docket no. d2016.9 - northwestern energy...docket no. 02016.9.68 phase two transmittal letter may31,...

BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MONTANA

DOCKET NO. D2016.9.68

Application for Authority to Change and Establish Natural Gas Delivery Service and Production Rates

Revenue Requirement (Phase One)

Allocated Cost of Service and Rate Design (Phase Two)

TESTIMONY AND EXHIBITS STATEMENTS & WORKPAPERS

(PHASE TWO)

May 31, 2017

r NorthWestern Energy

Delivering a Bright Future

Mr. Will Rosquist Administrator, Regulatory Division Montana Public Service Commission 1701 Prospect Avenue PO Box 202601 Helena, MT 59620-2601

May 31, 2017

RE: Docket No. 02016.9.68 - In the Matter of NorthWestern Energy's Application for Approval to Change and Establish Natural Gas Delivery Service and Production Rates - Phase Two - Allocated Cost of Service and Rate Design

Dear Mr. Rosquist:

NorthWestern Corporation, d/b/a NorthWestern Energy ("NorthWestern"), submits its Application for Phase Two - Allocated Cost of Service and Rate Design in Docket No. D2016.9.68. An original and ten copies are enclosed.

On September 2, 2016, NorthWestern filed its Motion to Bifurcate this Rate Case. The Commission granted NorthWestern's Motion. Ultimately, the Commission approved NorthWestern's request that the Phase Two portion of this docket be filed no later than May 31 , 2017.

NorthWestern retained Management Applications Consulting, Inc. ("MAC") to · complete the required allocated cost of service studies:

• embedded cost of service - transmission , distribution , storage, and production; and

• marginal cost of service - production.

As described in testimony, the embedded cost of service studies performed by MAC are well-developed , thorough analyses that provide a sound basis for rate development.

MAC also developed the rate design proposals in this filing with certain guidance from NorthWestern as described in the testimony.

11 EParkSt I Butte, MT59701-1711 I 0 406-497-1000 I F 406-497-2535 NorthWestern Energy.com

Docket No. 02016.9.68 Phase Two Transm ittal Letter May31 , 2017 Page 2 of 3

NorthWestern has also proposed a revision to its Natural Gas Tariff, Rule 6 -Line Extensions.

NorthWestern formed a stakeholder group that included NorthWestern employees, a representative of the Montana Consumer Counsel ("MCC"), two Commission staff members, and other interested parties to explore the rationale for, and the presentation and design of, a potential natural gas utility decoupling mechanism proposal. Four meetings were held. NorthWestern ultimately determined that it would not make a proposal for a natural gas decoupling mechanism at this time.

Documents submitted with this filing are:

1. Application ;

2. Marked-Up Tariffs;

3. Prefiled Direct Testimony and Exhibits of Joe Schwartzenberger;

4. Prefiled Direct Testimony and Exhibits of Paul M. Normand of MAC;

5. Statement L -Allocated Cost of Service; and

6. Statement M - Rate Design.

Three copies of this letter and documents submitted herewith are being delivered to the MCC. One copy of this filing is being served on the parties of record in Phase One of this docket.

The NorthWestern employee responsible for answering questions concerning this rate change request or for inquiries to the appropriate members of the Utility Staff is:

Joe Schwartzenberger Regulatory Affairs Department NorthWestern Energy 11 East Park St. Butte, MT 59701 (406) 497-3362 joe.schwartzenberger@northwestern .com

Docket No. 02016.9.68 Phase Two Transm ittal Letter May31, 2017 Page 3 of 3

NorthWestern's attorneys in this matter are:

Mr. Al Brogan NorthWestern Energy 208 N. Montana, Suite 205 Helena, Montana 59601 Tel. (406) 443-8903 al.brogan@northwestern .com

Ms. Ann Hill NorthWestern Energy 208 N. Montana Ave., Suite 205 Helena, Montana 59601 Tel. (406) 444-8110 ann [email protected]

Along with Joe Schwartzenberger, Al Brogan , and Ann Hill, please add Connie Moran to the official service list in this docket to receive copies of all documents. NorthWestern also requests that all electronic correspondence related to this filing be sent to [email protected].

If there are any questions in this regard , I can be reached at (406) 497-3362.

