

Generating Units; and

WHEREAS, the foregoing benefits will be economically achieved and their

attainment will be facilitated by having certain services performed by Black Hills Power

acting as agent on behalf of Cheyenne Light; and

WHEREAS, in addition, Cheyenne Light will sell its Surplus Energy to Black

Hills Power pursuant to the terms set forth herein.






NOW, THEREFORE, in consideration of the covenants and premises herein set

forth, and other good and sufficient consideration, the Parties mutually agree as follows:

ARTICLE I

TERM OF AGREEMENT

This Agreement shall become effective at 12:00 a.m. M.S.T. on January 1, 2008,

and shall continue in full force and effect from year to year until terminated by either

Party upon six (6) months written notice to the other Party or in accordance with section

6.10.

ARTICLE II

DEFINITIONS

For the purpose of this Agreement, the following definitions shall apply:

2.01 Agreement shall be this Agreement, including all attachments hereto, as

the same may be amended, supplemented, or modified in accordance with its terms.

2.02 Ancillary Services are those energy-related services that are necessary to

support the transmission of energy from generating resources to loads while maintaining

reliable operation of the transmission system in accordance with Good Utility Practice.

2.03 Balancing Authority shall mean the operator of an electric power system

or combination of electric power systems to which a common generation control scheme

is applied, whether such control is manual, automatic, or a combination of both.

2.04 Capacity Resources shall mean those available Generating Units and firm

purchased power resources owned or acquired by each Party to meet its Load






Responsibility and Planning Reserve Level. Each Party’s Capacity Resources shall

include those set forth in Schedule B of this Agreement and also includes any Capacity

Resources subsequently constructed, purchased, or otherwise acquired by a Party.

2.05 Control Area shall mean an electric system or systems bounded by

interconnection metering and telemetry, capable of controlling generation to maintain its

interchange with other Control Areas, and contributing to frequency regulation of the

interconnection.

2.06 Demand shall be the demand, expressed in mega-watts (MW), of all retail

and wholesale customers of a Party, for both firm and non-firm Energy, on whose behalf

a Party, by statute, franchise, regulatory requirements, or contract, has an obligation to

supply electricity, integrated over a period of one hour, plus the losses incidental to that

service.

2.07 Economic Dispatch shall be the distribution among alternative sources of

real time and forward scheduling of generating and purchased power resources to satisfy

Load Responsibilities for system economy with due consideration of incremental

generating costs, incremental transmission losses, and system reliability.

2.08 Energy Resources shall mean those available non-firm purchased power

resources owned or acquired by each Party to meet its Load Responsibility and Planning

Reserve Level.






2.09 Generating Unit shall be an electric generator, together with its prime

mover, and all auxiliary and appurtenant devices and equipment designed to be operated

as a unit for the production of Energy.

2.10 Good Utility Practice shall mean the practices, methods, and acts engaged

in or approved by a significant portion of the electric utility industry during the relevant

time period, or any of the practices, methods, and acts which, in the exercise of

reasonable judgment in light of the facts known at the time the decision was made, could

have been expected to accomplish the desired result at a reasonable cost consistent with

good business practices, reliability, safety, and expedition. Good Utility Practice is not

intended to be limited to the optimum practice, method, or act to the exclusion of all

others, but rather includes all acceptable practices, methods, or acts generally accepted in

the region.

2.11 Interruptible Load shall mean load that the end-use customer makes

available to a Party by contract or agreement for curtailment.

2.12 Load shall mean an end-use device or customer that receives power from

the System.

2.13 Load Responsibility of a Party during any period shall be as follows:

(a) The Peak Demand of a Party; less

(b) Interruptible Load, including load directly controlled by the Party

included in (a) above; plus






(c) The contractual amount of the Party’s off-system firm energy sales

and firm energy exchanges with other systems, including applicable reserves during the

period; less

(d) The contractual amount of the Party’s firm off-system energy

purchases and firm energy exchanges with other systems, including applicable reserves,

during the period from other systems.

2.14 Peak Demand for a period shall be highest Demand for any hour during

the period.

2.15 Planning Reserve Level of a Party shall be the MW amount of required

reserve capacity for a Party established by the Reliability Coordinator or by the Party

consistent with Good Utility Practice, expressed as a percentage of the Party’s forecasted

Load Responsibility.

2.16 Reliability Coordinator shall mean the entity that is the highest level of

authority that is responsible for the reliable operation of the System.

2.17 Reliability Requirements shall mean the applicable rules, requirements,

and standards promulgated by the Reliability Coordinator that govern the safe and

reliable operation of the System.

2.18 Surplus Energy shall mean Energy Resources available to a Party from its

Capacity Resources in excess of the Party’s Load Responsibility in any period.






2.19 System shall be the:

(a) Capacity Resources and Energy Resources owned, operated, and

controlled by the Parties;

(b) the interconnection equipment connecting the Generating Units to

the transmission grid or the transmission grid to the distribution facilities;

(c) the transmission rights necessary to transmit energy; and

(d) the distribution facilities utilized to serve the load that are owned

or operated by or for the benefit of the Parties.

2.20 System Purchases shall mean all purchases of capacity, energy, and

ancillary services from a third party to serve Load on the System.

ARTICLE III

BLACK HILLS POWER’S

SERVICE AS AGENT FOR CHEYENNE LIGHT

3.01 Agency

Subject to the terms of this agreement, Cheyenne Light appoints Black Hills

Power as its Agent for the purpose of performing the applicable duties set forth in Section

3.02.

3.02 Duties of Agent

In its capacity as Agent for Cheyenne Light, Black Hills Power shall perform the

following duties in accord with Good Utility Practice:

(a) Coordinate and direct the Economic Dispatch of the System,






(b) Arrange for Balancing Authority services through the Western Area

Colorado Missouri Balancing Authority (WACM) as needed on behalf of

Cheyenne Light, including but not limited to, regulation and frequency

response service and energy imbalance service. The WACM charges for

this service shall be included in the Black Hills Power’ fee on a pass

through basis;

(c) Monitor System conditions, perform periodic security assessments

consistent with Reliability Requirements and Good Utility Practice, and

take appropriate actions to maintain the reliability of the System through

generation control and load balancing;

(d) Arrange for the delivery of energy to Cheyenne Light as needed to meet

Cheyenne Light’s Load at a cost pursuant to Schedule C;

(e) Plan, coordinate, and schedule System Purchases;

(f) Obtain transmission service, including Ancillary Services, as necessary to

deliver energy to satisfy Cheyenne Light’s Load Responsibility;

(g) Plan for Cheyenne Light Capacity Resource and Energy Resource

requirements on a System-wide basis consistent with Reliability

Coordinator requirements, applicable regulatory requirements, and Good

Utility Practice;

(h) Develop all capacity and energy bills and billing-related information

between the Parties and with other wholesale transacting entities;






(i) Manage the reserve requirements for Cheyenne Light; and

(j) Engage in such other activities, or perform such other duties, as assigned

by the Parties by mutual agreement.

3.03 Reporting to Cheyenne Light

Black Hills Power shall communicate regularly with Cheyenne Light personnel

responsible for Cheyenne Light system operations and reliability and provide periodic

reports of its activities under this Article of the Agreement to Cheyenne Light, in a format

agreed upon by the Parties, at least on a monthly basis. Black Hills Power shall promptly

notify Cheyenne Light of situations or problems that may affect the reliability of the

Cheyenne Light system or that may adversely affect the performance of Black Hills

Power’s duties under this Article of the Agreement. Black Hills Power shall also provide

to Cheyenne Light, in such detail as is reasonably requested, reports on specific issues or

projects arising out of its duties under this Article of the Agreement.

3.04 Compensation of Agent

Cheyenne Light shall compensate Black Hills Power for the services specified in

this Article of the Agreement in accordance with Schedule A.

3.05 Reimbursement of Agent

Cheyenne Light shall reimburse Black Hills Power for its purchases and outlays

on behalf of Cheyenne Light for the services specified in this Article of the Agreement

pursuant to Schedule C. For Black Hills Power’s purchase of capacity, energy, and

ancillary services to serve both Parties’ Load in any hour, the costs of such purchases






shall be apportioned on the basis of the relative demands on each Party’s portion of the

System.

ARTICLE IV

MUTUAL OBLIGATION

4.01 Responsibility for Adequate Resources

Each Party shall own, or have available to it under contract, such Capacity

Resources and Energy Resources as are reasonably predicted to be necessary to supply its

Load Responsibility and its Planning Reserve Level.

ARTICLE V

SURPLUS ENERGY

5.01 Surplus Energy Sales

Cheyenne Light will sell Surplus Energy to Black Hills Power in accordance with

Schedule D, which schedule may be updated from time to time by mutual agreement of

the Parties.

ARTICLE VI

GENERAL

6.01 Regulatory Authorization

This Agreement is subject to certain regulatory approvals and each Party shall

diligently seek all such necessary regulatory authorization.






6.02 Effect on Other Agreements

This Agreement shall not modify the obligations of either Party under any other

agreement between the Parties that is in effect as of the date of this Agreement, or the

obligation of others not parties to this Agreement.

6.03 Schedules

The basis of compensation or payment between the Parties under this Agreement

shall be in accordance with arrangements agreed upon from time to time between the

Parties. Such arrangements shall be in the form of Schedules, each of which, when

signed by the Parties thereto, and approved or accepted, where necessary, by appropriate

regulatory authority, shall become a part of this Agreement.

6.04 Billings

Bills for services rendered hereunder shall be calculated in accordance with

applicable Schedules, and shall be issued on a monthly basis for services performed

during the preceding Month.

6.05 Waivers

Any waiver at any time by either Party of its right with respect to a default under

this Agreement, or with respect to any other matter arising in connection with this

Agreement, shall not be deemed a waiver with respect to any subsequent default or

matter. Any delay, short of the statutory period of limitation, in asserting or enforcing

any right under this Agreement, shall not be deemed a waiver of such right.






6.06 Successors and Assigns

This Agreement shall inure to the benefit of and be binding upon the Parties only,

and their respective successors and assigns, and shall not be assignable by either Party

without the written consent of the other Party.

6.07 No Third Party Beneficiaries

This Agreement does not create rights of any character whatsoever in favor of any

person, corporation, association, entity, or power suppliers, other than the Parties, and the

obligations herein assumed by the Parties are solely for the use and benefit of said

Parties. Nothing in this Agreement shall be construed as permitting or vesting, or

attempting to permit or vest, in any person, corporation, association, entity, or power

suppliers, other than the Parties, any rights hereunder or in any of the Generating Units or

other assets owned by the Parties, or the use thereof.

6.08 Amendment

It is contemplated by the Parties that it may be appropriate from time to time to

change, amend or supplement this Agreement. This Agreement may be changed,

amended, modified or supplemented by an instrument in writing executed by both of the

Parties after approval or acceptance for filing, if necessary, by the appropriate regulatory

authorities.

6.09 Liability and Indemnification

Subject to any applicable state or federal law which may specifically restrict

limitations on liability, each Party shall defend, indemnify, hold harmless, and release the






other Party, and their directors, officers, and employees, from and against any and all

liability for loss, damage, or expense alleged to arise from, or incidental to, injury to

persons, and/or damage to property in connection with its facilities or the production or

transmission of energy by or through such facilities. In no event shall one Party be liable

to the other Party for any indirect, special, incidental, or consequential damages with

respect to any claim arising out of this Agreement.

6.10 Regulatory Changes or Approvals.

If any regulatory agency having jurisdiction over either Party passes laws or

regulations that make the obligations of this Agreement vary in any way other than that

originally contemplated, then the Parties shall take such additional action as may

reasonably be required to promptly comply with the change in law and obtain any

additional required approvals. In the event such change or approval is not acceptable to

either party, the objecting party may terminate this Agreement by three months prior

written notice to the other party and after satisfaction of any and all outstanding

obligations.

6.11 Governing Law

The validity, interpretation and performance of this Agreement and each of its

provisions shall be governed by the applicable laws of the State of South Dakota.






6.12 Section Headings

The descriptive headings of the Articles and sections of this Agreement are used

for convenience only, and shall not modify or restrict any of the terms and provisions

thereof.

(The remainder of page is intentionally left blank)

(Signature page to follow)

Black Hils Power, Inc.Electric Rate Schedule FERC No. 34Cheyenne Light, Fuel and Power CompanyElectric Rate Schedule FERC No. i


IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed and

attested by their duly authorized offcers on the day and year first above written.

BLACK HILLS POWER, INe. CHEYENN LIGHT, FUEL & POWERCOMPAN

~c¥~ç:~Its: Senior Vice President, Its: President and COOGeneral Counsel

Issued by: Steven J. HelmersSenior Vice President and General Counsel

Issued on: February 23,2007

Effective Date:






SCHEDULE A Compensation of Agent

Generation Dispatch and Scheduling Services

Agent shall be compensated for these services on a monthly basis, based upon the

Agent’s annual generation dispatch department operations and maintenance costs

(Departmental Costs). The total Department Costs will be allocated based upon a ratio

share of each Party’s Capacity Resource, as shown in Schedule B.

Regulation and Energy Imbalance Services

These services will be provided by the Balancing Authority which serves, or will

serve, the combined Cheyenne Light and Agent’s loads and resources. The current

Balancing Authority is WACM. The Balancing Authority will bill Agent on a monthly

basis for these services and Cheyenne Light will reimburse Agent accordingly. The

Parties will each be responsible for their allocated share of these costs based upon the

load ratio share of each Party’s monthly scheduled energy as compared to the Parties’

combined total monthly scheduled energy.






SCHEDULE B Capacity Resources

Power Plan Capacity—Black Hills Power Ben French 25 MW Ben French Diesels 10 MW Ben French CTs 100 MW Lange CT 40 MW Neil Simpson I 21.8 MW Neil Simpson II 91 MW Neil Simpson CT 40 MW Osage 34.5 MW Colstrip Long Term Purchase 50 MW Wyodak 20% 72.4 MW TOTAL 484.7 MW Power Plant Capacity—Cheyenne Light Wygen II 95 MW Wygen I 60 MW Gillette CT 40 MW TOTAL 195 MW






SCHEDULE C Capacity, Energy, and Transmission Pricing From Black Hills Power to Cheyenne Light

The price of capacity and energy secured by Black Hills Power on behalf of

Cheyenne Light shall be based on Black Hills Power’s incremental cost if supplied by

Black Hills Power, and based on Black Hills Power’s actual cost if secured from a third

party, plus applicable taxes. The price of transmission secured by Black Hills Power on

behalf of Cheyenne Light shall be based on Black Hills Power’ actual cost, plus

applicable taxes






SCHEDULE D Pricing of Surplus Energy from Cheyenne Light to Black Hills Power

During periods when Cheyenne Light has resources in excess of its load, Black

Hills Power will purchase the Surplus Energy on an hourly basis. The price of Surplus

Energy supplied to Black Hills Power will be the variable cost under the Power Purchase

Agreement Between Black Hills Generation, Inc. and Cheyenne Light, Fuel and Power

Company under Black Hills Generation, Inc.’s FERC Electric Tariff, Original Volume

No. 1, Original Service Agreement No. 2. Following expiration of the Wygen I PPA, the

Parties will mutually agree to a price for Surplus Energy.

Jnofflclal FERC-Generated PDF of 20071214-0086 Received by FERC OSEC 12/13/2007 in Docket#: ER07-943-001

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DUPLICATE

C O U ~ ' S I [ L O l l S A T L A W

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December 13, 2007

VIA HAND DELIVERY

Hon. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, DC 20426

RE: Black Hills Power, Inc. Cheyenne Light, Fuel and Power Company Docket No. ER07-943- OQ/

! f - .

• . - . ,

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Dear Ms. Bose:

On May 29, 2007, Black Hills Power, Inc. (''Black Hills Power"), and Cheyenne Light, Fuel and Power Company ("CLFP") submitted for filing with the Federal Energy Regulatory Commission ("FERC") a Generation Dispatch and Energy Management Agreement ("Agreement") between Black Hills Power and CLFP. Black Hills Power and CLFP requested FERC to accept the Agreement effective as of 1anuary 1, 2008. At the request of FERC Staf~ Black Hills Power and CLFP supplement their May 29th filing to provide FERC with additional information about the Agreement.

The Agreement provides, among other things, that Black Hills Power will perform generation dispatch and energy management services to manage the dispatch of Black Hills Power's and CLFP's generating resources on a syste=n-wide, least-cost basis. By incorporating CLFP into its generation dispatch and energy management system, Black Hills Power will integrate CLFP's generating resources and loads into its resource and demand mix and provide CLFP with hourly load-following service. Black Hills Power will assess CLFP an allocated share of its generation dispatch and energy management operational costs as consideration for its services under the Agreement. Black Hills Power will not mark up its costs and therefore it will not earn a profit on the generation dispatch and energy management services it will provide to CLFP. May 29th Filing at 3.


Hon. Kimberly D. Bose December 13, 2007 Page 2

C O ~ N g | L O B | & ~ L & W

FERC Staff has asked Black Hills Power and CLFP to provide additional information about the charges Black Hills Power will assess CLFP for the provision of services under the Agreement. As noted, Black Hills Power will assess CLFP an allocated share of its generation dispatch and energy management operational costs as consideration for its services under the Agreement. The generation dispatch and mergy management services that Black Hills Power will provide include reliability management, load forecasting, economic dispatch, energy imbalance and load following, transmission schedulIng, and accounting services. Black Hills Power will modify its resource management software to include CLFP's loads and resources. The expenses Black Hills Power will incur in perform'rag generation dispatch and energy management services for itself and CLIP will be accounted for in Accounts 556, 926, or other appropriate accounts based on the actual duties performed by department personnel or the type of expense incun-ed by the department in the performance of those duties, such costs to be allocated to the appropriate FERC account based on the description for each such account in FERC's Uniform System of Accounts regulations, 18 C.F.R. Part 101. Such treatment is memorialized in a revised Schedule A to the Agreement, which is provided as Attachment A to this letter. For illustrative purposes, Attachment B to this letter provides a pro forma schedule of generation dispatch and scheduling cost detail for a test year ending September 30, 2006, that shows how a pro rata share of such costs would be allocated to CLFP under the AgreemenL

The Agreement further provides, among other things, that CLFP will sell all its surplus energy to Black Hills Power. CLFP expects to have surplus energy available to it in the next few years (for 2008, CLFP expects to have approximately 180,000 MWH of surplus energy), most of it expected to be available during off-peak hours. Under the Agreement, CLFP will sell that surplus energy to Black Hills Power at a price equal to the variable rate under one of CLFP's power purchase agreements with Black Hills Wyoming. May 29th Filing at 3-4.

In the May 29th filing of the Agreement, Black Hills Power committed that it will use the power procured from CLFP under the Agreement to displace higher-cost energy resources from its supply stack used to serve its customers, freeing up higher-cost energy that Black Hills Power can market in off-system wholesale transactions. Specifically, as Black Hills Power buys surplus energy from CLFP, Black Hills Power will add that energy to the resource stack available to it to serve its customers. Under its internal policies and practices, Black Hills Power serves its customers using the leust-cost resources available. During times when Black Hills Power is purchasing energy to serve its customers, if energy procured from CLFP is less expensive than the energy Black Hills Power is using to serve its customers at the time of the purchase, that lower-cost energy from CLFP will displace higher-cost energy from other resources, allowing Black Hills Power's customers to benefit fxom the lower-cost energy. Black Hills Power will offer the higher-cost power to the markets. May 29th at 4.

FERC Staff has asked Black Hills Power and CLFP to memorialize in the Agreement Black Hills Power's commitment that it will use the power procured from CLFP under the Agreement to displace higher-cost energy resources from its supply stack used to serve its customers. In response to Staff's request, Black Hills Power and CLFP have amended Schedule


Hon. Kimberly D. Bose December 13, 2007 Page 3

G O U N S | L O I | A T L A W

D to the Agreement to memorialize Black Hills Power's commitment with respect to its use of power procured from CLFP. The revised page of the Agreement is provided as Attachment C.

For the reasons explained in their May 29th filing of the Agreement and the further reasons provided above, Black Hills Power and CLFP request FERC to accept the Generation Dispatch and Energy Management Agreement effective as of January 1, 2008. Black Hills Power and CLFP request waiver of any FERC regulations necessary to make the Agreement effective as of January 1, 2008.

Black Hills requests FERC to establish a shortened notice period of not more than ten (I0) days for this submission of supplemental information. No party will be pr~udicod by granting the requested notice period because this submission merely provides additional information with respect to Black Hills Power's and CLFI"s Agreement. Moreover, Black Hills Power and CLFP have requested a January 1, 2008, effective date for the Agreement, so a shortened notice period and prompt consideration is needed. Good cause therefore exists for a shortened notice pe~od.

Michael C. Griffen Attorney for Black Hills Power, Inc., and Cheyenne Light, Fuel and Power Company

Attachments


ATTACHMENT A


Black Hills Power, Inc. Ehxqric Rate Schcclule FERC No. 34 Cheyenne Light, Fucl and Power Company Electric Rate Schedule FERC No. 1

First Substitute Sheet No. 17 Superseding Original Sheet No. 17

SCHEDULE A Compensation of Agent

Generation Dispatch and Schedul/ng Services

Agent shall be compca~ated for these services on a monthly basis, based upon the

Agent's generation dispatch department operations and maintenance costs (Monthly

Departmental Costs). Monthly Departmental Costs will be determined by totaling the costs

accrued by the Agent in that month in Department 13 as identified in the Agent's accounting

system. Department 13 will then record its costs to FERC Accounts 556, 926, or other

appropriate accounts based on the actual duties performed by department personnel or the type of

e x ~ incurred by the department in the tm'formancc of those dutes, such costs to be allocated

to the appropriate FERC account based on the description for each such account in FERC's

Uniform System of Accounts regulations, 18 C.F.R. Part 101. The total monthly Departmental

Costs will be allocated based upon a ratio share of each Party's Capac/ty Resource, as shown in

Schedule B.

Regulation and Energy Imbalance Services

These services will be provided by the Balancing Authority which serves, or will serve,

the combined Cheyenne Light and Agent's loads and resources. The current Balancing

Authority is WACM. The Balancing Authority will bLll Agent on a monthly basis for these

services and Cbeyermc Light will reimburse Agent accordingly. The Parties will each be

responsible for thc/r allocated share of these costs based upon the load ratio share of each Party's

monthly scheduled energy as compared to the Parties' combined total monthly scheduled energy.

Issued by:. Stcven J. Helmets Sen/or Vice Pr'esidcnt and Ge~ncral Counsel

Issued on: December 13, 2007

Effective Date: January I, 2008


[ Black Hills Power, Inc. Electric Rate Schedule FERC No. 34 Cheycmne Light, Fuel and Power Company Electric Rate Schedule FERC No. I

• " heet No. 17 SuoeNeding Ortotnml Sheet NQ, 17

SCHEDULE A Compensat ion of Agent

Generation Dispatch u d Scheduling Services

Agent shall be compensated for these services on a monthly basis, based upon the

Agent 's mmmfl-generation dispatch department operations and maintenance costs (Monthly

Departmental Costs). Monthly Denartm~n~al Costs will be determined by totnlinu the eost~

s e e m e d by the Apent in that month in DeDartment 13 as identified in the Apent 's

8G~unflng ~ s t e m . Denar tment 13 will then record |tu comm to FERC Aeeoun~ 256. 926. or

other unnronrlate aceount~ baaed on the actual duffel nerformed by denar tment nersnnnel

or the tvne of exoense Incurred by the dcoar tment in the nerformmnee of those dutes, w e h

costs to be allocated to the aunrourta te FERC account based on the doserintlou for each

such account in FERC's Uniform System of Accounts remdatiouL 18 C.FAL Part 101.

The total monthly Department/I ] Costs will be allocated based upon a ratio share o f each Party's

Capacity Resource, as shown in Schedule B.

Regulation u d Energy Imbalance Services

These services will be lXOVided by the Balancing Authority which serves, or will serve,

the combined Cbeyexme Light and Agent 's loads and resources. The current Balancing

Authority is WACM. The Balancing Authority will bill Agent on a monthly basis for these

services and Cheyenne Light will reimburse Agent accordingly. The Parties will each be

responsible for their allocated share o f these costs based upon the load ratio share of each Party's

monthly scheduled energy as compared to the Parties' combined total monthly scheduled energy.

Issued by: Steven J. Helmets Senior Vice President and General Counsel

Issued on: Mey-~lk.cember D. 2007

Effective Date: January 1, 2008


ATTACHMENT B


CHEYENNE LIGHT, WUEL AND POWER COMPANY Geueraflon Dilq~tch and Sclu~duffng Cost De/a/I - gkeh'/c For the Pro Forms Tzst Year Ended September 30, 2006

Page 1 of I

Line No...~ Description Reference Total Cost

1 2 3 4 5

• 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41

Costs Related to Generation Dispatch and Scheduling Labor Labor Overhead Materials end Supplies Overhead on Supplie* Other Non-lnve~ntory Supplies C ~ Services Meah & Eatertainment Led g Dues & Subscriptions Miscellaneous Exp Othe~ Travel Expenses

Total C, os~ Related to Generation Disi~tch and Schedul/n8

Note I $ 859,032

515,419 1,200

228 6,900

255,572 17,800 27,420 44,800 3,000

511400 $ 1,782,771

Powe~ Plant Cap~ty - Black Hills Power (MW) Ben French Ben French Diesels Ben French CT's l-ange C r Nell Simp~on 1 Nell Simpson I1 Neil Simpson CT

Colstrip Long-Term Purchase Wyodak 200/0

Total Power Plant Capacity - Black Hills Power (MW)

Note 2 25.00 10.00

100.00 40.00 21.80 91.00 40.00 34.50 50.00 72.40

484.70

Power Plant Capacity - Cheyenne Light (MW) Wygen II Wygon I (Purchase Powe~ Agleeme~t ) CT II (Pm'c~..se Power Agreement)

Total Power Plant Capacity - Cheyenne Light (MW)

Note 2 lO0.OO 60.00 40.00

200.00

Combined Capacity - Black Hills Power and Cheyenne Light line 26 + line 32 684.70

Cheyenne Percent of ~ity line 32 + line 34 29.21%

Amount to be Charged to Cheyenne Light line 13 x line 36 $ 520r747

Note (1) ToUd generation ~ and ~w, hedulm8 cos~ obutined from 2007 approved budget from the Black Hills Power Generation Dispa~h and Scheduling depemnent.

42 Note (2) Cos~ from Black Hills Power Genc~'a~on D i ~ c h and Scheduling are al~ocawd bas~ on the generation 43 asset's load ratio.


A]~I'ACHMENT C


Black Hills Power, Inc. Electric Rate Schedule FERC No. 34 Cheyenne Light, Fuel and Powe~ Company Electric Rate Schedule FERC No. I

First Substitute Sheet No. 20 Superseding Original Sheet No. 20

SCHEDULE D Pricing of Surplus Energy from Cheyenne Light to Black llllh Power

During periods when Cheyenne Light has resource, in excess of its load, Black Hills

Power will purchase the Surplus Energy on an hourly basis. The price of Surplus Energy

supplied to Black Hills Power will be the variable cost under the Power Purchase Agreement

Between Black Hills Generation, Inc. and Cheyenne Light, Fuel and Power Company under

Black Hills Generation, Inc.'s FERC Electric Tariff, Original Volume No. 1, Original Service

Agreement No. 2. Following expiration of the Wygen I PFA, the ParSes will mutually agree to a

price for Surplus Energy.

Black Hills Power commits that when it is purchasing power to serve its customers, it

will use the power procured from Cheyenne Light under this Agreement to displace higher-cost

energy resources from its supply stack used to serve Black Hills Power's customers.

Issued by: Steven J. Hdmers Senior Vice President and General Counsel

Issued on: December 13, 2007

Effective Date: J~,Imh-y I, 20)8


Black Hills Power, Inc. Electric Rate Schedule FERC No. 34 Cheyenne Light, Fuel and Power Company Electric Rate Schedule FERC No. 1

First SubstltuteO~e~mal Sheet No. 20 Sunersedinu Original Sheet No. 20

SCHEDULE D Pricing of Surplus Energy from Cheyenne Light to Black l t l lh Power

During periods when Cheyenne Light has resources in excess of its load, Black Hills

Power will purchase the Surplus Energy on an hourly basis. The price of Surplus Energy

supplied to Black Hills Power will be the variable cost under the Power Purchase Agreement

Between Black Hills Ganeration, Inc. and Cheyenne Light, Fuel and Power Company under

Black Hills Generation, Inc.'s FERC Electric Tariff, Original Volume No. 1, Original Service

Agreement No. 2. Following expiration of the Wygen I PPA, the Parties will mutually agree to a

price for Surplus Energy.

Black II|11~ Power comml~ that when It Is nurehMin~ nower to serve its customerL

it will use the nower orocured from Cheyenne Light under this Am'cement to disolace

higher-cost energy resource~ from its sunnlv stack used to serve Black HilIt ~)QIYCi",I

Issued by: Steven J. Helmen Senior Vice President and General Counsel

Issued on: M 4 ~ 2007

Effective Date: January 1, 2008

Direct Testimony Laura Patterson





December 1, 2011

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TABLE OF CONTENTS

I. Introduction And Qualifications .....................................................................................1

II. Purpose Of Testimony.....................................................................................................3

III. Compensation Philosophy And Programs ......................................................................4

IV. Company Annual Incentive Plan ....................................................................................7

V. Industry Compensation Comparisons ...........................................................................13

VI. Company Recovery Of Employee Compensation Expenses .......................................15

VII. Company Benefits And Periodic Review .....................................................................17

VIII. Collective Bargaining Agreement Between The Company and IBEW Local 111.......20

IX. Schedule H-2 Adjustments............................................................................................22

I. INTRODUCTION AND QUALIFICATIONS 1

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Q. PLEASE STATE YOUR NAME, BY WHOM YOU ARE EMPLOYED, AND

COMPANY ADDRESS.

A. My name is Laura A. Patterson and I am employed by Black Hills Corporation (“BHC”

or “Corporation”). My business address is 625 9th Street (4th Floor), Rapid City, SD

57701.

Q. PLEASE DESCRIBE YOUR POSITION WITHIN THE COMPANY AND AREAS

OF RESPONSIBILITY.

A. I am the Director of Compensation, Benefits and Human Resources Information Systems

(“HRIS”) for BHC. In my position, I am responsible for partnering with business leaders

to design and execute compensation and benefits strategies and plans. I also provide input

related to strategic planning, implementation and administration of compensation and

benefits programs, executive plans, equity programs, non-qualified plans and other

initiatives. My responsibility would also cover employees working for Cheyenne Light,

Fuel and Power Company (“Cheyenne Light” or “Company”).

Q. WOULD YOU BRIEFLY SUMMARIZE YOUR ACADEMIC AND

PROFESSIONAL BACKGROUND?

A. I have more than 20 years of experience in compensation and benefits, with

responsibilities including the development, management, administration and regulatory

compliance of such plans. I began my current position as Director of Compensation,

Benefits and HRIS for BHC in April 2009. Prior to this position, I spent 6 years as

Director of Compensation, Benefits and HRIS and 2 years as Employee Benefits

Manager, for PNM Resources, Inc. (PNMR), where I was responsible for managing and

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administrating all compensation and benefit programs for PNMR, its subsidiaries and for

its joint venture business with Cascade Investments, Optim Energy. Prior to working for

PNMR, I was employed as a Tax Manager and Human Capital Consultant for four years

at Arthur Andersen, a global tax and consulting firm. In this position, I worked with

organizations to identify, analyze and apply regulatory rules that govern structure,

compliance, and administration of employee benefit plans. Prior to Arthur Andersen, I

was employed as a Trust Officer at Mercantile Trust Company from 1995 to 1999. My

primary responsibilities included managing, administration of, and the sales of profit

sharing, 401(k), and money purchase retirement plans sponsored by a wide range of

clients. I have a Bachelor of Business Administration degree from the University of Iowa.

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Q. HAVE YOU PROVIDED TESTIMONY IN REGULATORY PROCEEDINGS

PRIOR TO THIS CASE?

A. Yes. I have previously testified in New Mexico PRC Case No. 06-00210-UT, a gas rate

case, in New Mexico PRC Case No. 07-00077-UT, an electric rate case, in Texas PUC

Case Docket No. 36025, an electric rate case, in Nebraska PUC Case Docket No. NG-

0061, a gas rate case, as well as in Colorado PUC Case Docket No. 11-AL-382E, an

electric rate case.

Q. PLEASE DESCRIBE YOUR PROFESSIONAL ASSOCIATIONS.

A. I serve on the Corporate Board of Directors of the International Foundation of Employee

Benefit Plans and serve on the Employee Benefits Committee for the U.S. Chamber of

Commerce. I am also a Certified Retirement Services Professional.

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A. I describe and support the general compensation program for BHC employees, and

particularly the employees of the applicant, Cheyenne Light including the variable

compensation program. I also explain why those programs and their associated costs are

reasonable and necessary to attract, motivate and retain well qualified and competent

employees to support utility operations and support recovery of the compensation-

related expenses of Company employees.

I also describe and support the general benefits programs and policies for BHC

employees, particularly the employees of the applicant, Cheyenne Light, including the

health, welfare and retirement benefits, and explain why those programs and their

associated costs are reasonable and necessary.

My testimony discusses and supports the additional costs related to the ratified

Collective Bargaining Agreement between Cheyenne Light and the IBEW Local 111.

My testimony specifically supports the following employee compensation related

adjustments contained on Schedule H-2 of the Cheyenne Light’s revenue requirement

model:

• Retiree Healthcare

• Pension Plan

• Pooled Medical

• 401k Plan

• Profit Sharing Plan (component of the 401k)

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III. COMPENSATION PHILOSOPHY AND PROGRAMS 1

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Q. WHAT IS BHC’S GENERAL COMPENSATION PHILOSOPHY?

A. BHC’s compensation philosophy is designed to attract, retain, and motivate employees

to achieve appropriate business results. All compensation programs are designed to meet

the following principles:

• Strategically Aligned – compensation practices reinforce each business segment’s

business strategy, structure, needs and culture.

• Externally Competitive – Each component of compensation (including base and

variable compensation) should be competitive at the median of the relevant labor

market. Base pay is intended to compare to the market median of the labor

market and reflect the individual’s sustainable performance levels over time.

Variable compensation should also compare to the market median and reflect the

individual’s contribution to business unit and Company results.

• Internally Equitable – pay grades assigned to jobs within the Company should

fairly reflect their value relative to other jobs in the Company. The metrics

utilized for recognizing performance should inspire confidence in BHC among its

employees, customers and the communities it serves.

• Personally Motivating – The compensation system should recognize employees

based on differences in individual contribution.

• Cost Effective – programs are designed to provide maximum value to BHC and its

customers in relation to the cost involved.

• Legally Defensible – programs are in compliance with all applicable state and

federal laws and regulations.

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Q. PLEASE DESCRIBE THE COMPANY’S COMPENSATION PROGRAMS. 1

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A. There are two primary components to the compensation program – Base Salary and

Variable Pay programs.

• Base Salary: Represents the fixed portion of an employee’s total cash

compensation opportunity. Base salary compensation is determined by the

market value of the job, specific performance standards and competencies. Base

salaries are reviewed on an annual basis and merit salary increases (for non-union

employees) are based on individual performance and contributions.

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• Variable Pay: Variable Pay is pay at risk that is earned and is not fixed or

guaranteed. BHC employees participate in the Annual Incentive Plan (AIP)

which is described in detail later in this testimony.

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Q. PLEASE EXPLAIN THE COMPANY’S PHILOSOPHY ON BASE PAY

COMPENSATION.

A. Base pay is intended to reflect the median of the market for similar positions in similar

companies. There are twenty-three (23) pay grades which are used for all non-executive

jobs in Wyoming. Each grade has a minimum, midpoint, and a maximum pay level.

This means that the pay ranges within the grades are competitive with what other

companies pay for similar positions. All jobs are compared to the market, where data

exists, and placed in the grade where the midpoint of the range is closest to the average

market rate for that job. BHC implemented a unified salary structure in 2009. Towers

Watson conducted an independent market review of the Company’s positions in 2009 and

benchmarked each position to a BHC salary grade based midpoints, which were designed

to closely reflect the market median values. Subsequent to the market review of all

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positions in 2009, the Human Resources Compensation Department periodically reviews

each position in the company to ensure that current compensation remains within the

competitive range.

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Market rates are determined by utilizing compensation survey data where companies

report actual compensation paid to employees by position. The survey most widely used

by BHC is from Towers Watson, as they are recognized nationally as the leader in the

energy services / utility market place. BHC also utilizes surveys conducted by Aon

Hewitt, Mercer, the American Gas Association (AGA), EAPDIS, LLC, the Edison

Electric Institute (EEI), ECI and other surveys, including several specific to wages by

state. The surveys provide compensation and other data for each position by company

size, revenue, and number of employees so that BHC can match each of its positions to

positions in the market that are most similar in duties and most similar for the company

size/revenue. An employee’s pay moves within the range based upon their performance,

level of skills, training or education required, and their time in the job. The BHC

Compensation Department reviews the pay structure annually to see how the structure

and pay practices reflect the market. As of November 2011, the average base pay for

non-union employees in Wyoming was 97% of the market median, indicating BHC

employees’ base pay rates were slightly below but within acceptable range of the market

median. The data source utilized in BHC’s market comparison analysis is primarily the

Towers Watson compensation data.

Q. DOES BHC HAVE A VARIABLE COMPENSATION COMPONENT OF ITS

TOTAL COMPENSATION PHILOSOPHY?

A. Yes. The Black Hills Corporation Annual Incentive Plan (the "AIP" or the "Plan", a/k/a

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the “Unified Incentive Plan” or “UIP”) is designed to motivate and reward employees for

achieving and exceeding goals that benefit our customers and our shareholders. The

Annual Incentive Plan is designed to reward eligible employees, including employees of

Cheyenne Light, who contribute to the success of the Black Hills Corporation and/or their

assigned subsidiary (also referred to as business unit); reward employees who contribute

to the quality of service provided to customers including, but not limited to, the provision

of safe, reliable and affordable service; motivate work performance and behavior that

supports the Corporation's financial and non-financial goals and increase the employee's

understanding of the Corporation's business objectives and performance.

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IV. COMPANY ANNUAL INCENTIVE PLAN 10

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Q. PLEASE DESCRIBE BHC’S ANNUAL INCENTIVE PLAN.

A. The purpose of BHC’s Annual Incentive Plan is to promote the Company’s pay for

performance philosophy, to provide competitive incentive opportunities that are

consistent with other companies in the industry, and to focus employees on important

performance objectives. BHC’s Annual Incentive Plan helps to ensure its total pay

position is competitive with market practices for BHC employees, that its total

compensation expense varies with the Company’s performance on measures important to

the customers, and provides a tool to align employees’ interests with customer and

community interests.

Q. WHAT PERFORMANCE GOALS ARE MEASURED UNDER THE AIP?

A. An eligible employee can earn an incentive award based on that employee’s performance

toward goals designed to achieve business unit operational performance targets. The

components of the incentive award are as follows:

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• An employee can qualify for up to 50% of the maximum possible award for goals

tied to customer satisfaction, cost control, safety, reliability, operations efficiency,

and other business unit operational measures;

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• An employee can qualify for up to 25% of the maximum possible award for the

achievement of business unit financial performance; and

• An employee can qualify for up to 25% of the maximum possible award if the

Company realizes established earnings per share (“EPS”) targets.

Each goal is measured independently and goal performance that meets or exceeds the

threshold level will be used to calculate the incentive award. Achievement of financial

results is not a condition to award incentive for achievement of other goals. An employee

can earn from 0% to 150% of the target percentage incentive based on achievement

against these goals. Performance below threshold results in a zero payout for the

associated goal. Achievement of the “target” performance on the goal results in a payout

of 100% of the payment relative to that goal. There is also a Maximum payout, which

means that if performance exceeds target, up to 150% of the target payment will be made

relative to that goal.

Q. HOW DOES THE AIP PROVIDE VALUE TO CUSTOMERS?

A. The AIP provides direct and indirect value to customers in a number of different ways.

For example, AIP goals are aligned with the Company’s high-level objectives and

strategic framework. Business unit goals are primarily designed to improve the

performance of utility operations by focusing on improvements to safety, reliability, and

customer satisfaction. Examples of Cheyenne Light’s business unit goals include:

• Continuous improvement in results from customer satisfaction surveys. These

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results are measured each quarter. 1

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• Service reliability metrics.

• Increase in number of completed service orders per day.

• Reduction in labor cost per service order.

• Meeting and exceeding occupational training standards.

• Reduction in number of lost time accidents, preventable vehicle accidents, and

OSHA recordable accidents.

However, it is important to understand that although actual base salaries for the

Company’s employees are slightly lower than market median levels, compensation would

not be competitive without the incentive plan component. An employee’s total cash (base

salary plus AIP award) earnings potential depends on both competitive base salary and on

a competitive AIP incentive compensation opportunity based on the achievement of key

operating and strategic goals. If BHC did not offer employees and officers the

opportunity to earn AIP incentive compensation, BHC would need to make-up the

difference by increasing base salaries in at least an equivalent amount, which would

result in higher fixed costs for salaries and benefits. An alternative to variable

compensation would be for BHC to raise all employees base pay to reflect the median

variable compensation earnings provided by other utilities. While this would provide a

competitive total compensation rate that is “fixed and measurable”, it would de-link those

costs with customer performance measures and increase overall costs as many of our

benefits are also tied to base pay rates. Instead, BHC’s AIP incentive is beneficial for the

customers, as it focuses employee activities on the Customer whether all of the Company

and personal objectives are met or not. Attracting and retaining a highly skilled and

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experienced workforce enables BHC to continue to provide service that is efficient,

effective, safe and reliable and helps avoid high costs associated with employee turnover.

AIP business unit goals support the strategic objectives of the Company, which include

achieving high levels of customer satisfaction, improving operations and safety, and

delivering excellent service.

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The AIP also provides direct and indirect benefits to customers in that BHC has a

common pay structure for all of its business units. This means that BHC can more easily

relocate employees among company business units, reduce the cost of maintaining

numerous payroll systems, reduce the cost of training employees on benefits, and better

manage the cost of administrating compensation plans than would be possible with

multiple compensation schemes. If any business unit had a different pay structure than

the other business units, it would lead to increased costs to customers.

Q. WHO IS ELIGIBLE TO PARTICIPATE IN THE AIP?

A. All regular full-time and part-time employees, both union and non-union, who are hired

and working by October 1 of the Plan Year are eligible to participate in the Plan for that

plan year, unless participating in another incentive plan. Part-time employees who work

a minimum of 20 hours per week are eligible for a pro-rata award based on their actual

wages for hours worked. Pro-rata awards for the number of months actively employed at

each eligibility level during the Plan Year will also be paid to Participants who are newly

hired on or by October 1 of the Plan Year; who are promoted, transferred or demoted

during the Plan Year; who are on leave of absence for any full months during the Plan

Year; who are on military leave for any months during the Plan Year; who leave the

Company due to Disability during the Plan Year; who leave the Company due to

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Retirement during the Plan Year; who are laid off under a severance agreement with the

Company during the Plan Year; and who die during the Plan Year.

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Q. HOW ARE AIP AWARDS DETERMINED?

A. A set of goals with “threshold,” “target,” and “maximum” performance metrics are

established at the beginning of each calendar year for each identified business unit. The

Company establishes its incentive targets to achieve the market median incentive

opportunity of similar companies. The “Threshold” is the minimum performance level

that must be met for the year – if the Threshold is not met, no incentive payment is made

relative to that goal. Target performance for each goal is set at a level of an “expected”

result, with sufficient stretch, necessary for a successful year. The goal is to provide

Cheyenne Light’s employees with a total compensation package that is competitive with

other companies when Cheyenne Light achieves target performance levels on annual

incentive goals. Operational (non-financial) goals can be based on Reliability of Service,

Safety, Customer Service, Effective use of Capital, expense management (reductions in

controllable O&M), and Process Improvement. The “Reliability” goal can include the

“controllable outages” measure, which is commonly used as a reliability indicator by

electric utilities, and which measures the controllable outages by the utility. The “Safety”

measures include chargeable vehicle incidents and lost time injury incidents, both of

which have implications for cost and service to customers. The “Customer Service”

measure includes 5 customer service quality metrics including customer service call time

and emergency service call times. “Process Improvement” goals reflect initiatives to

reduce on-going cost of service and focuses employees on identifying additional

opportunities to increase process efficiency and effectiveness for our customers. By

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having a portion of the incentive program tied to the business unit, employees and

management are held accountable for seeing that the overall operation of the delivery of

services occurs in the most efficient manner possible. The business unit component of the

AIP ensures that management and employees understand that strong performance for the

customer unrelated to financial results will be recognized and rewarded.

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Q. PLEASE EXPLAIN WHY TYING THE AIP GOALS TO EARNINGS PER

SHARE AND OPERATING INCOME BENEFITS CUSTOMERS.

A. Earnings Per Share (EPS) and Operating Income are easily recognized benchmarks for

successful and productive companies that are meeting their customers’ needs. They

provide Company-wide objective measures of performance, and cannot reasonably be

separated from customer interest. The customers benefit directly when they are being

served by a financially secure Company which is able to meet their needs efficiently and

economically and shareholders cannot have a successful, profitable company if the

Company does not attract and retain qualified and motivated employees who strive to

meet customer expectations and requirements. One of the most readily measurable

standards of long-term financial viability is EPS.

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Company financial health and customer interests go hand in hand. Customers benefit

because the overall financial health of the Company affects its perceived financial

welfare, general economic welfare, and thus ultimately it’s financing rates. Employees

have a direct impact on EPS and Operating Income through goals and performance

relating to cost control efforts, efficiencies gained through business process improvement

projects and other work which also results in benefits to customers.

Also, it is important to remember, as noted above, the overall payment of compensation

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and benefits to employees is competitive with market rates for those employees. Thus,

the overall compensation is market competitive and drives performance results, even with

this compensation methodology included in an employee’s compensation structure.

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V. INDUSTRY COMPENSATION COMPARISONS 4

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Q. DO OTHER COMPANIES IN THE UTILITY INDUSTRY USE A

COMPARABLE VARIABLE COMPENSATION MECHANISM?

A. Yes. Other utilities do provide incentive or variable compensation as part of their

compensation packages, as do companies in other industries. Without a similar plan,

BHC’s total compensation package may not be competitive with other utilities. Aon

Hewitt Associates, an international business consulting firm that specializes in

compensation issues, conducted a survey of broad-based variable pay plans in September

2011 titled “Salary and Variable Compensation Measurement Special Report – U.S.

Edition,” which includes 70 energy / utility companies. Results from the survey indicate

the following:

• 92% of participating companies offered at least one broad-based variable

compensation plan covering 98% of total U.S. employees, an increase from 89%

in 2007 and from 80% in 2002 as companies continue to turn to variable pay as a

means to attract, retain and award performance. All 70 energy / utility companies

offer at least one broad-based incentive plan and all cover 100% of their

employees.

• 87% of the participating companies in the survey have an annual incentive

program with a plan design similar to BHC’s AIP, where awards are based on the

combined achievement of Company financial and business unit operating

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• 91% of the participating companies reported the benefits realized from their

variable pay plan and the improved business results outweighed the cost.

• Notable outcomes reported by companies with a variable pay plan similar to the

AIP include reduced costs, increased productivity, increased quality, increased

customer satisfaction, and increased employee morale.

Other surveys published in 2011 include:

• Mercer: 91% of employers provide short-term incentive or variable pay plans, an

increase from 78% in 2004.