Enclosures cc: Montana Consumer Counsel

Sincerely,

() v ('\ · ,-~-:-=k:::_:~.:~:·----··· .. / (;.v Ac.Yv...:r o:-;; ~~

aoe Schwartzenberger Director of Regulatory Affairs

1

AL BROGAN NorthWestern Energy 208 N. Montana, Suite 205 Helena, Montana 59601 Tel. (406) 443-8903 [email protected] ANN HILL NorthWestern Energy 208 N. Montana, Suite 205 Helena, MT 59601 Tel. (406) 444-8110 [email protected] Attorneys for NorthWestern Energy

DEPARTMENT OF PUBLIC SERVICE REGULATION BEFORE THE PUBLIC SERVICE COMMISSION

OF THE STATE OF MONTANA IN THE MATTER OF NorthWestern’s ) REGULATORY DIVISION Request for Authority to Change and ) DOCKET NO. D2016.9.98 Establish Natural Gas Delivery Service and ) Production Rates – Phase Two Allocated ) Cost of Service and Rate Design

NorthWestern Energy’s Application for Phase Two

of this Docket

NorthWestern Corporation d/b/a NorthWestern Energy (“NorthWestern”) respectfully

submits this Application for Phase Two – Allocated Cost of Service and Rate Design

(“Application – Phase Two”) in this Docket to the Montana Public Service Commission

(“Commission”). In support thereof, NorthWestern states as follows:

2

I. Applicant's full name and Post Office address are:

North Western Energy 11 East Park Butte, MT 59701

II. Applicant is NorthWestern Corporation doing business as NorthWestern Energy in the States

of Montana, South Dakota and Nebraska as a public utility.

III.

The following described tariff sheets are the natural gas sheets impacted by the proposals in

this submittal that are presently in effect in the State of Montana and on file with the

Commission. All other natural gas sheets remain as previously approved by the Commission:

Natural Gas Rates:

Schedule Description Sheet No.

D-RG-1 Residential Natural Gas Service 10.1 D-RGCA-1 Residential Gas Core Aggregation Service 11.1 D-GSG-1 General Natural Gas Service 20.1 D-GSGCA-1 General Service Gas Core Aggregation 21.1 D-FTG-1 Firm Transportation Natural Gas Service 25.1 D-ITG-1 Interruptible Transportation Natural Gas Service 27.1 T-FUGC-1 Firm Utility Gas Contract Service 30.1 T-FTG-1 Firm Transportation Natural Gas Service 80.1 T-ITG-1 Interruptible Transportation Natural Gas Service 85.1 T-FSG-1 Firm Storage Natural Gas Service 90.1 Rule No. 6 Line Extensions R-6.1

3

IV.

Applicant will submit new tariff sheets for natural gas service to customers served by

Applicant in the State of Montana upon approval of the changes proposed in this filing. The

proposed new sheets will replace the present tariff sheets as follows:

Natural Gas Rates:

Schedule Description Sheet No.

D-RG-1 Residential Natural Gas Service 10.1 D-RGCA-1 Residential Gas Core Aggregation Service 11.1 D-GSG-1 General Natural Gas Service 20.1 D-GSGCA-1 General Service Gas Core Aggregation 21.1 D-FTG-1 Firm Transportation Natural Gas Service 25.1 D-ITG-1 Interruptible Transportation Natural Gas Service 27.1 T-FUGC-1 Firm Utility Gas Contract Service 30.1 T-FTG-1 Firm Transportation Natural Gas Service 80.1 T-ITG-1 Interruptible Transportation Natural Gas Service 85.1 T-FSG-1 Firm Storage Natural Gas Service 90.1 Rule No. 6 Line Extensions R-6.1

V. North Western has prepared, and files concurrently with this Application, its allocated cost of

service and rate design information, including Testimony and Exhibits and Statements L and

M prepared in accordance with the information required in Commission rules Allocated Cost

of Service (ARM 38.5.176) and Rate Design (ARM 38.5.177).

VI.

Attached in support of this filing are the following documents that are by this reference made

a part hereof:

1. Marked-Up Tariffs;

2. Prefiled Direct Testimony and Exhibits of Joe Schwartzenberger;

3. Prefiled Direct Testimony and Exhibits of Paul M. Normand;

4. Statement L - Allocated Cost of Service; and

5. Statement M - Rate Design.

Wherefore, NorthWestern respectfully requests that the Commission:

1. Approve the Natural Gas Supply Rate Design proposals

as presented in this filing;

2. Approve the Natural Gas Line Extension Tariff revisions

as presented in this filing;

Respectfully submitted this 31 st day of May 2017.

NORTHWESTERN ENERGY

4

CERTIFICATE OF SERVICE

I hereby certify that the original and eleven copies of NorthWestern Energy’s Allocated Cost of Service and Rate Design (Phase Two) in Docket No. D2016.9.68, the Natural Gas General Rate Filing, has been hand delivered to the Montana Public Service Commission with three copies to the Montana Consumer Counsel this date. It has also been e-filed with the Montana Public Service Commission and emailed to counsel of record and to those requesting electronic service only. It has also been served upon the following persons by postage prepaid via first class mail as follows: Robert Nelson Montana Consumer Counsel PO Box 201703 Helena, MT 59620-1703 Pat Corcoran NorthWestern Energy 11 East Park Butte MT 59701 Joe Schwartzenberger NorthWestern Energy 11 East Park Butte MT 59701 Thorvald A. Nelson Holland & Hart 6380 S. Fiddlers Green Circle Suite 500 Greenwood Village CO 80111 Ann Hill NorthWestern Energy 208 N Montana Ave Suite 205 Helena MT 59601

George Donkin J W Wilson & Associates Rosslyn Plaza E - Suite 602 1621 North Kent Street Arlington VA 22209 Kevin Degenstein Chief Operating Officer Gas Natural Inc. PO Box 2229 Great Falls MT 59403 Dr. John W. Wilson J W Wilson & Associates Rosslyn Plaza E - Suite 602 1621 North Kent Street Arlington VA 22209 Will Rosquist Administrator, Regulatory Div. Public Service Commission 1701 Prospect Ave PO Box 202601 Helena, MT 59620-2601

Connie Moran NorthWestern Energy 11 East Park Butte MT 59701 Al Brogan NorthWestern Energy 208 N Montana Ave Suite 205 Helena MT 59601 Al Clark 142 Buccaneer Drive Leesburg FL 34788 Nikolas S Stoffel Holland & Hart 6380 S. Fiddlers Green Circle Suite 500 Greenwood Village CO 80111 Jed Henthorne President and General Manager Energy West Montana Inc. PO Box 2229 Great Falls MT 59403

DATED this 31st day of May 2017.

Connie Moran Administrative Assistant

NorthWestern Energy

NATURAL GAS TARIFF

Revised Canceling Revised

Schedule No. D-RG-1

DISTRIBUTION BUSINESS UNIT RESIDENTIAL NATURAL GAS SERVICE

Sheet No. Sheet No.

APPLICABILITY: Applicable to residential service, including single family dwellings and single family living units which are individually metered, in all territory served by the Utility Distribution Business Unit (Utility).

RATES: Net Monthly Bill: Monthly Service Charge per Meter:

Commodity Charges (Monthly $/Therm)

Total Rate

~ $ 8.25

Distribution Charge $ 0.2451485

Transmission Charge

Storage Charge

Gas Supply Charge

Def erred Gas Cost Amortization DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization

Total

$ 0.1802384 0.1311393 0.1754036 0.0399117 0.0221061 0.2607600 0.2779149 0.0000000 0.0000203

(0.0014935) 0.0000000

$ 0.6754863 $ 0.6541898

Tax Portion of Rate

$ 0.0782676 $ 0.0723782

0.0323192 0.0467994 0.0098361 0.0050338 0.0001000 0.0022961

$ 0.1205229 $ 0.1265075

Rate Without Tax

~ $ 8.25

$ 0.1668809 $ 0.1078602

0.0988201 0.1286042 0.0300756 0.0170723 0.2606600 0.2756188 0.0000000 0.0000203

(0.0014935) 0.0000000

$ 0.5549634 $ 0.5276823

TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer' s bill.

PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.

LOW INCOME DISCOUNT: Customers of the Utility shall obtain a thirty percent (30%) discount during November 1st to April 30th from the above Regular Customer Rate(s) for residential usage, if they have satisfied the requirements for and are receiving energy assistance through the LIEAP program administered by the State of Montana Department of Public Health and Human Services.

(continued)

NATURAL GAS TARIFF

NorthWesterti Energy Canceling

44111 Revised 43rct Revised

Schedule No. D-RGCA-1

Sheet No. Sheet No.

11.1 11.1

DISTRIBUTION BUSINESS UNIT RESIDENTIAL GAS CORE AGGREGATION SERVICE

APPLICABILITY: Applicable to residential service, including single family dwellings and single family living units which are individually metered, being served under the Core Aggregation Gas Transportation Program (Program) in all territory served by the Utility Distribution Business Unit (Utility).