• World at Work: 90% of employers provide short-term incentive or variable pay

plans, an increase from 77% in 2004. Of those providing a short-term incentive

plan, 98% of hourly employees (average payout was 5%) and 100% of salaried

employees (average payout was 12%) are eligible under the plan.

• Pearl Meyer & Partners: 90% of utilities in the survey provide a short-term

incentive plan to all employees.

Q. HOW DOES BHC MAKE IMPROVEMENTS TO ITS AIP?

A. Through its annual planning process, BHC routinely evaluates the effectiveness of the

plan in meeting its goals. BHC also continuously evaluates the AIP design to ensure that

it remains competitive and comparable to other utilities.

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VI. COMPANY RECOVERY OF EMPLOYEE

COMPENSATION EXPENSES

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Q. WHAT TESTIMONY DO YOU PROVIDE IN SUPPORT OF THE INCLUSION

OF INCENTIVE COMEPNSATION IN THE REVENUE REQUIREMENTS?

A. Incentive compensation is a valid and appropriate component of compensation and

therefore, is an appropriate component of compensation expense, and the customers

receive the value from these business unit goals. Incentive compensation provides

measurable results that benefit our customers, as opposed to higher fixed compensation

without regard to critical corporate and business unit performance. Incentive

compensation is a component of overall compensation and is prudent and reasonable

when compared to other utilities. Incentive compensation supports strategic company

objectives, which in turn support enhanced safety, reliability and customer service. It is a

component of BHC’s pay-for-performance philosophy and puts a portion of cash

compensation dependent on results, rather than putting it in base pay, which would result

in fixed costs paid regardless of performance. It fosters the right behaviors and shared

commitment to performance improvements for the benefits of customers and other

stakeholders. Simply put, BHC has adopted an employee compensation plan that is

designed to benefit both the shareholder and the customers. The level of overall

compensation expense is reviewed annually to determine if these levels are reasonable

and competitive. Accordingly, the components that are used to accomplish the company

goals should be left to BHC management, who are acting in good faith.

Q. SHOULD THE COMPENSATION MERIT INCREASE BE APPROVED?

A. Recovering the actual amount of employee compensation expense is necessary – as

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described above -- to attract and retain the high quality of employees that are needed to

serve the customers of Cheyenne Light. Any review should focus on whether

compensation increases for employees are within a reasonable range. Under existing

economic conditions, independent surveys reflected that more than 95% of US-based

companies awarded merit pay increases during 2011, with an average budget of 3%.

Non-union employee pay changes are effective each March, with the next scheduled

increase to be effective March 2012. Increases in employee compensation are known and

measurable, and these increases in employee compensation are supported by extensive

reviews of competitive market data.

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Without merit increases, BHC would lag the median pay for these positions, significantly

increasing retention and performance risk, and the company will incur higher costs for

turnover and related issues. A summary of independent surveys regarding merit pay

follows:

• Mercer: The “Mercer September 2011 Compensation Planning Survey” reflects

that 97% of employers plan to provide merit increases to employees in 2012, with

an average budgeted increase at 3.0%. The utility companies in the survey also

reflect a budgeted increase of 3.0%.

• Aon Hewitt: The 2012 survey reflects that 98% of employers plan 2012 merit

increases, with an average budget of 3.0%. The utilities in the survey reflect a

merit budget average of 3.3%. The average budget reported for 2011 was 3.0%.

• Towers Watson: The 2012 survey reflects that 97% of employers plan 2012

merit increases, with an average budget of 3.0%. This survey does not reflect

utility specific information. The average budget for 2011 was 3.0%, with 95% of

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employers making merit increases. 1

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• World at Work: The 2012 survey of 5,818 employers reflects a 3.0% merit

increase budget average for 2012. For those employers located in Colorado, the

merit budget is 3.0%. The average merit increase reported for 2011 was 3.0%.

Simply put, the merit increases will be incurred, the overall compensation to Cheyenne

Light’s employees are fair and competitive as tested against prevailing market

comparisons, and the compensation structure and administration of Cheyenne Light must

be approved since those costs are representative of the costs that will be incurred once the

rates are placed into effect.

VII. COMPANY BENEFITS AND PERIODIC REVIEW 10

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Q. CAN YOU DESCRIBE THE BENEFIT PLANS THAT BHC PROVIDES TO ITS

CHEYENNE LIGHT EMPLOYEES?

A. BHC offers a combination of company-provided and voluntary benefits. Employees are

enrolled in company-provided benefits automatically and BHC pays the costs (for

example, short-term and long-term disability benefits). Employees choose whether or not

to participate in the voluntary benefits and they pay a portion or all of the costs. These

voluntary benefit programs consist of: (1) medical, dental and vision plans, (2) flexible

spending accounts, (3) life insurance and accidental death and dismemberment insurance,

(4) paid time off, (5) retirement, and (6) other benefits including educational assistance,

holidays and other time away from work, business travel accident insurance, rewards &

recognition and wellness programs.

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Q. WHAT BENCHMARKING HAS BEEN CONDUCTED TO EVALUATE

COST/PERFORMANCE LEVELS?

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A. BHC solicits a number of independent reviews of its benefits programs from external

organizations and consulting firms such as Towers Watson, Aon Hewitt, Mercer, etc.

These reviews cover a wide range of compensation and benefit program designs and

costs including compensation and benefit programs, Human Resource (HR) function

administrative expenses, and market data for positions. BHC also compares its benefit

programs and costs with companies from the utility sector and from general industry to

ensure the company can attract and retain employees with the skills necessary. In

addition, BHC utilizes multiple nationally recognized third-party surveys and also

conducts customized surveys where appropriate and necessary. These benchmarking

surveys allow BHC to evaluate the competitiveness and efficiencies of its benefit

programs and costs compared to other companies in the market. If a program does not

meet performance, cost or efficiency expectations, it is reviewed to determine the root

cause and the options or alternatives available. BHC closely monitors market practices

and benchmark data for costs to maintain competitive and cost effective programs.

Q. ARE BHC’S BENEFIT PROGRAM COSTS REASONABLE?

A. Yes, as a result of BHC’s active long-range planning, benefit program management,

aggressive healthcare initiatives, budget management and review process, and

benchmarking processes to determine performance in comparison to the market, the

benefit program costs are reasonable and prudent.

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Q. WHAT TYPE OF OVERSIGHT IS IN PLACE TO ENSURE THAT BHC’S

COMPENSATION AND BENEFIT PROGRAMS ARE THOSE THAT ARE

MOST BENEFICIAL FOR THE SUPPORT OF THE OPERATING

COMPANIES’ UTILITY SERVICE?

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A. The Human Resources Department, in partnership with the business unit leaders and

company management, develop annual budgets and long-range plans (5 years), including

compensation, benefit and other programs supporting the business’ goals and objectives.

HR and key operating personnel manage these budgets and review all programs for

effectiveness, cost and any proposed modifications. All programs are modeled to

determine impacts to cost and are benchmarked against the market parameters to ensure

competitiveness and cost effectiveness. All costs are reviewed during monthly financial

review, including budget variance reviews. With these monthly budget reviews,

management examines the budget variances, discusses the charges, and proposes

adjustments to current budget to ensure budget targets are met.

Accordingly, not only is the employee compensation and benefit expense reasonable, the

adjustments contained on Cheyenne Light’s Schedule H-2 are also reasonable, and should

be approved.

Q. ARE YOU AWARE OF OTHER STATE COMMISSIONS THAT HAVE

APPROVED THE EMPLOYEE COMPENSATION AND BENEFIT STRUCTURE

PROPOSED IN THIS PROCEEDING?

A. Yes. Through rate case settlements and contested proceedings commissions in Nebraska,

Iowa, and South Dakota have approved this employee compensation and benefit

structure. Black Hills Corporation places emphasis on maintaining a common employee

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payment scheme. The same is true for its proposal related to its employees living in or

supporting our customers in Wyoming.

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VIII. COLLECTIVE BARGAINING AGREEMENT BETWEEN THE 3

COMPANY AND IBEW LOCAL 111 4

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Q. DID THE COMPANY AND THE IBEW LOCAL 111 AGREE TO A NEW

CONTRACT DURING THE TEST YEAR?

A. Yes. The contract between the Company and IBEW Local 111, which represents certain

employees of Cheyenne Light expired on June 30, 2011. The parties reached an

agreement on a new contract in September and the Local 111 members ratified the

contract on September 12, 2011, with an effective date of July 1, 2011 through June 30,

2016.

Q. WHAT WERE THE MAIN COMPONENTS OF THE RATIFIED UNION

CONTRACT BETWEEN THE PARTIES?

A. The Company and IBEW Local 111 agreed to the following changes:

• Wage increases effective July 1, 2011 and effective July 1, 2012 with a wage

opener in 2013 to set wage increases for each July 1 of the final 3 years of the

contract – 2013, 2014 and 2015.

• Participation in the Company’s unified time off plan which results in represented

employees moving to the paid time off (PTO) plan effective January 1, 2012 and

eliminating the existing sick leave plan and vacation plan.

• Participation in the Company’s unified health and welfare benefits for active

employees as of January 1, 2012. With this contract change, all active employees

of the Company participate in the same unified health and welfare benefits. Since

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all active employees participate in unified health and welfare benefits, these costs

are aggregated company-wide (“Pooled Medical”) and are direct charged to each

business unit, including Cheyenne Light, based upon headcount.

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• A partial freeze of the Cheyenne Light, Fuel & Power Pension Plan (the “pension

plan”). Represented employees who were hired by CLFP (formerly a division of

Xcel Energy) prior to August 1, 2003, have an election of continuing participation

in the pension plan or freezing his/her accrued benefits as of December 31, 2011

and participating in the Company’s Retirement Savings 401(k) Plan – the

“401(k)” – for future contributions. All employees on or after August 1, 2003

will have a pension plan benefit frozen as of December 31, 2011 and will begin

participating in the 401(k) for future retirement contributions. All new hires on or

after January 1, 2012 will participate in the 401(k) only.

• In conjunction with the partial freeze of the pension plan, the represented

employees will participate in the unified 401(k) plan for Company employees.

The current company matching formula for represented employees is a match

contribution of 100% of the first 3% of eligible pay the employee saves plus a

match contribution of 50% of the next 2% of eligible pay saved by the employee

(for a maximum match of 4% of eligible pay). In conjunction with the partial

freeze of all three pension plans sponsored by BHC (including the Cheyenne

Light pension plan), under the unified 401(k), the Company matching

contribution is 100% of the first 6% of eligible pay the employee saves.

• The current retiree medical benefit provided under the contract was also frozen,

with those employees hired prior to August 1, 2003 (former Xcel Energy

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employees). These employees were grandfathered under the retiree medical plan,

which provides for retiree healthcare benefits on a cost-share basis, with the

retiree paying a portion of the monthly premium and the Company paying a

portion of the monthly premium. For those represented employees hired on or

after August 1, 2003, the retiree benefits (Retirement Spending Account and

Social Security Supplement) were frozen as of Decemeber 31, 2011. These

employees with frozen retiree benefits will begin accruing benefits under the

unified Retiree Medical Savings Account as of January 1, 2012.

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• The ratified contract also formalized the participation of the represented

employees in the Company’s Annual Incentive Plan (a/k/a Unified Incentive Plan)

and other company rewards and recognition programs.

IX. SCHEDULE H-2 ADJUSTMENTS 12

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Q. PLEASE DISCUSS YOUR SUPPORT FOR THE COMPENSATION AND

BENEFIT ADJUSTMENTS ON SCHEDULE H-2 OF THE REVENUE

REQUIREMENT MODEL?

A. Each of those expenses are employee expenses that Cheyenne Light will incur. The

levels set forth on Schedule H-2 of the revenue requirement model are representative of

the costs that Cheyenne Light will incur once rates are placed into effect. These are

legitimate employee expenses and appropriate for recovery in this rate case.

Q. PLEASE SUMMARIZE YOUR TESTIMONY AND CONCLUSIONS?

A. I describe the general compensation program for BHC employees, and particularly the

employees of the applicant, Cheyenne Light, including the variable compensation

program. I also explain why those programs and their associated costs are reasonable

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and necessary to attract, motivate and retain well qualified and competent employees to

support utility operations and support recovery of the compensation-related expenses of

Company employees.

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My testimony discusses and supports the additional costs related to the ratified

Collective Bargaining Agreement between Cheyenne Light and the IBEW Local 111.

My testimony specifically supports the following employee compensation related

adjustments contained on Schedule H-2 of the Cheyenne Light’s revenue requirement

model:

• Retiree Healthcare

• Pension Plan

• Pooled Medical

• 401k Plan

• Profit Sharing Plan (component of the 401k)

My recommendations are for the Commission to approve the recovery of legitimate

employee expenses. Those expenses are necessary to pay the employees – both direct

and allocated -- who provide utility service to Cheyenne Light’s customers.


A. Yes, it does.

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Direct Testimony and Exhibits Jennifer Landis





December 1, 2011

Table Of Contents

I. Introduction And Qualifications ......................................................................................... 1

II. Purpose Of Testimony ........................................................................................................ 2

III. Workforce Challenges ........................................................................................................ 2

IV. Strategic Philosophy And Programs ................................................................................... 3

V. Company Recovery Of Employee Strategic Workforce Development Expenses .............. 8

Exhibits

JCL-E1 Aging of the National Workforce Studies

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I. INTRODUCTION AND QUALIFICATIONS 1

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Q. PLEASE STATE YOUR NAME, BY WHOM YOU ARE EMPLOYED, AND

COMPANY ADDRESS.

A. My name is Jennifer Landis and I am employed by Black Hills Corporation (“Black

Hills” or “Corporation”). My business address is 625 9th Street, Rapid City, SD 57701.

Q. PLEASE DESCRIBE YOUR POSITION WITHIN THE COMPANY AND AREAS

OF RESPONSIBILITY.

A. I am the Director of Organization Development for Black Hills. In my position, I am

responsible for partnering with business leaders to design and execute talent management

strategies. Black Hills’ Strategic Workforce Planning efforts are a portion of those talent

management efforts. I provide the business leaders with the necessary information and

analysis they need in order to make informed workforce decisions. I also provide

direction for the strategic workforce planning efforts at Cheyenne Light, Fuel and Power

Company (“Cheyenne Light” or “Company”).

Q. PLEASE BRIEFLY SUMMARIZE YOUR ACADEMIC AND PROFESSIONAL

BACKGROUND.

A. I have a Bachelors Degree in Applied Management and a Masters Degree in Global

Human Resources Development. I have over 18 years experience in adult learning and

development with specializations in project management, leadership and employee

development, succession planning, employee engagement, and performance

management.

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Q. HAVE YOU PROVIDED TESTIMONY IN REGULATORY PROCEEDINGS

PRIOR TO THIS CASE?

A. No.


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A. I describe and support the Black Hills and Cheyenne Light strategic workforce planning

initiative, particularly the transition plan of hiring additional employees to prepare for

employee retirements of the applicant, Cheyenne Light. My testimony will explain why

the strategic workforce process programs and their associated costs are reasonable and

necessary to attract, motivate and retain well qualified and competent employees to

support utility operations. This testimony intends to build the foundation for current and

future recovery of compensation and benefit expenses for additional employee hires.

The current expenses are found in Schedules H-1 and H-2. These expenses are

necessary to implement Cheyenne Light’s strategic workforce process planning and

transition.

III. WORKFORCE CHALLENGES 17

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Q. PLEASE DESCRIBE THE WORKFORCE CHALLENGES THAT CHEYENNE

LIGHT AND ITS REGULATED AFFILIATES ARE FACING.

A. A significant portion of the Black Hills’ utility subsidiary workforce, including Cheyenne

Light, could retire over the next 5-7 years given 27% or 389 employees are age 55 or

older. Approximately 28% of Cheyenne Light’s workforce is 55 or older. As of 2008,

53% of the utilities workforce nationwide was age 45 or older. With over 50% of the

workforce eligible to retire within the next decade, many utilities will be competing for

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the same qualified candidate pool to replace retiring workers. Black Hills and Cheyenne

Light are taking actions to improve current employee retention as well as offer attractive

training and development opportunities to new employees. Black Hills is implementing a

strategic workforce planning process in order to proactively address these challenges

allowing us to stay competitive in the talent market. As technology continues to progress

and change the landscape of the utility workforce skills and duties, investment in

employee skill development and experience will be as important to providing safe,

reliable service as investing in utility equipment or infrastructure.

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IV. STRATEGIC PHILOSOPHY AND PROGRAMS 9

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Q. WHAT IS BLACK HILLS’ GENERAL STRATEGIC WORKFORCE

PHILOSOPHY?

A. Black Hills’ workforce philosophy is designed to help the various business units of the

Company, including Cheyenne Light, develop intelligently positioned human resource

solutions to ensure that the business units have the right human resource talent in the

right places at the right times. This philosophy allows Black Hills to execute a prudent

business strategy while continuing to provide safe, reliable service to our customers. All

workforce development programs take a multifaceted approach to employee talent

development by influencing internal supply, external supply, or current workforce

productivity.

Q. PLEASE DESCRIBE THE STRATEGIC WORKFORCE PLANNING PROCESS.

A. Black Hills’ strategic workforce planning process includes an examination of the current

workforce demographics, projection of potential losses due to employee retirement over

the next five (5) years, and a thorough discussion of the skills and knowledge that will be

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needed to continue to deliver safe, reliable service to our customers. Through this

process, Black Hills will be able to identify areas of risk due to shortage of workers, lack

of qualified employees possessing required skills and abilities, or both. Once these

human resource risks are identified, business unit leaders are able to develop an action

plan to address the risks. The business unit managers are empowered to prudently

manage human resources by taking actions internally through employee retention efforts

and employee development, or externally through recruiting and hiring practices.

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Q. PLEASE DESCRIBE THE IMPORTANCE OF WORKFORCE PLANNING FOR

THE UTILITY INDUSTRY AND ITS APPLICATION TO CHEYENNE LIGHT?

A. As noted by Mr. Stege, on behalf of Cheyenne Light and its affiliates, the Black Hills

strategic workforce planning team reviews and will continue to monitor, numerous

studies that have been published concerning the aging of the national workforce

necessary to serve and operate the nation’s utility systems including the following: 2009

Center for Energy Workforce Development (CEWD) Survey: Gaps in the Energy

Workforce Pipeline, The National Commission on Energy Policy’s Task Force on

America’s Future Energy Jobs, The Department of Energy’s Report of Workforce Trends

in the Electric Utilities Industry. These studies are attached to my testimony as Exhibit

JCL-G1. These studies highlight and demonstrate the challenge of the aging utility

workforce. As stated in the 2009 CEWD Survey:

The 2009 CEWD Gaps in the Energy Workforce Pipeline survey

predicts that by 2015, 46% of the existing skilled technician

workforce may need to be replaced due to potential retirement or

attrition and 51% of the engineering workforce.

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As discussed in Mr. Stege’s testimony, the aging utility workforce this is a looming issue

for Cheyenne Light as well. This challenge results in the need for increased hiring and

training of employees to ensure reliability and quality of service, as well as the safety of

the public and Cheyenne Light employees.

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Q. WHAT STAGE OF THIS PROCESS IS CHEYENNE LIGHT CURRENTLY IN?

A. Black Hills has examined the current workforce demographics (including tenure,

experience and skill capabilities) of Cheyenne Light and industry trends and risks. In

addition, it has projected the potential losses due to employee retirement over the next

five (5) years. Black Hills has facilitated a discussion to identify the employee skills and

knowledge that will be required to continue to deliver safe, reliable service. Black Hills

has worked closely with Cheyenne Light’s leadership team to create a workforce

development strategy that outlines the actions that are necessary for Cheyenne Light to

adequately address their workforce challenges in the near future.

Q. WHAT IS THE NEXT STEP?

A. Cheyenne Light will take that development strategy and create an action plan that will

focus on developing employee training and other programs. The action plan

implemented by Cheyenne Light is intended to provide for fully equipped and competent

employees to transition into jobs that will be vacated in whole or in part by an aging –

and eventually retiring – workforce. This action plan will include a variety of different

approaches for recruiting and then training its employees. For example, Cheyenne Light

will engage in community outreach programs that promote career opportunities in the

energy industry to school-age children. Cheyenne Light will also be active in recruiting

at local colleges and technical schools. To that end, Cheyenne Light will explore the

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feasibility of potentially working with degree programs to ensure students are educated

on the essential skills necessary in the energy industry. Finally, Cheyenne Light will

place a heavy focus and investment on the training and development of current Company

employees to ensure those employees possess the skills essential for keeping the

Company’s systems operating safely and reliably.

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Q. HAS THIS PROCESS GIVEN CHEYENNE LIGHT ANY INSIGHT ON ANY

WORKFORCE RETIREMENT ISSUES?

A. Yes. The strategic workforce planning process includes a retirement risk analysis that

projects potential retirements over the next five (5) years based on historical retirement

trends at Cheyenne Light and Black Hills as well as instances in which it is understood

that employees will be retiring either before or after age 62. This workforce analysis is

done at the job function level, which allows Cheyenne Light to view retirement

projections within specific groups rather than for the workforce as a whole. Within

Cheyenne Light’s operations, the Company could have 4 retirements in the next 3 years

(2 employees for gas operations and 2 employees for electric operations). That reduction

in workforce is a significant loss for relatively small groups of utility workers (13 for gas

operations and 15 for electric operations). The time period required to develop

competence in these employee roles is often between two (2) and four (4) years.

Accordingly, the Company must plan for replacements to be hired and trained as soon as

possible to ensure it can continue to provide safe, reliable service to Cheyenne Light’s

customers. Compounding the employee workforce reduction at Cheyenne Light, Black

Hills’ utility business units are also facing the same aging workforce challenges. Thus,

“borrowing” workers from other business units is not a viable option. Black Hills’

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business units are also geographically spread out which makes it even more difficult to

transfer workers across business units. Cheyenne Light will be able to take advantage of

the workforce economics that a regional gas and electric utility provides; however, the

workforce action plan demands that a local workforce be maintained and well-trained.

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Q. HOW DOES CHEYENNE LIGHT’S STRATEGIC WORKFORCE PLANNING

INITIATIVE AFFECT THIS RATE CASE?

A. Cheyenne Light is seeking to add one (1) additional line mechanic to its electric division

and one (1) additional gas technician due to impending retirements and additional

business needs. Cheyenne Light will provide these new employees the opportunity to

work closely with experienced employees prior to the expected retirement of those

employees. That training model will allow for valuable knowledge transfer, supervised

skill development and sufficient employee training. Waiting to hire replacements until

after our employees retire is not an economically viable option. A delayed hiring practice

will only strain the remaining employees who must not only cover the work of the recent

retirees, but also help to train and supervise the new employees while they get up to

speed on the job duties. This additional strain on our employees creates both safety risks

and efficiency issues. In addition, the strain could acerbate the workforce reduction

problem if employee satisfaction is deteriorated and qualified employees seek jobs

elsewhere.

Due to the highly technical nature of many utility positions, it takes significant time for

training, testing and other job aspects before the employee can perform the duties on their

own, often a period of several years. Advance hiring of employees allows sufficient time

for new employees to be trained without overloading current employees with an

7

unreasonable amount of additional work and limits safety and operational risks associated

with over-burdened employees.

1

2

V. COMPANY RECOVERY OF EMPLOYEE STRATEGIC WORKFORCE 3

DEVELOPMENT EXPENSES 4

5

6

7

8

9

10

11

12

13

Q. WHAT TESTIMONY DO YOU PROVIDE IN SUPPORT OF THE INCLUSION

OF STRATEGIC WORKFORCE PROCESS EMPLOYEE COSTS IN THE

REVENUE REQUIREMENTS?

A. Strategic Workforce Planning is a valid and appropriate component of utility

management and operations. Our customers will receive value from these business unit

goals in efficiency, safety and reliability. For these reasons this is an appropriate utility

expense to be recovered through this rate case.


A. Yes, it does.

8

Background ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙

There are three key factors that are creating gaps in the Electric and Natural Gas Utility workforce pipeline – an aging work force; skill gaps in the talent pool; and changing energy technology. The third CEWD Gaps in the Energy Workforce Pipeline Survey included questions to further refine existing projections on the retirement gap and to gain new insights into the impact of skill gaps and new technology.

The utility industry across the country is facing workforce shortages as aging skilled workers approach retirement and fewer qualified candidates are available to replace them. In both 2007 and 2008, CEWD surveyed electric and natural gas utilities on the age and years of service of employees in critical skilled utility technician jobs and in engineering and forecasted the possibility of retirements and attrition based on the results. Since the release of the initial survey in 2007, several factors have changed. Foremost, the U.S. economy weakened dramatically, delaying retirements among those reaching eligibility and impacting utilities’ capital expenditures.

The 2009 CEWD Gaps in the Energy Workforce Pipeline Survey predicts that by 2015, 46% of the existing skilled technician workforce may need to be replaced due to potential retirement or attrition and 51% of the engineering workforce. The 2009 CEWD

survey validates that with the economic downturn some retirements have been delayed and hiring has

been postponed, but the potential for retirement stays the same. In effect, the impact of the economic downturn has just delayed the timing of retirements and has not lessened the need for future replacements.

In previous years, the survey gathered data on age and years of service of current employees and made projections for retirements within the next five years. The analysis compared these data with the number of employees

currently in the pipeline in order to identify where gaps could potentially occur. Those results were used to assist utilities in better targeting their efforts to recruit and train potential job candidates to fill those gaps. Identifying where and when new employees will be needed is the first critical element in balancing the demand for employees with the supply of trained applicants.

This year’s survey took the next step and began to examine trends in hiring and training since workforce gaps had been identified. The survey also focused on where “skills gaps” occur – that is, where candidates fall short in terms of skills needed to qualify for the jobs companies are trying to fill. These data should further assist utilities in identifying those education programs that best meet the needs of the industry in preparing students with the competencies they will need to be successful in energy careers.

Gaps in the Energy Workforce Pipeline

2009 CEWD Survey Results

The 2009 CEWD Gaps in the Energy Workforce Pipeline

Survey predicts that by 2015, 46% of the existing skilled

technician workforce may need to be replaced due to

potential retirement or attrition and 51% of the engineering

workforce.

pmh

Typewritten Text

Exhibit JCL-E1

2 | P a g e

2009 Survey Findings ∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙∙

Industry Demand

In spite of a weakened economy, utilities continued to hire in 2009, albeit at a slowerthannormal pace. Hiring increased at utilities from 20062008, then slowed in 2009, dropping by 56 percent, with the biggest reductions in hiring for technician and engineering jobs. Though 88 percent of companies reported a slowdown in hiring, the vast majority of utilities (84 percent) reported they had not instituted hiring freezes and less than one third reported any downsizing.

Likely due to the stillstruggling economy, the 2009 survey showed that employees continued to postpone retirement, with most now retiring after age 58 with 25 years of service. Although earlier that the traditional retirement age of 65, some employees in these positions may opt for positions in other areas of the company or begin second careers as many of these positions are physically demanding.

There are approximately 535,000 employees in the electric and natural gas utilities and almost onethird (approximately 172,000) fall into four key job categories – lineworkers, plant / field operators, technicians, and pipefitters / pipelayers / welders. There is a potential to lose 46%, or almost 80,000, of these skilled trade employees by 2015. This is an increase over previous forecasts, reflecting retirements by those who have delayed leaving, in addition to employees who will reach the critical age category in the coming five years.

In addition, over half of the engineers employed by utilities will have the potential to retire.

Skills Gap

Surveyed companies reported difficulties in finding qualified applicants to fill all of the skilled craft positions. Overall, utilities reported that between 3050% of applicants (those that met the minimum requirements for a position) were not able to pass the preemployment aptitude tests. Additional applicants fall out of the process with background and drug screening. On average, companies needed to interview 30 applicants for every hire. Lineworkers appeared to be the most difficult to find, with an average of 50 applicants interviewed for every successful hire. Those companies that work with secondary and postsecondary institutions to develop programs tailored to the industry, such as energy career academies at the high school level, “boot camps” prior to apprenticeships, and community college programs aligned to the specific skill requirements report significant increases in the pass rate for preemployment tests.

Utilities have also been particularly challenged in filling engineering jobs with appropriately skilled applicants. To make up the shortfall, many have been willing to hire engineers who lacked electrical engineering degrees; in those cases, they’ve bridged the skills gap by providing companysponsored training to new hires. In the future, the companies report that they will begin requiring an electrical engineering degree, or relevant coursework, for electrical engineer positions. Approximately 23% of the engineer applicants did not have the relevant education or experience when they applied for positions. However, half of those utilities surveyed said they would help pay for employees to obtain an appropriate degree through tuition reimbursement plans.

Potential Replacements 2009 2015

Job Category

Potential Attrition & Retirement

%

Estimated Number of

Replacements

Technicians 50.7 27,800

Non Nuclear Plant Operators

49.2 12,300

Pipefitters / Pipelayers

46.1 8,900

Lineworkers 42.1 30,800

Engineers 51.1 16,400

3 | P a g e

Education and Training

Energy companies are looking for ways to reduce the cost of training and recruiting new employees. More than 80 percent said they had partnered with one or more community colleges or vocational programs to find job applicants and 76 percent

credited those programs with cost reductions and other quantifiable benefits, such as reducing the time and cost of recruiting and qualifying new hires.

Companies use a variety of education programs to train future skilled trade workers, including high school career academies, postsecondary certificate programs, pre apprenticeship training, and associate degree programs. Over 80% of respondents said they required a twoyear degree for technician positions.

The survey also looked closely at internal company training and apprenticeship programs. Lineworkers by far were most often required to complete an apprenticeship program, with more than 80 percent of utilities reporting this requirement. Technicians were required to complete apprenticeships at roughly 60 percent of utilities surveyed and plant/field operators were required to do so at roughly half of utilities. Pipefitters/pipelayers /welders were least likely to be required to complete apprenticeships; only 40 percent of utilities

reported such a program for these employees.

Most of the companies (about 85 percent) reported that they conduct lineworker training and apprenticeships internally within the company. Less that 25 percent of the respondents rely on technical / community colleges or other training providers to support their lineworker training.

Notably, of those apprenticeship programs, the vast majority – nearly 60 percent for lineworkers and 45 percent for technicians – were registered with the Department of Labor or with their state. This indicates that utilities are moving closer to a system of transportable credentials that reflect a high industry standard.

Impact of Emerging Technologies

The survey specifically asked questions about current positions in renewable generation, energy efficiency, and the Smart Grid. Although only a small percentage of respondents overall reported having dedicated positions in any of these technologies, it was clear that most of the positions were in management, analyst or consulting within the companies.

In terms of renewable generation technologies, no positions were shown for biofuels and ethanol, and almost no positions were noted for solar generation. Only 13 respondents reported having dedicated wind positions, with only four showing more than one or two positions. The majority of those were management positions; only one company reported having wind technicians. A similar number of respondents reported having positions in Smart Grid but the number of positions was higher, almost 400, with most of those in management and engineering. The job titles listed, however, included traditional titles such as Distribution Engineer or Project Manager, indicating that these are not likely to be unique positions, but additional responsibilities for existing positions. By far, the largest number of emerging technology positions was in energy efficiency, around 1,100. This is not surprising since most utilities have had energy efficiency or demand side management programs in effect for decades. Again, many of the positions were in management, but this job category also showed multiple positions such as analyst, coordinators, or consultants.

Because not everyone reported having dedicated positions in these emerging areas, it is difficult to extrapolate the number of future jobs. What can be learned from the results is that most of the positions are not discrete new jobs, but rather existing positions with additional or new skills. In addition, since most of the positions named are consulting, engineer, analyst or management positions, it is likely that the positions will require a fouryear or advanced degree.

Surveyed companies

reported difficulties in finding qualified applicants to fill all of the skilled craft

positions.

4 | P a g e

Conclusions and Recommendations

Energy companies have made significant strides since the first CEWD survey to address the skilled worker gap – through both internal training programs and external partnerships. Although efforts have been somewhat stymied by a stagnant economy, the industry has gained significant knowledge in identifying the types of education programs that will bridge the gap for the future.

Specific recommendations for building the future energy workforce pipeline include: • Support existing efforts to balance the supply and demand for workers by developing programs that can be scaled as

demand increases and decreases. • Continue to build partnerships with those in the education, labor and government sectors to develop secondary and

postsecondary programs specific to energy skilled trades positions. • Use the Energy Industry Competency Model developed by the industry for the skilled trades to create programs that

will reduce the skill gaps in applicants and provide quantifiable benefits to the companies. • Create industry recognized credentials that will allow students to demonstrate the skill level attained.

2009 Survey Methodology

The 2009 survey was conducted in June, 2009 and includes data from 31 companies representing 44 percent of all electric and natural gas utility employees in 46 states, with investorowned utilities making up the majority of respondents. The results are for nonnuclear generation, transmission and distribution and included specific questions on four skilled trades positions – lineworker, plant / field operator, technician, and pipefitter/ pipelayer/ welder – in addition to questions on engineering. The survey does not include data on positions in nuclear as the Nuclear Energy Institute conducts a similar survey for nuclear generation employees.

Members of CEWD may view survey details at www.cewd.org

701 Pennsylvania Ave. N.W. Washington, DC 200042696 202.638.5802

www.cewd.org www.getintoenergy.com

For information on membership, please contact us at [email protected]. © Center for Energy Workforce Development (CEWD)

August 2006

A REPORT TO THE UNITED STATES CONGRESS PURSUANT TO SECTION 1101

OF THE ENERGY POLICY ACT OF 2005

WORKFORCE TRENDS IN THE ELECTRIC UTILITY INDUSTRY

U.S. Department of Energy Workforce Trends in the Electric Utility Industry iii

SEC. 1101. WORKFORCE TRENDS AND TRAINEESHIP GRANTS

*** (b) WORKFORCE TRENDS. – (1) MONITORING. – The Secretary, in consultation with, and using data collected by, the Secretary of Labor, shall monitor trends in the workforce of– (A) skilled technical personnel that support energy technology industries; and (B) electric power and transmission engineers. (2) REPORT ON TRENDS. – Not later than 1 year after the date of enactment of this Act, the Secretary shall submit to Congress a report on current trends under paragraph (1), with recommendations (as appropriate) to meet the future labor requirements for the energy technology industries. (3) REPORT ON SHORTAGE. – As soon as practicable after the date on which the Secretary identifies or predicts a significant national shortage of skilled technical personnel in 1 or more energy technology industries, the Secretary shall submit to Congress a report describing the shortage. ***

– Energy Policy Act of 2005, August 8, 2005

iv U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry v

Table of Contents Page

LIST OF FIGURES ................................................................................................................................ VII LIST OF TABLES ....................................................................................................................................IX EXECUTIVE SUMMARY ......................................................................................................................XI

1. INTRODUCTION.................................................................................................................................. 1

2. ELECTRICAL LINEWORKERS........................................................................................................ 2 2.1 CURRENT WORKFORCE.......................................................................................................... 2

2.1.1 DEFINING AND CHARACTERIZING ELECTRICAL LINEWORKERS ............................................ 2 2.1.2 EMPLOYMENT OF LINEWORKERS, 1991-2005 ........................................................................ 2 2.1.3 LINEWORKER WAGES............................................................................................................. 5

2.2 RETIREMENT PROJECTIONS................................................................................................. 5 2.3 LINEWORKER TRAINING........................................................................................................ 6

2.3.1 LINEWORKER DEVELOPMENT PROCESS ................................................................................. 6 2.3.2 LINEWORKER TRAINING PROGRAMS...................................................................................... 7 2.3.3 APPRENTICESHIPS................................................................................................................... 8

2.4 FUTURE WORKFORCE............................................................................................................. 8 2.4.1 PROJECTED DEMAND.............................................................................................................. 8 2.4.2 RETIREMENT IMPACT ANALYSIS............................................................................................ 9

3. ELECTRIC POWER AND TRANSMISSION ENGINEERS........................................................ 11 3.1 CURRENT WORKFORCE........................................................................................................ 11

3.1.1 DEFINING AND CHARACTERIZING ELECTRIC POWER ENGINEERS ....................................... 11 3.1.2 EMPLOYMENT OF POWER ENGINEERS.................................................................................. 11 3.1.3 POWER ENGINEER EARNINGS............................................................................................... 11

3.2 FUTURE WORKFORCE........................................................................................................... 13 3.2.1 ANNUAL DEMAND FOR POWER ENGINEERS......................................................................... 13 3.2.2 ANNUAL SUPPLY OF POWER ENGINEERING GRADUATES .................................................... 14 3.2.3 WORKFORCE ANALYSIS USING DEPARTMENT OF EDUCATION PROJECTIONS..................... 14 3.2.4 UNCERTAINTY OF ASSUMPTIONS ......................................................................................... 15

3.3 STATUS OF POWER ENGINEERING EDUCATION IN THE U.S. ................................... 15 3.3.1 APPLIED ENGINEERING VS. STRATEGIC LONG-TERM RESEARCH........................................ 15 3.3.2 FACULTY TRENDS ................................................................................................................ 16 3.3.3 FOREIGN ENROLLMENT........................................................................................................ 17

4. CONCLUSIONS AND RECOMMENDATIONS............................................................................. 20

5. REFERENCES..................................................................................................................................... 22 APPENDIX A — ENERGY POLICY ACT OF 2005, SECTION 1101............................................ A-1 APPENDIX B — LIST OF ACRONYMS ........................................................................................... B-1 APPENDIX C — RESEARCH METHODOLOGY / DATA SOURCES..........................................C-1 APPENDIX D — BLS PROJECTION METHODOLOGY ...............................................................D-1 APPENDIX E — LINEWORKER WORKFORCE ANALYSIS ASSUMPTIONS........................ E-1 APPENDIX F — POWER ENGINEERING WORKFORCE ANALYSIS ASSUMPTIONS........ F-1

vi U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry vii

List of Figures Figure Page

1 Utility Lineworker Employment Levels, 1991-2005 .................................................. 3

2 Non-Utility Lineworker Employment Levels, 1999-2005 .......................................... 4

3 Comparative Hourly Wages for Electrical Lineworkers ............................................. 5

4 Age Demographics at TVA......................................................................................... 6

5 Generic Lineworker Training Process......................................................................... 7

6 Lineworker Training Institutions, 1990-2005 ............................................................. 8

7 Lineworker Supply and Demand Projections.............................................................. 9

8 Forecast of Electrical Engineers Entering the Power Industry...................................14

9 EPRI’s Strategic vs. Applied R&D Funding, 1981-2004 ..........................................16

10 Average Power Engineering Faculty per Power Program......................................... 17

11 Power Engineering Enrollment – Graduate Programs .............................................. 18

12 High-Skill-Related Visas........................................................................................... 19

viii U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry ix

List of Tables Tables Page

1 Engineering Starting Salaries, 2005 .......................................................................... 12

2 Median Salaries of U.S. Electrical Engineers ........................................................... 12

3 Basic Employment Data for Power Engineers, 1994, 2004, and 2014 ..................... 13

4 Lineworkers vs. Power Engineers ............................................................................. 20

x U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry xi

Executive Summary Section 1101 of the U.S. Energy Policy Act of 2005 (EPACT)1 calls for a report on the current trends in the workforce of (A) skilled technical personnel that support energy technology industries, and (B) electric power and transmission engineers. It also requests that the Secretary make recommendations (as appropriate) to meet the future labor requirements.

Background

The aging of the American workforce has emerged as a critical issue facing American productivity in the 21st century. As the so-called “Baby Boomer Generation” reaches retirement eligibility, the impact will be felt across both the public and private sectors. These 78 million individuals born between 1946 and 1964 have accumulated a wealth of experience and knowledge, and represent 44% of America’s workforce. For electric utilities, whose service quality and reliability depends on maintaining an adequate, knowledgeable workforce, managing the upcoming retirement transition is a particular challenge.

Electrical Lineworkers

Electrical lineworkers represent the physical labor required to operate and maintain the electric grid. They erect poles and light or heavy-duty transmission towers, and install or repair cables or wires used to carry electricity from the power plant to the customer. In 2005, power line installers working for electrical utilities and outsourcing companies numbered 58,020. Demand is expected to outpace supply over the next decade. As a result, they are one of the highest paid professions in the United States that does not require a post secondary education, attributable perhaps to the hazards inherent to the job.

The percentage of the lineworker workforce expected to retire within the next five to ten years could approach 50% in some organizations.2 The loss of institutional knowledge is a critical concern, especially for a profession heavily dependent on mentoring and on the job training. Although the number of lineworker training institutions has grown considerably, analysis indicates a significant forecasted shortage in the availability of qualified candidates by as many as 10,000 lineworkers, or nearly 20% of the current workforce. This could eventually limit the nation’s ability to maintain and/or increase electricity supply, potentially impacting the economic and national security of the United States.

The electric industry is actively engaged in addressing the lineworker shortage – building awareness of the problem, encouraging training initiatives, and increasing interest in the lineworker profession. However, given the importance of the electricity sector to the economy and security, public-private partnerships may be warranted to promote the energy industry as a viable employment option, to develop strategies for encouraging retirement-eligible workers to remain employed in the industry, and to ensure adequate training and education opportunities to support the reliability and safety of the electricity grid.

1 Public Law 109-58, August 8, 2005. 2 Based on discussions with industry stakeholders (see Appendix C).

xii U.S. Department of Energy Workforce Trends in the Electric Utility Industry

Electric Power and Transmission Engineers

Electric power engineers traditionally focus on systems and devices for the conversion, delivery, and use of electrical energy. While the fundamental principles of power engineering have been around for a long while, the application of these principles, as well as our understanding of the electric system, continues to evolve. This enables technology enhancements that significantly improve the capability, performance, and reliability of the entire electricity system.

The electric power engineer is critical to this process. In 2004, there were 10,280 electrical engineers working in the electric power generation, transmission, and distribution industry. By 2014, the Bureau of Labor Statistics projects demand will grow to 11,113. The number of job openings resulting from employment growth and from the need to replace electrical engineers who transfer to other occupations or leave the labor force is currently expected to be in rough balance with the supply of graduates. Over time, however, this situation may not be sustainable, since statistics indicate that the primary producer of power engineering graduates, i.e. university programs, may be in jeopardy.

University-based power engineering education programs are essential to the supply of power engineering graduates to meet future needs. Yet, the restructuring of the electric utility industry, along with wider interest in newer electrical engineering fields such as microelectronics, computers, and communications, have eroded support for power engineering programs and associated long-term strategic research. In addition, recent data shows a decline in the number of power engineering faculty, exacerbating the problem.

Today, the power engineering education system in the United States is at a critical decision point. Without strong support for strategic research in power systems engineering and without qualified replacements for retiring faculty, the strength of our Nation’s university-based power engineering programs will wane, and along with them, the foundation for innovation in the power sector to meet our energy challenges in the 21st century.

Recommendations This report provides two recommendations to meet future labor requirements: foster math and science education and build interest in energy-related careers. Based on the time necessary to develop qualified personnel, these recommendations can not immediately produce meaningful results. However, they are part of a long-term solution to meeting the future energy workforce demands of the United States.

U.S. Department of Energy Workforce Trends in the Electric Utility Industry 1

WORKFORCE TRENDS IN THE ELECTRIC UTILITY INDUSTRY

1. Introduction Section 1101 of EPACT calls for a report on the current trends in the workforce of (A) skilled technical personnel that support energy technology industries; and (B) electric power and transmission engineers. It also requests that the Secretary of Energy make recommendations (as appropriate) to meet the future labor requirements.

This document is the report to Congress, examining one segment of the energy technology industries identified in Section 1101(a), specifically, “the electric utility industry.”3 The purpose of the report is not to produce precise estimates of workforce requirements. It is also not a rigorous analysis assessing the interdependencies across the various energy segments. Rather, the report uses existing data to focus on workforce trends associated with the electricity delivery industry, in particular, lineworkers and power engineers, and highlights areas where shortages are likely to occur.

The report is further organized as follows:

• Section 2 addresses electrical lineworkers. It provides a brief overview of the current workforce, examines the impact of projected retirements, and discusses the status of training institutions.

• Section 3 addresses electrical power and transmission engineers. It estimates the current workforce, identifies future demand projections, and analyzes the trends for power engineering education.

• Section 4 presents specific recommendations for meeting the future labor requirements.

• There are several appendices. The entire text of Section 1101 of EPACT is provided in Appendix A. Appendix B lists the acronyms used throughout the report. Appendix C summarizes the research methodology, while Appendix D discusses future employment projections. Appendix E documents the assumptions for the lineworker analysis. Appendix F outlines some additional analysis for power engineers using data from the Department of Education.

3 This report was prepared under the direction of the U.S. Department of Energy, Office of Electricity Delivery and Energy Reliability. Research support for the study was provided by McNeil Technologies, Inc., Energetics, Inc., and Oak Ridge National Laboratory.

2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

2. Electrical Lineworkers 2.1 Current Workforce

2.1.1 Defining and Characterizing Electrical Lineworkers

The electric utility lineworker is the “backbone” of the utility system. The profession represents the physical labor required to operate and maintain the electric grid. There are multiple job descriptions involved in this labor segment, including electrical technicians, lineworkers, and their first line supervisors. The term is generic for utility construction workers.

The Bureau of Labor Statistics (BLS) assigns the following Standard Occupation Code (SOC) to lineworkers with the following job definitions/responsibilities:

Soc Code 49-9051 Electrical Power-Line Installers and Repairers: Install or repair cables or wires used in electrical power or distribution systems. May erect poles and light or heavy-duty transmission towers. Exclude "Electrical and Electronics Repairers, Powerhouse, Substation, and Relay" (49-2095).

This occupation code is the basis of all subsequent analysis in this report using BLS data for electrical lineworkers.

In addition to being physically demanding, the lineworker’s job can be dangerous. Risks include electrocution, injury due to falls, and flash burns. They also respond during the worst weather or disasters, which often cause extensive damage to the electrical lines. The job has quality of life drawbacks such as working for extensive periods in the elements and an unpredictable work schedule, a virtual on call status, 24 hours a day, 7 days a week. Lineworkers spend extended periods traveling by truck to check power lines. However, according to OSHA data, the injury rate within this occupation is on par with other professions. This is a tribute to the high degree of professionalism and concern for safety and safety equipment that are integral to the profession.

The lineworker’s job has a strong public service aspect, and may be likened to that of a “first responder.” Indeed, in the event of natural disasters such as hurricanes or ice storms, lineworkers are critical in restoring the electric system - and hence community - to normalcy.

2.1.2 Employment of Lineworkers, 1991-2005

In 2005, power line installers working for electric utilities numbered 53,780, the highest employment level since 1991. According to BLS data, in 2005, power line installers represented over 13 % of the electrical generation transmission and distribution sub-group of the electric utilities industry. The employment figures for electrical lineworker have gradually increased, averaging a 1.6% increase from 1999 to 2005. Figure 1 illustrates the lineworker employment levels.


Employment of Utility Lineworkers 1991-2005

53,680 53,780

50,860

44,660

47,74047,320

40,000

41,000

42,000

43,000

44,000

45,000

46,000

47,000

48,000

49,000

50,000

51,000

52,000

53,000

54,000

55,000

1991 1994 1997 2000 2003 2005

Year

Em

ploy

men

t (Pe

rson

s)

Fig. 1. Utility Lineworker Employment Levels, 1991-2005 (Source: BLS).

From the early 1990s into the early 2000s, electric power utilities experienced a general steady and overall decline in workforce levels. That trend may have been largely due to restructuring of the industry, which began in the early 1990s. The introduction of deregulation created a competitive utility market prompting electric utilities to downsize in an effort to reduce operating costs. As will be discussed later, the number of outsourced lineworkers (i.e., not employed by the utilities themselves) increased during this period.

Utilities reduced the number of maintenance staff, deferred maintenance, and canceled or put on hold capital expansion projects. According to Electric Utility Week, those states with active restructuring experienced a 29% reduction in their workforce while states that had not undergone regulatory reform as of 2003 had only a 19% decline in employment.4 The impact on electrical lineworkers was proportional. In 1991, there were 53,680 lineworker in the United States. By the year 2000, this number had been reduced to only 44,660, a 17% reduction.

Since 2000, the electric utility industry’s employment level for lineworkers has been steadily increasing. This hiring trend is driven by utilities’ anticipation of increased demand, and is a response to the long periods of little or no capital investment. Utilities, concerned with the prospect of meeting the rising demand for energy using the existing transmission lines, embarked upon a hiring trend focused on employment to maintain, upgrade, and expand the electric utility system.

4 Platts, 2004, “Unions See Hiring, Outsourcing, Medical Benefits as Big Issues in ‘04 Contract Talks”, Electric Utility Week, March 15.


Additionally, the August 2003 blackout drew public attention to the fragile state of the grid. The North American Electric Reliability Council (NERC) expressed concerns that an unintended consequence of deregulation was that reliability had been negatively impacted. Subsequently, NERC and other relevant regulatory bodies began pressuring utilities to assure that they were meeting reliability standards. This supported a continuing rise in the hiring of lineworkers.

Non-Utility Lineworkers

The data outlined above does not reflect outsourcing of the lineworker function. In order to provide clarity of the workforce trends, discussions with selected stakeholders were conducted, as outlined in Appendix C. Primary outsourced services include overhead distribution, underground distribution, cable replacement (directional, boring and conventional), transmission construction and maintenance, storm restoration, and right-of-way. Non-utility lineworkers play a vital role in ensuring the reliable operation of the grid. For instance, Pike Electric, the largest electrical contractor in the Eastern United States, had 2,800 crewmembers, supervisors, and support staff providing Hurricane Katrina assistance by September 1, 2005.

Outsourcing companies experienced significant growth during the 1990s. For the most part, the demographics demonstrate a younger workforce than in utilities, and thus, the retirement concern is less acute. However, according to the BLS data shown in Figure 2, the number of contract lineworkers has been gradually decreasing recently, to 4,240 in 2005. It is probable that some of the change from 1999 to 2003 is due to changes in the data collection process at BLS, as discussed in Appendix D. Nevertheless, even focusing just on the data since 2003, the number of contractors has continued to decline indicating that there is a real trend. This is consistent with utility hiring placing pressure upon the lineworker employment pool, where traditionally better benefits at utilities make them the preferred employer. Thus, undoubtedly, some of these outsourced lineworkers went to work for utilities.

Non-Utility Lineworkers

8,900

5,470

4,4504,240

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

1999 2003 2004 2005

Year

Con

trac

tors

Fig. 2. Non-Utility Lineworker Employment Levels, 1999-2005 (Source: BLS).


2.1.3 Lineworker Wages

Electric lineworkers are one of the highest paid professions in the United States that does not require a post secondary education. In May 2005, electric lineworkers earned a mean hourly wage of $25.14/hr or $52,290 per year. Experienced electric lineworkers earned well above $32.54/hr and during overtime, based on this pay, could earn $48.81/hr. So, if an experienced electric lineworker earning a wage of $32.54/hr worked 20 overtime hours every month, the compensation could exceed $79,397.60 per year.

Growth in the industry is outpacing the number of available and qualified personnel. Companies have remarked that they could grow immediately by 400-500 more people, if they could find the right candidates. This demand places upward pressure on wages. As shown in Figure 3, electric industry lineworkers enjoy compensation above that paid to telecommunications lineworkers, and machinery manufacturing. This premium may be attributed to the hazards inherent to the job.

Comparative Mean Hourly Wage for Utilities, Telecommunications and Metalworking Machinery Manufacturing, 2004

Tel

ecom

mun

icat

ions

Wir

ed T

elec

omm

unic

atio

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Fig. 3. Comparative Hourly Wages for Electrical Lineworkers (Source: BLS).

2.2 Retirement Projections To ascertain information on expected retirement, several utilities were contacted and asked to supply their retirement projections. Across the organizations contacted, retirement eligibility and the percentage of the workforce expected to retire within the next five to ten years varies from about 11% to as high as 50%. One utility indicated that the high level of retirements that began a few years ago is expected to persist for quite a number of years due to the demographic profile and includes a very high percentage of the lineworker and engineering workforce. Tennessee Valley Authority (TVA), whose age demographics are shown in Figure 4, has already turned over a quarter of its workforce in the past 5 years and expects at least another third to retire in the next 5 years. This is not atypical of the industry.

Electric Utilities Telecommunications Manufacturing


TVA - Age Demographics

179

867 924

1,1921,396

2,489

2,891

2,007

526

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Average Age: 46

Fig. 4. Age Demographics at TVA (Source: TVA).

The loss of institutional knowledge is a key concern of those organizations facing a large amount of workforce turnover in the next decade. Although the retirement figures cited above may seem alarming, it is very unlikely that all of these individuals will retire at the same time. Based on discussions with selected utilities, retirement projections are estimated at 5.4% per year for lineworkers through 2010 (equivalent to just over 3,100 lineworkers per year), and then appear to drop off significantly to around 2.2% in the out-years. For comparison, recent retirement numbers at these utilities averaged approximately 3% per year, but this already reflected an increase over historical averages. Although these numbers may be indicative of the industry as a whole, the magnitude of the impact on individual utilities varies significantly. However, the electric industry is very aware of the criticality of the lineworker retirement situation, and is aggressively pursuing various approaches to mitigate any impact.

2.3 Lineworker Training

2.3.1 Lineworker Development Process

In order to meet the electric industry’s need for skilled technical personnel to fill the positions left empty by retirement and other attrition, a highly efficient and effective education and training program is required. Figure 5 presents a description of the lineworker training process. Potential lineworkers pass through various stages of career development, from “Introductory Training” to formal apprenticeship programs to on the job learning.


INTRODUCTORY TRAINING

6 monthsto 2 years

Generally conducted at lineworker training school or community college.

REGISTERED LINEWORKER

Apprenticeship Program

On the job training in the workforce at jobsite.

WORK EXPERIENCE

During this time, lineworkers may train on various types of work involving underground and overhead transmission and distribution lines.

LINEWORKERWORKING

CAREER

JOURNEYMAN

LEAD LINEWORKER

2 yrs. 4-5 yrs. 4-5 yrs. 15-20 yrs.

GENERIC LINEWORKER TRAINING PROCESSGENERIC LINEWORKER TRAINING PROCESS

INTRODUCTORY TRAINING

6 monthsto 2 years

Generally conducted at lineworker training school or community college.

REGISTERED LINEWORKER

Apprenticeship Program

On the job training in the workforce at jobsite.

WORK EXPERIENCE

During this time, lineworkers may train on various types of work involving underground and overhead transmission and distribution lines.

LINEWORKERWORKING

CAREER

JOURNEYMAN

LEAD LINEWORKER

2 yrs. 4-5 yrs. 4-5 yrs. 15-20 yrs.

GENERIC LINEWORKER TRAINING PROCESSGENERIC LINEWORKER TRAINING PROCESS

Fig. 5. Generic Lineworker Training Process.

Thus, as can be seen from Figure 5, the process of training a lineworker to the journeyman level requires from 4.5 to 7 years. Even after obtaining journeyman status, an additional 4 to 5 years of work experience is required before a lineworker is fully trained to execute the full range of lineworker duties. When the training process is examined as an integral unit, it is apparent that preparing a highly skilled electric utility lineworker can require 10 to 12 years, including classroom instruction and on the job experience.

A number of utility organizations provide in-house training. Some have partnered with educational institutions to provide the training that their craft personnel require. Others recruit from “lineworker training schools” that offer 6-8 week or 12-13 week certificate programs for individuals without any experience. Since the attrition rate is very high for new lineworkers, these courses help orient trainees to the mindset needed for lineworker careers before utilities make a large investment in the employee’s career development. In many cases, however, utilities will bring trainees directly into their apprenticeship programs without the student having completed an introductory training program.

2.3.2 Lineworker Training Programs

In 2005, there were approximately 31 lineworker-training programs across the country, with a total of 1,360 active students in various stages of lineworker training. Figure 6 shows the growth trend in such training institutions. Should the present trend continue, the number of pre-apprenticeship lineworker training institutions across the country could increase to 45 institutions by the year 2015.


Growth of Pre-Apprenticeship Programs

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No. of Programs Fig. 6. Lineworker Training Institutions, 1990-2005.

2.3.3 Apprenticeships

After the introductory training is complete, lineworker trainees generally enter an apprenticeship program for 4-5 years. These programs are usually operated by utilities and provide on the job training for candidates training to be journeyman lineworker. Data from the Registered Apprenticeship Information System (RAIS) database maintained by the Department of Labor shows that there are currently 5,842 registered lineworker apprentices in the industry today. When trainees are participating in apprenticeship programs, they are considered part of the lineworker workforce, even though they have yet to attain journeyman status.

2.4 Future Workforce

2.4.1 Projected Demand

The BLS Employment Matrix estimates that during the period from 2004 to 2014, the projected job demand for the “Electrical Power-line Installers and Repairers” category will remain relatively constant, from 50,946 in 2004 to 50,726 in 2014. Note that these numbers do not reflect contractors or individuals at the training institutions. The methodology for calculating the future projections is provided in Appendix D.

The BLS calculations assume that the work patterns will not change significantly over the projection period. Yet, the Energy Information Administration (EIA) estimates that electricity


demand will grow by approximately 17% between 2005 and 2015.5 Thus, it seems likely that the demand for lineworkers would grow as well, albeit slightly, during this period, unless significantly improved productivity could be achieved. In recent years 2003-2005, the growth rate of the demand for lineworkers was 1.5% per year. In addition, BLS projects that output in electric power generation, transmission, and distribution (a function of productivity) will increase at an average rate of 1.5% between 2004 and 2014.

2.4.2 Retirement Impact Analysis

In order to achieve an understanding of the impact that pending retirements will have on the lineworker workforce, projections were made based upon actual data from selected utilities, and used as representative percentages of the broader utility industries. Discussion with representatives from these organizations indicated that it is likely that the profiles for these organizations do reflect overall trends in the industry.

Figure 7 shows an analysis of the projections for lineworker supply and demand for the period 2005 until 2015. Assumptions are documented in Appendix E.

Lineworker Demand and Supply Analysis

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rs Lineworker Demand ( no change)

Lineworker Demand (0.75% increase)

Lineworker Demand (1.5% increase)

Lineworker Supply (With intervention)

Lineworker Supply (Base Case)

Fig. 7. Lineworker Supply and Demand Projections.

Three demand curves are illustrated. The first is steady-state (i.e. no change); this reflects the BLS workforce projection. The 1.5% annual growth rate case is reflective of the recent growth rate, as mentioned above. It might be considered an “extreme” case. The third case attempts to represent a modest growth rate (0.75%) that might be needed to meet the construction and maintenance requirements for achieving EIA’s 17% electricity growth projection by 2015.

5 Energy Information Administration (EIA), 2005, "Annual Energy Outlook 2006 with Projections to 2030", Annual Energy Outlook, December.


Two supply cases are also presented. The base case represents the apprenticeship, training program, and retirement numbers remaining consistent with the current situation (i.e., 1,360 students actively enrolled at training institutions; 5,842 registered lineworker apprentices working in the industry; and approximately 5.4% annual retirement rate for the next five years). The intervention case models an increase in enrollment at the training programs and apprenticeships, as well as a reduction in the attrition rates. In addition, some projected retirements are “delayed” by a year.

As shown, the base case indicates a shortage in lineworkers, most acute around 2010. Despite the growth in training institutions, retirements outpace the supply of new lineworkers. Even with the subsequent growth of supply in the out-years, the loss of historical knowledge (and perhaps productivity due to the more inexperienced workforce) might by itself have a detrimental effect on the reliability and security of the grid. For instance, a shortfall in lineworkers would create longer restoration times after a disruption.

Aging workforce strategies can become an asset to organizations. Aggressive intervention, through training, workforce retention, and phased retirements, could help mitigate any consequences. Thus, the electric industry is being proactive in addressing the lineworker shortage by building awareness, encouraging training initiatives, and increasing interest in the lineworker profession at an early age.

A major obstacle is still the time period that it takes to properly train qualified lineworkers. Addressing the situation as early as possible may help the nation to maintain and/or increase electricity supply. This can be accomplished through strong public-private partnerships to promote the energy industry as a viable employment option, to develop strategies for encouraging retirement-eligible workers to remain employed in the industry, and to ensure adequate training and education opportunities. Also, developing and using technology to increase productivity and fostering knowledge transfer may be beneficial.


3. Electric Power and Transmission Engineers 3.1 Current Workforce

3.1.1 Defining and Characterizing Electric Power Engineers

The electric power engineer traditionally focuses on systems and devices for the conversion, delivery, and use of electrical energy. Often, electric power engineering is considered a concentration within the electrical engineering profession. Specific subject areas include electromechanics, which includes magnetic and electric energy conversion methods and devices; large-scale power systems, which includes the analysis, operations, economics and control of electrical energy networks; and power electronic techniques for energy control, which includes design and operating methods for power semiconductor circuits and systems. Power engineering programs also include economics, business, and communications topics so students are knowledgeable about the business side of the power industry, as well as the technical side.

While the fundamental principles of power engineering have been around for a long time, the application of these principles, as well as our understanding of the electric system, continues to evolve. Communications and controls is one area that has changed dramatically over time. The growth in information technologies, along with our ability to monitor grid conditions in near real-time, has allowed us to better understand the intricate operation of the grid, and resulted in a re-examination of the fundamental principles upon which grid technologies are designed, installed, and operated. In addition, new discoveries enable technology enhancements that significantly improve the capability, performance, and reliability of the entire electricity system, which is integral to the economic and national security of the United States.

3.1.2 Employment of Power Engineers

In 2004, there were 10,280 electrical engineers working in the electric power generation, transmission and distribution (T&D) industry. Although there are power engineers working outside the electric utility industry, it is impossible to identify these individuals within the general electrical engineering category. Thus, all subsequent analysis on power engineers will only consider the industrial category identified above.

3.1.3 Power Engineer Earnings

Earnings for engineers vary significantly by specialty, industry, and education. For instance, according to surveys by the IEEE-USA, Table 2 shows salaries for engineers working in the power and energy markets are behind other fields that employ electrical engineers.6 Even so, as a group, engineers earn some of the highest average starting salaries among those holding bachelor’s degrees. Table 1 shows average starting salary offers for engineers, according to a 2005 survey by the National Association of Colleges and Employers.

6 Chowdhury, B., 2000, “Power Education at the Crossroads,” IEEE Spectrum, October.


Table 1. Engineer Starting Salaries, 2005.

(Source: National Association of Colleges and Employers) Curriculum Bachelor's

Aerospace/aeronautical/astronautical $50,993

Agricultural 46,172

Bioengineering & biomedical 48,503

Chemical 53,813

Civil 43,679

Computer 52,464

Electrical/electronics & communications

51,888

Environmental/environmental health 47,384

Industrial/manufacturing 49,567

Materials 50,982

Mechanical 50,236

Mining & mineral 48,643

Nuclear 51,182

Petroleum 61,516

Table 2. Median Salaries of U.S. Electrical Engineers (Source: IEEE Spectrum, October 2000)

Engineering Discipline Salary

Solid-state circuits $93,500

Communications 92,900

Laser and electro-optics 91,000

Software, aerospace and electronics 89,000

Components, manufacturing 88,850

Signals and application 87,000

Antennas & propagation 86,000

Medicine & biology signal processing 85,000

Electron Devices 84,750

Network administration 81,000

Power Electronics 80,050

Circuits and systems 80,000

Instrumentation and measurement 76,000

Energy and power engineering 73,625


3.2 Future Workforce

In general, the BLS projects that electrical engineers should have favorable employment opportunities. As shown in Table 3, the projected demand for power engineers will grow to 11,113 by 2014. This represents an 8.1% increase.

Table 3. Basic Employment Data for Power Engineers, 1994, 2004, and 2014. (Source: BLS)

Number of Jobs Industry 1994 2004 Projected 2014 Total employment, all industries 129,246,000 145,612,000 164,540,000 Electrical engineers, all industries N/A 156,000 174,000 Total, Electric power generation, transmission and distribution industry 505,000 412,000 400,000

Electrical engineers, electric power generation, transmission and distribution industry

N/A 10,280 11,113

Although international competition and the use of engineering services performed in other countries may limit employment growth, strong demand for electrical devices such as giant electric power generators should boost employment opportunities. The number of job openings resulting from employment growth and from the need to replace electrical engineers who transfer to other occupations or leave the labor force is expected to be in rough balance with the supply of graduates.7

This growth is in contrast to the job market in the power sector over the past two decades. Jobs for new power engineering graduates began declining in the 1980s when utilities saw a decline in electric consumption. The job market remained challenging with deregulation in the 1990s.8 At the time, new graduates often received job offers from manufacturers rather than utilities. However, by 2001 and 2002, power engineering graduates found positions at generation companies, transmission companies, power traders, independent system operators, independent power producers, consulting companies, and large processing and manufacturing companies that have extensive electrical facilities.9

3.2.1 Annual Demand for Power Engineers

The annual demand for electrical engineers in the electric utility industry can be found by applying the replacement rate factor assigned by the BLS.10 The replacement factor for electrical engineers is 7%. This factor is determined by the number of openings resulting from employment growth or the need to replace workers who leave an occupation. Thus, the average annual demand for electrical engineers in the electric utility industry is 749 per year for the 10 year period from 2004 to 2014. The replacement rate does not include job growth openings which would increase demand for power engineers. 7 U.S. Department of Labor (DOL), Bureau of Labor Statistics (BLS), 2006, “Occupational Outlook Handbook.” 8 Chowdhury, B., 2000, “Power Education at the Crossroads,” IEEE Spectrum, October. 9 Heydt, Gerald T. and Vijay Vittal, 2003, “Feeding Our Profession,” IEEE Power & Energy Magazine, January/February. 10 DOL, “Occupational Projections and Training Data, 2004-5 edition,” describes the replacement rate in “Chapter V. Estimating Occupational Replacement Needs.”


Electrical Engineer Graduates Entering the Power Industry, and Projected Annual Demand

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3.2.2 Annual Supply of Power Engineering Graduates

The average number of electrical engineering graduates between 1999 and 2004 was 11,526.11 Assuming: a) the future supply will remain the same as observed for the period 1999 to 2004 at 11,526 electrical engineering graduates per year; and b) the same factor of the number of electrical engineers in the electric utility industry as compared to all industries (i.e., 6.5%) also applies to the graduating electrical engineers, then 749 electrical engineers will enter the electric utility industry each year. Thus, the annual supply matches annual demand, and there is no forecasted shortage. However, as noted in section 3.2.4, assuming a constant number of electrical engineers may be a high estimate of the future number of power engineering graduates.

3.2.3 Workforce Analysis Using Department of Education Projections

For comparison purposes, a workforce analysis was also performed using data from the Department of Education, Institute of Education Sciences (IES). The assumptions are documented in Appendix F. The analysis used forecasts of the number of bachelor’s degrees earned, along with assumptions based on historical data, to estimate the annual supply of electrical engineering graduates entering the electric utility industry. As can be seen in Figure 8, the supply of electrical engineering graduates should be sufficient to meet the demand, reinforcing the previous findings. However, underlying this analysis is the assumption that there is a strong power engineering education system in the United States that will continue to produce these graduates. Indications are that it is actually weakening, and the rate of weakening will likely escalate as faculty retirements occur without replacement. This will be explored in greater detail in Section 3.3.

Fig. 8. Forecast of Electrical Engineers Entering the Power Industry

Using Department of Education Projections for Engineering Graduates

11 Gibbons, Michael T, 2004, “The Year in Numbers,” ASEE Profiles of Engineering and Engineering Technology Colleges.


3.2.4 Uncertainty of Assumptions There is significant uncertainty associated with the assumptions. For instance, the percentage of power engineering graduates of the total electrical engineering graduates is likely overestimated. Over the past decades, there has been a decline in the United States of the number of students considering power engineering careers, while in many countries outside of the United States, the power engineering profession enjoys more prestige and thus, experiences higher enrollment levels.12 In the 1970s, power concentration represented approximately 10.5% of undergraduate electrical engineering students in the United States, with international figures being higher. Over time, enrollments dropped, and by 2001, that percentage dropped almost in half to 5.9%.13

If we assume that future enrollment approximates the factor stated for 2001 (i.e., 5.9%), then 680 electrical engineers will enter the electric utility industry each year. In this scenario, there will be a slight shortage of power engineers since annual supply is less than annual demand. However, with the inflow of other engineering disciplines into the power sector and the growth of other training options, this shortage is relatively small and not projected to significantly impact the industry.

3.3 Status of Power Engineering Programs in the United States

Power engineering education programs are essential to the supply of power engineering graduates needed to meet future demands. Yet, over the past two decades, the number of power engineering programs at universities has declined. Top-tier research schools have eliminated power engineering concentrations from their electrical engineering programs. This decision influenced other universities to do the same. Without strong support for strategic research in power systems and without qualified replacements for retiring faculty, the strength of the university-based power engineering education programs could erode.

3.3.1 Applied Engineering versus Strategic Long-Term Research

University curriculums are heavily influenced by industry needs and hiring rates, as well as the availability of research funding. In response to low interest in power engineering, some universities eliminated power engineering programs from their curriculum. Many of those programs that remained adjusted the curriculum to respond to the changing utility market. The focus shifted to developing applied skills rather than fostering a deeper understanding of power systems theory. Students are trained on how to use tools and technologies to complete work assignments, but few students emerge with the ability to develop the tools themselves. Without a balanced approach, there can be little advancement in developing new technologies or modernizing the grid beyond current solutions.

Power engineering programs receive funding for research from all levels of government, research institutes, and members of the utility industry. However, industry funding, e.g., the

12 Chowdhury, B., 2000, “Power Education at the Crossroads,” IEEE Spectrum, October. 13 Heydt, Gerald T. and Vijay Vittal, 2003, “Feeding Our Professions,” IEEE Power & Energy Magazine, January/February.


Strategic vs. Applied R&D Funding

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Applied R&DStrategic R&D

EPRI R&D Funding

2004 budget of $272 million (trough)

1994 budget of$595 million (peak)

Electric Power Research Institute (EPRI) as shown in Figure 9, is heavily weighted towards applied research and development (R&D).

Fig. 9. EPRI’s Strategic vs. Applied R&D Funding, 1981 – 2004 14

Since much of industry’s focus has shifted toward addressing short-term applied problems, their interest in, and support for, long-term strategic research has declined. This has impacted the universities. According to a 2001-2002 survey conducted by the IEEE Power Engineering Society Committee, “Although total average funding for power programs increased from $375k to $650k per institution since 1993-1994, this increase has been entirely due to increased government funding ($110k to $490k per institution) while industry funding has decreased ($265k to 160k per institution).”15

Utilities, in response to perceived shortages in power engineering graduates, developed their own in-house training programs, taking strong engineering graduates in other disciplines and training them in the power engineering skills necessary to carry out day-to-day responsibilities. However, once again, these training courses tend to focus on applications, rather than engineering theory. To foster innovation to keep the United States on the forefront of technological advancement and to maintain our leadership position amidst international competition, strong support of strategic research at universities is critical.

3.3.2 Faculty Trends Recent data shows a decline in the number of United States power engineering faculty, which could lead to a shortage in the education system if not resolved. In general, United States power engineering programs are run by fewer faculty members than foreign programs are, as is evident in Figure 10.

14 Perlman, Brett, 2004, “Energy Technology R&D Funding,” October. 15 IEEE Power Engineering Society Committee Report, 2002, “Electric Power Engineering Education Resources, 2001-2002,” IEEE Transactions on Power Systems.


U.S. vs. Foreign Power Engineering Faculty, 2003

0

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Fig. 10. Average Power Engineering Faculty per Power Program 16

The figure further illustrates that the average United States power program lost 0.8 faculty members recently, yet only hired 0.6 new faculty members. Thus, new faculty members are not being added at a rate sufficient to make up for the anticipated loss of retiring faculty, just at a time that major losses will be occurring in the overall workforce and there will be a need to educate the next generation of power engineers. This is in part because some schools do not rehire power faculty, but instead use the faculty slots to hire individuals with other technical knowledge, such as very large-scale integration (VLSI) or computers. In addition, the age of the remaining United States faculty members is fairly high. This skewing was a result of weak hiring during the 1980s and 1990s.17 If many power engineering professors retire around the same time and there is an insufficient pool of suitable replacements, the power engineering shortage could be exacerbated.

3.3.3 Foreign Enrollment In the late 1970s and early 1980s, the majority of graduate students studying electric power engineering were domestic, with a smaller percentage being international. In the mid 1980s, this trend began to shift, and domestic students began to be outnumbered by international students. This trend has continued to grow; now, 50-75% of students come from abroad. The majority of international students are from Asia, but some are from Europe, Africa, and Latin America. Most U.S. power engineering graduate students receive their Masters’ degrees, while more international students work to obtain their Ph.D., as shown in Figure 11.18 16 Sauer, Peter W., Gerald T Heydt and Vijay Vittal, 2003, “The State of Electric Power Engineering Education,” report to PSERC, March. 17 Heydt, Gerald T. and Vijay Vittal, 2003, “Feeding Our Profession,” IEEE Power & Energy Magazine, January/February. 18 Ibid.


International Students Enrolled in Electric Power Graduate Programs

Graduate Degrees in Electric Power Engineering in the U.S.

International Students Enrolled in Electric Power Graduate Programs

Fig. 11. Power Engineering Enrollment – Graduate Programs19 In the past, declines in the U.S. science and engineering labor force could be made up by attracting the best and brightest scientists and engineers from around the world. This might be a viable solution for power engineering, particularly in the short-term. However, with new cutting-edge, research infrastructure being built overseas, there is less incentive for students to remain in the United States upon graduation. In addition, security changes make it harder for students to get high-skill-related visas and affect foreigners’ abilities to obtain employment. As Figure 13 shows, in 2002 and 2003, fewer high-skill-related visas were issued to students and exchange visitors than there were in 2001.

19 Ibid.


Fig. 12. High-Skill-Related Visas20

20 NSF, 2004, “The United States is a Changing World,” S&E Indicators – 2004.

High-Skill-Related Temporary Visas Issued, 1998-2003

High-Skill-Related Visa Applications and Refusals, 2000-2003


4. Conclusions and Recommendations This report analyzes the current trends in the workforce of the electric utility industry. In particular, it focuses on electrical lineworkers and electric power engineers. Table 4 identifies some of the similarities and differences between these two professions. As mentioned in the introduction, this analysis is not intended to produce precise estimates of workforce requirements, but rather is meant to highlight areas where shortages are likely to occur.

Table 4. Lineworkers vs. Power Engineers

Differences Similarities

Lineworkers Power Engineers Demographics – dominated by “Baby-Boomers” Industry very aware of retirement

situation Industry not completely aware of pending retirement impact

Loss of institutional knowledge as more retire Short-term impact to utility operation

Long-term impact to national competitiveness

Mergers, cutbacks, and downsizing over the past two decades

Interest in field is growing Interest in field is declining

In-house training programs being developed by industry to fill perceived voids

Training programs nearly doubled in last 10 years

University programs have declined over the past decade

Potential lack of qualified, interested replacements

High pay, especially for limited post-secondary education

Low pay, compared to other concentrations within electrical engineering

Electrical Lineworkers

The percentage of the lineworker workforce expected to retire within the next five to ten years could approach 50% in some organizations. The loss of institutional knowledge is a critical concern, especially for a profession heavily dependent on mentoring and on the job training. Although the number of lineworker training institutions has grown considerably, analysis indicates a significant shortage in the availability of qualified candidates. This could eventually limit the nation’s ability to maintain and/or increase electricity supply, potentially impacting the economic and national security of the United States.

The electric industry has primary responsibility for maintaining the reliable, safe operation of the electric grid. Thus, it is actively engaged in addressing any potential workforce shortages – building awareness of the problem, encouraging training initiatives, and increasing interest in the lineworker profession. Yet, given the importance of the electricity sector to the economy and security, public-private partnerships may be warranted to promote the energy industry as a viable employment option, to develop strategies for encouraging retirement-eligible workers to remain employed in the industry, and to ensure adequate training and education opportunities to support the reliability and safety of the electricity grid.


Electric Power and Transmission Engineers

The number of job openings resulting from employment growth and from the need to replace electrical engineers who transfer to other occupations or leave the labor force is expected to be in rough balance with the supply of power engineering graduates. However, this situation is not sustainable without the existence of power engineering education programs to supply the graduates, and statistics indicate that these university programs are in jeopardy.

Despite industry’s apparent ability to meet short-term workforce demand on the applications side, the decline in support for basic power systems research and education is of concern. It is an engine for innovation, exploration, and ingenuity, and is necessary for sustaining scientific advancement to maintain our competitive position in the world. In addition, due to the reticence in the electric industry, incremental decisions usually last 30-40 years, requiring a broader, long-term perspective. Thus, public-private partnerships should be considered to keep America’s power research capabilities strong and secure.

Recommendations

EPACT directed the Secretary of Energy to offer recommendations (as appropriate) to meet the future labor requirements. Based on the time necessary to develop qualified personnel, many of these recommendations can not immediately produce meaningful results. However, they are part of a long-term solution to meeting the future energy workforce demands of the United States.

Fostering Math and Science Education One concern with the low interest in certain science and technology programs at the university level, such as power engineering, is the lack of preparation for such programs while students are in high school, or even grade school. Students need the right combination of math, physics, and chemistry in order to pursue engineering in college. A system of education through the secondary level that equips each new generation of Americans with the educational foundation for future study is essential. This principle is consistent with President Bush’s American Competitiveness Initiative.

Building Interest in Energy-related Careers There is a perception among some students that energy-related fields are obsolete and old fashioned. However, there are significant opportunities for creativity and innovation to meet the challenges of the 21st century. In addition, not all these positions require advanced degrees, so individuals of varying educational backgrounds can find rewarding jobs and build successful careers. Federal agencies, such as the Department of Energy and the Department of Labor, could work with the private sector to communicate what the energy industry is about and to build awareness for the careers of tomorrow.


5. References Accreditation Board for Engineering and Technology (ABET), 2006, “Accredited Engineering Programs.” Available at http://www.abet.org/accrediteac.asp Anderson, J., 1999, “Making Sense of Mergers and Acquisitions” The Electricity Journal 12(7). American Public Power Association (APPA), 2005, “Work Force Planning for Public Power Utilities: Ensuring Resources to Meet Projected Needs.” Available at http://www.appanet.org/files/PDFs/WorkForcePlanningforPublicPowerUtilities.pdf Ashworth, Michael J., 2006, “Preserving Knowledge Legacies: Workforce Aging, Turnover, and Human Resource Issues in the U.S. Electric Power Industry” International Journal of Human Resource Management. Bridgers, Mark and Heather Johnson, 2005, “An Aging Workforce” Electric Perspectives September/October. Brown, Matthew H. and Richard P. Sedano, 2004, Electricity Transmission: A Primer, June. Burr, Michael, 2004, “The Talent Bubble” Public Utilities Fortnightly February. Chowdhury, B., 2000, “Power Education at the Crossroads” IEEE Spectrum October. Colorado School of Mines, 2006, “Advanced Control of Energy and Power Systems.” Available at http://www.mines.edu/research/ord/CentersPDF/ACEPS~FY02.pdf Economic History Services, 2006, “What was the Inflation Rate like Then?” Available at http://eh.net/hmit/inflation/inflationq.php Electric Utility Week; Unions See Hiring, Outsourcing, Medical Benefits as Big Issues in ‘04 Contract Talks; March 15 2004 Energy Information Administration (EIA), 1999, “The Changing Structure of the Electric Power Industry 1999: Mergers and Other Corporate Combinations” December. Available at http://www.eia.doe.gov/cneaf/electricity/corp_str/chapter1.html Energy Information Administration (EIA), 2005, "Annual Energy Outlook 2006 with Projections to 2030" Annual Energy Outlook December. Available at http://www.eia.doe.gov/oiaf/aeo/pdf/aeotab_8.pdf. Gibbons, Michael T., 2004, “The Year in Numbers,” ASEE Profiles of Engineering and Engineering Technology Colleges. Heydt, Gerald T. and Vijay Vittal, 2003, “Feeding Our Profession” IEEE Power & Energy Magazine January/February.


Institute of Electrical and Electronics Engineers (IEEE) Power Engineering Society Committee, 2002, “Electric Power Engineering Education Resources, 2001-2002” report to IEEE Transactions on Power Systems. Available at http://powerlearn.ee.iastate.edu/survey/pdf/resources01-02.pdf Karady, George G. and G.T. Heydt, 2000, “Increasing Student Interest and Comprehension in Power Engineering Education at the Graduate and Undergraduate Levels” report to Institute of Electrical and Electronics Engineers (IEEE) November. Karady, George, G.T. Heydt, P. Crossley, Manfred Michel, Hugh Rudnick, and Shinichi Iwamoto, 1999, “Review of Electric Power Engineering Education Worldwide” paper presented at the Institute of Electrical and Electronics Engineers (IEEE) Power Engineering Society Summer Meeting, 2: 906-915. Niederjohn, M. Scott, 2003, “Regulatory Reform and Labor Outcomes in the U.S. Electricity Sector” Monthly Labor Review May. National Science Foundation (NSF), 2004, “The United States is a Changing World” S&E Indicators. Perlman, Brett, 2004, “Energy Technology R&D Funding,” October. Available at http://eent1.tamu.edu/txeef/presentations/2/4.pdf. Platts, 2000, “Dayton P&L Hikes Linemen Pay $2/Hour in Apparent Move to Stem Defections” Electric Utility Week October 23. Platts, 2004, “Unions See Hiring, Outsourcing, Medical Benefits as Big Issues in ‘04 Contract Talks”, Electric Utility Week March 15. Power Systems Engineering Research Center (PSERC), 2006, “About PSERC.” Available at http://www.pserc.wisc.edu/about.htm Ray, Dennis and Bill Snyder, 2005, “Strategies to Address the Problem of Exiting Expertise in the Electric Power Industry” paper presented at the Institute of Electrical and Electronics Engineers (IEEE) Hawaii International Conference on System Sciences, Symposium on Electric Power Systems Reliability, January 4-8. Reder, Wanda, 2004, “Managing the Aging Workforce With Technology and Process Improvement” presented at the Edison Electric Institute (EEI) Fall Conference, Minneapolis, Minnesota. Sauer, Peter W., Gerald T. Heydt and Vijay Vittal, 2003, “The State of Electric Power Engineering Education” report to Power Systems Engineering Research Center (PSERC), March. U.S.-Canada Power System Outage Task Force, 2004, “Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations” April.


U.S. Census Bureau, 2006, “Statistical Abstract of the United States: 2000; No.14. Resident Population Projections by Sex and Age: 2000 to 2050.” Available at http://www.census.gov/prod/2001pubs/statab/sec01.pdf U.S. Department of Education, Institute of Education Sciences, 2004, “Trends in Educational Equity of Girls and Women: 2004” NCES 2005–016. Available at http://nces.ed.gov/pubs2005/2005016.pdf U.S. Department of Education, Institute of Education Sciences, 2005, “Projection of Education Statistics to 2014” NCES 2005–074, September. Available at http://nces.ed.gov/pubs2005/2005074.pdf; U.S. Department of Education, Institute of Education Sciences Trends in Educational Equity of Girls and Women: 2004, NCES 2005–016. http://nces.ed.gov/pubs2005/2005016.pdf U.S. Department of Education, Institute of Education Sciences, 2005, “Projection of Education Statistics to 2014” NCES 2005–074, September. Available at http://nces.ed.gov/pubs2005/2005074.pdf U.S. Department of Labor (DOL), Bureau of Labor Statistics (BLS), 2006, “BLS Handbook of Methods – Chapter 13: Economic Growth and Employment Projections.” Available at http://www.bls.gov/emp/empmth01.htm (updated December 2005). U.S. Department of Labor (DOL), Bureau of Labor Statistics (BLS), 2006, “Industry-Occupation Employment Matrix, 2004 and projected 2014.” Available at http://data.bls.gov/oep/servlet/oep.nioem.servlet.ActionServlet?Action=empior&MultipleSelect=XXXXXX&Sort=ws_emp_b&StartItem=0&Resort=No&ResortButton=No&Base=2004&Proj=2014&SingleSelect=221100&Type=Industry&Number=10 U.S. Department of Labor (DOL), Bureau of Labor Statistics (BLS), 2006, “Occupational Outlook Handbook.” Available at http://www.bls.gov/oco/ocos027.htm

U.S. Department of Energy Workforce Trends in the Electric Utility Industry A-1

Appendix A

Energy Policy Act of 2005, Section 1101

SEC. 1101. WORKFORCE TRENDS AND TRAINEESHIP GRANTS (a) DEFINITIONS.— In this section:

(1) ENERGY TECHNOLOGY INDUSTRY.— The term “energy technology industry” includes—

(A) a renewable energy industry; (B) a company that develops or commercializes a device to increase energy

efficiency; (C) the oil and gas industry; (D) the nuclear power industry; (E) the coal industry; (F) the electric utility industry; and (G) any other industrial sector, as the Secretary determines to be appropriate.

(2) SKILLED TECHNICAL PERSONNEL.—The term “skilled technical personnel” means—

(A) journey- and apprentice-level workers who are enrolled in, or have completed, a federally-recognized or State-recognized apprenticeship program;

(B) other skilled workers in energy technology industries, as determined by the Secretary.

(b) WORKFORCE TRENDS.— (1) MONITORING.— The term Secretary, in consultation with, and using data

collected by, the Secretary of Labor, shall monitor trends in the workforce of— (A) skilled technical personnel that support energy technology industries; and (B) electric power and transmission engineers.

(2) REPORT ON TRENDS.—Not later than 1 year after the date of enactment of this Act, the Secretary shall submit to Congress a report on current trends under paragraph (1), with recommendations (as appropriate) to meet the future labor requirements for the energy technology industries.

(3) REPORT ON SHORTAGE.—As soon as practicable after the date on which the Secretary identifies or predicts a significant national shortage of skilled technical personnel in 1 or more energy technology industries, the Secretary shall submit to Congress a report describing the shortage. (c) TRAINEESHIP GRANTS FOR SKILLED TECHNICAL PERSONNEL.— The

Secretary, in consultation with the Secretary of Labor, may establish programs in the appropriate offices of the Department under which the Secretary provides grants to enhance training (including distance learning) for any workforce category for which a shortage is identified or predicted under subsection (b)(2).

(d) AUTHORIZATION OF APPROPRIATIONS.— There is authorized to be appropriated to carry out this section $20,000,000 for each of fiscal years 2006 through 2008.

A-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry B-1

Appendix B

List of Acronyms ABET Accreditation Board of Engineering and Technology APPA American Public Power Association BLS Bureau of Labor Statistics CPS Current Population Survey DOE Department of Energy DOL Department of Labor EIA Energy Information Administration EPACT U.S. Energy Policy Act of 2005 EPRI Electric Power Research Institute GDP Gross Domestic Product IEEE Institute of Electrical and Electronics Engineers IES Institute of Education Services NAICS North American Industry Classification System NERC North American Electric Reliability Council NSF National Science Foundation OES Occupational Employment Statistics OSHA Occupational Safety and Health Administration PSERC Power Systems Engineering Research Center R&D Research and Development RAIS Registered Apprenticeship Information system SOC Standard Occupation Code T&D Transmission and Distribution TVA Tennessee Valley Authority VLSI Very Large-Scale Integration

B-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry C-1

Appendix C

Research Methodology / Data Sources The methodology used to study the workforce trends within the electric utility industry involved examining available historical data and future employment projections on lineworkers and power engineers, conducting interviews with electric utilities and other industry stakeholders, and contacting learning institutions to ascertain the number of individuals in the pipeline. The analysis timeframe was constrained to a 25 year window, 1990-2015. This allowed for a retrospective, as well as a prospective view.

Data from Bureau of Labor Statistics (BLS) – The BLS compiles data on all U.S. labor categories. Using various sampling techniques, BLS is able to estimate the number of workers comprising any particular job category. Using BLS data, historical and current worker profiles were developed.

Interviews with Electric Utilities and Other Stakeholders – In order to gain an enhanced view of the workforce trends that might not be captured by the BLS data, interviews with selected utilities were conducted. These interviews focused on gathering current information on retirement profiles across the industry. They also identified the challenges with retaining and recruiting employees across the Nation.

Discussions with Learning Institutions – To obtain a deeper understanding of current training capacity across the country, interviews were conducted with training institutions that offer lineworker-training programs. Career centers at various universities were contacted regarding engineering enrollment levels.

Other Data Sources – In addition to DOL, data was extracted from other federal sources, including DOE’s Energy Information Administration (EIA). Researchers also examined reports published by organizations such as the Institute of Electrical and Electronics Engineers (IEEE), the American Public Power Association (APPA), the National Science Foundation (NSF), and the Power Systems Engineering Research Center (PSERC). Articles were garnered from journals such as Public Utilities Fortnightly, Electric Utility Week, Electric Perspectives, Monthly Labor Review, and IEEE Power and Energy Magazine.

C-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry D-1

Appendix D

BLS Projection Methodology21 National employment projections are developed every other year. The projections used in this report cover the 2004-2014 period. The next National projections cycle will cover the 2006-2016 period. Those projections are scheduled to be published in the November 2008 Monthly Labor Review. To determine future employment projections, the Department of Labor uses a six-step process. Each step is based on a separate projection procedure and model but relies on the same assumptions.

Size and Demographic of the Labor Force Using data from the U.S. Bureau of the Census, the future labor force is projected based on projections of the race, age, and sex of the current and projected population; trends in labor force participation rates; and the percent of each group in the population that will be seeking work. Approximately 130 categories are used. Once these criteria are determined, a trend rate of change in labor force participation is estimated (based on the previous 8 years). Modifications are made as needed to the rate to ensure consistency with demographic projections. Finally, the size of the work force is determined by multiplying the rates with population projections. Growth of the Aggregate Economy To project the growth of the economy, the BLS projects the GDP and the major categories of demand and income from “Macroeconomic Advisers, LLC WUMMSIM Model of the U.S. Economy (MA model)”. The two projections should provide results that are consistent with each other and with other assumptions of the other scenarios.

21 DOL, BLS, 2006, “BLS Handbook of Methods – Chapter 13: Economic Growth and Employment Projections.”

Six Steps Size and Demographic of the Labor Force Growth of the Aggregate Economy Final Demand of Gross Domestic Product (GDP) Inter-Industry Relationships (input-output) Industry Output and Employment Occupational Employment

Sample Assumptions

Broad social and educational trends will continue Fluctuations in economic activity due to the basic business cycle will occur

D-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

Final Demand of Gross Domestic Product To determine the final demand of GDP, the economy is broken into 180 sectors. A forecast of the final expenditures for each of the commodity sector in the input-output table is produced. Input-Output Tables To produce the GDP, an estimate of the flow of goods and services in the economy required is first used. Since GDP reflects only final sales, intermediate inputs must be determined. The input-output tables are then used to derive an estimate at the industry level of employment and capital necessary to produce a given level of GDP. Industry Employment The demand for wage and salary is projected using an equation that relates an industry’s labor demand to its output, its wage relative to its output price, and a time trend. The annual average weekly wage and salary hours per job are then estimated as a function of time and the unemployment rate. The projection of average hours is then used to convert the projection of wage and salary hours into jobs. Occupational Employment Occupational employment projections are based on an industry occupation matrix that shows the distribution of employees over 250 industries and 500 detailed occupations. Staffing patterns are based on data collected from State employment security agencies. Once projected staffing patterns are created, they are used to allocate each industry’s projected employment to detailed occupations. SOURCES OF BLS DATA The 2004-2014 National Industry-Occupation Employment Matrix was developed by the BLS as part of its ongoing Occupational Employment Projections Program. Data from the matrix underlies information on occupational employment growth presented in the Occupational Outlook Handbook and Career Guide to Industries. The 2004 matrix was developed primarily from the Occupational Employment Statistics (OES) survey, the Current Employment Statistics (CES) survey, and the Current Population Survey (CPS). OCCUPATIONAL AND INDUSTRY CLASSIFICATION SYSTEMS In January 2003, the Current Population Survey (CPS or "household" survey) adopted the 2002 Census occupational and industry classification systems, which are derived, respectively, from the 2000 Standard Occupational Classification (SOC) and the 2002 North American Industry Classification System (NAICS). These systems replaced the 1990 Census occupational and industry classifications. The introduction of the 2002 Census occupational and industry classification systems created a complete break in comparability with existing data series at all levels of occupation and industry aggregation. Hence, any comparisons of data on the different classifications are not possible without major adjustments.

U.S. Department of Energy Workforce Trends in the Electric Utility Industry E-1

Appendix E

Lineworker Workforce Analysis Assumptions This list of assumptions is the basis upon which the lineworker supply and demand analysis was conducted. General

All time based projections are made on the basis of linear extrapolation. All training program retention rates represent long-term averages over the analysis period. The workforce includes apprentices, contractors, and journeymen, but not pre-apprentices.

Retirements

The retirement profiles provided by the sampled utilities are consistent with retirement profiles across the industry.

Percentages are taken on the basis of a fixed employment pool versus augmenting or decrementing over time.

Retirement delays are of one-year duration. All line worker attrition is due to retirement.

Pre-Apprenticeship Training Institutions

Standard training program is 2 years in length One half of the program graduates per year Matriculating pre-apprenticeship graduates are fully absorbed by the private sector electrical

contractors. Apprenticeship Programs

Standard program is 4 years in length One quarter of the program graduates per year All matriculating apprentices are absorbed by the utility industry

Contractors

Contractor labor pool comes uniquely from the pool of matriculating pre-apprenticeship students.

Base Case Intervention Case Apprenticeship Growth Rate 0% 5% Apprenticeship Retention Rate 90% 90% Pre-Apprenticeship Growth Rate 0% 5% Pre-Apprenticeship Retention Rate 85% 85% Percent of delayed retirements 0% 10%

E-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

U.S. Department of Energy Workforce Trends in the Electric Utility Industry F-1

Appendix F

Power Engineering Workforce Analysis Assumptions22 Based on extrapolations of data from the Department of Education, Institute of Education Sciences (IES), between 2004 and 2014, there will be a 17% increase in the number of earned bachelor’s degrees. Projections of bachelor's degrees are based on projections of college-age populations and college enrollment, by sex, attendance status, level enrolled by student, and type of institution, as well as disposable income per capita and unemployment rates. By the year 2014, the IES projects that more than 60% of bachelor degrees will be earned by women. Men will be awarded 633,000 degrees, while 949,000 will be awarded to women.

22 The analysis shown in Appendix F is based on extrapolations of data from reports released by the U.S. Department of Education, National Center for Education Statistics. There is considerable uncertainty and volatility in the information. Therefore, this analysis must not be assumed to produce precise estimates of workforce requirements, but rather should be used only to indicate overall trends.

Actual and Projected Bachelor’s Degrees Earned: 1989-2014

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

Bac

helo

r's D

egre

es E

arne

d (M

illio

ns)

Total Men Women

Source: U.S. Department of Education, Institute of Education Sciences, Projections of Education Statistics to 2014, NCES 2005–074, September 2005. http://nces.ed.gov/pubs2005/2005074.pdf

Actual Projected

F-2 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

Based on historical data shown below, in recent years slightly over 1% of bachelor degrees awarded were in the field of electrical engineering. This analysis will assume that this percentage remains constant. Also, of graduating electrical engineers, it is assumed that 6.5% will enter the utility industry. This is the same proportion as in the overall electrical engineering workforce.