AVAILABILITY: Available to residential service customer loads, aggregated in accordance with Rate Schedule No. AGCT-1 and as is administratively feasible for the Utility.

RATES: Net Monthly Bill:

PLUS :

Monthly Service Charge per Meter:

Commodity Charges (Monthly $/Therm Distribution Charge

Transmission Charge

Storage Charge

DBU GT AC Amortization TBU GT AC Amortization Storage GTAC Amortization

Total

Total Rate

$-+.&G $ 8.25

$ 0.2451485 $ 0.1802384

0.1311393 0.1754036 0.0399117 0.0221061 0.0000203

(0.0014935) 0.0000000

Tax Portion of Rate Without

$ 0.0782676 $ 0.0723782

0.0323192 0.0467994 0.0098361 0.0050338

$-+.&G $ 8.25

$ 0.1668809 $ 0.1078602

0.0988201 0.1286042 0.0300756 0.0170723 0.0000203

(0.0014935) 0.0000000

$ 0.4147?63 $ 0.1?04?29 $ 0.?943034 $ 0.3762749 $ 0.1242114 $ 0.2520635

TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.


LOW INCOME DISCOUNT: Customers of the Utility shall obtain a thirty percent (30%) discount during November 1st to April 30tl1 from the above Regular Customer Rate(s) for residential usage, if they have satisfied the requirements for and are receiving energy assistance through the LIEAP program administered by the State of Montana Department of Public Health and Human Services.

DEFERRED GAS COST: Pursuant to MPSC Order the above Deferred Gas Cost Amortization shall be in effect until the balance is extinguished.

GAS TRANSPORTATION ADWSTMENT CLAUSE: Pursuant to MPSC Order the above GTAC Amortization shall be in effect until the balance is extinguished.

(continued)

NorthWestenf Energy

NATURAL GAS TARIFF


Schedule No. D-GSG-1

DISTRIBUTION BUSINESS UNIT GENERAL NATURAL GAS SERVICE

Sheet No. Sheet No.

APPLICABILITY: Applicable to commercial, industrial, multiple apartment buildings containing two or more dwelling units served through one meter, and other nonresidential core service in all territory served by the Utility Distribution Business Unit (Utility).

RATES: Net Monthly Bill: Monthly Servie Charge per Meter: Meters Rated @ Cu. Ft. per hour

0 to 300 301 to 1,000

1,001 to 2,000 2,001 to 5,000 5,001 to 10,000

10,001 to 30,000 >30,000

PLUS: Commodity Charges (Monthly $/Therm)

Distribution Charge

Transmission Charge

Storage Charge

Gas Supply Charge

Deferred Gas Cost Amortization DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization

Total

Total Rate

~ $16.60 ~ $21.90 $32.00 $35 .25 ~ $59 .25 ~ $72.75 $104 .35 $115 .00 $126.80 $139 .75

$ 0.2377063 $ 0.1777142

0.1267723 0.1886518 0.0384956 0.0245645 0.2607600 0.2779149 0.0000000 0.0000215

(0.0015870) 0.0000000

$ 0.6628487 $ 0.6541898

Tax Portion of Rate

$ 0.0764174 $ 0.0568862

0.0313002 0.0445858 0.0095047 0.0049248 0.0001000 0.0022961

$ 0.1173?23 $ 0.1086929

Rate Without

~ $16.60 ~ $21.90 ~ $35 .25 ~ $59.25 ~ $72.75 $104 .35 $115 .00 $126.80 $139 .75

$ 0.1612889 $ 0.1208280

0.0954721 0.1440660 0.0289909 0.0196397 0.2606600 0.2756188 0.0000000 0.0000215

(0 .0015870) 0.0000000

$ 0.5455264 $ 0.5276823



DEFERRED GAS COST: Pursuant to MPSC Order the above Deferred Gas Cost Amortization shall be in effect until the balance is extinguished.

(continued)

NorthWestern Energy

NATURAL GAS TARIFF

41 st Revised Canceling 4ot1i Revised

Schedule No. D-GSGCA-1

DISTRIBUTION BUSINESS UNIT GENERAL SERVICE GAS CORE AGGREGATION

Sheet No. Sheet No.