Although the number of women in technical fields is increasing, they currently account for approximately 20% of engineering degrees. If historical trends continue in the future, it is possible that 30% of engineering degrees will be awarded to women by 2014.

Percentage of EE Bachelor’s Degrees Earned of All Degrees awarded: 1970-2003

0.0%

0.5%

1.0%

1.5%

2.0%

2.5%

3.0%

1970

1972

1974

1976

1978

1980

1982

1984

1986

1988

1990

1992

1994

1996

1998

2000

2002

Perc

enta

ge o

f EE

Deg

rees

of a

ll D

egre

es

Aw

arde

d

Sources: http://nces.ed.gov/programs/digest/d04/tables/xls/tabn247.xls http://nces.ed.gov/programs/digest/d04/tables/dt04_283.asp

U.S. Department of Energy Workforce Trends in the Electric Utility Industry F-3

Based on this information, it is possible to project the number of future graduates in electrical engineering. The figure below provides historic as well as projected data of the number electrical engineering degrees. By 2014, nearly 17,000 electrical engineers will graduate each year, representing a 13% increase over 2004.

Combining historical data with projections of the number of future graduates, it is possible to predict the number of electrical engineers that will choose to work in the power industry after

Actual and Projected Electrical Engineering Bachelor’s Degrees Earned: 1989-2014

02468

1012141618

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

EE B

ache

lor's

Deg

rees

(Tho

usan

ds)

Total Men Women Sources: U.S. Department of Education, Institute of Education Sciences, Projection of Education Statistics to 2014, NCES 2005–074, September 2005. http://nces.ed.gov/pubs2005/2005074.pdf; U.S. Department of Education, Institute of Education Sciences Trends in Educational Equity of Girls and Women: 2004, NCES 2005–016. http://nces.ed.gov/pubs2005/2005016.pdf

Actual and Projected Percentage of Engineering Bachelor’s Degrees Earned by Women: 1969-2014

0

5

10

15

20

25

30

1969

-70

1974

-75

1979

-80

1984

-85

1989

-90

1994

-95

2000

-01

2004

-05

2009

-10

2014

-25

Perc

ent (

%)

Source: U.S. Department of Education, Institute of Education Sciences Trends in Educational Equity of Girls and Women: 2004, NCES 2005–016. http://nces.ed.gov/pubs2005/2005016.pdf

Actual

Projected Actual

Projected

F-4 U.S. Department of Energy Workforce Trends in the Electric Utility Industry

graduation. The figure below demonstrates the projected number of graduates entering the industry, as well as a prediction of the annual demand. It has been assumed that of those choosing to enter the power industry, 10% are international students who will return to their home country upon graduation. The annual demand for electrical engineers in the electric utility industry can be found by applying the replacement rate factor assigned by the BLS.23 The replacement factor for electrical engineers is 7%. This factor is determined by the number of openings resulting from employment growth or the need to replace workers who leave an occupation. Based on this, the annual demand in 2004 was 719 electrical engineers, and in 2013 will be 780 electrical engineers. Assuming that the annual increase in demand will be linear, as can be seen in the figure below, the supply of undergraduate level electrical engineers should be sufficient to meet the demand.

23 DOL, “Occupational Projections and Training Data, 2004-5 edition,” describes the replacement rate in “Chapter V. Estimating Occupational Replacement Needs.”

Electrical Engineers Entering the Power Industry, and Projected Annual Demand

500

600

700

800

900

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

Ann

ual D

eman

d

Supply Demand

Projected Actual

TASK FORCE ON AMERICA’S FUTURE ENERGY JOBS

N A T I O N A L C O M M I S S I O N O N E N E RG Y P O L I C Y ’ S

EXECUT IVE SUMMARY AND POL ICY RECOMMENDAT IONS

NATIONAL COMMISSION ON ENERGY POLICY | 1225 I STREET, NW, SUITE 1000 | WASHINGTON, D.C. 20005

T: 202-204-2400 | F: 202-637-9220 | WWW.ENERGYCOMMISSION.ORG

61443_C01_4_x.indd 1 9/30/10 7:02 PM

design: www.katetallentdesign.com

NCEP Task Force Staff

Sasha MacklerResearch Director

David RosnerAssociate Director, Energy Research

Marika TatsutaniWriter and Technical Editor

The Bipartisan Policy Center has engaged MOSAIC, a carbon neutral EPA Green Power Partner, for the production of this brochure, using 100% wind power and a waterless printing process. The brochure was printed on FSC certifi ed stock with 100% environmentally friendly soy-based inks. The savings below are achieved when PC recycled fi ber is used in place of virgin fi ber. This project uses 1423 lbs of paper which has a postconsumer recycled percentage of 30%.

4 trees preserved for the future

10 lbs water-borne waste not created

1,523 gal wastewater fl ow saved

169 lbs solid waste not generated

332 lbs net greenhouse gases prevented

2,540,055 BTUs energy not consumed

Disclaimer

This report is a product of a Task Force with participants of diverse expertise

and affi liations, addressing many complex and contentious topics. It is inevi-

table that arriving at a consensus document in these circumstances entailed

compromises. Accordingly, it should not be assumed that every member is

entirely satisfi ed with every formulation in this document, or even that all

participants would agree with any given recommendation if it were taken in

isolation. Rather, this group reached consensus on these recommendations as

a package, which taken as a whole offers a balanced approach to the issue.

It is also important to note that this report is a product solely of the partici-

pants from the NCEP convened Task Force on America’s Future Energy Jobs.

The views expressed here do not necessarily refl ect those of the National Com-

mission on Energy Policy.

Acknowledgements

The National Commission on Energy Policy would like to express its thanks for

the strong support of its funders. The Commission was founded in 2002 by

the William and Flora Hewlett Foundation and its partners.

The NCEP staff gratefully acknowledges the substantial guidance, research,

and support offered by M.J. Bradley & Associates, LLC throughout the course

of this effort. In particular, Michael Bradley, President, Carrie Jenks, Senior VP,

Tom Curry, Senior Policy Analyst, and Kathleen Robertson, Senior Policy

Analyst, were essential members of the project team as was Elizabeth Ewing,

of Ewing Smith Consulting, LLC. Additionally, special thanks to Ian Copeland,

President, Power, New Technology, and Rick Franzese, Senior Development

Manager, both of Bechtel Power Corporation, for generously lending their

expertise to the Task Force. Thanks also to Revis James, Director of the Energy

Technology Assessment Center at the Electric Power Research Institute for al-

lowing the Task Force to draw on the EPRI analyses in this area.

61443_C01_4.indd 2 9/27/10 9:40 AM




61443_P01_32.indd i61443_P01_32.indd i 9/27/10 9:48 AM9/27/10 9:48 AM

i i Task Force on America’s Future Energy Jobs

Carol Berrigan—Senior Director, Industry Infrastructure, Nuclear Energy Institute (NEI)

Ian Copeland—President, New Technology, Bechtel Power Corporation

Dr. Nancy Grasmick—State Superinten-dent of Schools, State of Maryland

Mary Miller—Vice President of Human Resources, Edison Electric Institute

Ann Randazzo—Director, Center for Energy and Workforce Development (CEWD)

William Stevens—Senior Power Technology Advisor, U.S. Environmental Protection Agency

Task Force Advisors

Advisors to the Task Force on America’s Future Energy Jobs provided invaluable technical input and information but did not participate in Task Force decisions aimed at developing policy recommendations. Therefore, Task Force advisors do not endorse the recommendations put forward in this white paper.

Paul Allen—Senior Vice President, Corporate Affairs, Chief Environmental Offi cer, Constellation Energy

Bill Banig—Legislature Director, United Mine Workers of America

Bob Baugh—Executive Director, Industrial Union Council, AFL-CIO

Abe Breehey—Director of Legislative Affairs, International Brotherhood of Boilermakers

Marcy Drummond—Vice President of Academic Affairs, Los Angeles Trade-Technical College

Dr. Scott Farrow—Chair of Economics Department, University of Maryland, Baltimore County (UMBC)

Barbara Hins-Turner—Executive Director, Center of Excellence for Energy Technology, Centralia College (WA)

Jim Hunter—Director, IBEW Utility Department, International Brotherhood of Electrical Workers

Dr. Nicholas P. Jones—Dean, G.W.C. Whiting School of Engineering, Johns Hopkins University

Gary Kaplan—Executive Director, JFYNetWorks

Nerida Perez—Vice President, Inclusion and Diversity, National Grid

Robert J. Pleasure—Director of Education, Building and Construction Trades Department, AFL-CIO

Dr. Nan Poppe—Campus President (retired May, 2010), Portland Community College

Roxanne Richards—Director, Workforce Development, Midwest Generation, Edison Mission Group

Van Ton-Quinlivan—Director, Workforce Development, Pacifi c Gas and Electric Company (PG&E)

Dee Torres—Recruiting Lead for Genera-tion, Exelon Corporation

Jeff Williams—Manager, Corporate Environmental Initiatives, Entergy Corporation

Task Force Participants

61443_P01_32.indd ii61443_P01_32.indd ii 9/27/10 9:49 AM9/27/10 9:49 AM

Task Force on America’s Future Energy Jobs 1

Policy Context .................................................................................................................................... 2

Executive Summary ............................................................................................................................ 6

Task Force Recommendations ......................................................................................................... 16

• Recommendation 1: Establish Regional, Multi-Stakeholder Workforce Consortia ............. 17

• Recommendation 2: Improve Data Collection ..................................................................... 22

• Recommendation 3: Best Practices and Training Standards for Energy Sector Jobs ..........23

• Recommendation 4: Support for Individuals .......................................................................26

• Recommendation 5: Education and Career Counseling ...................................................... 28

CONTENTS

61443_P01_32.indd 161443_P01_32.indd 1 9/27/10 9:49 AM9/27/10 9:49 AM

I

2 Task Force on America’s Future Energy Jobs

POLICY CONTEXT

n 2009, the National Commission on Energy Policy

(NCEP) convened a task force to explore the work-

force needs of the U.S. energy sector and develop

recommendations concerning how best to address

the intertwined challenges of preserving American

jobs and competitiveness, while also tackling energy

security and climate change. NCEP’s Task Force on

America’s Future Energy Jobs issued its fi rst report in

October 2009. Writing in the foreword to that report,

Task Force co-chairs Norman Augustine and Senator

Peter Domenici (retired) emphasized the urgency of

energy workforce issues in the context of high

unemployment and looming skill shortages in critical

energy industries.

61443_P01_32.indd 261443_P01_32.indd 2 9/27/10 9:49 AM9/27/10 9:49 AM


THE CASE FOR A COHERENT,

TARGETED NATIONAL POLICY TO

MEET EVOLVING ENERGY-SECTOR

WORKFORCE DEMANDS REMAINS

AS COMPELLING AS EVER.

One year later, with the national unemployment

rate still close to 10 percent (the unemployment

rate in the construction sector is more than 20

percent) and with Congress deadlocked over

energy and climate legislation, the case for a

coherent, targeted national policy to meet evolving

energy-sector workforce demands remains as

compelling as ever.

This report revisits the Task Force recommen-

dations and adds detail concerning the specifi c

steps that should be taken to implement them.

Specifi cally, we discuss concrete actions to

improve workforce training programs, improve

workforce data collection and management,

develop industry credentials, provide funding

for energy-related workforce training and

education, strengthen basic math and science

skills, and increase awareness of energy-sector

career opportunities. We believe all of these

steps are important as part of a comprehensive

strategy for preparing U.S. workers to participate

in and benefi t from the job opportunities

associated with transitioning to a low-carbon

economy. Most important, however, will be

greater clarity and certainty about the future

direction of energy and environmental policy

in the United States more broadly. During the

fall of 2009, Congress and the Administration

appeared to be making progress in advancing

a new long-term energy agenda for the nation

through stimulus funding and House-passed

energy and climate legislation. Indeed, the 2009

American Recovery and Reinvestment Act

provided funding to begin addressing some of

the specifi c needs highlighted in the Task Force

report, such as funding for regional energy train-

ing partnerships. Broader energy and climate

legislation, however, has since stalled in the Senate.

The current political stalemate perpetuates

uncertainties that threaten to undermine efforts

to prepare for the energy workforce needs of the

future because it discourages the investment

in the next generation of energy technologies

and infrastructure that could ignite a wave of

new job and career opportunities in the energy

sector. Without some regulatory certainty,

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WITHOUT SOME REGULATORY

CERTAINTY, THE ELECTRIC POWER

SECTOR WILL CONTINUE TO

DEFER MANY OF THE LARGE

CAPITAL INVESTMENTS NEEDED

TO BUILD NEW POWER PLANTS

AND TRANSMISSION CAPACITY,

LET ALONE WIND FARMS,

SOLAR INSTALLATIONS, NUCLEAR

PLANTS, AND OTHER

LOW-CARBON TECHNOLOGIES.

particularly as regards to future carbon and

renewable energy policies, the electric power

sector will continue to defer many of the large

capital investments needed to build new power

plants and transmission capacity, let alone wind

farms, solar installations, nuclear plants, and

other low-carbon technologies. And without a

sense of future investment patterns or a clear

policy path forward, it is diffi cult to predict the

types of skills that will be needed and when

new kinds of job opportunities will become

available. Interest in related training programs

or professional degrees and opportunities to

develop skills through apprenticeship programs

will suffer accordingly. In sum, the lack of a

long-term energy strategy for the United States

is more than just a climate issue, a competitive-

ness issue or an energy security issue—it is a

jobs issue. The longer Congress delays action

on diffi cult but critical policy questions, the

longer investments will be delayed, the less

time there will be to prepare American workers,

and the more likely it is that technologies will

be imported and domestic job opportunities

will be lost.

Of course, Task Force members recognize that

some near-term workforce challenges, particularly

in the electric sector, have shifted since we fi rst

met at the beginning of 2009. In particular,

concerns about a lack of qualifi ed applicants to

replace retiring workers moved a little further

away as employees postponed retirement in

response to the economic crisis. Longer term,

however, this issue is likely to re-emerge. As

the economy begins to rebound and employee

retirement savings recover, the industry could

face an even larger wave of retirements (a “silver

tsunami”) as some employees who postponed

retirement leave the work force at the same time

as those who are retiring on schedule.

The recommendations and specifi c implementa-

tion steps outlined in this follow-up Task Force

report will help to ensure that the electric utility

industry can fi nd workers with the skills to fi ll

these vacancies. More broadly, they aim to ensure

that America’s workers are equipped to under-

take—and benefi t from—a technology revolution

that must sooner or later transform our nation’s

energy systems and the larger economy.

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In January of 2009, the National Commission

on Energy Policy (NCEP) convened a group of

stakeholders with expertise in the workforce of

the U.S. electric power industry. The NCEP Task

Force on America’s Future Energy Jobs brought

together representatives from labor, the electric

power industry, and the training and educational

sectors to explore—over a series of three meetings

in six months—the existing demographic makeup

and anticipated workforce needs of the electric

power sector, along with the training institutions

and programs that support this sector. This report

summarizes the insights and conclusions resulting

from this effort.

EXECUTIVE SUMMARY

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THE UNITED STATES IS FACING

A CRITICAL SHORTAGE OF TRAINED

PROFESSIONALS TO MAINTAIN

THE EXISTING ELECTRIC POWER

SYSTEM AND DESIGN, BUILD,

AND OPERATE THE FUTURE ELECTRIC

POWER SYSTEM.

Broadly speaking, the Task Force believes the

United States is facing a critical shortage of

trained professionals to maintain the existing

electric power system and design, build, and

operate the future electric power system. The

implications of this shortfall are wide-ranging

and, in the view of the Task Force, of national

signifi cance. The ability to maintain a highly

reliable, economically affordable electric power

system while modernizing the nation’s generating

infrastructure to support an advanced, low-carbon

technology portfolio is in serious jeopardy. This

report highlights the main forces driving this

situation and lays out a series of recommenda-

tions for addressing the dominant workforce

challenges that will confront the electric power

industry over the next several years. Ensuring

the proper systems and institutions are in place

to respond to these challenges is important, not

only in terms of advancing critical public policy

goals with respect to energy, the economy, and

the environment, but because a substantial

opportunity exists to create new high-skill,

high-paying jobs in the energy sector at a time

when growing numbers of Americans are

unemployed or underemployed and face the

prospect of fi nancial insecurity.

There have, of course, been signifi cant changes

in the political and economic landscape since

the the Task Force was formed. The Obama

Administration is committed to an energy policy

that aims to reduce the nation’s consumption of

fossil fuels and contribution to global green-

house gas emissions. At the same time, an

unprecedented economic crisis has crippled

global fi nancial markets, halted global economic

growth, and led to massive job losses in the

United States and elsewhere. Against this

backdrop, the Task Force set about examining

workforce supply and demand dynamics in the

electric power industry. The American Recovery

and Reinvestment Act (ARRA) passed in 2009

provided a near-term infusion of resources

that have the potential to facilitate many of the

actions recommended in this report. To ensure

that these short-term investments build the long-

term capacity needed to address multi-decade

challenges like climate change, policymakers

should consider the actions recommended in

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this report when reauthorizing the Workforce

Investment Act (WIA) and crafting climate and

energy legislation.

Data and Defi nitions

NCEP conducted signifi cant background analytical

work to better assess the challenges that are

often reported anecdotally by concerned parties.

One of the most important conclusions from

this work is that data collection and measure-

ment systems needed to gauge the state of

our nation’s energy workforce are woefully

inadequate. For this reason, the NCEP team

endeavored to commission new work and

access available information to characterize

the challenges. While the data collected and

presented in this report represent a signifi cant

contribution to the debate, we believe that

this assessment is best used as an illustrative

guide to current workforce issues. We have

not attempted to develop a precise projection

of future workforce needs. Additionally, our

report is not intended to take the place of state

and regional workforce assessments that can

provide the insights needed to identify specifi c

focus areas for individual training programs or

education systems. As described further in the

report, we believe that bringing together major

stakeholder groups at a local or regional level is

the best way to evaluate specifi c training needs.

A theme that seems to resonate broadly across

the energy workforce debate is that “green jobs”

are a positive outcome to be promoted. However,

a universally accepted defi nition for what

constitutes a green job does not exist. Organiza-

tions of all types tend to attach the “green” label

when describing activities they support and

promote, which highlights the ambiguity in using

the term. While it is generally safe to assume

that jobs directly involved in the deployment

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THE NCEP TASK FORCE ON

AMERICA’S FUTURE ENERGY

JOBS BELIEVES DEBATING THE

DEFINITION OF GREEN JOBS MAY

BECOME A DISTRACTION …

WE BELIEVE THE TERM “FUTURE

ENERGY JOB” IS MORE

APPROPRIATE FOR OUR FOCUS.

1 Apollo Alliance and Green For All with Center for American Progress and Center on Wisconsin Strategy, “Green-Collar Jobs in America’s Cities: Building Pathways out of Poverty and Careers in the Clean Energy Economy.” 2008. Available http://www.green-forall.org/resources/green-collar-jobs-in-america2019s-cities.

2 While the Task Force future scenarios focus on electric power generation, transmission, and distribution, we recognize that electric utilities are frequently integrated with natural gas utilities and that natural gas utilities face similar workforce pressures. According to the Bureau of Labor Statistics, natural gas utilities employ about 106,000 people. The CEWD data referenced in this report combine natural gas utility workforce estimates with the electric utility workforce estimates.

of energy effi ciency and renewable energy

technologies would be considered “green,” a

number of complexities quickly emerge as soon

as one attempts to apply even this seemingly

simple defi nition. For example, a lineworker

building a transmission line that connects a

wind farm to the electric grid would be viewed

by most people as having a green job. If that

same transmission line carries electricity gener-

ated from nearby coal-fi red power plants, the

“greenness” of that job may not be as clear. This

example illustrates that the skills needed to

perform what many think of as a green job are

often the same as or very similar to traditional

energy-related jobs.

The NCEP Task Force on America’s Future Energy

Jobs believes debating the defi nition of green jobs

may become a distraction. In fact, we do not use

this term elsewhere in this report. Rather, because

our effort is focused on workforce needs associated

with building and supporting energy infrastructure

for a future low-carbon energy system, we believe

the term “future energy job” is more appropriate

for our focus. It implies that all types of jobs that

support an energy system consistent with a long-

term goal of reducing greenhouse gas emissions

should be seen in the same light. Some of the jobs

related to the transition to a carbon constrained

economy will be new and will require new skill

sets. But many more will use skills that are already

in demand today, such as those required for sheet

metal workers, transmission lineworkers, and

electricians.1 In effect, if the underlying policy

framework refl ects the objectives embedded in

the term “green job” then future energy jobs are

green jobs.

Overarching Challenges

As a starting point, Task Force members shared

a common recognition that the electric power

sector faces near- and long-term workforce chal-

lenges. Its workforce is aging and will need to be

replaced. Facing a wave of retirements over the

next decade, the electric power industry will

need to expand hiring and training programs just

to maintain the level of qualifi ed workers required

to operate existing facilities. In fact, new workers

will be needed to fi ll as many as one-third of the

nation’s 400,000 current electric power jobs by

2013.2 In the face of this surge in demand, compa-

nies are fi nding that applicants for open positions

at electricity companies are not as prepared as

they were in decades past. Companies are fi nding

that U.S. students are not graduating at the same

rates in the relevant fi elds and with the same

qualifi cations as in the past. While the Task Force

focused on direct electric power sector jobs, the

Task Force members recognize that other eco-

nomic sectors, such as the manufacturing sector,

face similar demographic, education, and training

challenges.

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In the long-term, the deployment of new tech-

nologies and generating assets—including new

energy effi ciency, nuclear, renewable, advanced

coal with carbon capture, and smart grid tech-

nologies—will require new design, construction,

operation, and maintenance skills. This is an

important opportunity for new job creation

and economic growth. If too few individuals

with the necessary expertise are available when

they are needed, workforce bottlenecks could

slow the transition to a low-carbon economy

regardless of the commercial readiness of the

underlying technologies. If the result is to

delay the effi cient adoption of improved low-

carbon alternatives, workforce shortages would

represent more than a lost opportunity—they

could impose substantial costs, both in terms of

economic burden and environmental damages

and could damage U.S. global competitiveness.

Task Force Approach

The Task Force focused on three broad categories

of jobs:

Jobs associated with operating and maintaining

the existing electric power infrastructure;

Jobs associated with designing and building

new electric generation capacity to meet future

low-carbon energy needs; and

Jobs associated with operating and maintaining

the electric power industry of the future.

The fi rst chapter summarizes the Task Force’s

fi ndings on existing power industry labor markets.

Rapid attrition due to retirements from an aging

pool of workers is the primary concern. Chapter 2

examines what happens when an expected surge

in demand for new low-carbon energy technologies

is layered on top of this declining base. Comparing

pending workforce requirements against the ex-

isting education and training pipeline is the focus

of the third chapter. Chapter 4 presents suggested

policy solutions and Task Force recommendations.

0

100,000

200,000

300,000

400,000

500,000

Existing ElectricPower Sector

Workforce (2008)

Potential Five-YearDemand for

Replacement Workers

Potential Ten-YearDemand for

Replacement Workers

Figure 1. Comparison of the Workers Needed to Replace Workers Retiring or Leaving the Industry for Other Reasons to Existing Employment Levels

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A LARGE FRACTION

(30–40 PERCENT)

OF ELECTRIC POWER WORKERS

WILL BE ELIGIBLE FOR

RETIREMENT OR LEAVE

THE INDUSTRY FOR OTHER

REASONS BY 2013.

We summarize key insights from the original

report along with our primary recommendations

below. References for the data are included in the

corresponding chapters.

Chapter 1 Critical Insights – Existing Electric

Power Sector Workforce

The electric power generation, transmission,

and distribution industry employs about

400,000 people.

A large fraction (30–40 percent) of electric

power workers will be eligible for retirement

or leave the industry for other reasons by 2013.

Of the 120,000 to 160,000 electric power

workers that will be eligible for retirement

or leave the industry for other reasons by

2013, industry surveys suggest 58,200 will be

skilled craft workers and another 11,200 will

be engineers.

Table I. CEWD Survey Results by Job Category

Job CategoryEstimated Number of

Potential Replacements by 2013

Electric Power Skilled Craft

58,200

Technicians 20,300

Non-Nuclear Plant Operators

8,900

Pipefi tters/Pipelayers 6,500

Lineworkers 22,500

Engineers 11,200

While recent industry estimates anticipate that

workers will delay retirement due to the current

economic downturn, it is impossible to predict

how long workers will extend employment.

There is a concern in the industry that delayed

retirement could lead to more acute worker

shortages at some point in the future if many

workers retire around the same time.

Chapter 2 Critical Insights – Potential Workforce

Demand Surge under a Federal Climate Policy

In addition to needing skilled workers to

replace retiring workers, the industry will

need skilled construction workers to design

and construct new electric sector infrastruc-

ture. We estimate that in 2022, design and

construction work for the electric sector

will require about 150,000 professional and

skilled craft workers from the construction

sector. This construction workforce is about

40 percent the size of the existing electric

power workforce.

Demand for skilled workers to operate and

maintain the electric generation systems of the

future will increase steadily as new technolo-

gies come online. The number of additional

workers that will be needed by 2030 is roughly

60,000—an increase of almost 15 percent.

Table 2. Projected O&M Jobs in 2030 Given the Projected New Generation under the EPRI Prism Analysis

Job Category Range of Expected Demand

Skilled Electric Power Craft Workers

35,000 to 70,000

Professional Staff 18,500 to 35,000

Total 53,500 to 105,000

The deployment trajectory for new generation

technologies directly impacts workforce

demand. In scenarios with steady annual de-

ployment of new generating assets, workforce

demands will peak at a lower level and will

be spread out over more years. In scenarios

where construction is delayed and several

generating assets are planned to come into

operation in the same year, the workforce peak

is higher and the demand is more concen-

trated around the peak year. This variability

reinforces the need for local and regional

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assessments of workforce demand as climate

policy becomes clearer.

The industry needs to prepare to meet a long-

term, sustained need for training, beyond the

retirement gap.

With respect to the design, construction, and

operation and maintenance (O&M) of infra-

structure and supporting technologies:

Demand for construction labor to build new

high-voltage transmission lines and substations

is expected to spike, especially in light of the

transmission investments anticipated under

the recent economic stimulus package. We

estimate the peak demand for construction

labor and skilled crafts to be about 10,000 to

15,000. However, policy and regulatory delays

have affected the construction timetable of a

number of proposed transmission lines. These

delays increase the uncertainty around projec-

tions of future workforce demand.

The near-term deployment of smart grid

technologies will require over 90,000

workers. However, smart grid deployment

will result in about 25,000 electricity power

industry workers looking to transition to new

positions. This supply of workers highlights

the need for training programs that retrain

existing workers to take advantage of new

opportunities within the industry.

Construction and maintenance of CO2 pipelines

as part of a commitment to expanded carbon

capture and storage (CCS) will marginally add

to the demand for skilled workers. While not

directly calculated as part of the NCEP Task

Force estimates, additional workers will be

needed to retrofi t fossil fuel-fi red power plants

with carbon capture technologies.

200

400

600

800

1,000

1,200

1,400

1,600

2007 2012 2017 2022 2027

Per

sonn

el

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Mile

s

Estimated Annual Worker Need

Cumulative Miles ofNew CO

2 Pipeline

Figure 2. Estimated Workforce to Design and Construct CO2 Pipelines to Support EPRI

Prism CCS Deployment

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Running energy effi ciency programs requires

people to design and administer programs

and people to promote those programs and

sign up new customers. We estimate that

utility or other third-party managed energy

effi ciency programs in the United States will

require all or part of the time of approximately

11,000 employees per year through 2030.

Additionally, we expect the program managers

to hire contractors to implement or deploy

effi ciency technologies. These contractors are

expected to signifi cantly outnumber the

number of direct employees required to ad-

minister and promote customer-side effi ciency

programs and could number in the thousands

for each program. While these jobs will be an

important component of future energy jobs,

the Task Force decided not to seek to quantify

these jobs.

0

100,000

200,000

300,000

400,000

500,000Existing

Electric PowerSector

Workforce(2008)

Potential Five-YearDemand

for ReplacementWorkers

PotentialTen-Year Demandfor Replacement

Workers

Peak NewGenerationDesign and

Construction WorkerDemand Underthe EPRI PrismScenario (2022)

Peak Smart GridDeployment

Worker Demand(2012)

Smart GridO&M Worker

Demand (2018)

Direct EnergyEfficiency

Worker Demand(2018)

Peak Design andConstruction of

New TransmissionUnder theEPRI Prism

Scenario (2012)

New GenerationO&M Worker

Demand(2030)

Figure 3. Comparison of Major Sources of Worker Demand to Existing Employment Levels

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Chapter 3 Challenges – Training the Future

Energy Workforce

Challenges to preparing students in grades K-12:

Low Graduation Rates. Of the approximately

four million students who will begin high

school this fall in the United States, less

than three million are expected to complete

high school.

Lack of Technical Skills. Of those who

complete high school, many are ill-prepared

to pursue a career that requires basic

technical skills.

Lack of Industry-Specifi c Training for

Educators. Teacher training and retraining

is a key component of repairing our basic

educational system.

Challenges to training and educating skilled

craft workers:

Individuals can acquire the technical skills

and training to enter the skilled craft electric

power or construction workforce from several

types of institutions or programs, including:

- community colleges,

- community-based organizations (CBOs),

- apprenticeship programs,

- company-specifi c training programs, and

- worker retraining programs.

Understanding the Electric Power Sector

Demand for Skilled Workers. A key challenge

is aligning training programs with the

demand for workers. This challenge is

compounded by the current system used by

the Bureau of Labor Statistics (BLS) to

estimate future industry demand. That

system relies on historical trends to project

future industry growth and does not in-

clude estimates for replacing positions lost

through retirements or other attrition.

Lack of Communication among Stakeholder

Groups. Compounding the assessment

challenge noted above is the fact that better

communication is needed among stake-

holders—particularly between training

institutions and the electric power sector.

Lack of Credential Portability. A lack of

standardized skill sets and curricula for

some of the skilled crafts within the electric

power sector presents a signifi cant challenge

for students, community colleges, and

employers. This issue is specifi c to a subset

of skilled crafts within the electric power

sector—it does not apply to skilled crafts in

the construction sector.

Collecting and Tracking Skilled Workforce

Data. Information on the number of people

that pass through existing training systems

and their ultimate employment is currently

not well captured.

Costs of Education. Even students who

have adequate education in technical skills 0

1

2

3

4

5

Entering 9th Grade Completing 12th Grade Science Proficiency

Mill

ions

of St

uden

ts

Advanced

Proficient

Basic

Below Basic

Figure 4. U.S. High School Graduation Rate and Science Profi ciency

NEW WORKERS WILL

HAVE TO COME FROM A

TRAINING SYSTEM THAT

NEEDS TO BE REFOCUSED

AND REINVIGORATED.

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may have trouble paying for post-secondary

education.

Improving the Image of Electricity Industry

Careers. Students and parents often do

not view apprenticeship programs or other

programs outside the four-year degree

construct as providing similar or better op-

portunities for career and salary potential.

Lack of Career Preparatory Skills within the

Workforce. Because of a lack of technical

skills among the potential workforce,

introductory courses have become more

prevalent at the community college level.

Challenges to training and educating engineers:

Lack of math and science skills in the

population of high school graduates.

Mobilizing the Research Community. Profes-

sional engineers are needed to develop, design

and implement new, low-carbon technologies

that produce electricity. There is a need for

active and invigorated research programs in

power engineering and related areas. To ap-

propriately engage students, faculty need to be

engaged through the development of research

programs, including programs that are multi-

disciplinary in their approach and thinking.

Encouraging Students to Work in the Electric

Power Sector. In addition to stimulating

research, it is important to foster mechanisms

for pulling both research and students into

the electric power sector.

Costs of Education. The cost of education

in the United States is daunting and can be

a barrier to entry.

Future Energy Jobs

High School Diploma or GEDCareer and Technical Education

Colleges and Universities(PhDs, Masters Degrees)

Colleges and Universities(Bachelors Degree)

Apprenticeship Programs,Company- and Labor-Sponsored Training, Regional Skill Centers

Community Colleges(Certificates, Associates Degrees,Pre-Apprenticeship Programs);Community-BasedOrganization Training

Figure 5. Energy Sector Workforce Pipeline

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T

TASK FORCE RECOMMENDATIONS

he workforce challenges identifi ed by the Task Force

are signifi cant and addressing them will take a

concerted and sustained effort by many stakeholders.

To advance that process, the Task Force developed a

set of fi ve primary recommendations for federal policy.

While these recommendations are specifi cally focused

on the development of direct future energy jobs

associated with design, construction, and operation

of assets in the energy sector, many of the insights

could be applied to job training associated with

deploying energy effi ciency and manufacturing the

materials and equipment needed to build and operate

the future energy system.

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MANY OF THESE INSIGHTS

COULD BE APPLIED TO JOB

TRAINING ASSOCIATED WITH

DEPLOYING ENERGY EFFICIENCY

AND MANUFACTURING THE

MATERIALS AND EQUIPMENT

NEEDED TO BUILD AND OPERATE

THE FUTURE ENERGY SYSTEM.

Recommendation 1: Evaluate regional train-ing needs and facilitate multi-stakeholder energy sector training programs across the country. In addition to the work currently under-

way at DOL and DOE to address the workforce

gaps associated with projected retirements and the

initiatives in the American Recovery and Reinvest-

ment Act of 2009, Congress should appropriate

funds through existing funding mechanisms that

allow DOL and DOE to work with existing state or

regional energy workforce consortia or establish

new state or regional energy workforce consortia,

as appropriate. These consortia should be tasked

with evaluating near- and long-term needs for a

skilled workforce, including:

Workforce gaps at existing facilities over

the next ten years associated with workforce

retirements;

Workforce gaps over the next twenty years

associated with

constructing new low-carbon generating assets

and retrofi tting existing generating assets,

constructing the additional electric infra-

structure needed to effectively use new and

retrofi tted generating assets (e.g. transmission

lines, CO2 pipelines, local distribution

systems),

operating and maintaining new and

retrofi tted generating assets and the accom-

panying infrastructure, and

deploying energy effi ciency in the retrofi tting

of the nation’s building stock and in Smart

Grid technologies.

As a part of this evaluation, DOL, DOE, and each

state or regional energy workforce consortium

should highlight any policy uncertainties that are

currently delaying or have the potential to delay

the deployment of new generating assets, retrofi t

technologies, and infrastructure that are essential

to the transition to a low carbon economy.

In regions of the country where workforce gaps

have been identifi ed, Congress should provide

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fi nancial resources and coordination assistance to

support the development of targeted local or re-

gional training programs for energy sector workers.

DOL should award funding on a competitive basis

through the Green Jobs Act, or other appropriate

federal funding mechanisms, to training programs

that meet the following criteria:

Involve a wide range of stakeholders from

industry, education, labor, professional orga-

nizations, and workforce development agencies

or non-profi t community groups that focus

on workforce development in all stages of

program development.

Coordinate the use of resources at a regional

level while recruiting and matching skills to

jobs at a local level. For example,

Recruit prospective employees from local

populations using local groups, such

as community-based organizations or

workforce investment boards, that have a

deep knowledge of the community and a

capacity to prepare prospective employees

through education and training; and

Integrate regional employer needs into the

curriculum development process.

Build upon existing programs and infrastructure,

including training and education programs

run by community-based organizations,

technical or community colleges, and stake-

holder companies, and joint labor-management

apprenticeship programs.

Include curricula and course content that

utilize industry skill standards and lead to

industry-recognized credentials.

Use best practices (identifi ed under Recom-

mendation 3) in developing training and

education programs.

Encourage development of accredited, credential-

focused programs that put individuals on

a long-term career track. Programs should

allow transferability of credits throughout the

industry and should develop skills that trans-

late from one program to the next. Programs

should issue ‘stackable’ credentials that allow

individuals to develop the building blocks of a

career in the energy sector.

Develop innovative strategies to engage

populations that have traditionally been under-

represented in the energy sector workforce,

in particular communities of color, and to

address the needs of lower-skilled, low-income

workers to enable them to access career path-

ways into the energy sector workforce.

Include a strategy for sustaining the program

over the long term.

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IN REGIONS OF THE COUNTRY

WHERE WORKFORCE GAPS HAVE

BEEN IDENTIFIED, CONGRESS

SHOULD PROVIDE FINANCIAL

RESOURCES AND COORDINATION

ASSISTANCE TO SUPPORT THE

DEVELOPMENT OF TARGETED

LOCAL OR REGIONAL TRAINING

PROGRAMS FOR ENERGY SECTOR

WORKERS.

Implementation Steps

As part of implementing the above recommen-

dations, any funding provided for energy sector

workforce training through new or existing

mechanisms should:

Be distributed through a peer-review process

that involves representatives from industry,

the education community, and labor groups

in developing solicitations and awarding

grants, and

Prioritize grant recipients that provide training

towards industry-recognized credentials,

and who also develop training materials and

programs that can be replicated and readily

shared (as described in Recommendation 3).

In addition, the criteria described as part of this

set of recommendations should be used as a

template for awarding funds through any new

grant programs and through existing or reau-

thorized mechanisms, such as the Workforce

Investment Act (WIA). Specifi cally, the Task

Force supports a number of modifi cations to WIA

that have been proposed by the AFL-CIO, the

American Association of Community Colleges,

and the Association for Career and Technical

Education and urges Congress to consider the

following recommendations in the context of

WIA reauthorization:

Modify performance indicators to recognize skill

attainment and allow for longer term training:

WIA performance indicators strongly

infl uence the approach taken by local boards

and One Stop Career Centers in providing

the longer-term training that many workers,

especially low-skilled workers, need. The

current performance indicators, which put a

heavy emphasis on job placement, retention

and earnings, are “work fi rst” measures. They

should be modifi ed to count interim and

progressive indicators of skill attainment,

including measures of “work readiness” for

very low-skilled workers. Similarly, one of

the “core indicators” in the WIA performance

standards is “earnings received in unsub-

sidized employment.” The value of fringe

benefi ts should be added to the calculation

of earnings for this performance standard.

Expand representation on workforce boards:

While it is important to keep Workforce

Investment Boards (WIBs) to a manageable

size to ensure effectiveness, strengthening

connections between education, labor,

business, and workforce groups requires a

true partnership. Congress should continue

efforts to bring together key stakeholders

in states, regions and localities to plan

effective workforce and economic develop-

ment activities. At the state level, workforce

boards should include representation from

business, labor, education/training, and

61443_P01_32.indd 1961443_P01_32.indd 19 9/27/10 9:49 AM9/27/10 9:49 AM


government. In addition, at the local level,

the workforce investment board should

have a minimum level of representation

from the following four sectors: business

(15 percent), labor (15 percent), community

(15 percent), and education (15 percent).

Promote regional workforce investment areas:

Regional industry partnerships allow busi-

nesses, labor unions, educators, and the

public workforce system to establish or expand

industry or sector partnerships that help

workers train for and advance in high-demand

and emerging industries. Sector strategies

would identify skilled workforce needs

within the targeted industry or sector,

and develop training and educational strate-

gies using career pathways to ensure that

employers have the skilled workers to meet

their needs. This coordinated approach would

help more individuals access the education

and training they need for successful careers.

One implementation option would be to use

the Secretary of Labor’s challenge grants

to provide incentives for WIBs to expand

their geographic scope to encompass areas

that correspond to regional labor markets,

industry clusters, and commuting patterns.

Strengthen Data sharing and common

measures:

Failure to coordinate federal reporting

requirements across programs can create

burdens for WIA and other workforce-related

initiatives. Sharing data across programs

would make it easier for programs and pro-

viders to collect accountability information,

and foster an environment of collaboration

and effi ciency in the workforce and education

systems. Further efforts are needed to align

data systems at the state and local levels

and to reduce barriers to data sharing.

Interpretations of the Family Educational

Rights and Privacy Act of 1976 (FERPA)

combined with prohibitions on sharing

unemployment insurance wage data across

states have contributed to these barriers. By

contrast, Section 113(b)(2)(F) of the Carl D.

Perkins Act gives programs fl exibility to use

“substantially similar information gathered

for other state and federal programs” in

measuring performance, but this language

is rarely utilized. Similar language and

more practical mechanisms to promote

data sharing should be included in WIA.

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The use of common measures would facili-

tate collaboration and coordination across

workforce programs and facilitate a greater

alignment of their goals. Improvements

that increase the effi ciency of workforce

programs such as WIA, Perkins, Trade

Adjustment Assistance, and adult education

and family literacy can benefi t participants

to the extent they lead to better coordination

and targeting of services. The point is not

to measure everything that is important to

each program, but to concentrate on out-

comes that are important for all workforce

development programs and to leave room

for adding new measures as required.

Incentive grants should be structured to

reward coordination. Under the current

incentive grant program, states may apply

for funds under Title I and Title II of the WIA.

To be eligible for funds, states must exceed

relevant performance targets. Grant recipi-

ents are encouraged to use these funds for

activities that (a) promote coordination and

collaboration among the agencies admin-

istering WIA Title I and Title II programs,

(b) are innovative, and (c) are targeted to

improve performance. The Task Force rec-

ommends continuing this grant program.

Additionally, we believe Congress should

consider providing further incentives to states

that take concrete steps toward sharing data

and using common measures.

Utilize youth services to create strong skills

training pathways for students:

Young people in the workforce development

system have needs that are different from

those of most adults and dislocated workers.

To address them requires a separate funding

stream targeted to providing activities and

assessing accountability for the youth popu-

lation. At the same time, better coordination

is needed, especially across WIA and other

federally funded programs. Both the education

and workforce systems have a unique role to

play in serving the youth population.

The current allocation of funds across in-

school and out-of-school youth programs

allows local WIBs to make spending decisions

based on the unique needs of their commu-

nities and should be maintained. Programs

that reach students during the summer and

after the school day can play a critical role in

reducing drop-out rates and preparing

young people to become productive members

of the community. Changes to the current

allocation, on the other hand, could mean a

cut in services to many at-risk students and

reduced opportunities for coordination and

reinforcement across different programs.

Additionally, options to integrate WIB

services, such as One Stop Career Centers,

with campus career centers should also

be explored.

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Recommendation 2: Improve energy sector workforce data collection and performance measurement metrics and tools. Improve the

collection, management, and availability of work-

force data for the energy sector to facilitate the

measurement of progress in addressing identifi ed

needs and to enable more effective identifi cation

of future needs. Workforce data should include

people entering energy sector-specifi c training

programs and/or the energy workforce; these

data should be measured against the workforce

targets identifi ed by the state energy workforce

consortia in Recommendation 1.

BLS should be provided with the resources to

accurately assess workforce needs in the energy

industry and to incorporate industry input on

growth and staffi ng patterns. This will allow for

improved forecasts of future demand for differ-

ent types of skills, including emerging skills

associated with the build out of low-carbon energy

infrastructure.


Federal agencies should work to improve

existing systems for collecting, managing, and

disseminating workforce data relevant to the

energy sector. This would facilitate efforts to

measure progress toward addressing identifi ed

workforce needs while also enabling more

effective identifi cation of future needs. In addi-

tion, it is essential to understand how proposed

legislative initiatives, such as an energy or climate

bill, will impact the energy-sector workforce.

To implement this recommendation, the Task

Force believes that Congress should:

Direct the Department of Education (ED) to

lead a multi-stakeholder task force to standardize

CIP (Classifi cation of Instructional Program)

codes for the energy industry. Such a task

force should:

Organize CIP codes by industry / career

cluster

Develop a process for tracking the number of

individuals who complete programs at private

institutions, apprenticeship programs, and

non-credit bearing programs to more accu-

rately refl ect the potential supply of talent

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Direct the BLS to track data on the demand

for skilled workers in the energy sector.

BLS should:

Modify energy-related Standard Occupa-

tional Classifi cation System (SOC) codes

to more accurately refl ect groupings of

skill requirements. These changes should

be made prior to the next scheduled SOC

codes revision in 2018. BLS should seek

industry input on any revisions.

Reconcile differences in codes to allow

for comprehensive data collection and to

more accurately refl ect future demand for

different types of skills, including emerg-

ing skills associated with the build out of

low-carbon energy infrastructure.

Develop a mechanism to facilitate industry

input to BLS forecasts with the aim of incor-

porating industry projections of growth and

staffi ng patterns and accurately assessing

future energy workforce needs. State forecasts

should incorporate input from state energy

workforce consortia to improve assessments

of future needs at the state level.

Build capability for developing workforce

scenarios and projections as a tool for ana-

lyzing the impacts of proposed legislation,

including especially legislation concerning

energy, climate change, and related issues.

Direct DOE, ED, and DOL to create a na-

tional longitudinal data collection system, in

coordination with the repository described in

Recommendation 3, to track student progress

from secondary through post-secondary educa-

tion and employment.

Recommendation 3: Identify training standards and best practices for energy sector jobs. DOL in consultation with industry,

labor, and education stakeholders, including ED

and DOE, should develop a repository of best

practices for electric power sector job training

that is widely accessible, transparently managed,

and maintained by a public entity. This reposi-

tory should include existing skill standards and

registered apprenticeship programs for electric

power sector jobs. Examples of best practices

can be found at energy career academies at

the secondary level, and at pre-apprenticeship,

certifi cate, associate degree, apprenticeship,

and community-based training programs at the

post-secondary level.

The purpose of the repository should be three-

fold: (1) it should be a resource for employers

to evaluate training programs and potential

employees, (2) it should be a resource for

individuals to evaluate training options as they

move through a career, and (3) it should be a

resource for educators as they develop courses

and curricula.

As a part of this initiative, this group should

identify skill areas where best practices or training

standards do not exist or should be expanded,

and work to fi ll such gaps.


To promote the development and use of

industry-recognized credentials, Congress

should direct DOL to work with DOE and ED to

organize and monitor the development of such

credentials and appropriate funds as necessary

to support these efforts. Specifi cally, the agen-

cies should:

AS A PART OF THIS INITIATIVE,

THIS GROUP SHOULD IDENTIFY

SKILL AREAS WHERE BEST

PRACTICES OR TRAINING

STANDARDS DO NOT EXIST OR

SHOULD BE EXPANDED, AND

WORK TO FILL SUCH GAPS.

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Identify existing industry-recognized credentials,

Support (through grants or other funding

mechanisms) the development of new

industry-recognized credentials where there

are gaps, and

Create a central repository for these credentials.

Since the publication of the Task Force report,

the Center for Energy Workforce Development

(an Advisor to the Task Force), has been working

with stakeholders to develop industry-recognized

credentials for the energy sector. Based on this

work, the Task Force offers the following rec-

ommendations concerning the development of

an industry-recognized credential repository:

All energy credentials should follow the

defi nitions used by the American National

Standards Institute (ANSI).3

Credentials for utility technicians and non-

nuclear plant operators should be issued

consistent with the American National

Standard, ASTM 2659 – Standard Practice

for Certifi cate Programs.

Credentials for lineworkers may be issued

through a certifi cate or certifi cation that

would meet the accreditation requirements of

the American National Standards Institute.

DOE should use the repository of validated

industry-recognized credentials for grant

making, curriculum development, and train-

ing programs, such as certifi ed apprenticeship

programs.

Credentials or certifi cations for positions out-

side the nuclear industry should be developed

by a neutral third-party and should include

input from subject matter experts to identify

relevant competencies, design skill assessments,

if needed, and develop effective curricula.

Credentials for positions in the nuclear

industry comply with Nuclear Regulatory

Commission regulations, but are typically

developed based on consensus standards and

detailed job task analyses.

Industry credentials should be embedded in

a pathway that is linked to a job or series of

jobs or to specialized skill(s) associated with a

job. Some jobs may require multiple cre-

dentials. In those cases, required credentials

should build on one another and should not

necessitate investments of money and time in

duplicative education or training programs.

3 The nuclear industry works through INPO and that National Academy of Nuclear Training and adheres to Nuclear Regulatory Commission regulations for training plant operators and technicians.

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Credentialing in the Energy Sector

Credentialing is becoming more important in many industries, including the energy industry. It is increasingly being

tied to education programs, both secondary and post-secondary, to grants from the Department of Labor and other

sources, Perkins funding, and employment. As the need for credentialing grows, so does the misunderstanding of what

the term “credentialing” means. For example, the term “certifi cation” is often understood as having the same mean-

ing as credentialing, even when it really means simply getting a certifi cate or occupational license. This confusion is

common not only among the general public, but in the education and business worlds, and even within credentialing

organizations.

The American National Standards Institute (ANSI) accredits developers of standards as well as certifi cation bodies

and certifi cate issuers; it is thus a leading authority on the development and differentiation of standards for various

credentials. ANSI defi nes different forms of credentials as follows:

Certifi cates

Generally associated with education and training – educational process

Indicates that the content has been learned in an educational event

May or may not have an assessment

Course/training is generally designed by an instructor or group of experts

Generally good for life – no renewal period

Owned by the individual – “cannot be taken away” by the educational institution

Certifi cation

Focus is on the “job”, “occupation” or “practice”

Determining the competencies to successfully practice – job/practice analysis

Results from an assessment process (examination or demonstration of skills)

Is a third party, independent judgment regarding whether competencies have been achieved

Time limited – must re-certify within a designated period of time

Certifi cation does not belong to the individual – can be taken away

Licensure

Generally associated with “State” Licensure but there are federal licenses, e.g. FAA, EPA (although they call their

examinations “certifi cation”)

State Licensure

Legal right to practice in a job/occupation/profession

Scope of practice is determined by the state legislature

Sometimes based on a national “Certifi cation”

Time limited – must re-license within a designated period of time

Professions are licensed to “protect the public”

Examinations are often created by “Federations”

Degrees and diplomas are also considered credentials, but both industry and the public have a common understanding of

these credentials.

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Recommendation 4: Provide funding sup-port to individuals seeking energy sector related training and education. The Task

Force recommends that fi nancial support,

targeted to those most in need, be provided to

individuals pursuing energy-related technical

and professional training (or retraining) and to

students pursuing post-secondary degrees in

engineering and other energy-related technical

fi elds. Using existing funding mechanisms as

appropriate, Congress should consider:

Developing a program that provides fi nancial

support through educational scholarships or

grants to individuals,

Providing worker training tax credits to energy

companies who support apprenticeships and

internships, and

Clarifying and streamlining support for

apprenticeships, technical certifi cations, and

on-the-job training for veterans by combining

the benefi ts of the Post-9/11 GI Bill and the

Montgomery GI Bill into one program.


Financial support for energy-sector training and

education can be provided by modifying and

expanding existing programs. Specifi cally, the

Task Force recommends the following actions:

Reconcile differences between the Montgomery

GI Bill and the Post 9/11 GI Bill. These are the

two programs currently being used to provide

GI benefi ts. While the Post-9/11 GI Bill

expanded and streamlined benefi ts for service

members who wished to pursue higher

education, it did not do the same for service

members who wished to pursue apprenticeship

and on-the-job training opportunities. This

is signifi cant because of the disparity in

benefi ts between the Montgomery and Post

9/11 Bills and the enrollment process for the

Montgomery GI Bill. With respect to benefi ts,

the Post-9/11 GI Bill includes college tuition

payments for the service member or a family

member, as well as a housing allowance and

a book allowance. By contrast, the Montgom-

ery GI Bill provides support in the form of a

monthly stipend, which is set annually and is

the same throughout the country. Given this

disparity, it is unlikely that a service member

would choose to apply for support under the

Montgomery GI Bill instead of the Post-9/11

GI Bill unless he or she were interested in

apprenticeship or job training, which is not

covered by the Post-9/11 GI Bill. Differences

in the enrollment process for the two pro-

grams further disadvantage funding support

for apprenticeships and on-the-job training.

To use the Montgomery GI program, service

members must enroll at the time of enlist-

ment and agree to pay $100 per month for

the fi rst year of enlistment. This means that

service members interested in pursuing

apprenticeship or job training not only have

access to less generous benefi ts, they must

know their plans, decide what type of pro-

gram to pursue, and begin paying fees much

earlier. This creates a signifi cant disparity in

favor of veterans choosing college rather than

apprenticeship and job training.

Senator Daniel Akaka, Chairman of the Sen-

ate Committee on Veterans’ Affairs, recently

introduced a bill (S. 3447) with two cosponsors,

Senators Mark Begich and Debbie Stabenow,

that begins to address many of these disparities.

Most signifi cantly, the proposed legislation

would provide benefi ts through the Post-9/11

GI Bill to veterans pursuing on-the-job training

and apprenticeship programs. While S. 3447

is still working its way through Congress, the

Task Force supports Senator Akaka’s efforts.

THE WORKFORCE TRAINING

PIPELINE FOR THE ENERGY

SECTOR INCLUDES A

VARIETY OF PROGRAMS

AND INSTITUTIONS. THESE

SHOULD BE REVIEWED TO

DETERMINE IF THERE ARE

BARRIERS TO FUNDING FOR

TRAINING AND EDUCATION,

ESPECIALLY FOR SKILLED

CRAFT WORKERS IN THE

ELECTRIC SECTOR.

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Increase the tax deduction for employees

who receive education assistance from their

employer. Section 127 of the tax code allows

taxpayers to exclude up to $5,250 per year in

employer-provided educational assistance when

fi guring their gross income for tax purposes.

The amount of this deduction has not changed

since 1986. The Task Force recommends

that it be increased to at least $10,000 for

employees seeking their fi rst undergraduate

degree or for employees seeking less than a

bachelor’s degree. In addition, current IRS

policy limits the tax deduction to employees

who intend to remain in their current jobs.

The Task Force recommends that the deduc-

tion be expanded to include employees who

wish to pursue further education to qualify

for a new job.

Review existing educational grant programs for

opportunities to promote energy-sector work-

force training. As discussed in the Task Force

report, the workforce training pipeline for the

energy sector includes a variety of programs

and institutions. These should be reviewed to

determine if there are barriers to funding for

training and education, especially for skilled

craft workers in the electric sector. For example:

Pell Grants are an important source of

support for training. In 2007–2008, this

program provided grants ranging from

$400 to $4,310 to more than 5.5 million;

overall funding provided through Pell

Grants totaled nearly $15 billion. Current

rules limit Pell Grants for career and

technical training to those programs that

“prepare students for gainful employment

in a recognized occupation.” The problem

is that those terms are not currently well-

defi ned. The Task Force supports efforts by

the Department of Education to clarify this

requirement so that more support can be

provided for career and technical training.

Grants authorized by the Carl D. Perkins

Career and Technical Education Act repre-

sent the largest source of federal funding

for secondary schools and the primary

source of federal funding for education

programs that provide individuals with the

knowledge and skills to compete in the

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workforce. The Task Force supports efforts

to increase funding for Perkins Grants. At

a minimum, funding for Perkins Grants

should be indexed to infl ation.

Recommendation 5: Aggressively focus on revitalizing the math and science skills, education, and career counseling of indi-viduals who have the interest and skills to work in the energy sector. Enhance

preparatory skill training for technically rigorous

careers by:

Improving and expanding contextual education

in science, technology, engineering, math,

and environmental literacy for students in all

grades from kindergarten through 12th grade,

Expanding the use of instructional technology

at all levels to provide access to computerized

and on-line educational resources and infor-

mation about science, technology, engineering

and math,

Integrating lessons in applied math and sci-

ence into the foundational curriculum for all

students, with a particular emphasis on early

(K–4) education,

Expanding educational opportunities that

include reading, writing, and applied math

and science for adults who wish to enter the

energy workforce,

Providing opportunities for teachers and

instructors to learn about the energy sector

and greenhouse gas emissions through off-

site programs organized by local colleges,

universities, and industry partners,

Ensuring that students are at or above grade

level in math,

Developing energy-related, contextual modules

for math and science teacher training carried

out at colleges and universities, including

historically black colleges and universities or

other minority institutions,

Developing robust programs to train and

retrain our teachers in math and science,

Engaging retired professionals and helping

them transition from a career in energy to the

education system, and

Creating seamless pathways from K–12

through post-secondary education.

Engage the next generation of energy scientists

and engineers by following through on and

expanding commitments to U.S.-based research

and development efforts. This should include:

Finishing the ten-year doubling4 of the budgets

for the National Science Foundation (NSF),

DOE Offi ce of Science, and the National

Institutes of Standards and Technology (NIST),

ENGAGE THE NEXT

GENERATION OF ENERGY

SCIENTISTS AND ENGINEERS

BY FOLLOWING THROUGH

ON AND EXPANDING

COMMITMENTS TO

U.S.-BASED RESEARCH AND

DEVELOPMENT EFFORTS.

61443_P01_32.indd 2861443_P01_32.indd 28 9/27/10 9:49 AM9/27/10 9:49 AM


with a special emphasis on (1) encouraging

high-risk, high-return research; (2) supporting

researchers at the beginning of their careers;

and (3) research focused on low-carbon energy

sources and technologies.

Investing in sustained research programs

and academic tracks that support advanced

energy systems.

Increase awareness of opportunities in the

energy sector by:

Creating targeted career awareness material

that addresses specifi c audiences including

youth, adults, minority populations, veterans,

government offi cials, and educators,

Developing messaging materials that (1)

highlight how critically important technically

educated individuals are for addressing

our long-term energy and environmental

challenges and (2) address a lack of public

awareness about the security, pay, and job

satisfaction associated with careers in the

electric sector,

Supporting community-based organizations

that help to match potential job seekers and

employers,

Informing career counselors and educators

about job opportunities and experiences in

the energy sector, and

Communicating that skilled trades are a vital

component of the American economy and

should be viewed as desirable options for

individuals seeking career training.


A number of initiatives to improve education

and increase awareness of energy-sector jobs

are currently underway at the Department of

Labor and at other federal agencies. To aug-

ment these ongoing efforts, Congress should

reauthorize the America COMPETES Act,

which was originally passed in response to the

Rising Above the Gathering Storm report. The

America COMPETES Act provides for invest-

ments in STEM education; sets budgets for

science research agencies (such as NIST, NSF,

and the DOE Offi ce of Science) on a path to

doubling; and continues support for the new

Advanced Research projects Agency for Energy

(ARPA-E).5

4 White House Offi ce of Management and Budget. “A New Era of Responsibility: Renewing America’s Promise (FY2010 Budget). February 26, 2009. Available at www.whitehouse.gov/omb/assets/fy2010_new_era/a_new_era_of_responsibility2.pdf

5 ARPA-E was created to pursue advances in high-risk, high-reward energy technologies.

61443_P01_32.indd 2961443_P01_32.indd 29 9/27/10 9:49 AM9/27/10 9:49 AM


Notes

61443_P01_32.indd 3061443_P01_32.indd 30 9/27/10 9:49 AM9/27/10 9:49 AM

design: www.katetallentdesign.com

NCEP Task Force Staff

Sasha MacklerResearch Director

David RosnerAssociate Director, Energy Research

Marika TatsutaniWriter and Technical Editor

The Bipartisan Policy Center has engaged MOSAIC, a carbon neutral EPA Green Power Partner, for the production of this brochure, using 100% wind power and a waterless printing process. The brochure was printed on FSC certifi ed stock with 100% environmentally friendly soy-based inks. The savings below are achieved when PC recycled fi ber is used in place of virgin fi ber. This project uses 1423 lbs of paper which has a postconsumer recycled percentage of 30%.

4 trees preserved for the future

10 lbs water-borne waste not created

1,523 gal wastewater fl ow saved

169 lbs solid waste not generated

332 lbs net greenhouse gases prevented

2,540,055 BTUs energy not consumed

Disclaimer

This report is a product of a Task Force with participants of diverse expertise

and affi liations, addressing many complex and contentious topics. It is inevi-

table that arriving at a consensus document in these circumstances entailed

compromises. Accordingly, it should not be assumed that every member is

entirely satisfi ed with every formulation in this document, or even that all

participants would agree with any given recommendation if it were taken in

isolation. Rather, this group reached consensus on these recommendations as

a package, which taken as a whole offers a balanced approach to the issue.

It is also important to note that this report is a product solely of the partici-

pants from the NCEP convened Task Force on America’s Future Energy Jobs.

The views expressed here do not necessarily refl ect those of the National Com-

mission on Energy Policy.

Acknowledgements

The National Commission on Energy Policy would like to express its thanks for

the strong support of its funders. The Commission was founded in 2002 by

the William and Flora Hewlett Foundation and its partners.

The NCEP staff gratefully acknowledges the substantial guidance, research,

and support offered by M.J. Bradley & Associates, LLC throughout the course

of this effort. In particular, Michael Bradley, President, Carrie Jenks, Senior VP,

Tom Curry, Senior Policy Analyst, and Kathleen Robertson, Senior Policy

Analyst, were essential members of the project team as was Elizabeth Ewing,

of Ewing Smith Consulting, LLC. Additionally, special thanks to Ian Copeland,

President, Power, New Technology, and Rick Franzese, Senior Development

Manager, both of Bechtel Power Corporation, for generously lending their

expertise to the Task Force. Thanks also to Revis James, Director of the Energy

Technology Assessment Center at the Electric Power Research Institute for al-

lowing the Task Force to draw on the EPRI analyses in this area.

61443_C01_4.indd 2 9/27/10 9:40 AM




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61443_C01_4_x.indd 1 9/30/10 7:02 PM

Direct Testimony and Exhibits Brian G. Iverson





December 1, 2011

Table of Contents

I. Introduction and Qualifications .......................................................................................... 1

II. Purpose of Testimony ......................................................................................................... 2

III. Accounting Records............................................................................................................ 3

IV. Financial Integrity of Cheyenne Light................................................................................ 3

V. Capital Structure ................................................................................................................. 7

VI. Cost of Debt ........................................................................................................................ 8

Exhibits

Exhibit BGI-E1: Black Hills Corporation Credit Ratings

Exhibit BGI-E2: Cheyenne Light Historical Debt Structure

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I. INTRODUCTION AND QUALIFICATIONS

Q. WHAT IS YOUR NAME AND BUSINESS ADDRESS?

A. My name is Brian G. Iverson. My business address is 625 9th Street, Rapid City, South

Dakota 57709.


A. I am currently employed by Black Hills Corporation (“Black Hills Corporation”) as Vice

President and Treasurer.

Q. ON WHOSE BEHALF ARE YOU APPEARING IN THIS APPLICATION?

A. I am appearing on behalf of Cheyenne Light, Fuel & Power Company (“Cheyenne

Light”), a wholly-owned direct subsidiary of Black Hills Corporation.

Q. PLEASE DESCRIBE YOUR DUTIES AND RESPONSIBILITIES IN YOUR

CURRENT POSITION.

A. In my role, I am responsible for the financing activities of Black Hills Corporation and its

subsidiaries and affiliates, including Cheyenne Light.

Q. WOULD YOU PLEASE OUTLINE YOUR EDUCATIONAL AND

PROFESSIONAL BACKGROUND?

A. I have a B.S. degree in Accounting and a M.B.A. from the University of South Dakota. I

am a Certified Public Accountant (South Dakota). I have a law degree also from the

University of South Dakota.

I have been employed by Black Hills Corporation since 2004, working in various

positions within the legal, regulatory and resource planning areas. Prior to joining Black

Hills Corporation, I worked in the banking industry and in the private practice of law,

where I focused on business and financial transactions.

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II. PURPOSE OF TESTIMONY


A. The purpose of my testimony is to support the following areas of the rate application:

• Certify Books and Records of Cheyenne Light

• Certify Use of Federal Energy Regulatory Commission (“FERC”) Uniform

System of Accounts for Cheyenne Light

• Discuss Corporate Finance Philosophy of Cheyenne Light

• Support Proposed Capital Structure of Cheyenne Light

• Support Long Term Debt and Cost of Equity

• Discuss Debt Financing Activity

• Support Weighted Average Cost of Capital

Q. ARE YOU SPONSORING ANY EXHIBITS?

A. Yes. I am sponsoring Exhibit Nos. BGI-E1 through BGI-E2 which I will describe and

refer to in my testimony. The Exhibits attached to this testimony are as follows:

• BGI-E1: Black Hills Corporation Credit Ratings

• BGI-E2: Cheyenne Light Historical Debt Structure

Q. HAVE THE TESTIMONY AND EXHIBITS WHICH YOU ARE SPONSORING

BEEN PREPARED BY YOU OR UNDER YOUR SUPERVISION?

A. Yes.

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III. ACCOUNTING RECORDS

Q. ARE YOU FAMILIAR WITH THE BOOKS AND RECORDS OF CHEYENNE

LIGHT AND THE MANNER IN WHICH THEY ARE KEPT?

A. Yes. The financial statements and records have been prepared on the accrual basis in

conformity with GAAP and in accordance with accounting requirements of the Federal

Energy Regulatory Commission as set forth in its applicable Uniform System of

Accounts.

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IV. FINANCIAL INTEGRITY OF CHEYENNE LIGHT

Q. PLEASE EXPLAIN THE CORPORATE FINANCE PHILOSOPHY OF

CHEYENNE LIGHT.

A. The corporate philosophy of Cheyenne Light is the same philosophy established by Black

Hills Corporation. That corporate philosophy is that Cheyenne Light must maintain

financial integrity and its ability to access capital as needed at a reasonable cost.

Financial integrity is critical to Cheyenne Light’s ability to satisfy its obligation to supply

safe and reliable electric services. Cheyenne Light defines financial integrity as the

financial stability necessary to weather the peaks and valleys of business cycles, volatility

in financial markets and interest rates, and unanticipated changes in operational

requirements, all of which may strain an organization’s ability to finance expenditures

and provide quality service. A strong financial position provides the financial flexibility

necessary to meet the ongoing demand for utility services. Cheyenne Light is

conservative in its financial philosophy and only takes on risk where appropriate and

reasonable. Even with a conservative corporate finance philosophy, no corporation is

insulated from market forces, credit crunches, and other financing difficulties that cannot

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be foreseen or avoided. In those situations, Cheyenne Light follows the guidelines of

prudence and reasonableness in evaluating its credit and financing options.

Q. WHAT IS CHEYENNE LIGHT’S PRO FORMA CAPITAL STRUCTURE?

A. Cheyenne Light’s expert witness, Dr. William Avera, provides a detailed analysis in

support of the recommended capital structure in his testimony. However, my testimony

supports the pro forma capital structure for Cheyenne Light of 54 percent equity and 46

percent debt.

Q. HOW DO INVESTORS EVALUATE A COMPANY’S FINANCIAL INTEGRITY?

A. Dr. Avera will cover this topic in greater detail; however, investors generally rely on

nationally recognized credit rating services to evaluate a company’s financial integrity and

to inform them of the company’s current financial position. Three nationally recognized

credit rating services are Moody’s Investors Service (“Moody’s”), Standard and Poor’s

("S&P"), and Fitch Ratings (“Fitch”). As of November 22, 2011, Black Hills

Corporation’s senior secured debt is respectively rated Baa3 by Moody’s, BBB- by S&P,

and BBB- by Fitch. Each credit rating agency rates Black Hills Corporation with a

“stable” outlook. Exhibit BGI-E1 shows Black Hills Corporation’s key credit ratings.

Q. HOW DO RATING AGENCIES PERFORM THIS FUNCTION?

A. The credit rating services issue guidelines that all companies must follow. Those credit

rating services generally require a company to provide detailed financial and operational

information to rating agencies for their analysis before issuing credit ratings for the

company’s securities. As noted below, these credit rating agencies compare quantitative

measures of a company’s financial performance, as well as a qualitative assessment of the

company’s risks (such as management, forecasts, and regulatory climate), to their

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guidelines to rate the company and determine the investment attributes of its debt

securities. The credit ratings given by these agencies provide important information to

creditors, investors, vendors and counterparties regarding the creditworthiness of Black

Hills Corporation and Cheyenne Light.

Q. WHAT CRITERIA DO RATING AGENCIES USE IN EVALUATING A

UTILITY?

A. As noted by Dr. Avera, the ratings evaluation process includes an analysis of both

qualitative and quantitative factors. There are several steps in the ratings evaluation

process. For example, one step is to assess the extent of a “regulated” company’s

exposure to unregulated businesses. The strongest position is enjoyed by those

companies operating in a wholly regulated business. Another step in the methodology is

to assess the credit support that is gained from operating within a particular regulatory

framework. The rating agencies also consider the exact level of risk posed by the

business. These criteria and others established by the credit rating agencies then lead to

an overall assessment of the qualitative business risk of the company’s activities.

As part of the quantitative assessment of a given entity, the rating agencies will review

numerous financial ratios of a given entity. Such ratios will be used to review trends over

various periods of time within a given entity, as well as to provide comparisons among

other companies in a given industry, or among various industry averages.

For example, Moody’s has identified four areas that are considered most useful in

completing analysis for electric utility companies. They are as follows: (1) Regulated

Framework, (2) Ability to Recover Costs and Earn Returns, (3) Diversification and (4)

Financial Strength and Liquidity. By maintaining good credit ratings, Black Hills

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Corporation achieves better credit terms and lower cost of debt which directly benefits

our customers.

Q. WHAT IS THE FINANCIAL CONDITION OF CHEYENNE LIGHT?

A. The financial integrity of Cheyenne Light is sound. The goal of Cheyenne Light is to

maintain and, if possible, improve its credit metrics.

If Cheyenne Light’s credit metrics are weak, that will impact its ability to obtain short

and long-term financing, the cost of such financing, and vendor payment terms, including

collateral requirements. While Cheyenne Light does not have a credit rating, it has access

to capital through Black Hills Corporation, its parent company, and through the issuance

of first mortgage bonds. Cheyenne Light’s financial integrity is an important factor in

supporting Black Hills Corporation’s investment grade credit rating.

As a means of protecting its credit ratings, Cheyenne Light generally maintains and will

continue to maintain a capitalization level (GAAP basis) of approximately 45 to 50%

debt and expects to continue this level of capitalization in the future.

Q. HOW DOES THIS FINANCE PHILOSOPHY AFFECT THE RETURNS THAT

EQUITY INVESTORS EXPECT?

A. For a company to attract equity capital, the potential investor must believe that the

company will earn a return that exceeds the cost of capital. If a company earns less than

its cost of capital, value is destroyed for the shareholders, and consequently, the ability to

raise additional capital for future projects declines. The components of cost of capital

include both cost of debt and the cost of equity. The cost of equity is impacted by a

number of factors, including the risk premium investors expect above the long-term U.S.

Treasury Rates, the market risk of the company, the industry risk premium, the size of

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market capitalization, and the ratio of debt to total capitalization. The market meltdown

in the fourth quarter of 2008 increased risk the premium investors need to attract capital,

which increased the cost of equity for all companies, including Cheyenne Light.

Cheyenne Light believes that its cost of equity capital is 10.9% and therefore is

requesting rates to support that return. If Cheyenne Light earns less than 10.9% on its

current equity capital component, its shareholders will not meet their return expectations,

and consequently, access to capital markets will be diminished. I believe the philosophy

of Cheyenne Light is consistent with the opinion of Dr. Avera.

Q. HOW DO THE CREDIT RATING AGENCIES AFFECT THE COMPANY’S

ABILITY TO ISSUE DEBT?

A. The ratings of credit agencies affect a company’s ability to issue debt in a couple of

ways. First, the lower the rating, the greater the risk premium required from those willing

to invest in a company. Second, a low rating also limits the number of potential investors

interested in a company’s debt, which reduces the market for the company’s debt. Both

of these circumstances tend to increase the overall cost of debt to a company.

Q. WHY IS THIS IMPORTANT TO CHEYENNE LIGHT?

A. Access to capital is important to refinancing and for expansion of plant and the potential

acquisition of additional generation for Cheyenne Light. In addition, as noted above,

credit ratings impact vendor payments, including collateral requirements.

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V. CAPITAL STRUCTURE

Q. WHAT IS THE CAPITAL STRUCTURE PROPOSED FOR CHEYENNE LIGHT?

A. The Company proposes a capital structure of 54 percent common stock equity and 46

percent debt.

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Q. WHY IS THIS CAPITAL STRUCTURE APPROPRIATE FOR CHEYENNE

LIGHT?

A. As Dr. Avera testifies, this capital structure is appropriate because of the financial

position and relative size of Cheyenne Light to support utility operations, to serve its

customers with the appropriate capacity, for replacement and expansion of assets used to

provide power, to maintain liquidity, and to attract cost effective sources of capital for

refinancing plant improvement and growth.

Q. IS THE CAPITAL STRUCTURE PROPOSED FOR CHEYENNE LIGHT

CONSISTENT WITH ITS HISTORICAL CAPITAL STRUCTURE?

A. Yes. Exhibit BGI-E2 sets forth the capital structure for Cheyenne Light for the calendar

years 2008, 2009, and 2010, and for the eight months ended August 31, 2011. As shown

on this Exhibit, the percentage of debt of Cheyenne Light has been less than 46 percent

for each of the years shown on the Exhibit.

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VI. COST OF DEBT

Q. WHAT IS THE COST OF DEBT FOR CHEYENNE LIGHT?

A. The pro forma cost of debt for Cheyenne Light is 6.1 percent.

Q. HOW DID YOU DETERMINE THE COST OF DEBT FOR CHEYENNE LIGHT?

A. Cheyenne Light has a projected $127 million of existing long-term debt outstanding as of

December 31, 2011 based on actual debt.

The average cost of long-term debt is determined by taking the weighted average of the

amount of the individual debt issue components and their respective interest rates

(adjusted for issuance costs). Reference is made to Schedule G-1.

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Q. WHAT IS THE WEIGHTED AVERAGE COST OF CAPITAL REQUESTED

FOR CHEYENNE LIGHT?

A. The weighted average cost of capital requested for Cheyenne Light incorporates the cost

of equity of 10.9 percent, the weighted average embedded cost of debt of 6.10 percent,

and a capital structure of 54 percent equity and 46 percent debt financing. This

calculation results in a weighted average cost of capital of 8.70 percent. The result is

presented in Statement G.

Q. DOES THAT CONCLUDE YOUR DIRECT TESTIMONY?

A. Yes.

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Exhibit BGI-E1

BHC Credit Ratings

from SEC 10Q

Credit Ratings

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such

financing, and vendor payment terms, including collateral requirements. As of September 30, 2011,

our senior unsecured credit ratings, as assessed by the three major credit rating agencies, were as

follows:

Rating Agency

Rating

Outlook

Moody's Baa3 Stable

S&P

BBB-

Stable

Fitch BBB- Stable

Marc

h

Marc

h

Marc

h

Marc

h

2008

2008

2008

2008

June

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June

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2008

2008

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Marc

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June

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Marc

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2010

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2010

June

June

June

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2010

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2010

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2010

January

2011

January

2011

January

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January

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Febru

ary

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Febru

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2011

2011

2011

2011

Marc

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2011

2011

2011

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April

April

April

April

2011

2011

2011

2011

May

May

May

May

2011

2011

2011

2011

June

June

June

June

2011

2011

2011

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July

July

July

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QT

DM

TD

CLFP Capital Structure

QTD 2008, 2009, 2010

MTD Jan 2011-Aug 2011

(in millions)

pmh

Typewritten Text

pmh

Typewritten Text

Exhibit BGI-E2

pmh

Typewritten Text

Cheyenne Light Historical Debt Structure

pmh

Typewritten Text

BEFORE THE

PUBLIC SERVICE COMMISSION OF THE STATE OF WYOMING




December 1, 2011

INDEX TO THE DIRECT TESTIMONY OF WILLIAM E. AVERA

I. INTRODUCTION AND EXPERIENCE............................................................................ 1

A. Qualifications................................................................................................................ 1 B. Overview....................................................................................................................... 3 C. Summary and Conclusions ........................................................................................... 5

II. FUNDAMENTAL ANALYSES............................................................................................ 6 A. Cheyenne Light, Fuel and Power Company ................................................................. 7 B. Utility Industry.............................................................................................................. 8 C. Impact of Capital Market Conditions ......................................................................... 10

III. CAPITAL MARKET ESTIMATES .................................................................................. 14 A. Economic Standards.................................................................................................... 15 B. Comparable Risk Proxy Groups ................................................................................. 17 C. Discounted Cash Flow Analyses................................................................................. 23 D. Capital Asset Pricing Model ....................................................................................... 38 E. Risk Premium Approach ............................................................................................. 44 F. Expected Earnings Approach...................................................................................... 46 G. Flotation Costs ............................................................................................................ 49

IV. RETURN ON EQUITY FOR CHEYENNE LIGHT....................................................... 50 A. Implications for Financial Integrity ............................................................................ 51 B. Other Exposures.......................................................................................................... 53 C. Capital Structure ......................................................................................................... 56 D. ROE Recommendation ............................................................................................... 60

LIST OF EXHIBITS

Exhibit No. DescriptionWEA-1 Qualifications of William E. Avera WEA-2 DCF Model – Utility Proxy Group WEA-3 “br + sv” Growth Rate – Utility Proxy Group WEA-4 DCF Model – Non-Utility Proxy Group WEA-5 “br + sv” Growth Rate – Non-Utility Proxy Group WEA-6 Capital Asset Pricing Model WEA-7 Utility Risk Premium WEA-8 Expected Earnings Approach WEA-9 Capital Structure

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DIRECT TESTIMONY OF WILLIAM E. AVERA

I. INTRODUCTION AND EXPERIENCE 1

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A. William E. Avera, 3907 Red River, Austin, Texas, 78751.

Q. IN WHAT CAPACITY ARE YOU EMPLOYED?

A. I am the President of FINCAP, Inc., a firm providing financial, economic, and policy

consulting services to business and government.

Q. ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS PROCEEDING?


Light” or “the Company”).

A. Qualifications

Q. WHAT ARE YOUR QUALIFICATIONS? 10

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A. I received a B.A. degree with a major in economics from Emory University. After

serving in the U.S. Navy, I entered the doctoral program in economics at the University

of North Carolina at Chapel Hill. Upon receiving my Ph.D., I joined the faculty at the

University of North Carolina and taught finance in the Graduate School of Business. I

subsequently accepted a position at the University of Texas at Austin where I taught

courses in financial management and investment analysis. I then went to work for

International Paper Company in New York City as Manager of Financial Education, a

position in which I had responsibility for all corporate education programs in finance,

accounting, and economics.

In 1977, I joined the staff of the Public Utility Commission of Texas (“PUCT”) as

Director of the Economic Research Division. During my tenure at the PUCT, I managed

a division responsible for financial analysis, cost allocation and rate design, economic

and financial research, and data processing systems, and I testified in cases on a variety

of financial and economic issues. Since leaving the PUCT in 1979, I have been engaged

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as a consultant. I have participated in a wide range of assignments involving utility-

related matters on behalf of utilities, industrial customers, municipalities, and regulatory

commissions. I have previously testified before the Federal Energy Regulatory

Commission (“FERC”), as well as the Federal Communications Commission (“FCC”),

the Surface Transportation Board (and its predecessor, the Interstate Commerce

Commission), the Canadian Radio-Television and Telecommunications Commission, and

regulatory agencies, courts, and legislative committees in over 40 states, including the

Public Service Commission of the State of Wyoming (“WPSC” or “the Commission”).

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In 1995, I was appointed by the PUCT, with the approval of the Governor, to the

Synchronous Interconnection Committee to advise the Texas legislature on the costs and

benefits of connecting Texas to the national electric transmission grid. In addition, I

served as an outside director of Georgia System Operations Corporation, the system

operator for electric cooperatives in Georgia.

I have served as Lecturer in the Finance Department at the University of Texas at

Austin and taught in the evening graduate program at St. Edward’s University for twenty

years. In addition, I have lectured on economic and regulatory topics in programs

sponsored by universities and industry groups. I have taught in hundreds of educational

programs for financial analysts in programs sponsored by the Association for Investment

Management and Research, the Financial Analysts Review, and local financial analysts

societies. These programs have been presented in Asia, Europe, and North America,

including the Financial Analysts Seminar at Northwestern University. I hold the

Chartered Financial Analyst (CFA®) designation and have served as Vice President for

Membership of the Financial Management Association. I have also served on the Board

of Directors of the North Carolina Society of Financial Analysts. I was elected Vice

Chairman of the National Association of Regulatory Utility Commissioners (“NARUC”)

Subcommittee on Economics and appointed to NARUC’s Technical Subcommittee on

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the National Energy Act. I have also served as an officer of various other professional

organizations and societies. A resume containing the details of my experience and

qualifications is attached as Exhibit WEA-1.

B. Overview

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 4

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A. The purpose of my testimony is to present to the WPSC my independent assessment of

the fair rate of return on equity (“ROE”) for the jurisdictional electric and gas utility

operations of Cheyenne Light. In addition, I also examined the reasonableness of

Cheyenne Light’s requested capital structure, considering both the specific risks faced by

the Company and other industry guidelines.

Q. PLEASE SUMMARIZE THE INFORMATION AND MATERIALS YOU RELIED

ON TO SUPPORT THE OPINIONS AND CONCLUSIONS CONTAINED IN

YOUR TESTIMONY.

A. To prepare my testimony, I used information from a variety of sources that would

normally be relied upon by a person in my capacity. In connection with the present filing,

I considered and relied upon corporate disclosures and other published information

relating to Cheyenne Light and its parent company, Black Hills Corporation (“Black Hills

Corp.”). I also reviewed information relating generally to current capital market

conditions and specifically to current investor perceptions, requirements, and

expectations for electric and gas utilities. These sources, coupled with my experience in

the fields of finance and utility regulation, have given me a working knowledge of the

issues relevant to investors’ required return for Cheyenne Light, and they form the basis

of my analyses and conclusions.

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Q. WHAT IS THE PRACTICAL TEST OF THE REASONABLENESS OF THE ROE

USED IN SETTING A UTILITY’S RATES?

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A. The rate of return on common equity compensates shareholders for the use of their capital

to finance the plant and equipment necessary to provide utility service. Investors commit

capital only if they expect to earn a return on their investment commensurate with returns

available from alternative investments with comparable risks. To be consistent with

sound regulatory economics and the standards set forth by the Supreme Court in the

Bluefield 1 and Hope 2 cases, a utility’s allowed return on common equity should be

sufficient to: (1) fairly compensate investors for capital they have invested in the utility,

(2) enable the utility to offer a return adequate to attract new capital on reasonable terms,

and (3) maintain the utility’s financial integrity.

Q. HOW IS YOUR TESTIMONY ORGANIZED?

A. I first reviewed the operations and finances of Cheyenne Light and the general conditions

in the utility industry and the capital markets. With this as a background, I conducted

various well-accepted quantitative analyses to estimate the current cost of equity,

including alternative applications of the discounted cash flow (“DCF”) model, the Capital

Asset Pricing Model (“CAPM”), an equity risk premium approach based on allowed rates

of return, as well as reference to expected earned rates of return for utilities. Based on

the cost of equity estimates indicated by my analyses, the Company’s ROE was evaluated

taking into account the specific risks and potential challenges for Cheyenne Light, as well

as other factors (e.g., flotation costs) that are properly considered in setting a fair rate of

return on equity for the Company’s jurisdictional utility operations in Wyoming.

1 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679 (1923). 2 FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944).

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C. Summary and Conclusions

Q. WHAT ARE YOUR FINDINGS REGARDING A FAIR ROE FOR CHEYENNE

LIGHT?

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A. A. Based on the results of my analyses and the economic requirements necessary to

support continuous access to capital, I recommend that Cheyenne Light be authorized a

fair ROE in the range of 10.5 percent to 11.5 percent. The bases for my conclusion are

summarized below:

• In order to reflect the risks and prospects associated with Cheyenne Light’s jurisdictional utility operations, my analyses focused on a proxy group of other utilities with comparable investment risks. Consistent with the fact that utilities must compete for capital with firms outside their own industry, I also referenced a proxy group of low- risk companies in the non-utility sector of the economy;

• I applied both the DCF and CAPM methods, as well as the risk premium and expected earnings approaches, to estimate a fair ROE for Cheyenne Light;

• Based on the results of these analyses, and giving less weight to extremes at the high and low ends of the range, I concluded that the cost of equity for the proxy groups of utilities and non-utility companies is in the 10.3 percent to 11.3 percent range, or 10.5 percent to 11.5 percent after incorporating a minimal adjustment to account for the impact of common equity flotation costs;

• The reasonableness of an ROE range of 10.5 percent to 11.5 percent for Cheyenne Light is also supported by the greater investment risks implied by the Company’s relative size and low credit rating, as well as the expected upward trend in long-term capital costs; and,

• As reflected in the testimony of Mr. Brian Iverson, Cheyenne Light is requesting a fair ROE of 10.9 percent to balance customer impact during these challenging economic times with the Company’s need to maintain is financial integrity and access to capital. This 10.9 percent ROE falls below the midpoint of my recommended range and, in my professional opinion, represents a reasonable rate of return on common equity for Cheyenne Light.

Q. WHAT OTHER EVIDENCE DID YOU CONSIDER IN EVALUATING YOUR

ROE RECOMMENDATION IN THIS CASE?

A. My recommendation was reinforced by the following findings:

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• Sensitivity to financial market and regulatory uncertainties has increased dramatically and investors recognize that constructive regulation is a key ingredient in supporting utility credit standing and financial integrity;

• The potential for turmoil in the domestic and global financial markets and continued economic uncertainties exacerbate the risks faced by utilities and their investors and are a legitimate consideration in evaluating a fair ROE for Cheyenne Light; and,

• Providing Cheyenne Light with the opportunity to earn a return that reflects these realities is an essential ingredient to support the Company’s financial position, which ultimately benefits customers by ensuring reliable service at lower long-run costs.

Q. WHAT IS YOUR CONCLUSION AS TO THE REASONABLENESS OF

CHEYENNE LIGHT’S CAPITAL STRUCTURE?

A. Based on my evaluation, I concluded that a common equity ratio of 54 percent represents

a reasonable capitalization for Cheyenne Light. This conclusion was based on the

following findings:

• The common equity ratio implied by Cheyenne Light’s capital structure is consistent with the range of capitalizations maintained by the proxy group of utilities based on data at year-end 2010 and near-term expectations;

• The additional uncertainties associated with Cheyenne Light’s relatively weak credit standing and small size warrant a more conservative financial posture; and,

• The requested capitalization reflects the need to support the credit standing and financial flexibility of Cheyenne Light as the Company seeks to fund system investments and meet the requirements of customers.

II. FUNDAMENTAL ANALYSES 26

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Q. WHAT IS THE PURPOSE OF THIS SECTION?

A. As a predicate to the quantitative analyses that I address later in this testimony, this

section briefly reviews the operations and finances of Cheyenne Light. In addition, it

examines the risks and prospects for the electric utility industry and conditions in the

capital markets and the general economy. An understanding of the fundamental factors

driving the risks and prospects of utilities is essential in developing an informed opinion

of investors’ expectations and requirements that are the basis of a fair rate of return.

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A. Cheyenne Light, Fuel and Power Company

Q. BRIEFLY DESCRIBE CHEYENNE LIGHT. 1

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A. Cheyenne Light supplies electric and natural gas utility service to Wyoming’s capital city

and vicinity. The Company’s electric utility system provides service to approximately

39,630 customers, with Cheyenne Light’s peak load being approximately 181 megawatts

(“MW”). The Company’s generating capacity consists of the 95 MW, Wygen II coal-

fired facility located near Gillette, Wyoming. Cheyenne Light also obtains a portion of

the power required to meet customers’ needs under contracts with Black Hills Wyoming,

LLC, which includes an option for the Company to acquire an ownership interest in

Wygen I, a 90 MW coal-fired plant. In addition, Cheyenne Light also has long-term

contracts for the purchase of renewable wind energy.

Cheyenne Light’s natural gas distribution system provides service to

approximately 34,600 customers. Annual natural gas throughput amounts to

approximately 13.7 million dekatherms (“Dth”), with sales to residential and commercial

customers accounting for approximately 34 percent of this total, and transportation

volumes making up the remaining 66 percent. Cheyenne Light obtains its natural gas

supplies from independent suppliers, with deliveries made under a combination of

transportation agreements with interstate pipelines and direct deliveries by suppliers to

certain transportation customers. As of September 30, 2011, Cheyenne Light had total

capital of approximately $421 million, with operating revenues for 2011 year-to-date

totaling approximately $121 million. The Company’s retail utility operations are subject

to the jurisdiction of the WPSC. While Cheyenne Light has a gas cost tracking

mechanism in place that allows it to pass-through changes in natural gas costs to

customers, it currently does not have any regulatory mechanisms in Wyoming to adjust

for the impact of abnormal weather on earnings, or for changes in retail loads related to

energy efficiency or price elasticity outside of a rate case.

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Q. WHERE DOES CHEYENNE LIGHT OBTAIN THE CAPITAL USED TO

FINANCE ITS INVESTMENT IN UTILITY PLANT?

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A. As a wholly-owned subsidiary of Black Hills Corp., the Company obtains common

equity capital solely from its parent, whose common stock is publicly traded on the New

York Stock Exchange. In addition to common equity, Cheyenne Light has access to long-

term debt financing by issuing bonds in its own name, or through debt capital allocated to

the Company from Black Hills Corp.

Q. WHAT CREDIT RATINGS HAVE BEEN ASSIGNED TO BLACK HILLS CORP.?

A. Black Hills Corp. has been assigned a corporate credit rating of “BBB-” by Standard &

Poor’s Corporation (“S&P”), an issuer credit rating of “Baa3” by Moody’s Investor

Services, Inc. (“Moody’s”), and an issuer default rating of “BBB-” by Fitch Ratings Ltd.

(“Fitch”). These ratings represent the lowest rung on the ladder of the investment grade

scale.

B. Utility Industry

Q. HOW HAVE INVESTORS’ RISK PERCEPTIONS FOR THE UTILITY

INDUSTRY EVOLVED?

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A. Implementation of structural change, along with other factors impacting the economy and

the industry, has caused investors to rethink their assessment of the relative risks

associated with utilities. There has been a steady erosion in credit quality throughout the

utility industry for more than a decade, both as a result of revised perceptions of the risks

in the industry and the weakened finances of the utilities themselves. S&P observed with

respect to the industry’s future that:

Looming costs associated with environmental compliance, slack demand caused by economic weakness, the potential for permanent demand destruction caused by changes in consumer behavior and closing of manufacturing facilities, and numerous regulatory filings seeking recovery

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of costs are some of the significant challenges the industry has to deal with.

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Similarly, Moody’s noted:

[A] sustained period of sluggish economic growth, characterized by high unemployment, could stress the sector’s recovery prospects, financial performance, and credit ratings. The quality of the sector’s cash flows are already showing signs of decline, partly because of higher operating costs and investments.4

Moody’s concluded, “we also see the sector’s overall business and operating risks

increasing.”5

Q. WHAT PRINCIPAL FACTORS ARE CONSIDERED BY INVESTORS IN

ASSESSING RISKS IN THE UTILITY INDUSTRY?

A. In recent years, utilities and their customers have had to contend with dramatic

fluctuations in energy costs due to ongoing price volatility in the spot markets and

investors recognize the prospect of further turmoil in energy markets. Increased

environmental pressures and speculation over the potential costs associated with new

regulatory mandates have also created uncertainties. Investors are also aware of the

financial and regulatory pressures faced by utilities associated with both rising costs and

the need to undertake significant capital investments. As Moody’s observed:

[W]e also see the sector’s overall business risk and operating risks increasing, owing primarily to rising costs associated with upgrading and expanding the nation’s trillion dollar electric infrastructure.6

3 Standard & Poor’s Corporation, “U.S. Regulated Electric Utilities Head Into 2010 With Familiar Concerns,” RatingsDirect (Dec. 28, 2009). 4 Moody’s Investors Service, “U.S. Electric Utilities: Uncertain Times Ahead; Strengthening Balance Sheets Now Would Protect Credit,” Special Comment (Oct. 28, 2010). 5 Moody’s Investors Service, “Regulation Provides Stability As Risks Mount,” Industry Outlook (Jan. 19, 2011). 6 Moody’s Investors Service, “Regulation Provides Stability As Risks Mount,” Industry Outlook (Jan. 19, 2011).

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Similarly, S&P noted that cost increases and capital projects, along with uncertain load

growth, were a significant challenge to the utility industry.

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While enhancing the infrastructure necessary to meet the energy needs of

customers is certainly desirable, the associated capital expenditures imposes additional

financial responsibilities on utilities that are heightened during times of capital market

turmoil. As Value Line observed with respect to gas utilities:

The economy remains weighed down by tight credit, a soft housing market, and high unemployment. The weakness in the housing sector has particularly affected this industry. The large inventory of unsold houses has limited the need for natural gas. This is particularly troubling for these utilities as we enter the peak heating season. Moreover, customer growth has declined, which continues to pressure revenues across this group. Additionally, more conservation consumer spending has impacted customer usage, which has hurt volumes. Lastly, bill collection has been difficult given high unemployment rates. Looking ahead, these factors will likely continue to play on these companies …8

In addition to uncertainties over customer usage and growth, utilities such as Cheyenne

Light continue to face the same ongoing challenges and risks that have confronted them

in the past, including those related to inflation, weather, rate regulation, operating

hazards, and capital market uncertainties, as well as extraordinary risks such as legal

liabilities and natural disasters.

C. Impact of Capital Market Conditions

Q. WHAT ARE THE IMPLICATIONS OF RECENT CAPITAL MARKET

CONDITIONS?

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A. The deep financial and real estate crisis that the country experienced in late 2008, and

continuing into 2009 led to unprecedented price fluctuations in the capital markets as

7 Standard & Poor’s Corporation, “Industry Economic And Ratings Outlook,” RatingsDirect (Feb. 2, 2010). 8 The Value Line Investment Survey at 547 (Dec. 10, 2010).

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investors dramatically revised their risk perceptions and required returns. As a result of

investors’ trepidation to commit capital, stock prices declined sharply while the yields on

corporate bonds experienced a dramatic increase.

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With respect to utilities specifically, as of September 2011, the Dow Jones Utility

Average stock index remained approximately 17 percent below the previous high reached

in May 2008. This prolonged sell-off in common stocks and sharp fluctuations in utility

bond yields reflect the fact that the utility industry is not immune to the impact of

financial market turmoil and the ongoing economic downturn. As the Edison Electric

Institute noted in a letter to congressional representatives in September 2008 as the

financial crisis intensified, capital market uncertainties have serious implications for

utilities and their customers:

In the wake of the continuing upheaval on Wall Street, capital markets are all but immobilized, and short-term borrowing costs to utilities have already increased substantially. If the financial crisis is not resolved quickly, financial pressures on utilities will intensify sharply, resulting in higher costs to our customers and, ultimately, could compromise service reliability.9

While conditions have improved significantly since the depths of the crisis,

investors have nonetheless had to confront ongoing fluctuations in share prices and stress

in the credit markets.10 Investors have faced a myriad of challenges and uncertainties,

including the threat of a U.S. government default and political brinksmanship over raising

the federal debt ceiling. The sovereign debt crisis in Europe has also dealt a harsh blow

to investor confidence, and concerns over potential exposure to a Euro-zone default has

again undermined confidence in the financial and banking sector. Meanwhile,

9 Letter to House of Representatives, Thomas R. Kuhn, President, Edison Electric Institute (Sep. 24, 2008). 10 See, e.g., Gongloff, Mark, “Stock Rebound Is a Crisis Flashback – Late Surge Recalls Market’s Volatility at Peak of Credit Difficulties; Unusual Correlations,” Wall Street Journal at B1 (Feb. 6, 2010).