21.1 21.1

APPLICABILITY: Applicable to commercial, industrial, multiple apartment buildings containing two or more dwelling units served through one meter, and other nonresidential core service, being served under the Core Aggregation Gas Transportation Program (Program) in all territory served by the Utility Distribution Business Unit (Utility) .

AVAILABILITY: Available to general service customer loads, aggregated in accordance with Rate Schedule No. AGCT-1 and as is administratively feasible for the Utility.

RATES: Net Monthly Bill: Monthly Servie Charge per Meter: Meters Rated @ Cu. Ft. per hour

0 to 300 301 to 1,000

1,001 to 2,000 2,001 to 5,000 5,001 to 10,000

10,001 to 30,000 >30,000

PLUS : Commodity Charges (Monthly $/Therm)

Distribution Charge

Transmission Charge

Storage Charge

DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization

Total

Total Rate

~ $16.60

~ $21.90 $32.00 $35 .25

~ $59 .25

~ $72.75 $104.35 $115 .00 $126.80 $139 .75

$ 0.2377063 $ 0.1777142

0.1?677?3 0.1886518 0.0384956 0.0245645 0.0000215

(0.0015870) 0.0000000

$ 0.4014087 $ 0.3893650

Tax Portion of Rate

$ 0.0764174 $ 0.0568862

0.031300? 0.0445858 0.0095047 0.0049248

$ 0.1172?23 $ 0.1063968

Rate Without Tax

~ $16 .60 ~ $21 .90 W-,00.- $35 .25 ~ $59 .25 ~ $72.75 $104 .35 $115 .00 $126.80 $139 .75

$ 0.161?889 $ 0.1208280

0.0954721 0.1440660 0.0289909 0.0196397 0.0000215

(0 .0015870) 0.0000000

$ 0.?841864 $ 0.2829682



(continued)

NATURAL GAS TARIFF

NorthWestern Energy Canceling

41 st Revised 40111 Revised

Sheet No. Sheet No.

Schedule No. D-FTG-1

DISTRIBUTION BUSINESS UNIT FIRM TRANSPORTATION NATURAL GAS SERVICE

APPLICABILITY: Applicable to Shippers for finn transportation service on the Utility Distribution System under the tenns of a Gas Transportation Service Agreement (Agreement) between the Utility Distribution Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).



Meters Rated @ Cu. Ft. per hour

2,000 to 5,000 5,000 to 10,000

10,001 to 30,000 >30,000

PLUS: Distribution Charge: ($/MDDQ)

Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)

GT AC Amortization (MDDQ)

Total Rate

$ 97.35 $ 125.60 $ 111.25$143.55 $ 152.90 $ 197.30 $ 177.55 $ 229.10

$ 0.8532345 $ 0.8616035 $ 0.0001412

Tax Portion of Rate

$ 0.2374280 $ 0.2932334

Rate Without Tax

$ 97.35 $ 125.60 $ 111.25 $ 143.55 $ 152.90 $ 197.30 $ 177.55 $ 229.10

$ 0.6158065 $ 0.5683701 $ 0.0001412

MINIMUM BILL: Per respective contracts. $ 0.0017935 $ 0.0017935 TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.

PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1 .

APPLICATION OF RATES :

Monthly Bill Components: Each month, Shipper' s bill shall consist of a Monthly Service Charge and a Reservation Charge.

1. Monthly Service Charge: The Monthly Service Charge shall be the product of the number of delivery meters at Shipper' s facility times the applicable Meter Charge(s) set forth above under RATES. If Shipper receives service under more than one rate schedule through a single meter, only one Service Charge per meter per month shall apply.

(continued)

NATURAL GAS TARIFF

NorthWesterii Energy

27th Revised Canceling 26th Revised

Sheet No. Sheet No.

27.1 27.1

Schedule No. D-ITG-1

DISTRIBUTION BUSINESS UNIT INTERRUPTIBLE TRANSPORTATION NATURAL GAS SERVICE

APPLICABILITY: Applicable to Shippers for interruptible transportation service on the Utility Distribution System under the terms of an Interruptible Gas Transportation Service Agreement (Agreement) between the Utility Distribution Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).




2,000 to 5,000 5,000 to 10,000

10,001 to 30,000 >30,000

PLUS: Distribution Charge: (Monthly Rate per Therm)

Distribution Commodity Rate

MINIMUM BILL: Per respective contracts.

Total Rate

$ 97.35 $ 125.60 $ 111.25 $ 143.55 $ 152.90 $ 197.30 $ 177.55 $ 229.10

$ 0.0268518 $ 0.0279461

Tax Portion of Rate

$ 0.0066037 $ 0.0057117

Rate Without

$ 97.35 $ 125.60 $ 111.25$143.55 $ 152.90$197.30 $ 177.55 $ 229.10

$ 0.0202481 $ 0.0222344

TAX PORTION OF RA TE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.

PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1.

APPLICATION OF RATES: Monthly Bill Components: Each month, Shipper's bill shall include a Monthly Service Charge and an Interruptible Distribution Commodity Charge for the actual quantities of natural gas delivered for Shipper.

1. Monthly Service Charge: The Monthly Service Charge shall be the product of the number of delivery meters at Shipper 's facility times the applicable Meter Charge(s) set forth above. If Shipper receives service under more than one rate schedule through a single meter, only one service charge per meter per month shall apply.

2. Commodity Charge: The Monthly Commodity Charge shall be the produce of the actual monthly quantities of gas delivered to Shipper at Shipper ' s Point(s) of Delivery times the Maximum Distribution Commodity Rate set forth above, unless otherwise negotiated between the Utility and Shipper.

(continued)

NorthWestern Energy

NATURAL GAS TARIFF


Schedule No. T-FUGC-1

TRANSPORTATION BUSINESS UNIT FIRM UTILITY GAS CONTRACT SERVICE

Sheet No. Sheet No.

APPLICABILITY: Applicable to natural gas utilities receiving service as of November 1, 1991 for Firm Utility Gas Contract Sales Service provided under terms and conditions of contracts with the Utility Transportation Business Unit (Utility) as approved by the Montana Public Service Commission.

RATES: Net Monthly Bill Monthly Service Charge per Meter:


10,001 to 30,000 >30,000

PLUS: Transmission Charges: Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)

Transmission Commodity Rate (Therm)

GT AC Amortization (Therm) PLUS : Storage Charges: Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)

Storage Commodity Rate (Therm)

Storage GT AC Amortization (MDDQ) PLUS: Gas Supply Charges (Therm)

Deferred Gas Cost Amortization (Therm)

Total Rate

$101.65 $149 .05 $262.10 $384.40

$ 0.6563?77 $ 0.7802544 $ 0.0090245 $ 0.0093001

$ (0.0014680)

$ 0.5219868 $ 0.1617700 $ 0.001888? $ 0.0005852 $ 0.0000000

$ 0.?607600 $ 0.2779149 $ 0.0000000

Tax Portion of Rate

$ 0.1614102 $ 0.3159685 $ 0.0031?53 $ 0.0037662

$ 0.1283718 $ 0.0560650 $ 0.0004643 $ 0.0002028

$ 0.0001000 $ 0.0022961

Rate Without Tax

$101.65 $149 .05 $26? .10 $384.40

$ 0.4949175 $ 0.4642679 $ 0.0058992 $ 0.0055339

$ (0.0014680)

$ 0.3936150 $ 0.1057050 $ 0.0014239 $ 0.0003824 $ 0.0000000

$ 0.2606600 $ 0.2756188 $ 0.0000000



(continued)

NorthWestern Energy

NATURAL GAS TARIFF

41 st Revised Canceling 40t11 Revised

Schedule No. T-FTG-1

TRANSPORTATION BUSINESS UNIT FIRM TRANSPORTATION NATURAL GAS SERVICE

Sheet No. Sheet No.

80.1 80.1

APPLICABILITY: Applicable to Shippers for firm transportation service on the Utility Transmission System under the terms of a Firm Gas Transportation Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).




5,000 to 10,000 10,001 to 30,000

>30,000 PLUS: Transmission Reservation Rate (MDDQ):

Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)

Transmission Commodity Rate (Therm):

Maximum

Minimum

GT AC Amortization

Balancing Penalty Rate

Total Rate

$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70

$ 1.0323733 $ 1.0462758

$ 0.0079951 $ 0.0079285 $ 0.0017935

$ (0.0007528)

Tax Portion of Rate

$ 0.2538910 $ 0.3010417

$ 0.0020959 $ 0.0022812

Higher of $25 .001 Dekatherm Or 150% of Market Price

Rate Without Tax

$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70

$ 0.7784823 $ 0.7452341

$ 0.0058992 $ 0.0056473 $ 0.0017935

$ (0.0007528)



GAS TRANSPORTATION ADJUSTMENT CLAUSE: Pursuant to MPSC Order the above GTAC Amortization shall be in effect until the balance is extinguished.