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speculation that the economy is poised on the brink of a “double-dip” recession has

increased, with unemployment remaining at 9 percent, falling consumer confidence, and

continued weakness plaguing the real estate sector.

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In response, investors have repeatedly fled to the safety of U.S. Treasury bonds,

and stock prices have experienced renewed volatility. As the Wall Street Journal noted

in August 2011:

Stocks spiraled downward Thursday as investors buckled under the strain of the global economic slowdown and the failure of policy makers to stabilize financial markets. … The nervousness among investors is being reflected in an extraordinary rally in U.S. Treasury bonds, regarded as a safe haven for investors in time of turmoil. … The Dow’s decline was its biggest point drop since the market was plunging amid a crisis of confidence in banks in late 2008. On Thursday, the focus shifted to world governments, which are laboring under mountains of debt and have diminished ability to prop up the financial system.11

The dramatic rise in the price of gold and other commodities also attests to investors’

heightened concerns over prospective challenges and risks, including the overhanging

threat of inflation, a double-dip recession, and renewed economic turmoil. With respect

to utilities, Moody’s noted the dangers to credit availability associated with exposure to

European banks,12 and concluded:

Over the past few months, we have been reminded that global financial markets, which are still receiving extraordinary intervention benefits by sovereign governments, are exposed to turmoil. Access to the capital markets could therefore become intermittent, even for safer, more defensive sectors like the power industry.13

11 Lauricella, Tom, “Stocks Nose-Dive Amid Global Fears – Weak Outlook, Government Debt Worries Drive Dow’s Biggest Point Drop Since ’08,” Wall Street Journal at A1 (Aug. 5, 2011). 12 Moody’s Investors Service, “Electric Utilities Stable But Face Increasing Regulatory Uncertainty,” Industry Outlook (Jul. 22, 2010). 13 Moody’s Investors Service, “Regulation Provides Stability As Risks Mount,” Industry Outlook (Jan. 19, 2011).

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Uncertainties surrounding economic and capital market conditions heighten the risks

faced by utilities, which, as described earlier, face a variety of operating and financial

challenges.

Q. HOW DO INTEREST RATES ON LONG-TERM BONDS COMPARE WITH

THOSE PROJECTED FOR THE NEXT FEW YEARS?

A. Table WEA-1 below compares current interest rates on 30-year Treasury bonds, triple-A

rated corporate bonds, and double-A rated utility bonds with near-term projections from

The Value Line Investment Survey (“Value Line”), IHS Global Insight, Blue Chip

Financial Forecasts (“Blue Chip”), Standard & Poor’s Corporation (“S&P”), and the

Energy Information Administration (“EIA”):

TABLE WEA-1 INTEREST RATE TRENDS

Current (a) 2012 2013 2014 201530-Yr. Treasury

Value Line (b) 4.2% 3.9% 4.1% 4.5% 5.0%IHS Global Insight (c) 4.2% 4.7% 5.0% 5.1% 6.0%Blue Chip (d) 4.2% 5.2% 5.2% 5.5% 5.7%

AAA CorporateValue Line (b) 5.0% 4.6% 4.7% 5.2% 5.7%IHS Global Insight (c) 5.0% 5.2% 6.0% 6.2% 6.8%Blue Chip (d) 5.0% 5.8% 5.9% 6.3% 6.5%S&P (e) 5.0% 4.5% 4.7% 5.9% 6.8%

AA UtilityIHS Global Insight (c) 5.0% 5.4% 6.3% 6.4% 7.2%EIA (f) 5.0% 5.5% 6.4% 7.0% 7.4%

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(b) The Value Line Investment Survey, Forecast for the U.S. Economy (Nov. 25, 2011).(c) IHS Global Insight, U.S. Economic Outlook at 19 (Feb. 2011).(d) Blue Chip Financial Forecasts, Vol. 30, No. 6 (Jun. 1, 2011).(e)

(f) Energy Information Administration, Annual Energy Outlook 2011 (April 26, 2011).

Standard & Poor's Corporation, "U.S. Economic Forecast: Still Treading Water," RatingsDirect (Aug. 17, 2011).

Based on monthly average bond yields for the six-month period May - Oct. 2011 reported at www.credittrends.moodys.com and http://www.federalreserve.gov/releases /h15/data.htm.

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As evidenced above, there is a clear consensus that the cost of permanent capital will be

higher in the 2012-2015 timeframe than it is currently. As a result, current cost of capital

estimates are conservative, because they are likely to understate investors’ requirements

at the time the rates set in this proceeding become effective.

Q. WHAT DO THESE EVENTS IMPLY WITH RESPECT TO THE ROE FOR

CHEYENNE LIGHT?

A. No one knows the future of our complex global economy. We know that the financial

crisis had been building for a long time, and few predicted that the economy would fall as

rapidly as it did, or that corporate bond yields would fluctuate as dramatically as they

have. While conditions in the economy and capital markets appear to have stabilized

significantly since 2009, investors continue to react swiftly and negatively to any future

signs of trouble in the financial system or economy. Given the importance of reliable

utility service, it would be unwise to ignore investors’ increased sensitivity to risk and

future capital market trends in evaluating a fair ROE in this case. Similarly, the

Company’s capital structure must also preserve the financial flexibility necessary to

maintain access to capital even during times of unfavorable market conditions.

III. CAPITAL MARKET ESTIMATES 17

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A. In this section, I develop capital market estimates of the cost of equity. First, I address

the concept of the cost of equity, along with the risk-return tradeoff principle fundamental

to capital markets. Next, I describe DCF, CAPM, and risk premium analyses conducted

to estimate the cost of equity for benchmark groups of comparable risk firms and evaluate

expected earned rates of return for utilities. Finally, I examine the issue of flotation costs,

which are properly considered in evaluating a fair ROE.

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A. Economic Standards

Q. WHAT ROLE DOES THE RETURN ON COMMON EQUITY PLAY IN A

UTILITY’S RATES?

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A. The return on common equity is the cost of inducing and retaining investment in the

utility’s physical plant and assets. This investment is necessary to finance the asset base

needed to provide utility service. Competition for investor funds is intense and investors

are free to invest their funds wherever they choose. Investors will commit money to a

particular investment only if they expect it to produce a return commensurate with those

from other investments with comparable risks.

Q. WHAT FUNDAMENTAL ECONOMIC PRINCIPLE UNDERLIES THE COST OF

EQUITY CONCEPT?

A. The fundamental economic principle underlying the cost of equity concept is the notion

that investors are risk averse. In capital markets where relatively risk-free assets are

available (e.g., U.S. Treasury securities), investors can be induced to hold riskier assets

only if they are offered a premium, or additional return, above the rate of return on a risk-

free asset. Because all assets compete with each other for investor funds, riskier assets

must yield a higher expected rate of return than safer assets to induce investors to invest

and hold them.

Given this risk-return tradeoff, the required rate of return (k) from an asset (i) can

generally be expressed as:

ki = Rf +RPi

where: Rf = risk-free rate of return, and RPi = Risk premium required to hold riskier asset i.

Thus, the required rate of return for a particular asset at any time is a function of: (1) the

yield on risk-free assets, and (2) the asset’s relative risk, with investors demanding

correspondingly larger risk premiums for bearing greater risk.

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Q. IS THERE EVIDENCE THAT THE RISK-RETURN TRADEOFF PRINCIPLE

ACTUALLY OPERATES IN THE CAPITAL MARKETS?

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A. Yes. The risk-return tradeoff can be readily documented in segments of the capital

markets where required rates of return can be directly inferred from market data and

where generally accepted measures of risk exist. Bond yields, for example, reflect

investors’ expected rates of return, and bond ratings measure the risk of individual bond

issues. Comparing the observed yields on government securities, which are considered

free of default risk, to the yields on bonds of various rating categories demonstrates that

the risk-return tradeoff does, in fact, exist.

Q. DOES THE RISK-RETURN TRADEOFF OBSERVED WITH FIXED INCOME

SECURITIES EXTEND TO COMMON STOCKS AND OTHER ASSETS?

A. It is generally accepted that the risk-return tradeoff evidenced with long-term debt

extends to all assets. Documenting the risk-return tradeoff for assets other than fixed

income securities, however, is complicated by two factors. First, there is no standard

measure of risk applicable to all assets. Second, for most assets – including common

stock – required rates of return cannot be directly observed. Yet there is every reason to

believe that investors exhibit risk aversion in deciding whether or not to hold common

stocks and other assets, just as when choosing among fixed-income securities.

Q. IS THIS RISK-RETURN TRADEOFF LIMITED TO DIFFERENCES BETWEEN

FIRMS?

A. No. The risk-return tradeoff principle applies not only to investments in different firms,

but also to different securities issued by the same firm. The securities issued by a utility

vary considerably in risk because they have different characteristics and priorities. Long-

term debt secured by a mortgage on property is senior among all capital in its claim on a

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utility’s net revenues and is, therefore, the least risky.14 Following bonds are other debt

instruments also holding contractual claims on the utility’s net revenues, such as

subordinated debentures. The last investors in line are common shareholders. They

receive only the net revenues, if any, remaining after all other claimants have been paid.

As a result, the rate of return that investors require from a utility’s common stock, the

most junior and riskiest of its securities, must be considerably higher than the yield

offered by the utility’s senior, long-term debt.

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Q. WHAT DOES THE ABOVE DISCUSSION IMPLY WITH RESPECT TO

ESTIMATING THE COST OF EQUITY FOR A UTILITY?

A. Although the cost of equity cannot be observed directly, it is a function of the returns

available from other investment alternatives and the risks to which the equity capital is

exposed. Because it is unobservable, the cost of equity for a particular utility must be

estimated by analyzing information about capital market conditions generally, assessing

the relative risks of the company specifically, and employing various quantitative

methods that focus on investors’ required rates of return. These various quantitative

methods typically attempt to infer investors’ required rates of return from stock prices,

interest rates, or other capital market data.

B. Comparable Risk Proxy Groups

Q. HOW DID YOU IMPLEMENT THESE QUANTITATIVE METHODS TO

ESTIMATE THE COST OF COMMON EQUITY FOR CHEYENNE LIGHT?

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A. Application of the DCF model and other quantitative methods to estimate the cost of

common equity requires observable capital market data, such as stock prices. Moreover,

even for a firm with publicly traded stock, the cost of common equity can only be

14 That being said, even secured long-term debt is effectively “junior” to long-term cost commitments necessary to operate the underlying business such as power agreements, fuel contracts and certain leases. The magnitude of these non-debt obligations can affect the cost of all forms of capital, including equity.

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estimated. As a result, applying quantitative models using observable market data only

produces an estimate that inherently includes some degree of observation error. Thus, the

accepted approach to increase confidence in the results is to apply the DCF model and

other quantitative methods to a proxy group of publicly traded companies that investors

regard as risk-comparable.

Q. WHAT SPECIFIC PROXY GROUP OF UTILITIES DID YOU RELY ON FOR

YOUR ANALYSIS?

A. In order to reflect the risks and prospects associated with Cheyenne Light’s jurisdictional

utility operations, my DCF analyses focused on a reference group of other utilities

composed of those companies classified by The Value Line Investment Survey (“Value

Line”) as electric utilities with: (1) both electric and gas utility operations, (2) an S&P

corporate credit rating of “BBB-” to “BBB+”, and (3) a Value Line Safety Rank of “2” or

“3”. In addition, I eliminated two utilities that otherwise would have been in the proxy

group, but are not appropriate for inclusion because they are currently involved in a

major merger or acquisition. These criteria resulted in a proxy group composed of twenty

companies, which I will refer to as the “Utility Proxy Group.”

Q. WHAT OTHER PROXY GROUP DID YOU CONSIDER IN EVALUATING A

FAIR ROE FOR CHEYENNE LIGHT?

A. Under the regulatory standards established by Hope and Bluefield, the salient criterion in

establishing a meaningful benchmark to evaluate a fair ROE is relative risk, not the

particular business activity or degree of regulation. With regulation taking the place of

competitive market forces, required returns for utilities should be in line with those of

non-utility firms of comparable risk operating under the constraints of free competition.

Consistent with this accepted regulatory standard, I also applied the DCF model to a

reference group of low-risk companies in the non-utility sectors of the economy. I refer

to this group as the “Non-Utility Proxy Group”.

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Q. DO UTILITIES HAVE TO COMPETE WITH NON-REGULATED FIRMS FOR

CAPITAL?

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A. Yes. The cost of capital is an opportunity cost based on the returns that investors could

realize by putting their money in other alternatives. Clearly, the total capital invested in

utility stocks is only the tip of the iceberg of total common stock investment, and there

are a plethora of other enterprises available to investors beyond those in the utility

industry. Utilities must compete for capital, not just against firms in their own industry,

but with other investment opportunities of comparable risk.

Q. IS IT CONSISTENT WITH THE BLUEFIELD AND HOPE CASES TO

CONSIDER REQUIRED RETURNS FOR NON-UTILITY COMPANIES?

A. Yes. Returns in the competitive sector of the economy form the very underpinning for

utility ROEs because regulation purports to serve as a substitute for the actions of

competitive markets. The Supreme Court has recognized that it is the degree of risk, not

the nature of the business, which is relevant in evaluating an allowed ROE for a utility.

The Bluefield case refers to “business undertakings attended with comparable risks and

uncertainties.” 15 It does not restrict consideration to other utilities. Similarly, the Hope

case states:

By that standard the return to the equity owner should be commensurate with returns on investments in other enterprises having corresponding risks.16

As in the Bluefield decision, there is nothing to restrict “other enterprises” solely to the

utility industry.

Indeed, in teaching regulatory policy I usually observe that in the early

applications of the comparable earnings approach, utilities were explicitly eliminated due

15 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679 (1923). 16 Federal Power Comm’n v. Hope Natural Gas Co. (320 U.S. 391, 1944).

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to a concern about circularity. In other words, soon after the Hope decision regulatory

commissions did not want to get involved in circular logic by looking to the returns of

utilities that were established by the same or similar regulatory commissions in the same

geographic region. To avoid circularity, regulators looked only to the returns of non-

utility companies.

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Q. DOES CONSIDERATION OF THE RESULTS FOR THE NON-UTILITY PROXY

GROUP MAKE THE ESTIMATION OF THE COST OF EQUITY USING THE

DCF MODEL MORE RELIABLE?

A. Yes. The estimates of growth from the DCF model depend on analysts’ forecasts. It is

possible for utility growth rates to be distorted by short-term trends in the industry or the

industry falling into favor or disfavor by analysts. The result of such distortions would be

to bias the DCF estimates for utilities. For example, Value Line observed that near-term

growth rates understate the longer-term expectations for gas utilities:

Natural Gas Utility stocks have fallen near the bottom of our Industry spectrum for Timeliness. Accordingly, short-term investors would probably do best to find a group with better prospects over the coming six to 12 months. Longer-term, we expect these businesses to rebound. An improved economic environment, coupled with stronger pricing, should boost results across this sector over the coming years.17

Because the Non-Utility Proxy Group includes low risk companies from many industries,

it diversifies away any distortion that may be caused by the ebb and flow of enthusiasm

for a particular sector.

Q. WHAT CRITERIA DID YOU APPLY TO DEVELOP THE NON-UTILITY PROXY

GROUP?

A. My comparable risk proxy group of non-utility firms was composed of those U.S.

companies followed by Value Line that: (1) pay common dividends; (2) have a Safety

17 The Value Line Investment Survey at 445 (Mar. 12, 2010).

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Rank of “1”; (3) have a Financial Strength Rating of “B++” or greater; (4) have a beta of

0.75 or less; and, (5) have investment grade credit ratings from S&P.

Q. DO THESE CRITERIA PROVIDE OBJECTIVE EVIDENCE TO EVALUATE

INVESTORS’ RISK PERCEPTIONS?

A. Yes. Credit ratings are assigned by independent rating agencies for the purpose of

providing investors with a broad assessment of the creditworthiness of a firm. Ratings

generally extend from triple-A (the highest) to D (in default). Other symbols (e.g., "A+")

are used to show relative standing within a category. Because the rating agencies’

evaluation includes virtually all of the factors normally considered important in assessing

a firm’s relative credit standing, corporate credit ratings provide a broad, objective

measure of overall investment risk that is readily available to investors. Although the

credit rating agencies are not immune to criticism, their rankings and analyses are widely

cited in the investment community and referenced by investors. Investment restrictions

tied to credit ratings continue to influence capital flows, and credit ratings are also

frequently used as a primary risk indicator in establishing proxy groups to estimate the

cost of common equity.

While credit ratings provide the most widely referenced benchmark for

investment risks, other quality rankings published by investment advisory services also

provide relative assessments of risks that are considered by investors in forming their

expectations for common stocks. Value Line’s primary risk indicator is its Safety Rank,

which ranges from “1” (Safest) to “5” (Riskiest). This overall risk measure is intended to

capture the total risk of a stock, and incorporates elements of stock price stability and

financial strength. Given that Value Line is perhaps the most widely available source of

investment advisory information, its Safety Rank provides useful guidance regarding the

risk perceptions of investors.

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The Financial Strength Rating is designed as a guide to overall financial strength

and creditworthiness, with the key inputs including financial leverage, business volatility

measures, and company size. Value Line’s Financial Strength Ratings range from “A++”

(strongest) down to “C” (weakest) in nine steps. Finally, Value Line’s beta measures the

volatility of a security's price relative to the market as a whole. A stock that tends to

respond less to market movements has a beta less than 1.00, while stocks that tend to

move more than the market have betas greater than 1.00.

Q. HOW DO THE OVERALL RISKS OF YOUR PROXY GROUPS COMPARE TO

CHEYENNE LIGHT?

A. Table WEA-2 compares the Utility Proxy Group with the Non-Utility Proxy Group and

Cheyenne Light across four key indicators of investment risk. Because the Company

does not have publicly traded common stock, the Value Line risk measures shown reflect

those published for the Company’s parent, Black Hills Corp.

TABLE WEA-2 COMPARISON OF RISK INDICATORS

S&P Value Line

Credit Rating

Safety Rank

Financial Strength

Beta

Utility Group BBB 2 B++ 0.75

Non-Utility Proxy Group A 1 A+ 0.71

Cheyenne Light BBB- 3 B+ 0.85

Q. WHAT DO THESE COMPARISONS INDICATE REGARDING THE RISKS

THAT INVESTORS ASSOCIATE WITH THE FIRMS IN YOUR PROXY

GROUPS?

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A. As discussed earlier, Black Hills Corp. is assigned a corporate credit rating of “BBB-” by

S&P, which falls below the average corporate credit rating for the Utility Proxy Group.

Similarly, the average Value Line Safety Rank, Financial Strength Rating, and beta for the

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Utility Proxy Group suggests less risk than investors would associate with Black Hills

Corp. Considered together, a comparison of these objective measures, which consider a

broad spectrum of risks, including financial and business position, and exposure to firm-

specific factors, indicates that investors would likely conclude that the overall investment

risks for Cheyenne Light are greater than those of the firms in the Utility Proxy Group.

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The Non-Utility Proxy Group’s average risk measures also suggest less risk than

for Cheyenne Light. While the impact of differences in regulation is reflected in

objective risk measures, my analyses conservatively focus on a lower-risk group of non-

utility firms. The 34 companies that make up the Non-Utility Proxy Group are

representative of the pinnacle of corporate America. These firms, which include

household names such as AT&T, Coca-Cola, Colgate-Palmolive, Exxon-Mobil, and

Wal-Mart – to name a few – have long corporate histories, well-established track records,

and exceedingly conservative risk profiles. Many of these companies pay dividends on a

par with utilities, with the average dividend yield for the group approaching 3 percent.

Moreover, because of their significance and name recognition, these companies receive

intense scrutiny by the investment community, which increases confidence that published

growth estimates are representative of the consensus expectations reflected in common

stock prices.

C. Discounted Cash Flow Analyses

Q. HOW IS THE DCF MODEL USED TO ESTIMATE THE COST OF EQUITY? 19

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A. The DCF model attempts to replicate the market valuation process that sets the price

investors are willing to pay for a share of a company’s stock. The model rests on the

assumption that investors evaluate the risks and expected rates of return from all

securities in the capital markets. Given these expectations, the price of each stock is

adjusted by the market until investors are adequately compensated for the risks they bear.

Therefore, we can look to the market to determine what investors believe a share of

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common stock is worth. By estimating the cash flows investors expect to receive from

the stock in the way of future dividends and capital gains, we can calculate their required

rate of return. In other words, the cash flows that investors expect from a stock are

estimated, and given its current market price, we can “back-into” the discount rate, or

cost of equity, that investors implicitly used in bidding the stock to that price.

Notationally, the general form of the DCF model is as follows:

te

tt

e

t

ee kP

kD

kD

kDP

)1()1()1()1( 22

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0 ++

+++

++

+= L

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where: P0 = Current price per share; Pt = Expected future price per share in period t; Dt = Expected dividend per share in period t; ke = Cost of equity.

That is, the cost of equity is the discount rate that will equate the current price of a share

of stock with the present value of all expected cash flows from the stock.

Q. WHAT FORM OF THE DCF MODEL IS CUSTOMARILY USED TO ESTIMATE

THE COST OF EQUITY IN RATE CASES?

A. Rather than developing annual estimates of cash flows into perpetuity, the DCF model

can be simplified to a “constant growth” form:18

gkDP

e −= 1

0 17

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where: g = Investors’ long-term growth expectations.

18 The constant growth DCF model is dependent on a number of strict assumptions, which in practice are never strictly met. These include a constant growth rate for both dividends and earnings; a stable dividend payout ratio; the discount rate exceeds the growth rate; a constant growth rate for book value and price; a constant earned rate of return on book value; no sales of stock at a price above or below book value; a constant price-earnings ratio; a constant discount rate (i.e., no changes in risk or interest rate levels and a flat yield curve); and all of the above extend to infinity.

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The cost of equity ( ) can be isolated by rearranging terms within the equation: ek1

gPDke +=

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This constant growth form of the DCF model recognizes that the rate of return to

stockholders consists of two parts: 1) dividend yield (D1/P0); and 2) growth (g). In other

words, investors expect to receive a portion of their total return in the form of current

dividends and the remainder through price appreciation.

Q. WHAT FORM OF THE DCF MODEL DID YOU USE?

A. I applied the constant growth DCF model to estimate the cost of equity for Cheyenne

Light, which is the form of the model most commonly relied on to establish the cost of

equity for traditional regulated utilities and the method most often referenced by

regulators.

Q. HOW IS THE CONSTANT GROWTH FORM OF THE DCF MODEL

TYPICALLY USED TO ESTIMATE THE COST OF EQUITY?

A. The first step in implementing the constant growth DCF model is to determine the

expected dividend yield (D1/P0) for the firm in question. This is usually calculated based

on an estimate of dividends to be paid in the coming year divided by the current price of

the stock. The second, and more controversial, step is to estimate investors’ long-term

growth expectations (g) for the firm. The final step is to sum the firm’s dividend yield

and estimated growth rate to arrive at an estimate of its cost of equity.

Q. HOW WAS THE DIVIDEND YIELD FOR THE UTILITY PROXY GROUP

DETERMINED?

A. Estimates of dividends to be paid by each of these utilities over the next twelve months,

obtained from Value Line, served as D1. This annual dividend was then divided by the

average stock price for the 30 days ended November 18, 2011 to arrive at the expected

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dividend yield for each utility. The stock prices, expected dividends, and resulting

dividend yields for the firms in the Utility Proxy Group are presented on page 1 of

Exhibit WEA-2. As shown there, dividend yields for the firms in the Utility Proxy Group

ranged from 3.2 percent to 5.6 percent, and averaged 4.5 percent.

Q. WHAT IS THE NEXT STEP IN APPLYING THE CONSTANT GROWTH DCF

MODEL?

A. The next step is to evaluate long-term growth expectations, or “g”, for the firm in

question. In constant growth DCF theory, earnings, dividends, book value, and market

price are all assumed to grow in lockstep, and the growth horizon of the DCF model is

infinite. But implementation of the DCF model is more than just a theoretical exercise; it

is an attempt to replicate the mechanism investors used to arrive at observable stock

prices. A wide variety of techniques can be used to derive growth rates, but the only “g”

that matters in applying the DCF model is the value that investors expect.

Q. ARE HISTORICAL GROWTH RATES LIKELY TO BE REPRESENTATIVE OF

INVESTORS’ EXPECTATIONS FOR UTILITIES?

A. No. If past trends in earnings, dividends, and book value are to be representative of

investors’ expectations for the future, then the historical conditions giving rise to these

growth rates should be expected to continue. That is clearly not the case for utilities,

where structural and industry changes have led to declining growth in dividends, earnings

pressure, and, in many cases, significant write-offs. While these conditions serve to

distort historical growth measures, they are not representative of long-term expectations

for the utility industry or the forward-looking expectations that investors have

incorporated into current market prices. As a result, historical growth measures for

utilities do not currently meet the requirements of the DCF model.

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Q. DO THE GROWTH RATE PROJECTIONS OF SECURITY ANALYSTS

CONSIDER HISTORICAL TRENDS?

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A. Yes. Professional security analysts study historical trends extensively in developing their

projections of future earnings. Hence, to the extent there is any useful information in

historical patterns, that information is incorporated into analysts’ growth forecasts.

Q. DID YOU CONSIDER EXPECTED DIVIDEND GROWTH RATES IN APPLYING

THE DCF MODEL?

A. Yes. As noted earlier, the DCF model is predicated on the assumption that investors

arrive at the price they are willing to pay for a particular common stock by discounting

future cash flows at their required rate of return. Growth rates in dividends per share

(“DPS”) are frequently used as a basis to apply the constant growth DCF model, and my

DCF analysis for the Utility Proxy Group incorporated the DPS growth projections

published by Value Line.

Q. ARE DPS GROWTH RATES LIKELY TO PROVIDE A MEANINGFUL GUIDE

TO INVESTORS' GROWTH EXPECTATIONS FOR UTILITIES?

A. No. While the DCF model is technically concerned with growth in dividend cash flows,

implementation of this DCF model is solely concerned with replicating the forward-

looking evaluation of real-world investors. In the case of utilities, dividend growth rates

are not likely to provide a meaningful guide to investors’ current growth expectations.

This is because utilities have significantly altered their dividend policies in response to

more accentuated business risks in the industry.19 As a result of this trend towards a more

conservative payout ratio, dividend growth in the utility industry has remained largely

19 For example, the payout ratio for electric utilities fell from approximately 80% historically to on the order of 60%. The Value Line Investment Survey (Sep. 15, 1995 at 161, Feb. 4, 2011 at 2237).

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stagnant as utilities conserve financial resources to provide a hedge against heightened

uncertainties.

Q. ARE THESE DISTORTIONS ASSOCIATED WITH DPS GROWTH RATES SELF

EVIDENT?

A. Yes. The projected DPS growth rates published by Value Line for each of the firms in the

Utility Proxy Group are shown on page 2 of Exhibit WEA-2. As shown there, one-

quarter of the individual DPS growth rates reported by Value Line for the companies in

the Utility Proxy Group were zero or negative.

Q. WHAT ARE INVESTORS MOST LIKELY TO CONSIDER IN DEVELOPING

THEIR LONG-TERM GROWTH EXPECTATIONS?

A. As payout ratios for firms in the utility industry trended downward, investors’ focus has

increasingly shifted from dividends to earnings as a measure of long-term growth. Future

trends in earnings per share (“EPS”), which provide the source for future dividends and

ultimately support share prices, play a pivotal role in determining investors’ long-term

growth expectations. The importance of earnings in evaluating investors’ expectations

and requirements is well accepted in the investment community, and surveys of analytical

techniques relied on by professional analysts indicate that growth in earnings is far more

influential that trends in DPS. Apart from Value Line, investment advisory services do

not generally publish comprehensive DPS growth projections, and this scarcity of

dividend growth rates relative to the abundance of earnings forecasts attests to their

relative influence. The fact that securities analysts focus on growth EPS, and that

dividend growth rates are not routinely published, indicates that projected EPS growth

rates are likely to provide a superior indicator of the future long-term growth expected by

investors.

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Q. WHAT ARE SECURITY ANALYSTS CURRENTLY PROJECTING IN THE WAY

OF GROWTH FOR THE FIRMS IN THE UTILITY PROXY GROUP?

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A. The projected EPS growth rates for each of the firms in the Utility Proxy Group reported

by Value Line, Thomson Reuters (“IBES”), and Zacks Investment Research (“Zacks”) are

displayed on Exhibit WEA-3.20

Q. SOME ARGUE THAT ANALYSTS’ GROWTH RATES ARE BIASED. DO YOU

BELIEVE THESE PROJECTIONS ARE INAPPROPRIATE FOR ESTIMATING

INVESTORS’ REQUIRED RETURN USING THE DCF MODEL?

A. No. In applying the DCF model to estimate the cost of common equity, the only relevant

growth rate is the forward-looking expectations of investors that are captured in current

stock prices. Investors, just like securities analysts and others in the investment

community, do not know how the future will actually turn out. They can only make

investment decisions based on their best estimate of what the future holds in the way of

long-term growth for a particular stock, and securities prices are constantly adjusting to

reflect their assessment of available information.

Any claims that analysts’ estimates are not relied upon by investors are illogical

given the reality of a competitive market for investment advice. The market for

investment advice is intensely competitive, and securities analysts are personally and

professionally motivated to provide the most accurate assessment possible of future

growth trends. If financial analysts’ forecasts do not add value to investors’ decision

making, then it is irrational for investors to pay for these estimates. Similarly, those

financial analysts who fail to provide reliable forecasts will lose out in competitive

markets relative to those analysts whose forecasts investors find more credible. The

20 Formerly I/B/E/S International, Inc., IBES growth rates are now compiled and published by Thomson Reuters.

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reality that analyst estimates are routinely referenced in the financial media and in

investment advisory publications (e.g., Value Line) implies that investors use them as a

basis for their expectations.

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The continued success of investment services such as Thomson Reuters and

Value Line, and the fact that projected growth rates from such sources are widely

referenced, provides strong evidence that investors give considerable weight to analysts’

earnings projections in forming their expectations for future growth. While the

projections of securities analysts may be proven optimistic or pessimistic in hindsight,

this is irrelevant in assessing the expected growth that investors have incorporated into

current stock prices, and any bias in analysts’ forecasts – whether pessimistic or

optimistic – is similarly irrelevant if investors share the analysts’ views. Earnings growth

projections of security analysts provide the most frequently referenced guide to investors’

views and are widely accepted in applying the DCF model. As explained in New

Regulatory Finance:

Because of the dominance of institutional investors and their influence on individual investors, analysts’ forecasts of long-run growth rates provide a sound basis for estimating required returns. Financial analysts exert a strong influence on the expectations of many investors who do not possess the resources to make their own forecasts, that is, they are a cause of g [growth]. The accuracy of these forecasts in the sense of whether they turn out to be correct is not an issue here, as long as they reflect widely held expectations.21

Q. HOW ELSE ARE INVESTORS’ EXPECTATIONS OF FUTURE LONG-TERM

GROWTH PROSPECTS OFTEN ESTIMATED WHEN APPLYING THE

CONSTANT GROWTH DCF MODEL?

A. In constant growth theory, growth in book equity will be equal to the product of the

earnings retention ratio (one minus the dividend payout ratio) and the earned rate of

21 Morin, Roger A., “New Regulatory Finance,” Public Utilities Reports, Inc. at 298 (2006).

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return on book equity. Furthermore, if the earned rate of return and the payout ratio are

constant over time, growth in earnings and dividends will be equal to growth in book

value. Despite the fact that these conditions are seldom, if ever, met in practice, this

“sustainable growth” approach may provide a rough guide for evaluating a firm’s growth

prospects and is frequently proposed in regulatory proceedings.

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Accordingly, while I believe that analysts’ EPS growth forecasts provide a

superior and more direct guide to investors’ growth expectations, I have included the

“sustainable growth” approach for completeness. The sustainable growth rate is

calculated by the formula, g = br+sv, where “b” is the expected retention ratio, “r” is the

expected earned return on equity, “s” is the percent of common equity expected to be

issued annually as new common stock, and “v” is the equity accretion rate.

Q. WHAT IS THE PURPOSE OF THE “SV” TERM?

A. Under DCF theory, the “sv” factor is a component of the growth rate designed to capture

the impact of issuing new common stock at a price above, or below, book value. When a

company’s stock price is greater than its book value per share, the per-share contribution

in excess of book value associated with new stock issues will accrue to the current

shareholders. This increase to the book value of existing shareholders leads to higher

expected earnings and dividends, with the “sv” factor incorporating this additional

growth component.

Q. WHAT GROWTH RATE DOES THE EARNINGS RETENTION METHOD

SUGGEST FOR THE UTILITY PROXY GROUP?

A. The sustainable, “br+sv” growth rates for each firm in the proxy group are summarized

on page 2 of Exhibit WEA-2, with the underlying details being presented on Exhibit

WEA-3. For each firm, the expected retention ratio (b) was calculated based on Value

Line’s projected dividends and earnings per share. Likewise, each firm’s expected earned

rate of return (r) was computed by dividing projected earnings per share by projected net

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book value. Because Value Line reports end-of-year book values, an adjustment was

incorporated to compute an average rate of return over the year, consistent with the

theory underlying this approach to estimating investors’ growth expectations.

Meanwhile, the percent of common equity expected to be issued annually as new

common stock (s) was equal to the product of the projected market-to-book ratio and

growth in common shares outstanding, while the equity accretion rate (v) was computed

as 1 minus the inverse of the projected market-to-book ratio.

Q. WHAT COST OF EQUITY ESTIMATES WERE IMPLIED FOR THE UTILITY

PROXY GROUP USING THE DCF MODEL?

A. After combining the dividend yields and respective growth projections for each utility,

the resulting cost of equity estimates are shown on page 3 of Exhibit WEA-2.

Q. IN EVALUATING THE RESULTS OF THE CONSTANT GROWTH DCF

MODEL, IS IT APPROPRIATE TO ELIMINATE ESTIMATES THAT ARE

EXTREME LOW OR HIGH OUTLIERS?

A. Yes. In applying quantitative methods to estimate the cost of equity, it is essential that the

resulting values pass fundamental tests of reasonableness and economic logic.

Accordingly, DCF estimates that are implausibly low or high should be eliminated when

evaluating the results of this method.

Q. HOW DID YOU EVALUATE DCF ESTIMATES AT THE LOW END OF THE

RANGE?

A. It is a basic economic principle that investors can be induced to hold more risky assets

only if they expect to earn a return to compensate them for their risk bearing. As a result,

the rate of return that investors require from a utility’s common stock, the most junior and

riskiest of its securities, must be considerably higher than the yield offered by senior,

long-term debt. Consistent with this principle, the DCF results must be adjusted to

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eliminate estimates that are determined to be extreme low outliers when compared

against the yields available to investors from less risky utility bonds.

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Q. WHAT DOES THIS TEST OF LOGIC IMPLY WITH RESPECT TO THE DCF

RESULTS FOR THE UTILITY PROXY GROUP?

A. As noted earlier, the average S&P corporate credit rating for the Utility proxy Group is

“BBB”. Companies rated “BBB-”, “BBB”, and “BBB+” are all considered part of the

triple-B rating category, with Moody’s monthly yields on triple-B bonds averaging

approximately 5.2 percent in September 2011.22 It is inconceivable that investors are not

requiring a substantially higher rate of return for holding common stock. Consistent with

this principle, the DCF results for the Utility Proxy Group must be adjusted to eliminate

estimates that are determined to be extreme low outliers when compared against the

yields available to investors from less risky utility bonds.

Q. HAVE SIMILAR TESTS BEEN APPLIED BY REGULATORS?

A. Yes. FERC has noted that adjustments are justified where applications of the DCF

approach produce illogical results. FERC evaluates DCF results against observable

yields on long-term public utility debt and has recognized that it is appropriate to

eliminate estimates that do not sufficiently exceed this threshold. In a 2002 opinion

establishing its current precedent for determining ROEs for electric utilities, for example,

FERC noted:

An adjustment to this data is appropriate in the case of PG&E’s low-end return of 8.42 percent, which is comparable to the average Moody’s “A” grade public utility bond yield of 8.06 percent, for October 1999. Because investors cannot be expected to purchase stock if debt, which has less risk than stock, yields essentially the same return, this low-end return cannot be considered reliable in this case.23

22 Moody’s Investors Service, www.credittrends.com. 23 Southern California Edison Company, 92 FERC ¶ 61,070 at p. 22 (2000).

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Similarly, in its August 2006 decision in Kern River Gas Transmission Company, FERC

noted that:

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[T]he 7.31 and 7.32 percent costs of equity for El Paso and Williams found by the ALJ are only 110 and 122 basis points above that average yield for public utility debt. 24

The Commission upheld the opinion of Staff and the Administrative Law Judge that cost

of equity estimates for these two proxy group companies “were too low to be credible.” 25

The practice of eliminating low-end outliers has been affirmed in numerous

FERC proceedings,26 and in its April 15, 2010 decision in SoCal Edison, FERC affirmed

that, “it is reasonable to exclude any company whose low-end ROE fails to exceed the

average bond yield by about 100 basis points or more.”27

Q. WHAT ELSE SHOULD BE CONSIDERED IN EVALUATING DCF ESTIMATES

AT THE LOW END OF THE RANGE?

A. As indicated earlier, while corporate bond yields have declined substantially as the worst

of the financial crisis has abated, it is generally expected that long-term interest rates will

rise as the recession ends and the economy returns to a more normal pattern of growth.

As shown in Table WEA-3 below, forecasts of IHS Global Insight and the EIA imply an

average triple-B bond yield of approximately 7.2 over the period 2012-2015:

24 Kern River Gas Transmission Company, Opinion No. 486, 117 FERC ¶ 61,077 at P 140 & n. 227 (2006). 25 Id. 26 See, e.g., Virginia Electric Power Co., 123 FERC ¶ 61,098 at P 64 (2008). 27 Southern California Edison Co., 131 FERC ¶ 61,020 at P 55 (2010) (“SoCal Edison”).

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TABLE WEA-3 IMPLIED UTILITY BOND YIELDS

2012-15Projected AA Utility Yield

IHS Global Insight (a) 6.33%EIA (b) 6.57%

Average 6.45%

Current BBB - AA Yield Spread (c) 0.77%

Implied Triple-B Utility Yield 7.22%

(a)(b)

(c)

Energy Information Administration, Annual Energy Outlook 2011 (Apr. 26, 2011).Based on monthly average bond yields for the six-month period May - October 2011.

IHS Global Insight, U.S. Economic Outlook at 19 (Feb. 2011).

The increase in debt yields anticipated by IHS Global Insight and EIA is also supported

by the widely-referenced Blue Chip Financial Forecasts, which projects that yields on

corporate bonds will climb more than 100 basis points through the period 2013-2017.

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Q. WHAT DOES THIS TEST OF LOGIC IMPLY WITH RESPECT TO THE DCF

ESTIMATES BASED ON PROJECTED GROWTH IN DPS?

A. As highlighted on page 3 of Exhibit WEA-3, eleven of the individual DCF estimates

based on Value Line’s projected DPS growth rates ranged from 1.9 percent to 6.9 percent.

Four of these values were equal to or below current utility bond yields, with cost of

equity estimates below 7.2 percent being less than the yield on triple-B utility bonds

expected during the period 2012-2015. In light of the risk-return tradeoff principle and

the test applied in SoCal Edison, it is inconceivable that investors are not requiring a

substantially higher rate of return for holding common stock, which is the riskiest of a

utility’s securities. As a result, consistent with the test of economic logic applied by

FERC and the upward trend expected for utility bond yields, these values provide little

28 Blue Chip Financial Forecasts, Vol. 30, No. 6 (Jun. 1, 2011), Vol. 30, No. 11 (Nov. 1, 2011).

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guidance as to the returns investors require from utility common stocks and should be

excluded.

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Q. DO YOU ALSO RECOMMEND EXCLUDING ESTIMATES AT THE HIGH END

OF THE RANGE OF DCF RESULTS?

A. Yes. The upper end of the cost of common equity range produced by the DPS growth

rates was set by a cost of equity estimate of 18.1 percent. When compared with the

balance of the remaining estimates, this value is clearly implausible and should be

excluded in evaluating the results of the DCF model for the Utility Proxy Group. This is

also consistent with the precedent adopted by FERC, which has established that estimates

found to be “extreme outliers” should be disregarded in interpreting the results of the

DCF model.29

Q. DID YOU APPLY SIMILAR TESTS OF ECONOMIC LOGIC TO THE DCF

ESTIMATES BASED ON EPS AND BR+SV GROWTH PROJECTIONS?

A. Yes. I applied the same approach to evaluate low and high-end DCF cost of equity

estimates produced using projected EPS and br+sv growth rates, with illogical estimates

being highlighted on page 3 of Exhibit WEA-2.

Q. WHAT COST OF COMMON EQUITY ESTIMATES ARE IMPLIED BY YOUR

DCF RESULTS FOR THE UTILITY PROXY GROUP?

A. As shown on page 3 of Exhibit WEA-2 and summarized in Table WEA-4, below, after

eliminating illogical low-end values, application of the constant growth DCF model

resulted in cost of common equity estimates ranging from 9.1 percent to 10.3 percent:

29 See, e.g., ISO New England, Inc., 109 FERC ¶ 61,147 at P 205 (2004).

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TABLE WEA-4 DCF RESULTS –UTILITY PROXY GROUP

Growth Rate Average Cost of EquityDPS 9.8%EPS Value Line 10.3% IBES 10.3% Zacks 9.6%br+sv 9.1%

Q. WHAT WERE THE RESULTS OF YOUR DCF ANALYSIS FOR THE NON-

UTILITY PROXY GROUP?

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A. I applied the DCF model to the Non-Utility Proxy Group in exactly the same manner

described earlier for the proxy group of utilities. The results of my DCF analysis for the

Non-Utility Proxy Group are presented in Exhibit WEA-4, with the sustainable, “br+sv”

growth rates being developed on Exhibit WEA-5. As shown on Exhibit WEA-4 and

summarized in Table WEA-5, below, after eliminating illogical low- and high-end values,

application of the constant growth DCF model resulted in cost of common equity

estimates ranging from 10.4 percent to 12.5 percent:

TABLE WEA-5 DCF RESULTS – NON-UTILITY PROXY GROUP

Growth Rate Average Cost of EquityDPS 10.4%EPS Value Line 11.5% IBES 12.1% Zacks 11.9%br+sv 12.5%

Q. DO THE HIGHER DCF ESTIMATES FOR THE NON-UTILITY PROXY GROUP

DEMONSTRATE THAT THE RISKS OF THESE COMPANIES ARE GREATER

THAN CHEYENNE LIGHT?

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A. No. While we are accustomed to associating higher risk with higher returns, DCF

estimates of investors’ required rate of return do not always produce that result.

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Performing the DCF calculations for the Non-Utility Proxy Group produced ROE

estimates that are higher than the DCF estimates for the Utility Proxy Group, even though

the risks that investors associate with the group of non-utility firms - as measured by

S&P’s credit ratings and Value Line’s Safety Rank, Financial Strength, and Beta – are

lower than the risks investors associate with the Utility Proxy Group. The actual cost of

equity is unobservable, and DCF estimates may depart from these values because

investors’ expectations may not be captured by the inputs to the ROE model, particularly

the assumed growth rate. Nevertheless, regulators have relied upon DCF calculations for

years in evaluating a fair ROE. The divergence between the DCF estimates for the

Utility and Non-Utility Proxy Groups suggests that both should be considered to ensure a

balanced end-result.

D. Capital Asset Pricing Model

Q. PLEASE DESCRIBE THE CAPM. 12

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A. The CAPM is generally considered to be the most widely referenced method for

estimating the cost of equity both among academicians and professional practitioners,

with the pioneering researchers of this method receiving the Nobel Prize in 1990. The

CAPM is a theory of market equilibrium that measures risk using the beta coefficient.

Assuming investors are fully diversified, the relevant risk of an individual asset (e.g.,

common stock) is its volatility relative to the market as a whole, with beta reflecting the

tendency of a stock’s price to follow changes in the market. The CAPM is

mathematically expressed as

Rj = Rf +βj(Rm - Rf)

where: Rj = required rate of return for stock j; Rf = risk-free rate; Rm = expected return on the market portfolio; and, βj = beta, or systematic risk, for stock j.

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Like the DCF model, the CAPM is an ex-ante, or forward-looking model based on

expectations of the future. As a result, in order to produce a meaningful estimate of

investors’ required rate of return, the CAPM must be applied using estimates that reflect

the expectations of actual investors in the market, not with backward-looking, historical

data.

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Q. HOW DID YOU APPLY THE CAPM TO ESTIMATE THE COST OF EQUITY?

A. Application of the CAPM to the Utility Proxy Group based on a forward-looking

estimate for investors’ required rate of return from common stocks is presented on

Exhibit WEA-6. In order to capture the expectations of today’s investors in current

capital markets, the expected market rate of return was estimated by conducting a DCF

analysis on the dividend paying firms in the S&P 500 Composite Index.

The dividend yield for each firm was calculated based on the annual indicated

dividend payment obtained from Value Line, increased by one-years’ growth using the

rate discussed subsequently (1 + g) to convert them to year-ahead dividend yields

presumed by the constant growth DCF model. The growth rate was equal to the

consensus earnings growth projections for each firm published by IBES, with each firm’s

dividend yield and growth rate being weighted by its proportionate share of total market

value. Based on the weighted average of the projections for the 370 individual firms,

current estimates imply an average growth rate over the next five years of 11.0 percent.

Combining this average growth rate with a year-ahead dividend yield of 2.5 percent

results in a current cost of common equity estimate for the market as a whole (Rm) of

approximately 13.5 percent. Subtracting a 3.1 percent risk-free rate based on the average

yield on 30-year Treasury bonds produced a market equity risk premium of 10.4 percent.

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Q. WHAT WAS THE SOURCE OF THE BETA VALUES YOU USED TO APPLY THE

CAPM?

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A. I relied on the beta values reported by Value Line, which in my experience is the most

widely referenced source for beta in regulatory proceedings. As noted in New Regulatory

Finance:

Value Line is the largest and most widely circulated independent investment advisory service, and influences the expectations of a large number of institutional and individual investors. … Value Line betas are computed on a theoretically sound basis using a broadly based market index, and they are adjusted for the regression tendency of betas to converge to 1.00.30

Q. WHAT ELSE SHOULD BE CONSIDERED IN APPLYING THE CAPM?

A. As explained by Morningstar:

One of the most remarkable discoveries of modern finance is that of a relationship between firm size and return. The relationship cuts across the entire size spectrum but is most evident among smaller companies, which have higher returns on average than larger ones.31

Because empirical research indicates that the CAPM does not fully account for observed

differences in rates of return attributable to firm size, a modification is required to

account for this size effect.

According to the CAPM, the expected return on a security should consist of the

riskless rate, plus a premium to compensate for the systematic risk of the particular

security. The degree of systematic risk is represented by the beta coefficient. The need

for the size adjustment arises because differences in investors’ required rates of return

that are related to firm size are not fully captured by beta. To account for this,

Morningstar has developed size premiums that need to be added to the theoretical CAPM

30 Morin, Roger A., “New Regulatory Finance,” Public Utilities Reports at 71 (2006). 31 Morningstar, “Ibbotson SBBI 2010 Valuation Yearbook,” at p. 85 (footnote omitted).

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cost of equity estimates to account for the level of a firm’s market capitalization in

determining the CAPM cost of equity.

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an adjustment to recognize the impact of size distinctions, as measured by market

capitalization.

Q. WHAT COST OF EQUITY IS INDICATED BASED ON THIS FORWARD-

LOOKING APPLICATION OF THE CAPM?

A. The average market capitalization of the Utility Proxy Group is $8.2 billion. Based on

data from Morningstar, this means that the theoretical CAPM cost of equity estimate

must be increased by 81 basis points to account for the industry group’s relative size. As

shown on page 1 of Exhibit WEA-6, adjusting the 10.9 percent theoretical CAPM result

to incorporate this size adjustment results in an indicated cost of common equity of 11.7

percent.

Q. IS IT APPROPRIATE TO CONSIDER ANTICIPATED CAPITAL MARKET

CHANGES IN APPLYING THE CAPM?

A. Yes. As discussed earlier, there is widespread consensus that interest rates will increase

materially as the economy continues to strengthen. As a result, current bond yields are

likely to understate capital market requirements at the time the outcome of this

proceeding becomes effective. Accordingly, in addition to the use of current bond yields,

I also applied the CAPM based on the forecasted long-term Treasury bond yields

developed based on projections published by Value Line, IHS Global Insight and Blue

Chip.

32 Id. at Table C-1.

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Q. WHAT COST OF EQUITY WAS PRODUCED BY THE CAPM AFTER

INCORPORATING FORECASTED BOND YIELDS?

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A. As shown on page 2 of Exhibit WEA-6, incorporating a forecasted Treasury bond yield

for 2012-2015 implied a cost of equity of approximately 11.4 percent for the Utility

Proxy Group, or 12.2 percent after adjusting for the impact of relative size.

Q. SHOULD THE CAPM APPROACH BE APPLIED USING HISTORICAL RATES

OF RETURN?

A. No. The CAPM cost of common equity estimate is calibrated from investors’ required

risk premium between Treasury bonds and common stocks. In response to heightened

uncertainties, investors have repeatedly sought a safe haven in U.S. government bonds

and this “flight to safety” has pushed Treasury yields significantly lower while yield

spreads for corporate debt have widened. This distortion not only impacts the absolute

level of the CAPM cost of equity estimate, but it affects estimated risk premiums.

Economic logic would suggest that investors’ required risk premium for common stocks

over Treasury bonds has also increased.

Meanwhile, backward-looking approaches incorrectly assume that investors’

assessment of the required risk premium between Treasury bonds and common stocks is

constant, and equal to some historical average. At no time in recent history has the

fallacy of this assumption been demonstrated more concretely than it is today. This

incongruity between investors’ current expectations and historical risk premiums is

particularly relevant during periods of heightened uncertainty and rapidly changing

capital market conditions, such as those experienced recently.33

33 FERC has previously rejected CAPM methodologies based on historical data because whatever historical relationships existed between debt and equity securities may no longer hold. See Orange & Rockland Utils., Inc., 40 F.E.R.C. P63,053, at pp. 65,208 -09 (1987), aff'd, Opinion No. 314, 44 F.E.R.C. P61,253 at 65,208.

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Q. HAS THE FEDERAL RESERVE CONTINUED TO PURSUE A POLICY OF

ACTIVELY MANAGING LONG-TERM GOVERNMENT BOND YIELDS?

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A. Yes. In September 2011, the Federal Reserve announced “Operation Twist”, involving

the exchange of short-term Treasury instruments for longer-term government bonds, in an

effort to put downward pressure on long-term interest rates. The ongoing potential for

renewed turmoil in the capital markets has certainly come to a head in recent months,

with common stock prices exhibiting the dramatic volatility that is indicative of

heightened sensitivity to risk. Nowhere has this been more evident than in the market for

Treasury bonds, with yields being pushed significantly lower due to a global “flight to

safety” in the face of rising political, economic, and capital market risks. In turn, this has

led to a dramatic increase in risk premiums, as illustrated by the spreads between triple-B

utility bond yields and 30-year Treasuries shown in Figure WEA-1, below:

FIGURE WEA-1 YIELD SPREAD (BASIS POINTS) BBB UTILITY – 30-YR. TREASURY

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This increase in the yield spread indicates that the additional compensation investors

demand to take on higher risks has increased. As S&P observed:

Standard & Poor’s U.S. speculative-grade composite spread, which measures the extra yield above U.S. Treasury bonds that investors demand to hold the bonds of riskier companies, widened by 63% to 781 basis points (bps) from April 18, 2011, to Sept. 30, 2011. This sharp expansion reflected the bond market’s increasing aversion to credit risk in an

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uncertain and riskier environment. … During periods of stress, correlations frequently increase among risky asset classes such as the relationship between the return on speculative-grade bonds and the return from equities.

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Equity risk premiums cannot be observed directly, but because common stock investors

are the last in line with respect to their claim on a utility’s cash flows, higher yield

spreads imply an even steeper increase in the additional return required from an

investment in common equity. In short, heightened capital market and economic

uncertainties, and the increase in risk premiums demanded by investors, further

undermine any reliance on historical studies to apply the CAPM.

E. Risk Premium Approach

Q. BRIEFLY DESCRIBE THE RISK PREMIUM METHOD. 11

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A. The risk premium method of estimating investors’ required rate of return extends to

common stocks the risk-return tradeoff observed with bonds. The cost of equity is

estimated by first determining the additional return investors require to forgo the relative

safety of bonds and to bear the greater risks associated with common stock, and by then

adding this equity risk premium to the current yield on bonds. Like the DCF model, the

risk premium method is capital market oriented. However, unlike DCF models, which

indirectly impute the cost of equity, risk premium methods directly estimate investors’

required rate of return by adding an equity risk premium to observable bond yields.

Q. HOW DID YOU IMPLEMENT THE RISK PREMIUM METHOD?

A. I based my estimates of equity risk premiums on surveys of previously authorized rates of

return on common equity. Authorized returns presumably reflect regulatory

commissions’ best estimates of the cost of equity, however determined, at the time they

34 Standard & Poor’s Corporation, “Recent Expansion In Credit Spreads Shows Bond Market Stress, But Less Severe Than During The Financial Crisis,” RatingsDirect (Oct. 11, 2011).

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issued their final order. Such returns should represent a balanced and impartial outcome

that considers the need to maintain a utility’s financial integrity and ability to attract

capital. Moreover, allowed returns are an important consideration for investors and have

the potential to influence other observable investment parameters, including credit ratings

and borrowing costs. Thus, this data provides a logical and frequently referenced basis

for estimating equity risk premiums for regulated utilities.

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The rates of return on common equity authorized utilities by regulatory

commissions across the U.S. are compiled by Regulatory Research Associates and

published in its Regulatory Focus report. In Exhibit WEA-7, the average yield on public

utility bonds is subtracted from the average allowed rate of return on common equity for

electric utilities to calculate equity risk premiums for each year between 1974 and 2010.

Over this 37-year period, these equity risk premiums averaged 3.36 percent, and the yield

on public utility bonds averaged 9.01 percent.

Q. IS THERE ANY CAPITAL MARKET RELATIONSHIPS THAT MUST BE

CONSIDERED WHEN IMPLEMENTING THE RISK PREMIUM METHOD?

A. Yes. There is considerable evidence that the magnitude of equity risk premiums is not

constant and that equity risk premiums tend to move inversely with interest rates. In

other words, when interest rate levels are relatively high, equity risk premiums narrow,

and when interest rates are relatively low, equity risk premiums widen. The implication

of this inverse relationship is that the cost of equity does not move as much as, or in

lockstep with, interest rates. Accordingly, for a 1 percent increase or decrease in interest

rates, the cost of equity may only rise or fall, say, 50 basis points. Therefore, when

implementing the risk premium method, adjustments may be required to incorporate this

inverse relationship if current interest rate levels have changed since the equity risk

premiums were estimated.

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Finally, it is important to recognize that the historical focus of the risk premium

studies almost certainly ensures that they fail to fully capture the significantly greater

risks that investors now associate with providing electric and gas utility service. As a

result, they are likely to understate the cost of equity for a firm operating in today's utility

industry.

Q. WHAT COST OF EQUITY IS IMPLIED BY SURVEYS OF ALLOWED RATES

OF RETURN ON EQUITY?

A. Based on the regression output between the interest rates and equity risk premiums

displayed on page 4 of Exhibit WEA-7, the equity risk premium increased approximately

41 basis points for each percentage point drop in the yield on average public utility

bonds. As illustrated on page 1 of Exhibit WEA-7, with the yield on average public

utility bonds in October 2011 being 4.66 percent, this implied a current equity risk

premium of 5.14 percent. Adding this equity risk premium to the yield on triple-B utility

bonds of 5.24 percent produces a current cost of equity of approximately 10.4 percent.

Q. WHAT COST OF EQUITY WAS PRODUCED BY THE RISK PREMIUM

APPROACH AFTER INCORPORATING FORECASTED BOND YIELDS?

A. As shown on page 2 of Exhibit WEA-7, incorporating a forecasted yield for 2012-2015

and adjusting for changes in interest rates since the study period implied an equity risk

premium of 4.27 percent. Adding this equity risk premium to the average implied yield

on triple-B public utility bonds for 2012-2015 of 7.22 percent resulted in an implied cost

of equity of approximately 11.5 percent.

F. Expected Earnings Approach

Q. WHAT OTHER BENCHMARKS DID YOU EXAMINE TO EVALUATE THE

ROE FOR CHEYENNE LIGHT?

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A. As I noted earlier, I also evaluated the ROE by reference to expected rates of return for

utilities. Reference to rates of return available from alternative investments of

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comparable risk can provide an important benchmark in assessing the return necessary to

assure confidence in the financial integrity of a firm and its ability to attract capital. This

approach is consistent with the economic underpinnings for a fair rate of return, as

reflected in the comparable earnings test established by the Supreme Court in Hope and

Bluefield. Moreover, it avoids the complexities and limitations of capital market methods

and instead focuses on the returns earned on book equity, which are readily available to

investors.

Q. WHAT ECONOMIC PREMISE UNDERLIES THE EXPECTED EARNINGS

APPROACH?

A. The simple, but powerful concept underlying the expected earnings approach is that

investors compare each investment alternative with the next best opportunity. If the

utility is unable to offer a return similar to that available from other opportunities of

comparable risk, investors will become unwilling to supply the capital on reasonable

terms. For existing investors, denying the utility an opportunity to earn what is available

from other similar risk alternatives prevents them from earning their opportunity cost of

capital. In this situation the government is effectively taking the value of investors’

capital without adequate compensation.

Q. HOW IS THE COMPARISON OF OPPORTUNITY COSTS TYPICALLY

IMPLEMENTED?

A. The traditional comparable earnings test identifies a group of companies that are believed

to be comparable in risk to the utility. The actual earnings of those companies on the

book value of their investment are then compared to the allowed return of the utility.

While the traditional comparable earnings test is implemented using historical data taken

from the accounting records, it is also common to use projections of returns on book

investment, such as those published by recognized investment advisory publications (e.g.,

Value Line). Because these expected returns on book value equity are analogous to the

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allowed return on a utility’s rate base, this measure of opportunity costs results in a direct,

“apples to apples” comparison. My application of the expected earnings approach was

focused exclusively on forward-looking projections, not historical data.

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Moreover, regulators do not set the returns that investors earn in the capital

markets – they can only establish the allowed return on the value of a utility’s investment,

as reflected on its accounting records. As a result, the expected earnings approach

provides a direct guide to ensure that the allowed ROE is similar to what other utilities of

comparable risk will earn on invested capital. This opportunity cost test does not require

theoretical models to indirectly infer investors’ perceptions from stock prices or other

market data. As long as the proxy companies are similar in risk, their expected earned

returns on invested capital provide a direct benchmark for investors’ opportunity costs

that is independent of fluctuating stock prices, market-to-book ratios, debates over DCF

growth rates, or the limitations inherent in any theoretical model of investor behavior.

Q. WHAT RATES OF RETURN ON EQUITY ARE INDICATED FOR UTILITIES

BASED ON THE EXPECTED EARNINGS APPROACH?

A. Value Line reports that its analysts anticipate an average rate of return on common equity

of 10.5 percent for electric and gas utilities over its forecast horizon.35 Meanwhile, for

the firms in the Utility Proxy Group specifically, the returns on common equity projected

by Value Line over its forecast horizon are shown on Exhibit WEA-8. Consistent with

the rationale underlying the development of the br+sv growth rates, these year-end values

were converted to average returns using the same adjustment factor discussed earlier and

developed on Exhibit WEA-3. As shown on Exhibit WEA-8, Value Line’s projections for

the Utility Proxy Group suggest an average ROE of 10.7 percent.

35 The Value Line Investment Survey at 541 (Sep. 9, 2011) and 901 (Sep. 25, 2011).

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G. Flotation Costs

Q. WHAT OTHER CONSIDERATIONS ARE RELEVANT IN DETERMINING THE

ROE FOR CHEYENNE LIGHT?

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A. The common equity used to finance the investment in utility assets is provided from

either the sale of stock in the capital markets or from retained earnings not paid out as

dividends. When equity is raised through the sale of common stock, there are costs

associated with “floating” the new equity securities. These flotation costs include

services such as legal, accounting, and printing, as well as the fees and discounts paid to

compensate brokers for selling the stock to the public. Also, some argue that the “market

pressure” from the additional supply of common stock and other market factors may

further reduce the amount of funds that a utility nets when it issues common equity.

Q. IS THERE AN ESTABLISHED MECHANISM FOR A UTILITY TO RECOGNIZE

EQUITY ISSUANCE COSTS?

A. No. While debt flotation costs are recorded on the books of the utility, amortized over the

life of the issue, and thus increase the effective cost of debt capital, there is no similar

accounting treatment to ensure that equity flotation costs are recorded and ultimately

recognized. Alternatively, no rate of return is authorized on flotation costs necessarily

incurred to obtain a portion of the equity capital used to finance plant. In other words,

equity flotation costs are not included in a utility’s rate base because neither that portion of

the gross proceeds from the sale of common stock used to pay flotation costs is available to

invest in plant and equipment, nor are flotation costs capitalized as an intangible asset.

Unless some provision is made to recognize these issuance costs, a utility’s revenue

requirements will not fully reflect all of the costs incurred for the use of investors’ funds.

Because there is no accounting convention to accumulate the flotation costs associated with

equity issues, they must be accounted for indirectly, with an upward adjustment to the

cost of common equity being the most logical mechanism.

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Q. WHAT IS THE MAGNITUDE OF THE ADJUSTMENT TO THE “BARE BONES”

COST OF COMMON EQUITY TO ACCOUNT FOR ISSUANCE COSTS?

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A. While there are a number of ways in which a flotation cost adjustment can be calculated,

one of the most common methods used to account for flotation costs in regulatory

proceedings is to apply an average flotation-cost percentage to a utility’s dividend yield.

Based on a review of the finance literature, New Regulatory Finance concluded:

The flotation cost allowance requires an estimated adjustment to the return on equity of approximately 5% to 10%, depending on the size and risk of the issue.36

Alternatively, a study of data from Morgan Stanley regarding issuance costs associated

with utility common stock issuances suggests an average flotation cost percentage of 3.6

percent.37

Issuance costs are a legitimate consideration in setting the ROE for a utility, and

applying these expense percentages to a representative dividend yield for a utility of 4.5

percent implies a flotation cost adjustment on the order of 16 to 45 basis points.

IV. RETURN ON EQUITY FOR CHEYENNE LIGHT 16

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A. This section also discusses the relationship between ROE and preservation of a utility’s

financial integrity and the ability to attract capital. In addition, I examine other factors

properly considered in determining a fair rate of return, including Cheyenne Light’s

specific exposures and the reasonableness of the Company’s requested capital structure.

Finally, this section presents my conclusions regarding a fair ROE range and my

recommended ROE for Cheyenne Light.

36 Roger A. Morin, “New Regulatory Finance,” Public Utilities Reports, Inc. at 323 (2006). 37 Application of Yankee Gas Services Company for a Rate Increase, DPUC Docket No. 04-06-01, Direct Testimony of George J. Eckenroth (Jul. 2, 2004) at Exhibit GJE-11.1. Updating the results presented by Mr. Eckenroth through April 2005 also resulted in an average flotation cost percentage of 3.6%.

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A. Implications for Financial Integrity

Q. WHY IS IT IMPORTANT TO ALLOW CHEYENNE LIGHT AN ADEQUATE

ROE?

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A. Given the social and economic importance of the utility industry, it is essential to

maintain reliable and economical service to all consumers. While it is customers that

ultimately realize the benefits of reliable utility service, a utility’s ability to fulfill its

mandate can be compromised if it lacks the necessary financial wherewithal or is unable

to earn a return sufficient to attract sufficient capital.

As documented earlier, the major rating agencies have warned of exposure to

uncertainties associated with political and regulatory developments, especially in view of

current financial and operating pressures in the utility industry. Investors understand just

how swiftly unforeseen circumstances can lead to deterioration in a utility’s financial

condition, and stakeholders have discovered first hand how difficult and complex it can

be to remedy the situation after the fact. Investors’ increased reticence to supply

additional capital during times of crisis highlights the need to preserve financial

flexibility and the importance of allowing an adequate ROE.

Q. WHAT ROLE DOES REGULATION PLAY IN ENSURING ACCESS TO

CAPITAL FOR CHEYENNE LIGHT?

A. Considering investors’ heightened awareness of the risks associated with the utility

industry and the damage that results when a utility’s financial flexibility is compromised,

supportive regulation remains crucial to the Company’s access to capital. Investors

recognize that regulation has its own risks, and that constructive regulation is a key

ingredient in supporting utility credit ratings and financial integrity, particularly during

times of adverse conditions. Fitch concluded, “[G]iven the lingering rate of

unemployment and voter concerns about the economy, there could well be pockets of

adverse rate decisions, and those companies with little financial cushion could suffer

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adverse effects.”38 Moody’s has also emphasized the need for regulatory support,

concluding:

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For the longer term, however, we are becoming increasingly concerned about possible changes to our fundamental assumptions about regulatory risk, particularly the prospect of a more adversarial political (and therefore regulatory) environment. A prolonged recessionary climate with high unemployment, or an intense period of inflation, could make cost recovery more uncertain.39

S&P noted, “the quality of regulation is at the forefront of our analysis of utility

creditworthiness.”40

Q. DO CUSTOMERS BENEFIT BY ENHANCING THE UTILITY’S FINANCIAL

FLEXIBILITY?

A. Yes. Providing an ROE that is sufficient to maintain Cheyenne Light’s ability to attract

capital, even under duress, is consistent with the economic requirements embodied in the

Supreme Court’s Hope and Bluefield decisions, but it is also in customers’ best interests.

Ultimately, it is customers and the service area economy that enjoy the benefits that come

from ensuring that the utility has the financial wherewithal to take whatever actions are

required to ensure a reliable energy supply. By the same token, customers also bear a

significant burden when the ability of the utility to attract capital is impaired and service

quality is compromised.

38 Fitch Ratings Ltd., “U.S. Utilities, Power and Gas 2010 Outlook,” Global Power North America Special Report (Dec. 4, 2009). 39 Moody’s Investors Service, “U.S. Regulated Electric Utilities, Six-Month Update,” Industry Outlook (July 2009). 40 Standard & Poor’s Corporation, “Assessing U.S. Utility Regulatory Environments,” RatingsDirect (Nov. 7, 2008).

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B. Other Exposures

Q. WHAT IS THE IMPLICATION OF BLACK HILLS CORP.’S RELATIVE

CREDIT STANDING?

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A. In a recent report by S&P ranking U.S. regulated utilities from strongest to weakest,

Black Hills Corp. was ranked 179 out of the total 184 companies with investment grade

credit ratings.41 In other words, according to S&P only 5 companies in the utility

industry with investment grade ratings have a credit profile weaker than Black Hills

Corp. During the financial crisis Fitch observed that, “‘flight to quality’ is selective

within the [utility] sector, favoring companies at higher rating levels.”42 Because of the

weaker overall credit standing associated with Cheyenne Light, there is little backstop in

the event of a crisis and reduced flexibility to respond to other challenges, such as

increased capital outlays or renewed energy market volatility.

Strengthening financial integrity is imperative to ensure the capability to maintain

existing ratings while confronting potential challenges. As the Chairman of the New

York State Public Service Commission noted in his role as spokesman for the National

Association of Regulatory Utility Commissioners:

While there is a large difference between A and BBB, there is an even brighter line between Investment Grade (BBB-/Baa3 bond ratings by S&P/Moody’s, and higher) and non-Investment Grade (Junk) (BB+/Ba1 and lower). The cost of issuing non-investment grade debt, assuming the market is receptive to it, has in some cases been hundreds of basis points over the yield on investment grade securities. To me this suggests that you do not want to be rated at the lower end of the BBB range because an unexpected shock could move you outside the investment grade range.43

41 Standard & Poor’s Corporation, “Issuer Ranking: U.S. Regulated Electric Utilities, Strongest To Weakest,” RatingsDirect (Jul. 5, 2011). 42 Fitch Ratings Ltd., “U.S. Utilities, Power and Gas 2009 Outlook,” Global Power North America Special Report (Dec. 22, 2008). 43 Brown, George, “Credit and Capital Issues Affecting the Electric Power Industry,” Federal Energy Regulatory Commission Technical Conference (Jan. 13, 2009).

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As a result, the stakes associated with an inadequate rate of return are increased

dramatically for Cheyenne Light.

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Q. WOULD INVESTORS CONSIDER CHEYENNE LIGHT’S RELATIVE SIZE IN

THEIR ASSESSMENT OF THE COMPANY’S RISKS AND PROSPECTS?

A. Yes. A firm’s relative size has important implications for investors in their evaluation of

alternative investments, and it is well established that smaller firms are more risky than

larger firms. With a market capitalization of approximately $1.3 billion, Black Hills

Corp. is significantly smaller than the publicly traded firms in the Utility Proxy Group

used subsequently to estimate the cost of equity, which have an average capitalization of

approximately $8.1 billion. Cheyenne Light, in turn, is considerably smaller than its

parent.

The magnitude of the size disparity between Cheyenne Light and other firms in

the utility industry has important practical implications with respect to the risks faced by

investors. All else being equal, it is well accepted that smaller firms are more risky than

their larger counterparts, due in part to their relative lack of diversification and lower

financial resiliency. This size relationship is well established and widely documented in

the financial literature.44 In the case of a smaller utility, its earnings are principally

dependent on the economic, social, regulatory, and other factors affecting a more limited

constituency. This can result in significant exposure, especially where key employers or

industries dominate the economy.

Additionally, due to the lower density and other characteristics of its service

territory, a smaller utility serving more sparsely populated rural areas generally incurs

44 See, e.g., Eugene F. Fama and Kenneth R. French, “The Cross-Section of Expected Stock Returns”, The Journal of Finance (June 1992); George E. Pinches, J. Clay Singleton, and Ali Jahankhani, “Fixed Coverage as a Determinant of Electric Utility Bond Ratings”, Financial Management (Summer 1978).

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higher investment and expenses per customer than is typical for other utility providers.

Meanwhile, larger utilities generally enjoy improved exposure to financial markets,

which enhances their ability to raise additional capital relative to smaller utilities. As a

result, they are better prepared to withstand adverse events and possess greater financial

flexibility to respond or adapt to changing market conditions, such as those that currently

confront the utility industry. Common sense and accepted financial doctrine hold that

investors require higher returns from smaller companies, and unless that compensation is

provided in the rate of return allowed for a utility, the tests embodied in the Bluefield and

Hope cases cannot be met.

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Q. WHAT IS THE MAGNITUDE OF THE ADJUSTMENT REQUIRED TO

ACCOUNT FOR THIS SIZE PREMIUM?

A. As discussed earlier, extensive analyses of firm size and returns are available from

Morningstar.. For the 1926 to 2011 period, Morningstar reported a size premium in

excess of the return implied by the CAPM of 182 basis points for a company with a

market capitalization of $1.3 billion.45

Similarly, a study reported in Public Utilities Fortnightly noted that the betas of

small companies do not fully account for the higher realized rates of return associated

with small company stocks:

The smaller deciles show returns not fully explainable by the CAPM. The difference in risk premium (realized versus CAPM) grows larger as one moves from the largest companies in decile 1 to the smallest in decile 10. The difference is especially pronounced for deciles 9 and 10, which contain the smallest companies. 46

45 Morningstar, “Ibbotson SBBI 2011 Valuation Yearbook,” at Table 7-5 (2011). 46 Annin, Michael, “Equity and the Small-Stock Effect”, Public Utilities Fortnightly (Oct. 15, 1995), at 43.

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The study went on to conclude that a publicly traded utility with a market capitalization

of $1.0 billion would require a small company premium of approximately 130 basis

points above the rate of return for larger firms.

Q. WHAT DOES THIS EVIDENCE IMPLY WITH RESPECT TO THE COST OF

EQUITY FOR A RELATIVELY SMALL UTILITY, SUCH AS CHEYENNE

LIGHT?

A. Considering Black Hills Corp.’s equity market capitalization of approximately $1.3

billion, and the fact that Cheyenne Light is considerably smaller still, this data implies

that investors require a rate of return that exceeds the cost of equity estimates discussed

above.

Q. HAVE YOU MADE A SPECIFIC ADJUSTMENT TO YOUR ROE RESULTS TO

REFLECT THE IMPACT OF THE COMPANY’S SMALLER SIZE?

A. No. While the impact of a firm’s relative size is properly included in estimating

investors’ required rate of return, I have not made a specific adjustment to the results of

my analyses.47 Rather, I recommend that the Company’s smaller size be considered in

establishing a point estimate from within my recommended range.

C. Capital Structure

Q. IS AN EVALUATION OF THE CAPITAL STRUCTURE MAINTAINED BY A

UTILITY RELEVANT IN ASSESSING ITS ROE?

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A. Yes. Other things being equal, a higher debt ratio, or lower common equity ratio,

translates into increased financial risk for all investors. A greater amount of debt means

more investors have a senior claim on available cash flow, thereby reducing the certainty

that each will receive his contractual payments. This increases the risks to which lenders

47 As discussed earlier, my CAPM analysis incorporated an adjustment to reflect the average market capitalization of the Utility Proxy Group, but this does not fully consider the impact of Cheyenne Light’s smaller size.

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are exposed, and they require correspondingly higher rates of interest. From common

shareholders’ standpoint, a higher debt ratio means that there are proportionately more

investors ahead of them, thereby increasing the uncertainty as to the amount of cash flow,

if any that will remain.

Q. WHAT COMMON EQUITY RATIO IS USED IN CHEYENNE LIGHT’S

CAPITAL STRUCTURE?

A. As summarized in the testimony of Mr. Brian Iverson, Cheyenne Light is proposing a

common equity ratio of 54 percent.

Q. HOW DOES THIS COMPARE WITH COMMON EQUITY RATIOS

MAINTAINED BY THE PROXY GROUP?

A. As shown on Exhibit WEA-9, common equity ratios for the individual firms in the Utility

Proxy Group ranged from a low of 25.3 percent to a high of 55.6 percent at year-end

2010, with the average being 46.2 percent. Meanwhile, Value Line’s three-to-five year

forecast indicates an average common equity ratio of 49.4 percent for the Utility Proxy

Group, with the individual equity ratios ranging from 31.5 percent to 58.5 percent.

Q. WHAT IMPLICATION DOES THE INCREASING RISK OF THE INDUSTRY

HAVE FOR THE CAPITAL STRUCTURES MAINTAINED BY UTILITIES?

A. As discussed earlier, utilities are facing rising cost structures, significant capital

investment plans, energy market volatility, uncertainties over accommodating future

environmental mandates, and ongoing regulatory risks. Coupled with the potential for

turmoil in capital markets, these considerations warrant a stronger balance sheet to deal

with an increasingly uncertain environment. A more conservative financial profile, in the

form of a higher common equity ratio, is consistent with increasing uncertainties and the

need to maintain the continuous access to capital that is required to fund operations and

necessary system investment, even during times of adverse capital market conditions.

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Moody’s has repeatedly warned investors of the risks associated with debt

leverage and fixed obligations and advised utilities not to squander the opportunity to

strengthen the balance sheet as a buffer against future uncertainties.

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concluded:

From a credit perspective, we believe a strong balance sheet coupled with abundant sources of liquidity represents one of the best defenses against business and operating risk and potential negative ratings actions.49

Similarly, S&P noted that, “we generally consider a debt to capital level of 50% or

greater to be aggressive or highly leveraged for utilities.”50 Fitch affirmed that it expects

regulated utilities to employ “a judicious mix of debt and equity to finance high levels of

planned investments.”51 More recently, Moody’s affirmed that it expects regulated

utilities to strengthen their balance sheets in order “to prepare for more challenging

business conditions.”52

Q. WHAT OTHER FACTORS DO INVESTORS CONSIDER IN THEIR

ASSESSMENT OF A COMPANY’S CAPITAL STRUCTURE?

A. Depending on their specific attributes, contractual agreements or other obligations that

require the utility to make specified payments may be treated as debt in evaluating the

Company’s financial risk. For example, power purchase agreements (“PPA”) typically

obligate the utility to make specified minimum contractual payments. As a result, when a

48 Moody’s Investors Service, “Storm Clouds Gathering on the Horizon for the North American Electric Utility Sector,” Special Comment (Aug. 2007); “U.S. Electric Utility Sector,” Industry Outlook (Jan. 2008). 49 Moody’s Investors Service, “U.S. Electric Utilities Face Challenges Beyond Near-Term,” Industry Outlook (Jan. 2010). 50 Standard & Poor’s Corporation, “Ratings Roundup: U.S. Electric Utility Sector Maintained Strong Credit Quality In A Gloomy 2009,” RatingsDirect (Jan. 26, 2010). 51 Fitch Ratings Ltd., “U.S. Utilities, Power, and Gas 2010 Outlook,” Global Power North America Special Report (Dec. 4, 2009). 52 Moody’s Investors Service, “U.S. Electric Utilities: Uncertain Times Ahead; Strengthening Balance Sheets Now Would Protect Credit,” Special Comment (Oct. 28, 2010).

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utility enters into a PPA, the fixed charges associated with the contract increase the

utility’s financial risk in the same way that long-term debt and other financial obligations

increase financial leverage. Because investors consider the debt impact of such fixed

obligations in assessing a utility’s financial position, they imply greater risk and reduced

financial flexibility. In order to offset the resulting debt equivalent, the utility must

rebalance its capital structure by increasing its common equity in order to restore its

effective capitalization ratios to previous levels.

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These commitments have been repeatedly cited by major bond rating agencies in

connection with assessments of utility financial risks,53 with S&P adjusting Black Hills

Corp.’s reported debt amounts upward to include debt equivalents associated with leases

and power purchase obligations.54 Unless this additional financial risk is offset by

maintaining a higher equity ratio, the resulting leverage will weaken the Company’s

creditworthiness and imply greater risk.

Q. WHAT DOES THIS EVIDENCE SUGGEST WITH RESPECT TO CHEYENNE

LIGHT’S PROPOSED CAPITAL STRUCTURE?

A. Based on my evaluation, I concluded that Cheyenne Light’s requested capital structure

represents a reasonable mix of capital sources from which to calculate the Company’s

overall rate of return. While industry averages provide one benchmark for comparison,

each firm must select its capitalization based on the risks and prospects it faces, as well

its specific needs to access the capital markets. A public utility with an obligation to

serve must maintain ready access to capital so that it can meet the service requirements of

its customers. The need for access becomes even more important when the company has

53 See, e.g., Standard & Poor’s Corporation, “Implications Of Operating Leases On Analysis Of U.S. Electric Utilities,” RatingsDirect (Jan. 15, 2008) 54 Standard & Poor’s Corporation, “Black Hills Corp.,” RatingsXpress (July 27, 2011).

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large capital requirements over a period of years, and financing must be continuously

available, even during unfavorable capital market conditions.

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Cheyenne Light’s proposed capital structure is consistent with industry

benchmarks and reflects the Company’s ongoing efforts to maintain its credit standing

and support access to capital on reasonable terms. The reasonableness of Cheyenne

Light’s requested capital structure is reinforced by the ongoing uncertainties associated

with the utility industry, the need to accommodate the additional risks associated the

Company’s relatively small size, and the importance of supporting continued investment

in system improvements, even during times of adverse industry or market conditions.

D. ROE Recommendation

Q. PLEASE SUMMARIZE THE RESULTS OF YOUR ANALYSES. 10

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A. The cost of equity estimates produced by the analyses described in my testimony are

summarized in Table WEA-6, below:

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TABLE WEA-6 SUMMARY OF COST OF EQUITY ESTIMATES

DCF Utility Non-UtilityDividend Growth 9.8% 10.4%Earnings Growth

Value Line 10.3% 11.5%IBES 10.3% 12.1%Zacks 9.6% 11.9%

br + sv 9.1% 12.5%CAPM - Current Bond Yield

Unadjusted 10.9%Size Adjusted 11.7%

CAPM - Projected Bond YieldUnadjusted 11.4%Size Adjusted 12.2%

Utility Risk PremiumCurrent Bond Yields 10.4%Projected Bond Yields 11.5%

Expected EarningsValue Line 2014-16 10.5%Utility Proxy Group 10.7%

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Based on my assessment of the relative strengths and weaknesses inherent in each

method, and conservatively giving less emphasis to the upper- and lower-most

boundaries of the range of results, I concluded that the cost of common equity indicated

by my analyses is in the 10.3 percent to 11.3 percent range. After incorporating an

adjustment for flotation costs of 20 basis points to my “bare bones” cost of equity range, I

concluded that my analyses indicate a fair ROE in the 10.5 percent to 11.5 percent range,

with a midpoint of 11.0 percent.

Cheyenne Light’s relatively weaker credit standing and small size imply a level of

investment risk and required return that exceeds that of the proxy groups used to estimate

the cost of equity. As discussed in the testimony of Mr. Brian Iverson, however,

Cheyenne Light is requesting an ROE of 10.9 percent in this case. Because the

Company’s requested ROE falls below the midpoint of my recommended range, it

represents a reasonable compromise between balancing the impact on customers and the

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need to provide Cheyenne Light with a return that is adequate to compensate investors,

maintain financial integrity, and attract capital.

Apart from the results of the quantitative methods summarized above, it is crucial

to recognize the importance of supporting the Company’s financial position so that

Cheyenne Light remains prepared to respond to unforeseen events that may materialize in

the future. Recent challenges in the economic and financial market environment

highlight the imperative of maintaining the Company’s financial strength in attracting the

capital needed to secure reliable service at a lower cost for customers. The

reasonableness of the Company’s requested ROE is reinforced by the fact that current

cost of capital estimates are likely to understate investors’ requirements at the time the

outcome of this proceeding becomes effective and beyond.

Q. DOES THIS CONCLUDE YOUR PRE-FILED DIRECT TESTIMONY?

A. Yes.

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Exhibit WEA-1 Page 1 of 6

WILLIAM E. AVERA

FINCAP, INC. 3907 Red River Financial Concepts and Applications Austin, Texas 78751 Economic and Financial Counsel (512) 458–4644 FAX (512) 458–4768 [email protected] Summary of Qualifications Ph.D. in economics and finance; Chartered Financial Analyst (CFA ®) designation; extensive expert witness testimony before courts, alternative dispute resolution panels, regulatory agencies and legislative committees; lectured in executive education programs around the world on ethics, investment analysis, and regulation; undergraduate and graduate teaching in business and economics; appointed to leadership positions in government, industry, academia, and the military. Employment Principal, FINCAP, Inc. (Sep. 1979 to present)

Financial, economic and policy consulting to business and government. Perform business and public policy research, cost/benefit analyses and financial modeling, valuation of businesses (almost 200 entities valued), estimation of damages, statistical and industry studies. Provide strategy advice and educational services in public and private sectors, and serve as expert witness before regulatory agencies, legislative committees, arbitration panels, and courts.

Director, Economic Research Division, Public Utility Commission of Texas (Dec. 1977 to Aug. 1979)

Responsible for research and testimony preparation on rate of return, rate structure, and econometric analysis dealing with energy, telecommunications, water and sewer utilities. Testified in major rate cases and appeared before legislative committees and served as Chief Economist for agency. Administered state and federal grant funds. Communicated frequently with political leaders and representatives from consumer groups, media, and investment community.

Manager, Financial Education, International Paper Company New York City (Feb. 1977 to Nov. 1977)

Directed corporate education programs in accounting, finance, and economics. Developed course materials, recruited and trained instructors, liaison within the company and with academic institutions. Prepared operating budget and designed financial controls for corporate professional development program.


Lecturer in Finance, The University of Texas at Austin (Sep. 1979 to May 1981) Assistant Professor of Finance, (Sep. 1975 to May 1977)

Taught graduate and undergraduate courses in financial management and investment theory. Conducted research in business and public policy. Named Outstanding Graduate Business Professor and received various administrative appointments.

Assistant Professor of Business, University of North Carolina at

Chapel Hill (Sep. 1972 to Jul. 1975)

Taught in BBA, MBA, and Ph.D. programs. Created project course in finance, Financial Management for Women, and participated in developing Small Business Management sequence. Organized the North Carolina Institute for Investment Research, a group of financial institutions that supported academic research. Faculty advisor to the Media Board, which funds student publications and broadcast stations.

Education

Ph.D., Economics and Finance, University of North Carolina at

Chapel Hill (Jan. 1969 to Aug. 1972)

Elective courses included financial management, public finance, monetary theory, and econometrics. Awarded the Stonier Fellowship by the American Bankers' Association and University Teaching Fellowship. Taught statistics, macroeconomics, and microeconomics. Dissertation: The Geometric Mean Strategy as a Theory of Multiperiod Portfolio Choice

B.A., Economics, Emory University, Atlanta, Georgia (Sep. 1961 to Jun. 1965)

Active in extracurricular activities, president of the Barkley Forum (debate team), Emory Religious Association, and Delta Tau Delta chapter. Individual awards and team championships at national collegiate debate tournaments.

Professional Associations Received Chartered Financial Analyst (CFA) designation in 1977; Vice President for Membership, Financial Management Association; President, Austin Chapter of Planning Executives Institute; Board of Directors, North Carolina Society of Financial Analysts; Candidate Curriculum Committee, Association for Investment Management and Research; Executive Committee of Southern Finance Association; Vice Chair, Staff Subcommittee on Economics and National Association of Regulatory Utility Commissioners (NARUC); Appointed to NARUC Technical Subcommittee on the National Energy Act. Teaching in Executive Education Programs University-Sponsored Programs: Central Michigan University, Duke University, Louisiana State University, National Defense University, National University of Singapore, Texas A&M University, University of Kansas, University of North Carolina, University of Texas.


Business and Government-Sponsored Programs: Advanced Seminar on Earnings Regulation, American Public Welfare Association, Association for Investment Management and Research, Congressional Fellows Program, Cost of Capital Workshop, Electricity Consumers Resource Council, Financial Analysts Association of Indonesia, Financial Analysts Review, Financial Analysts Seminar at Northwestern University, Governor's Executive Development Program of Texas, Louisiana Association of Business and Industry, National Association of Purchasing Management, National Association of Tire Dealers, Planning Executives Institute, School of Banking of the South, State of Wisconsin Investment Board, Stock Exchange of Thailand, Texas Association of State Sponsored Computer Centers, Texas Bankers' Association, Texas Bar Association, Texas Savings and Loan League, Texas Society of CPAs, Tokyo Association of Foreign Banks, Union Bank of Switzerland, U.S. Department of State, U.S. Navy, U.S. Veterans

dministration, in addition to Texas state agencies and major corporations. A Presented papers for Mills B. Lane Lecture Series at the University of Georgia and Heubner Lectures at the University of Pennsylvania. Taught graduate courses in finance and economics for evening program at St. Edward's University in Austin from January 1979 through 1998. Expert Witness Testimony Testified in over 300 cases before regulatory agencies addressing cost of capital, regulatory policy, ate design, and other economic and financial issues. r

Federal Agencies: Federal Communications Commission, Federal Energy Regulatory Commission, Surface Transportation Board, Interstate Commerce Commission, and the Canadian

adio-Television and Telecommunications Commission. R State Regulatory Agencies: Alaska, Arizona, Arkansas, California, Colorado, Connecticut, Delaware, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan, Missouri, Nevada, New Mexico, Montana, Nebraska, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South Carolina, South Dakota, Texas, Utah, Virginia,

ashington, West Virginia, Wisconsin, and Wyoming. W Testified in 42 cases before federal and state courts, arbitration panels, and alternative dispute tribunals (89 depositions given) regarding damages, valuation, antitrust liability, fiduciary duties, and other economic and financial issues. Board Positions and Other Professional Activities Audit Committee and Outside Director, Georgia System Operations Corporation (electric system operator for member-owned electric cooperatives in Georgia); Chairman, Board of Print Depot, Inc. and FINCAP, Inc.; Co-chair, Synchronous Interconnection Committee, appointed by Public Utility Commission of Texas and approved by governor; Appointed by Hays County Commission to Citizens Advisory Committee of Habitat Conservation Plan, Operator of AAA Ranch, a certified organic producer of agricultural products; Appointed to Organic Livestock Advisory Committee by Texas Agricultural Commissioner Susan Combs; Appointed by Texas Railroad Commissioners to study group for The UP/SP Merger: An Assessment of the Impacts on the State of Texas; Appointed by Hawaii Public Utilities Commission to team reviewing affiliate relationships of Hawaiian Electric Industries; Chairman, Energy Task Force, Greater Austin-San Antonio Corridor Council; Consultant to Public Utility Commission of Texas on cogeneration policy and other matters; Consultant to


Public Service Commission of New Mexico on cogeneration policy; Evaluator of Energy Research Grant Proposals for Texas Higher Education Coordinating Board. Community Activities Board of Directors, Sustainable Food Center; Chair, Board of Deacons, Finance Committee, and Elder, Central Presbyterian Church of Austin; Founding Member, Orange-Chatham County (N.C.) Legal Aid Screening Committee. Military Captain, U.S. Naval Reserve (retired after 28 years service); Commanding Officer, Naval Special Warfare Engineering (SEAL) Support Unit; Officer-in-Charge of SWIFT patrol boat in Vietnam; Enlisted service as weather analyst (advanced to second class petty officer). Bibliography M onographs

Ethics and the Investment Professional (video, workbook, and instructor’s guide) and Ethics Challenge Today (video), Association for Investment Management and Research (1995)

“Definition of Industry Ethics and Development of a Code” and “Applying Ethics in the Real World,” in Good Ethics: The Essential Element of a Firm’s Success, Association for Investment Management and Research (1994)

“On the Use of Security Analysts’ Growth Projections in the DCF Model,” with Bruce H. Fairchild in Earnings Regulation Under Inflation, J. R. Foster and S. R. Holmberg, eds. Institute for Study of Regulation (1982)

An Examination of the Concept of Using Relative Customer Class Risk to Set Target Rates of Return in Electric Cost-of-Service Studies, with Bruce H. Fairchild, Electricity Consumers Resource Council (ELCON) (1981); portions reprinted in Public Utilities Fortnightly (Nov. 11, 1982)

“Usefulness of Current Values to Investors and Creditors,” Research Study on Current-Value Accounting Measurements and Utility, George M. Scott, ed., Touche Ross Foundation (1978)

“The Geometric Mean Strategy and Common Stock Investment Management,” with Henry A. Latané in Life Insurance Investment Policies, David Cummins, ed. (1977)

Investment Companies: Analysis of Current Operations and Future Prospects, with J. Finley Lee and Glenn L. Wood, American College of Life Underwriters (1975)

A rticles

“Should Analysts Own the Stocks they Cover?” The Financial Journalist, (March 2002) “Liquidity, Exchange Listing, and Common Stock Performance,” with John C. Groth and Kerry

Cooper, Journal of Economics and Business (Spring 1985); reprinted by National Association of Security Dealers

“The Energy Crisis and the Homeowner: The Grief Process,” Texas Business Review (Jan.–Feb. 1980); reprinted in The Energy Picture: Problems and Prospects, J. E. Pluta, ed., Bureau of Business Research (1980)

“Use of IFPS at the Public Utility Commission of Texas,” Proceedings of the IFPS Users Group Annual Meeting (1979)


"Production Capacity Allocation: Conversion, CWIP, and One-Armed Economics,” Proceedings of the NARUC Biennial Regulatory Information Conference (1978)

"Some Thoughts on the Rate of Return to Public Utility Companies,” with Bruce H. Fairchild in Proceedings of the NARUC Biennial Regulatory Information Conference (1978)

"A New Capital Budgeting Measure: The Integration of Time, Liquidity, and Uncertainty,” with David Cordell in Proceedings of the Southwestern Finance Association (1977)

"Usefulness of Current Values to Investors and Creditors,” in Inflation Accounting/Indexing and Stock Behavior (1977)

"Consumer Expectations and the Economy,” Texas Business Review (Nov. 1976) "Portfolio Performance Evaluation and Long-run Capital Growth,” with Henry A. Latané in

Proceedings of the Eastern Finance Association (1973) Book reviews in Journal of Finance and Financial Review. Abstracts for CFA Digest. Articles in

Carolina Financial Times. S elected Papers and Presentations

“Economic Perspective on Water Marketing in Texas,” 2009 Water Law Institute, The University of Texas School of Law, Austin, TX (Dec. 2009).

“Estimating Utility Cost of Equity in Financial Turmoil,” SNL EXNET 15th Annual FERC Briefing, Washington, D.C. (Mar. 2009)

"The Who, What, When, How, and Why of Ethics," San Antonio Financial Analysts Society (Jan. 16, 2002). Similar presentation given to the Austin Society of Financial Analysts (Jan. 17, 2002)

“Ethics for Financial Analysts,” Sponsored by Canadian Council of Financial Analysts: delivered in Calgary, Edmonton, Regina, and Winnipeg, June 1997. Similar presentations given to Austin Society of Financial Analysts (Mar. 1994), San Antonio Society of Financial Analysts (Nov. 1985), and St. Louis Society of Financial Analysts (Feb. 1986)

“Cost of Capital for Multi-Divisional Corporations,” Financial Management Association, New Orleans, Louisiana (Oct. 1996)

"Ethics and the Treasury Function,” Government Treasurers Organization of Texas, Corpus Christi, Texas (Jun. 1996)

"A Cooperative Future,” Iowa Association of Electric Cooperatives, Des Moines (December 1995). Similar presentations given to National G & T Conference, Irving, Texas (June 1995), Kentucky Association of Electric Cooperatives Annual Meeting, Louisville (Nov. 1994), Virginia, Maryland, and Delaware Association of Electric Cooperatives Annual Meeting, Richmond (July 1994), and Carolina Electric Cooperatives Annual Meeting, Raleigh (Mar. 1994)

"Information Superhighway Warnings: Speed Bumps on Wall Street and Detours from the Economy,” Texas Society of Certified Public Accountants Natural Gas, Telecommunications and Electric Industries Conference, Austin (Apr. 1995)

"Economic/Wall Street Outlook,” Carolinas Council of the Institute of Management Accountants, Myrtle Beach, South Carolina (May 1994). Similar presentation given to Bell Operating Company Accounting Witness Conference, Santa Fe, New Mexico (Apr. 1993)

"Regulatory Developments in Telecommunications,” Regional Holding Company Financial and Accounting Conference, San Antonio (Sep. 1993)


“Estimating the Cost of Capital During the 1990s: Issues and Directions,” The National Society of Rate of Return Analysts, Washington, D.C. (May 1992)

“Making Utility Regulation Work at the Public Utility Commission of Texas,” Center for Legal and Regulatory Studies, University of Texas, Austin (June 1991)

"Can Regulation Compete for the Hearts and Minds of Industrial Customers,” Emerging Issues of Competition in the Electric Utility Industry Conference, Austin (May 1988)

"The Role of Utilities in Fostering New Energy Technologies,” Emerging Energy Technologies in Texas Conference, Austin (Mar. 1988)

"The Regulators’ Perspective,” Bellcore Economic Analysis Conference, San Antonio (Nov. 1987) "Public Utility Commissions and the Nuclear Plant Contractor,” Construction Litigation

Superconference, Laguna Beach, California (Dec. 1986) "Development of Cogeneration Policies in Texas,” University of Georgia Fifth Annual Public

Utilities Conference, Atlanta (Sep. 1985) "Wheeling for Power Sales,” Energy Bureau Cogeneration Conference, Houston (Nov. 1985). "Asymmetric Discounting of Information and Relative Liquidity: Some Empirical Evidence for

Common Stocks" (with John Groth and Kerry Cooper), Southern Finance Association, New Orleans (Nov. 1982)

“Used and Useful Planning Models,” Planning Executive Institute, 27th Corporate Planning Conference, Los Angeles (Nov. 1979)

"Staff Input to Commission Rate of Return Decisions,” The National Society of Rate of Return Analysts, New York (Oct. 1979)

""Discounted Cash Life: A New Measure of the Time Dimension in Capital Budgeting,” with David Cordell, Southern Finance Association, New Orleans (Nov. 1978)

“The Relative Value of Statistics of Ex Post Common Stock Distributions to Explain Variance,” with Charles G. Martin, Southern Finance Association, Atlanta (Nov. 1977)

“An ANOVA Representation of Common Stock Returns as a Framework for the Allocation of Portfolio Management Effort,” with Charles G. Martin, Financial Management Association, Montreal (Oct. 1976)

“A Growth-Optimal Portfolio Selection Model with Finite Horizon,” with Henry A. Latané, American Finance Association, San Francisco (Dec. 1974)

“An Optimal Approach to the Finance Decision,” with Henry A. Latané, Southern Finance Association, Atlanta (Nov. 1974)

“A Pragmatic Approach to the Capital Structure Decision Based on Long-Run Growth,” with Henry A. Latané, Financial Management Association, San Diego (Oct. 1974)

“Growth Rates, Expected Returns, and Variance in Portfolio Selection and Performance Evaluation,” with Henry A. Latané, Econometric Society, Oslo, Norway (Aug. 1973)

DCF MODEL ‐ UTILITY PROXY GROUP Exhibit WEA‐2Page 1 of 3

DIVIDEND YIELD

(a) (b)

Company Price Dividends Yield1 Alliant Energy 40.94$ 1.70$ 4.2%2 ALLETE 38.66$ 1.78$ 4.6%3 Ameren Corp. 31.63$ 1.54$ 4.9%4 Avista Corp. 24.83$ 1.10$ 4.4%5 Black Hills Corp. 32.83$ 1.46$ 4.4%6 CenterPoint Energy 20.29$ 0.79$ 3.9%7 CMS Energy 20.65$ 0.84$ 4.1%8 DTE Energy Co. 51.38$ 2.32$ 4.5%9 Empire District Elec 19.88$ 0.64$ 3.2%10 Entergy Corp. 68.25$ 3.32$ 4.9%11 Exelon Corp. 43.64$ 2.10$ 4.8%12 Integrys Energy Group 51.39$ 2.72$ 5.3%13 Pepco Holdings 19.45$ 1.08$ 5.6%14 PG&E Corp. 41.51$ 1.82$ 4.4%15 PPL Corp. 29.28$ 1.40$ 4.8%16 Pub Sv Enterprise Grp 33.47$ 1.37$ 4.1%17 SCANA Corp. 42.03$ 1.94$ 4.6%18 Sempra Energy 53.17$ 1.92$ 3.6%19 TECO Energy 18.27$ 0.85$ 4.7%20 UIL Holdings 33.58$ 1.73$ 5.2%

Average 4.5%

(a) Average of closing prices for 30 trading days ended Nov. 18, 2011.(b) www.valueline.com (retrieved Nov. 17, 2011).


GROWTH RATES

(a) (a) (b) (c) (e)

Dividend br+svCompany Growth V Line IBES Zacks Growth

1 Alliant Energy 6.0% 7.0% 4.9% 6.0% 5.6%2 ALLETE 2.0% 4.5% 6.0% 5.0% 3.3%3 Ameren Corp. ‐3.0% ‐2.0% ‐2.1% 4.0% 2.5%4 Avista Corp. 9.0% 4.5% 4.7% 4.7% 3.1%5 Black Hills Corp. 1.5% 8.5% 4.0% 5.0% 2.5%6 CenterPoint Energy 3.0% 3.0% 6.2% 5.9% 4.1%7 CMS Energy 14.0% 7.0% 5.9% 5.5% 4.8%8 DTE Energy Co. 4.0% 4.5% 3.4% 4.2% 3.5%9 Empire District Elec ‐1.0% 7.0% 10.2% 8.9% 3.3%10 Entergy Corp. 2.5% 1.5% ‐3.2% ‐0.6% 5.1%11 Exelon Corp. 0.0% ‐1.5% ‐0.3% 0.0% 5.4%12 Integrys Energy Group 0.0% 9.0% 9.4% 4.5% 3.1%13 Pepco Holdings 1.0% 2.5% 7.5% 4.0% 2.6%14 PG&E Corp. 4.5% 6.0% 1.7% 4.0% 6.0%15 PPL Corp. 3.5% 7.0% 3.7% 12.2% 8.8%16 Pub Sv Enterprise Grp 1.5% 1.0% 1.4% 2.0% 7.0%17 SCANA Corp. 2.0% 3.0% 4.5% 4.2% 4.8%18 Sempra Energy 9.0% 3.5% 7.3% 7.0% 6.1%19 TECO Energy 4.5% 10.5% 5.4% 4.7% 5.7%20 UIL Holdings 0.0% 3.0% 4.0% 4.0% 2.3%

(a) The Value Line Investment Survey ( Aug. 26, Sep. 23, & Nov. 4, 2011).(b) www.finance.yahoo.com (Retrieved Nov. 18, 2011).(c) www.zacks.com (retrieved Nov. 18, 2011).(d) See Exhibit WEA‐3.

Earnings Growth


DCF COST OF EQUITY ESTIMATES

(a) (a) (a) (a) (a)

Dividend br+svCompany Growth V Line IBES Zacks Growth

1 Alliant Energy 10.2% 11.2% 9.1% 10.2% 9.7%2 ALLETE 6.6% 9.1% 10.6% 9.6% 8.0%3 Ameren Corp. 1.9% 2.9% 2.7% 8.9% 7.4%4 Avista Corp. 13.4% 8.9% 9.1% 9.1% 7.5%5 Black Hills Corp. 5.9% 12.9% 8.4% 9.4% 7.0%6 CenterPoint Energy 6.9% 6.9% 10.1% 9.8% 8.0%7 CMS Energy 18.1% 11.1% 10.0% 9.6% 8.9%8 DTE Energy Co. 8.5% 9.0% 8.0% 8.7% 8.0%9 Empire District Elec 2.2% 10.2% 13.4% 12.1% 6.5%10 Entergy Corp. 7.4% 6.4% 1.7% 4.3% 10.0%11 Exelon Corp. 4.8% 3.3% 4.5% 4.8% 10.2%12 Integrys Energy Group 5.3% 14.3% 14.7% 9.8% 8.4%13 Pepco Holdings 6.6% 8.1% 13.1% 9.6% 8.2%14 PG&E Corp. 8.9% 10.4% 6.1% 8.4% 10.3%15 PPL Corp. 8.3% 11.8% 8.5% 17.0% 13.6%16 Pub Sv Enterprise Grp 5.6% 5.1% 5.5% 6.1% 11.1%17 SCANA Corp. 6.6% 7.6% 9.1% 8.8% 9.5%18 Sempra Energy 12.6% 7.1% 10.9% 10.6% 9.7%19 TECO Energy 9.2% 15.2% 10.1% 9.4% 10.4%20 UIL Holdings 5.2% 8.2% 9.2% 9.2% 7.4%

Average (b) 9.8% 10.3% 10.3% 9.6% 9.1%

(a) Sum of dividend yield (page 1) and respective growth rate (page 2).(b) Excludes highlighted figures.

Earnings Growth


BR+SV GROWTH RATE

(a) (a) (a) (b) (c) (d) (e)Adjustment ‐‐‐‐‐‐‐‐‐ ʺsvʺ Factor ‐‐‐‐‐‐‐‐

Company EPS DPS BVPS b r Factor Adjusted r br s v sv br + sv1 Alliant Energy $3.60 $2.10 $30.15 41.7% 11.9% 1.0192 12.2% 5.1% 0.0143 0.3653 0.52% 5.6%2 ALLETE $3.25 $1.95 $40.00 40.0% 8.1% 1.0300 8.4% 3.3% 0.0224 ‐ 0.00% 3.3%3 Ameren Corp. $2.50 $1.54 $36.00 38.4% 6.9% 1.0174 7.1% 2.7% 0.0105 (0.2000) ‐0.21% 2.5%4 Avista Corp. $2.00 $1.40 $22.75 30.0% 8.8% 1.0206 9.0% 2.7% 0.0152 0.2417 0.37% 3.1%5 Black Hills Corp. $2.25 $1.55 $30.50 31.1% 7.4% 1.0223 7.5% 2.3% 0.0294 0.0615 0.18% 2.5%6 CenterPoint Energy $1.35 $0.90 $12.00 33.3% 11.3% 1.0468 11.8% 3.9% 0.0041 0.4000 0.17% 4.1%7 CMS Energy $1.75 $1.10 $15.00 37.1% 11.7% 1.0334 12.1% 4.5% 0.0118 0.3023 0.36% 4.8%8 DTE Energy Co. $4.25 $2.70 $46.50 36.5% 9.1% 1.0187 9.3% 3.4% 0.0066 0.1913 0.13% 3.5%9 Empire District Elec $1.75 $1.20 $17.75 31.4% 9.9% 1.0156 10.0% 3.1% 0.0080 0.1548 0.12% 3.3%10 Entergy Corp. $7.00 $3.60 $65.00 48.6% 10.8% 1.0275 11.1% 5.4% (0.0103) 0.2571 ‐0.27% 5.1%11 Exelon Corp. $3.75 $2.10 $26.25 44.0% 14.3% 1.0201 14.6% 6.4% (0.0197) 0.5000 ‐0.99% 5.4%12 Integrys Energy Group $4.00 $2.72 $41.75 32.0% 9.6% 1.0122 9.7% 3.1% 0.0028 0.1211 0.03% 3.1%13 Pepco Holdings $1.65 $1.16 $21.20 29.7% 7.8% 1.0226 8.0% 2.4% 0.0240 0.1167 0.28% 2.6%14 PG&E Corp. $4.25 $2.20 $38.00 48.2% 11.2% 1.0360 11.6% 5.6% 0.0183 0.2000 0.37% 6.0%15 PPL Corp. $3.00 $1.70 $25.50 43.3% 11.8% 1.0741 12.6% 5.5% 0.1039 0.3200 3.32% 8.8%16 Pub Sv Enterprise Grp $3.25 $1.45 $26.50 55.4% 12.3% 1.0336 12.7% 7.0% 0.0000 0.3375 0.00% 7.0%17 SCANA Corp. $3.50 $2.10 $37.25 40.0% 9.4% 1.0415 9.8% 3.9% 0.0432 0.2158 0.93% 4.8%18 Sempra Energy $5.50 $2.50 $52.25 54.5% 10.5% 1.0354 10.9% 5.9% 0.0061 0.2536 0.16% 6.1%19 TECO Energy $1.75 $1.05 $13.25 40.0% 13.2% 1.0289 13.6% 5.4% 0.0076 0.3837 0.29% 5.7%20 UIL Holdings $2.35 $1.73 $27.00 26.4% 8.7% 1.0225 8.9% 2.3% (0.0028) 0.2800 ‐0.08% 2.3%

‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 2015 ‐‐‐‐‐‐‐‐‐‐‐‐‐


BR+SV GROWTH RATE

(a) (a) (f) (a) (a) (f) (g) (a) (a) (h) (a) (a) (g) ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 2010 ‐‐‐‐‐‐‐‐‐‐‐‐‐ ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 2015 ‐‐‐‐‐‐‐‐‐‐‐‐‐ Chg ‐‐‐‐ Common Shares ‐‐‐‐

Company Eq Ratio Tot Cap Com Eq Eq Ratio Tot Cap Com Eq Equity High Low Avg. M/B 2010 2015 Growth1 Alliant Energy 49.5% $5,841 $2,891 51.5% $6,805 $3,505 3.9% $55.00 $40.00 $47.50 1.575 110.89 116.00 0.91%2 ALLETE 55.8% $1,748 $975 58.5% $2,250 $1,316 6.2% $45.00 $35.00 $40.00 1.000 35.80 40.00 2.24%3 Ameren Corp. 50.9% $15,185 $7,729 53.5% $17,200 $9,202 3.5% $35.00 $25.00 $30.00 0.833 240.40 256.00 1.27%4 Avista Corp. 48.4% $2,325 $1,125 48.5% $2,850 $1,382 4.2% $35.00 $25.00 $30.00 1.319 57.12 60.50 1.16%5 Black Hills Corp. 48.1% $2,286 $1,100 50.0% $2,750 $1,375 4.6% $40.00 $25.00 $32.50 1.066 39.27 45.00 2.76%6 CenterPoint Energy 26.2% $12,199 $3,196 31.5% $16,200 $5,103 9.8% $25.00 $15.00 $20.00 1.667 424.70 430.00 0.25%7 CMS Energy 29.5% $9,473 $2,795 35.5% $11,000 $3,905 6.9% $25.00 $18.00 $21.50 1.433 249.60 260.00 0.82%8 DTE Energy Co. 48.7% $13,811 $6,726 48.0% $16,900 $8,112 3.8% $70.00 $45.00 $57.50 1.237 169.43 174.00 0.53%9 Empire District Elec 48.7% $1,351 $658 53.0% $1,450 $769 3.2% $25.00 $17.00 $21.00 1.183 41.58 43.00 0.67%10 Entergy Corp. 42.1% $20,166 $8,490 42.5% $26,300 $11,178 5.7% $100.00 $75.00 $87.50 1.346 178.75 172.00 ‐0.77%11 Exelon Corp. 52.9% $25,651 $13,569 53.5% $31,000 $16,585 4.1% $60.00 $45.00 $52.50 2.000 662.00 630.00 ‐0.99%12 Integrys Energy Group 56.8% $5,119 $2,907 54.5% $6,025 $3,284 2.5% $55.00 $40.00 $47.50 1.138 77.35 78.30 0.24%13 Pepco Holdings 51.0% $8,292 $4,229 52.0% $10,200 $5,304 4.6% $30.00 $18.00 $24.00 1.132 225.08 250.00 2.12%14 PG&E Corp. 49.3% $22,863 $11,271 53.5% $30,200 $16,157 7.5% $55.00 $40.00 $47.50 1.250 395.23 425.00 1.46%15 PPL Corp. 39.8% $20,621 $8,207 56.0% $30,800 $17,248 16.0% $45.00 $30.00 $37.50 1.471 483.39 680.00 7.06%16 Pub Sv Enterprise Grp 55.2% $17,452 $9,634 55.5% $24,300 $13,487 7.0% $45.00 $35.00 $40.00 1.509 505.97 506.00 0.00%17 SCANA Corp. 47.1% $7,854 $3,699 49.5% $11,325 $5,606 8.7% $55.00 $40.00 $47.50 1.275 127.00 150.00 3.38%18 Sempra Energy 49.6% $18,186 $9,020 51.0% $25,200 $12,852 7.3% $80.00 $60.00 $70.00 1.340 240.45 246.00 0.46%19 TECO Energy 40.8% $5,318 $2,170 47.5% $6,100 $2,898 6.0% $25.00 $18.00 $21.50 1.623 214.90 220.00 0.47%20 UIL Holdings 41.6% $2,588 $1,077 41.5% $3,250 $1,349 4.6% $45.00 $30.00 $37.50 1.389 50.51 50.00 ‐0.20%

(a) The Value Line Investment Survey ( Aug. 26, Sep. 23, & Nov. 4, 2011).(b) Computed using the formula 2*(1+5‐Yr. Change in Equity)/(2+5 Yr. Change in Equity).(c) Product of average year‐end ʺrʺ for 2015 and Adjustment Factor.(d) Product of change in common shares outstanding and M/B Ratio.(e) Computed as 1 ‐ B/M Ratio.(f) Product of total capital and equity ratio.(g) Five‐year rate of change.(h) Average of High and Low expected market prices divided by 2014‐16 BVPS.

‐‐‐‐‐‐‐‐ 2015 Price ‐‐‐‐‐‐‐‐

DCF MODEL Exhibit WEA‐4Page 1 of 1

NON‐UTILITY PROXY GROUP

(a) (a) (a) (b) (c) (d) (e) (e) (e) (e) (e)

DividendCompany Yield DPS V Line IBES Zacks br+sv DPS V Line IBES Zacks br+sv

1 Abbott Labs. 3.63% 9.0% 8.5% 8.9% 6.7% 18.6% 12.6% 12.1% 12.5% 10.3% 22.2%2 AT&T Inc. 5.75% 3.5% 7.5% 5.8% 4.5% 4.8% 9.3% 13.3% 11.6% 10.3% 10.6%3 Automatic Data Proc. 2.71% 8.5% 7.5% 10.9% 11.4% 11.0% 11.2% 10.2% 13.6% 14.1% 13.7%4 Bard (C.R.) 0.67% 5.5% 9.0% 11.1% 11.2% 20.3% 6.2% 9.7% 11.8% 11.9% 21.0%5 Baxter Intʹl Inc. 2.05% 7.0% 9.5% 9.6% 9.3% 14.5% 9.1% 11.6% 11.7% 11.4% 16.6%6 Becton, Dickinson 1.84% 11.0% 8.0% 9.8% 10.8% 8.7% 12.8% 9.8% 11.6% 12.6% 10.5%7 Bristol‐Myers Squibb 4.47% 3.5% 8.0% ‐0.5% 1.5% 8.3% 8.0% 12.5% 4.0% 6.0% 12.8%8 Brown‐Forman ʹBʹ 1.69% 5.0% 8.0% 13.0% 13.0% 10.9% 6.7% 9.7% 14.7% 14.7% 12.6%9 Church & Dwight 1.60% 16.5% 10.5% 11.8% 12.0% 12.5% 18.1% 12.1% 13.4% 13.6% 14.1%10 Coca‐Cola 2.71% 9.5% 10.0% 9.2% 9.0% 10.3% 12.2% 12.7% 11.9% 11.7% 13.0%11 Colgate‐Palmolive 2.67% 10.5% 10.0% 9.0% 8.8% 13.2% 13.2% 12.7% 11.7% 11.5% 15.9%12 ConAgra Foods 3.54% 6.0% 9.5% 6.3% 7.0% 6.7% 9.5% 13.0% 9.8% 10.5% 10.2%13 Costco Wholesale 1.18% 8.0% 11.0% 13.2% 13.1% 8.5% 9.2% 12.2% 14.4% 14.3% 9.7%14 Exxon Mobil Corp. 2.21% 8.0% 9.5% 5.4% 5.6% 9.9% 10.2% 11.7% 7.6% 7.8% 12.1%15 Genʹl Mills 3.22% 10.0% 8.0% 7.7% 8.0% 8.4% 13.2% 11.2% 10.9% 11.2% 11.6%16 Heinz (H.J.) 3.55% 6.5% 6.5% 7.7% 8.0% 11.8% 10.1% 10.1% 11.3% 11.6% 15.3%17 Hormel Foods 1.91% 12.5% 10.0% 9.5% 9.3% 10.3% 14.4% 11.9% 11.4% 11.2% 12.2%18 Johnson & Johnson 3.43% 7.0% 5.0% 6.1% 6.0% 8.8% 10.4% 8.4% 9.5% 9.4% 12.2%19 Kellogg 3.08% 7.0% 9.0% 8.5% 9.0% 10.3% 10.1% 12.1% 11.6% 12.1% 13.4%20 Kimberly‐Clark 4.13% 3.5% 7.0% 7.7% 6.8% 11.9% 7.6% 11.1% 11.8% 10.9% 16.1%21 Kraft Foods 3.27% 6.0% 8.5% 9.7% 8.0% 5.6% 9.3% 11.8% 13.0% 11.3% 8.9%22 Lorillard Inc. 4.59% 22.0% 13.0% 9.5% 7.0% NMF 26.6% 17.6% 14.1% 11.6% NMF23 McCormick & Co. 2.22% 7.0% 11.0% 9.0% 9.0% 15.2% 9.2% 13.2% 11.2% 11.2% 17.4%24 McDonaldʹs Corp. 2.82% 8.5% 8.0% 10.3% 9.7% 10.1% 11.3% 10.8% 13.1% 12.5% 12.9%25 McKesson Corp. 0.97% 9.0% 8.0% 13.3% 11.8% 12.0% 10.0% 9.0% 14.3% 12.8% 13.0%26 PepsiCo, Inc. 3.16% 6.0% 10.0% 8.5% 8.3% 11.4% 9.2% 13.2% 11.7% 11.5% 14.5%27 Pfizer, Inc. 3.98% 3.0% 10.5% 3.5% 3.5% 8.7% 7.0% 14.5% 7.5% 7.5% 12.7%28 Procter & Gamble 3.26% 7.5% 8.0% 9.8% 9.4% 4.9% 10.8% 11.3% 13.1% 12.7% 8.2%29 Raytheon Co. 3.76% 11.5% 5.5% 9.2% 10.8% 7.1% 15.3% 9.3% 13.0% 14.6% 10.8%30 Sherwin‐Williams 1.86% 7.5% 11.0% 10.7% 9.8% 14.0% 9.4% 12.9% 12.6% 11.7% 15.8%31 Sysco Corp. 3.40% 5.0% 7.5% 7.6% 11.5% 12.7% 8.4% 10.9% 11.0% 14.9% 16.1%32 Verizon Communic. 5.19% 2.0% 5.5% 8.5% 3.8% 6.0% 7.2% 10.7% 13.7% 9.0% 11.2%33 Walgreen Co. 2.27% 21.0% 11.5% 14.4% 13.4% 5.3% 23.3% 13.8% 16.7% 15.7% 7.5%34 Wal‐Mart Stores 2.68% 18.0% 9.0% 10.4% 11.0% 7.4% 20.7% 11.7% 13.1% 13.7% 10.1%

Average (f) 10.4% 11.5% 12.1% 11.9% 12.5%

(a) www.valueline.com (retrieved Jul. 29, 2011).(b) Thomson Reuters Company in Context Report (Aug. 3, 2011).(c) www.zacks.com (retrieved Aug. 4, 2011).(d) See Exhibit WEA‐5.(e) Sum of dividend yield and respective growth rate.(f) Excludes highlighted figures.

Growth RatesEPS

Cost of Equity EstimatesEPS

BR+SV GROWTH RATE Exhibit WEA‐5Page 1 of 2


(a) (a) (a) (b) (c) (d) (e)Adjust. ‐‐‐‐‐‐‐‐‐ ʺsvʺ Factor ‐‐‐‐‐‐‐‐

Company EPS DPS BVPS b r Factor Adj. r br s v sv br + sv1 Abbott Labs. $6.00 $2.20 $20.50 63.3% 29.3% 1.0341 30.3% 19.2% (0.0072) 0.7842 ‐0.57% 18.6%2 AT&T Inc. $3.35 $2.00 $25.80 40.3% 13.0% 1.0273 13.3% 5.4% (0.0126) 0.4267 ‐0.54% 4.8%3 Automatic Data Proc. $3.60 $1.68 $20.40 53.3% 17.6% 1.0621 18.7% 10.0% 0.0131 0.7527 0.98% 11.0%4 Bard (C.R.) $8.35 $0.90 $39.30 89.2% 21.2% 1.0715 22.8% 20.3% 0.0003 0.7380 0.02% 20.3%5 Baxter Intʹl Inc. $6.35 $1.58 $23.65 75.1% 26.8% 1.0598 28.5% 21.4% (0.0961) 0.7133 ‐6.86% 14.5%6 Becton, Dickinson $7.65 $2.50 $37.05 67.3% 20.6% 1.0325 21.3% 14.4% (0.0810) 0.6976 ‐5.65% 8.7%7 Bristol‐Myers Squibb $2.65 $1.54 $11.65 41.9% 22.7% 1.0207 23.2% 9.7% (0.0202) 0.7088 ‐1.43% 8.3%8 Brown‐Forman ʹBʹ $5.00 $1.60 $24.80 68.0% 20.2% 1.0486 21.1% 14.4% (0.0486) 0.7082 ‐3.44% 10.9%9 Church & Dwight $3.10 $0.72 $19.70 76.8% 15.7% 1.0403 16.4% 12.6% (0.0015) 0.6248 ‐0.09% 12.5%10 Coca‐Cola $5.60 $2.80 $20.45 50.0% 27.4% 1.0372 28.4% 14.2% (0.0469) 0.8260 ‐3.87% 10.3%11 Colgate‐Palmolive $7.30 $3.20 $15.55 56.2% 46.9% 1.0959 51.4% 28.9% (0.1755) 0.8928 ‐15.67% 13.2%12 ConAgra Foods $2.50 $1.10 $15.65 56.0% 16.0% 1.0241 16.4% 9.2% (0.0445) 0.5529 ‐2.46% 6.7%13 Costco Wholesale $4.70 $1.10 $34.10 76.6% 13.8% 1.0255 14.1% 10.8% (0.0341) 0.6752 ‐2.31% 8.5%14 Exxon Mobil Corp. $10.75 $2.60 $53.25 75.8% 20.2% 1.0372 20.9% 15.9% (0.1026) 0.5824 ‐5.97% 9.9%15 Genʹl Mills $3.35 $1.58 $15.35 52.8% 21.8% 1.0549 23.0% 12.2% (0.0523) 0.7209 ‐3.77% 8.4%16 Heinz (H.J.) $4.40 $2.60 $17.10 40.9% 25.7% 1.0580 27.2% 11.1% 0.0085 0.7641 0.65% 11.8%17 Hormel Foods $2.25 $0.80 $15.00 64.4% 15.0% 1.0508 15.8% 10.2% 0.0021 0.6250 0.13% 10.3%18 Johnson & Johnson $6.20 $2.91 $35.80 53.1% 17.3% 1.0520 18.2% 9.7% (0.0149) 0.6130 ‐0.91% 8.8%19 Kellogg $5.35 $2.15 $10.40 59.8% 51.4% 1.0415 53.6% 32.0% (0.2470) 0.8811 ‐21.76% 10.3%20 Kimberly‐Clark $6.50 $3.00 $19.80 53.8% 32.8% 1.0226 33.6% 18.1% (0.0777) 0.7916 ‐6.15% 11.9%21 Kraft Foods $3.25 $1.60 $30.85 50.8% 10.5% 1.0407 11.0% 5.6% 0.0004 0.4391 0.02% 5.6%22 Lorillard Inc. $12.30 $6.60 $9.20 46.3% NMF NMF NMF NMF (0.5490) 0.9503 ‐52.17% NMF23 McCormick & Co. $4.45 $1.45 $22.45 67.4% 19.8% 1.0727 21.3% 14.3% 0.0114 0.7506 0.85% 15.2%24 McDonaldʹs Corp. $6.50 $3.25 $17.60 50.0% 36.9% 1.0150 37.5% 18.7% (0.1039) 0.8324 ‐8.65% 10.1%25 McKesson Corp. $7.35 $1.20 $51.65 83.7% 14.2% 1.0561 15.0% 12.6% (0.0109) 0.4835 ‐0.53% 12.0%26 PepsiCo, Inc. $6.40 $2.47 $27.65 61.4% 23.1% 1.0658 24.7% 15.1% (0.0482) 0.7831 ‐3.78% 11.4%27 Pfizer, Inc. $2.10 $1.12 $11.25 46.7% 18.7% 1.0025 18.7% 8.7% (0.0007) 0.5909 ‐0.04% 8.7%28 Procter & Gamble $5.65 $3.00 $30.75 46.9% 18.4% 1.0264 18.9% 8.8% (0.0566) 0.6925 ‐3.92% 4.9%29 Raytheon Co. $6.25 $2.50 $41.40 60.0% 15.1% 1.0306 15.6% 9.3% (0.0453) 0.4982 ‐2.26% 7.1%30 Sherwin‐Williams $7.50 $2.20 $33.00 70.7% 22.7% 1.0717 24.4% 17.2% (0.0459) 0.7067 ‐3.25% 14.0%31 Sysco Corp. $2.90 $1.20 $10.95 58.6% 26.5% 1.0471 27.7% 16.3% (0.0449) 0.7810 ‐3.51% 12.7%32 Verizon Communic. $3.25 $2.12 $19.15 34.8% 17.0% 1.0336 17.5% 6.1% (0.0017) 0.6670 ‐0.11% 6.0%33 Walgreen Co. $4.10 $1.50 $20.30 63.4% 20.2% 1.0121 20.4% 13.0% (0.1085) 0.7100 ‐7.70% 5.3%34 Wal‐Mart Stores $6.00 $2.20 $24.20 63.3% 24.8% 1.0025 24.9% 15.7% (0.1210) 0.6877 ‐8.32% 7.4%

‐‐‐‐‐‐‐‐‐‐‐ 2015 ‐‐‐‐‐‐‐‐‐‐

BR+SV GROWTH RATE Exhibit WEA‐5Page 2 of 2


(a) (a) (f) (a) (a) (g) (a) (a) (f) ‐‐‐‐‐ Common Shares ‐‐‐‐‐

Company 2010 2015 Chg. High Low Avg. M/B 2010 2015 Growth1 Abbott Labs. $22,388 $31,500 7.1% $105.00 $85.00 $95.00 4.634 1,547.00 1,535.00 ‐0.16%2 AT&T Inc. $111,956 $147,060 5.6% $50.00 $40.00 $45.00 1.744 5,911.10 5,700.00 ‐0.72%3 Automatic Data Proc. $5,479 $10,200 13.2% $90.00 $75.00 $82.50 4.044 492.00 500.00 0.32%4 Bard (C.R.) $1,632 $3,340 15.4% $165.00 $135.00 $150.00 3.817 84.97 85.00 0.01%5 Baxter Intʹl Inc. $6,567 $11,950 12.7% $90.00 $75.00 $82.50 3.488 580.73 505.00 ‐2.76%6 Becton, Dickinson $5,435 $7,520 6.7% $135.00 $110.00 $122.50 3.306 229.82 203.00 ‐2.45%7 Bristol‐Myers Squibb $15,638 $19,230 4.2% $45.00 $35.00 $40.00 3.433 1,699.30 1,650.00 ‐0.59%8 Brown‐Forman ʹBʹ $2,060 $3,350 10.2% $95.00 $75.00 $85.00 3.427 144.99 135.00 ‐1.42%9 Church & Dwight $1,871 $2,800 8.4% $60.00 $45.00 $52.50 2.665 142.40 142.00 ‐0.06%10 Coca‐Cola $31,003 $45,000 7.7% $130.00 $105.00 $117.50 5.746 2,292.00 2,200.00 ‐0.82%11 Colgate‐Palmolive $2,675 $7,000 21.2% $160.00 $130.00 $145.00 9.325 494.85 450.00 ‐1.88%12 ConAgra Foods $4,924 $6,265 4.9% $40.00 $30.00 $35.00 2.236 442.27 400.00 ‐1.99%13 Costco Wholesale $10,829 $13,975 5.2% $115.00 $95.00 $105.00 3.079 433.51 410.00 ‐1.11%14 Exxon Mobil Corp. $146,839 $213,000 7.7% $140.00 $115.00 $127.50 2.394 4,979.00 4,000.00 ‐4.28%15 Genʹl Mills $5,403 $9,360 11.6% $60.00 $50.00 $55.00 3.583 656.50 610.00 ‐1.46%16 Heinz (H.J.) $3,109 $5,555 12.3% $80.00 $65.00 $72.50 4.240 321.77 325.00 0.20%17 Hormel Foods $2,407 $4,000 10.7% $45.00 $35.00 $40.00 2.667 265.96 267.00 0.08%18 Johnson & Johnson $56,579 $95,200 11.0% $100.00 $85.00 $92.50 2.584 2,738.10 2,660.00 ‐0.58%19 Kellogg $2,158 $3,270 8.7% $95.00 $80.00 $87.50 8.413 365.60 315.00 ‐2.94%20 Kimberly‐Clark $5,917 $7,420 4.6% $105.00 $85.00 $95.00 4.798 406.90 375.00 ‐1.62%21 Kraft Foods $35,942 $54,000 8.5% $60.00 $50.00 $55.00 1.783 1,748.10 1,750.00 0.02%22 Lorillard Inc. ($225) $1,175 NMF $205.00 $165.00 $185.00 20.109 147.00 128.00 ‐2.73%23 McCormick & Co. $1,463 $3,030 15.7% $100.00 $80.00 $90.00 4.009 133.10 135.00 0.28%24 McDonaldʹs Corp. $14,634 $17,000 3.0% $115.00 $95.00 $105.00 5.966 1,053.60 965.00 ‐1.74%25 McKesson Corp. $7,220 $12,660 11.9% $110.00 $90.00 $100.00 1.936 252.00 245.00 ‐0.56%26 PepsiCo, Inc. $21,476 $41,500 14.1% $140.00 $115.00 $127.50 4.611 1,581.00 1,500.00 ‐1.05%27 Pfizer, Inc. $87,813 $90,000 0.5% $30.00 $25.00 $27.50 2.444 8,012.00 8,000.00 ‐0.03%28 Procter & Gamble $61,439 $80,000 5.4% $110.00 $90.00 $100.00 3.252 2,838.50 2,600.00 ‐1.74%29 Raytheon Co. $9,754 $13,250 6.3% $90.00 $75.00 $82.50 1.993 359.00 320.00 ‐2.27%30 Sherwin‐Williams $1,609 $3,300 15.4% $125.00 $100.00 $112.50 3.409 107.02 100.00 ‐1.35%31 Sysco Corp. $3,828 $6,130 9.9% $55.00 $45.00 $50.00 4.566 588.38 560.00 ‐0.98%32 Verizon Communic. $38,575 $54,003 7.0% $65.00 $50.00 $57.50 3.003 2,828.10 2,820.00 ‐0.06%33 Walgreen Co. $14,400 $16,250 2.4% $75.00 $65.00 $70.00 3.448 938.61 800.00 ‐3.15%34 Wal‐Mart Stores $68,542 $70,245 0.5% $85.00 $70.00 $77.50 3.202 3,516.00 2,900.00 ‐3.78%

(a) www.valueline.com (retrieved Jul. 29, 2011).(b) Computed using the formula 2*(1+5‐Yr. Change in Equity)/(2+5 Yr. Change in Equity).(c) Product of year‐end ʺrʺ for 2015 and Adjustment Factor.(d) Product of change in common shares outstanding and M/B Ratio.(e) Computed as 1 ‐ B/M Ratio.(f) Five‐year rate of change.(g) Average of High and Low expected market prices divided by 2015 BVPS.

‐‐‐‐‐‐‐‐‐‐ 2015 Price ‐‐‐‐‐‐‐‐‐ ‐‐‐‐ Common Equity ‐‐‐‐

CAPM ‐ CURRENT BOND YIELD Exhibit WEA‐6Page 1 of 2

UTILITY PROXY GROUP

Market Rate of Return

Dividend Yield (a) 2.5%

Growth Rate (b) 11.0%

Market Return (c) 13.5%

Less: Risk‐Free Rate (d)Long‐term Treasury Bond Yield 3.1%

Market Risk Premium (e) 10.4%

Utility Proxy Group Beta (f) 0.75

Risk Premium (g) 7.8%

Plus: Risk‐free Rate (d)Long‐term Treasury Bond Yield 3.1%

Unadjusted CAPM (h) 10.9%

Size Adjustment (i) 0.81%

Implied Cost of Equity (j) 11.7%

(a)

(b)

(c) (a) + (b)(d)

(e) (c) ‐ (d).(f) www.valueline.com (retrieved Nov. 17, 2011).(g) (e) x (f).(h) (d) + (g).(i) Morningstar , ʺIbbotson SBBI 2011 Valuation Yearbook,ʺ at Table 7‐5 (2011). (j) (h) + (i).

Weighted average dividend yield for the dividend paying firms in the S&P 500 from www.valueline.com (retrieved Nov. 2, 2011).Weighted average of IBES earnings growth rates for the dividend paying firms in the S&P 500 (retrieved Nov. 15, 2011).

Average yield on 30‐year Treasury bonds for October 2011 from the Federal Reserve Board at http://www.federalreserve.gov/releases/h15/data/Monthly/H15_TCMNOM_Y20.txt.

CAPM ‐ PROJECTED BOND YIELD Exhibit WEA‐6Page 2 of 2

UTILITY PROXY GROUP

Market Rate of Return

Dividend Yield (a) 2.5%

Growth Rate (b) 11.0%

Market Return (c) 13.6%

Less: Risk‐Free Rate (d)Projected Long‐term Treasury Bond Yield 5.0%

Market Risk Premium (e) 8.6%

Utility Proxy Group Beta (f) 0.75

Risk Premium (g) 6.4%

Plus: Risk‐free Rate (d)Projected Long‐term Treasury Bond Yield 5.0%

Unadjusted CAPM (h) 11.4%

Size Adjustment (i) 0.81%

Implied Cost of Equity (j) 12.2%

(a)

(b)

(c) (a) + (b)(d)

(e) (c) ‐ (d).(f) www.valueline.com (retrieved Nov. 17, 2011).(g) (e) x (f).(h) (d) + (g).(i) Morningstar , ʺIbbotson SBBI 2011 Valuation Yearbook,ʺ at Table 7‐5 (2011). (j) (h) + (i).

Weighted average dividend yield for the dividend paying firms in the S&P 500 from www.valueline.com (retrieved Nov. 2, 2011).Weighted average of IBES earnings growth rates for the dividend paying firms in the S&P 500 (retrieved Nov. 15, 2011).

Average projected 30‐year Treasury bond yield for 2012‐2015 based on data from the Value Line Investment Survey, Forecast for the U.S. Economy (Nov. 25, 2011), IHS Global Insight, U.S. Economic Outlook at 19 (Feb. 2011), Blue Chip Financial Forecasts, Vol. 30, No. 6 (Jun. 1, 2010).

ELECTRIC UTILITY RISK PREMIUM Exhibit WEA‐7Page 1 of 4

CURRENT BOND YIELDS

Current Equity Risk Premium(a) Avg. Yield over Study Period 9.01%(b) October 2011 Average Utility Bond Yield 4.66%

Change in Bond Yield ‐4.35%

(c) Risk Premium/Interest Rate Relationship ‐0.4095Adjustment to Average Risk Premium 1.78%

(a) Average Risk Premium over Study Period 3.36%Adjusted Risk Premium 5.14%

Implied Cost of Equity(b) October 2011 BBB Utility Bond Yield 5.24%

Adjusted Equity Risk Premium 5.14%

Risk Premium Cost of Equity 10.38%

(a) Exhibit WEA‐7, page 3.(b) Moodyʹs Investors Service, www.creditrends.com.(c) Exhibit WEA‐7, page 4.


PROJECTED BOND YIELDS

Current Equity Risk Premium(a) Avg. Yield over Study Period 9.01%(b) Projected Avg. Utility Bond Yield 2012‐15 6.79%

Change in Bond Yield ‐2.22%

(c) Risk Premium/Interest Rate Relationship ‐0.4095Adjustment to Average Risk Premium 0.91%

(a) Average Risk Premium over Study Period 3.36%Adjusted Risk Premium 4.27%

Implied Cost of Equity(d) Projected BBB Utility Bond Yield 2012‐15 7.22%

Adjusted Equity Risk Premium 4.27%

Risk Premium Cost of Equity 11.49%

(a) Exhibit WEA‐7, page 3.(b)

(c) Exhibit WEA‐7, page 4.(d) Table WEA‐3.

Implied average yield on utility bonds for 2012‐15 based on data from IHS Global Insight, U.S. Economic Outlook at 19 (Feb. 2011), Energy Information Administration, Annual Energy Outlook 2011 (Apr. 26, 2011), and Moodyʹs Investors Service at www.credittrends.com.


AUTHORIZED RETURNS(a) (b)

Allowed Average Utility RiskYear ROE Bond Yield Premium

1974 13.10% 9.27% 3.83%1975 13.20% 9.88% 3.32%1976 13.10% 9.17% 3.93%1977 13.30% 8.58% 4.72%1978 13.20% 9.22% 3.98%1979 13.50% 10.39% 3.11%1980 14.23% 13.15% 1.08%1981 15.22% 15.62% ‐0.40%1982 15.78% 15.33% 0.45%1983 15.36% 13.31% 2.05%1984 15.32% 14.03% 1.29%1985 15.20% 12.29% 2.91%1986 13.93% 9.46% 4.47%1987 12.99% 9.98% 3.01%1988 12.79% 10.45% 2.34%1989 12.97% 9.66% 3.31%1990 12.70% 9.76% 2.94%1991 12.55% 9.21% 3.34%1992 12.09% 8.57% 3.52%1993 11.41% 7.56% 3.85%1994 11.34% 8.30% 3.04%1995 11.55% 7.91% 3.64%1996 11.39% 7.74% 3.65%1997 11.40% 7.63% 3.77%1998 11.66% 7.00% 4.66%1999 10.77% 7.55% 3.22%2000 11.43% 8.09% 3.34%2001 11.09% 7.72% 3.37%2002 11.16% 7.53% 3.63%2003 10.97% 6.61% 4.36%2004 10.75% 6.20% 4.55%2005 10.54% 5.67% 4.87%2006 10.36% 6.08% 4.28%2007 10.36% 6.11% 4.25%2008 10.46% 6.65% 3.81%2009 10.48% 6.28% 4.20%2010 10.34% 5.56% 4.78%

Average 12.38% 9.01% 3.36%

(a)

(b) Moodyʹs Investors Service.

Major Rate Case Decisions, Regulatory Focus, Regulatory Research Associates; UtilityScope Regulatory Service , Argus.


REGRESSION RESULTS

SUMMARY OUTPUT

Regression StatisticsMultiple R 0.9007749R Square 0.8113955Adjusted R Square 0.8060068Standard Error 0.0052509Observations 37

ANOVAdf SS MS F Significance F

Regression 1 0.004151593 0.00415 150.573 3.1021E‐14Residual 35 0.000965016 2.8E‐05Total 36 0.005116609

Coefficients Standard Error t Stat P‐value Lower 95% Upper 95% Lower 95.0% Upper 95.0%Intercept 0.0705528 0.003129538 22.5441 2E‐22 0.06419946 0.07690607 0.064199459 0.076906074X Variable 1 ‐0.409496 0.033371508 ‐12.2708 3.1E‐14 ‐0.4772442 ‐0.3417485 ‐0.47724424 ‐0.34174854

COMPARABLE EARNINGS APPROACH Exhibit WEA‐8Page 1 of 1

UTILITY PROXY GROUP

(a) (b) (c)

Expected Return Adjustment Adjusted ReturnCompany on Common Equity Factor on Common Equity

1 Alliant Energy 12.0% 1.019234 12.2%2 ALLETE 9.5% 1.029985 9.8%3 Ameren Corp. 7.0% 1.01744 7.1%4 Avista Corp. 9.0% 1.02055 9.2%5 Black Hills Corp. 7.5% 1.022337 7.7%6 CenterPoint Energy 11.5% 1.046754 12.0%7 CMS Energy 12.5% 1.033447 12.9%8 DTE Energy Co. 9.0% 1.018735 9.2%9 Empire District Elec 9.5% 1.015554 9.6%10 Entergy Corp. 11.5% 1.027496 11.8%11 Exelon Corp. 15.0% 1.020066 15.3%12 Integrys Energy Group 9.5% 1.012171 9.6%13 Pepco Holdings 7.5% 1.022648 7.7%14 PG&E Corp. 11.5% 1.035992 11.9%15 PPL Corp. 11.5% 1.074133 12.4%16 Pub Sv Enterprise Grp 12.5% 1.033632 12.9%17 SCANA Corp. 9.5% 1.041545 9.9%18 Sempra Energy 10.5% 1.035388 10.9%19 TECO Energy 13.0% 1.02892 13.4%20 UIL Holdings 9.0% 1.022536 9.2%

Average (d) 10.7%

(a) The Value Line Investment Survey ( Aug. 26, Sep. 23, & Nov. 4, 2011).(b) Adjustment to convert year‐end return to an average rate of return from Exhibit WEA‐3.(c) (a) x (b).(d) Excludes highlighted figures.

CAPITAL STRUCTURE Exhibit WEA‐9Page 1 of 1

UTILITY PROXY GROUP

Common CommonCompany Debt Preferred Equity Debt Other Equity

1 Alliant Energy 46.3% 4.2% 49.5% 45.5% 3.0% 51.5%2 ALLETE 44.4% 0.0% 55.6% 41.5% 0.0% 58.5%3 Ameren Corp. 47.1% 0.0% 52.9% 45.5% 1.0% 53.5%4 Avista Corp. 47.4% 2.2% 50.4% 51.5% 0.0% 48.5%5 Black Hills Corp. 52.0% 0.0% 48.0% 50.0% 0.0% 50.0%6 CenterPoint Energy 74.7% 0.0% 25.3% 68.5% 0.0% 31.5%7 CMS Energy 71.7% 0.0% 28.3% 64.0% 0.5% 35.5%8 DTE Energy Co. 49.9% 2.1% 48.0% 52.0% 0.0% 48.0%9 Empire District Elec 51.3% 0.0% 48.7% 47.0% 0.0% 53.0%10 Entergy Corp. 54.8% 1.6% 43.6% 56.5% 1.0% 42.5%11 Exelon Corp. 47.2% 0.3% 52.4% 46.5% 0.0% 53.5%12 Integrys Energy Group 47.6% 0.0% 52.4% 45.0% 0.5% 54.5%13 Pepco Holdings 46.6% 0.0% 53.4% 48.0% 0.0% 52.0%14 PG&E Corp. 50.4% 1.1% 48.5% 45.5% 1.0% 53.5%15 PPL Corp. 59.9% 0.0% 40.1% 43.0% 1.0% 56.0%16 Pub Sv Enterprise Grp 48.1% 0.0% 51.9% 44.5% 0.0% 55.5%17 SCANA Corp. 54.8% 0.0% 45.2% 50.5% 0.0% 49.5%18 Sempra Energy 50.2% 0.5% 49.2% 49.0% 0.0% 51.0%19 TECO Energy 59.4% 0.0% 40.6% 52.5% 0.0% 47.5%20 UIL Holdings 60.7% 0.0% 39.2% 58.5% 0.0% 41.5%

Average 53.2% 0.6% 46.2% 50.3% 0.4% 49.4%

(a) Company Form 10‐K and Annual Reports.(b) The Value Line Investment Survey ( Aug. 26, Sep. 23, & Nov. 4, 2011).

Value Line Projected (b)At Fiscal Year‐End 2010 (a)