(continued)

NorthWesteni Energy

NATURAL GAS TARIFF

41 st Revised Canceling 40111 Revised

Schedule No. T-ITG-1

Sheet No. Sheet No.

TRANSPORTATION BUSINESS UNIT INTERRUPTIBLE TRANSPORTATION NATURAL GAS SERVICE

APPLICABILITY: Applicable to Shippers for interruptible transportation service on the Utility Transmission System under the terms of an Interruptible Gas Transportation Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).




5,000 to 10,000 10,001 to 30,000

>30,000 PLUS: Transmission Charge (Therm):

Maximum: Transmission Commodity Rate

Minimum: Transmission Commodity Rate

Balancing Penalty Rate

Unauthorized System Use Rate

Total Rate

$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70

$ 0.0411794 $ 0.0424136

$ 0.0017935

Tax Portion of Rate

$ 0.0104419 $ 0.0086686

Higher of $25 .00/ Dekatherm Or 150% of Market Price

$ 25.00


Rate Without Tax

$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70

$ 0.0307375 $ 0.0337450

$ 0.0017935

TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer' s bill.


PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1 .

(continued)

NorthWestern Energy

NATURAL GAS TARIFF

Canceling 40th Revised 39t1i Revised

Schedule No. T-FSG-1

TRANSPORTATION BUSINESS UNIT FIRM STORAGE NATURAL GAS SERVICE

Sheet No. Sheet No.

APPLICABILITY: Applicable to Shippers for Firm Storage Service under the terms of a Firm Gas Storage Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and the Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).

RATES: Tax Portion of Rate Without Total Rate Rate Tax

Monthly Rate: Withdrawal Reservation Rate (MDDQ): $ 0.4934520 $ 0.1217889 $ 0.3716631

$ 0.4950196 $ 0.1008486 $ 0.3941710 Injection Commodity Rate (Therm): $ 0.0025500 $ 0.0006292 $ 0.0019208

$ 0.0025583 $ 0.0005212 $ 0.0020371 Withdrawal Commodity Rate (Therm): $ 0.00?5500 $ 0.0006292 $ 0.0019208

$ 0.0025583 $ 0.0005212 $ 0.0020371 Storage Capacity Rate (Therm) : $ 0.00?42?6 $ 0.0005980 $ 0.0018246

$ 0.0024302 $ 0.0004951 $ 0.0019351 GTAC Amortization (MDDQ): $ 0.0000000 $ 0.0000000


APPLICATION OF RATES:

Monthly Bill Components: Each month, Shipper's bill shall include a Withdrawal Reservation Charge and, if applicable, an Injection Commodity Charge for the quantities of natural gas nominated by Shipper and received by Utility for injection into storage, a Withdrawal Commodity Charge for the quantities of natural gas nominated by Shipper and delivered by Utility from storage for Shipper's account and a Storage Capacity Charge.

1. Withdrawal Reservation Charge: The Monthly Withdrawal Reservation Charge shall be the product of the Shipper's Storage Maximum Daily Delivery Quantity (MDDQ) as set forth in the Agreement times the applicable rate set forth above.

2. Injection Commodity Charge: The Monthly Injection Commodity Charge shall be the product of the Shipper's nominated quantities of natural gas received by the Utility for injection into storage times the applicable rate set forth above.

3. Withdrawal Commodity Charge: The Monthly Withdrawal Commodity Charge shall be the produce of the Shipper's nominated quantities of natural gas delivered by the Utility from storage times the applicable rate set forth above.

4. Storage Capacity Charge: The Monthly Storage Capacity Charge shall be the product of the Shipper's storage balance at the end of the month times the applicable rate set forth above.

5. Discounting Rates: The Utility shall have the ability to discount the Monthly Withdrawal Reservation Rate set forth above if the Shipper can demonstrate that, as a direct result of the

(continued)

N ~-4-L""W"Z: .... N NATURAL GAS TARIFF oru1-weSLCTil

Energy Canceling

Rule No. 6

LINE EXTENSIONS

Revised Revised

Sheet No. Sheet No.

6-1 Free Main Line Extension Allowance - Upon application for natural gas Core service, the Utility shall make an extension of the distribution main pipeline free of charge to the Applicant for Service up to the level of cost shown below, but no greater than the entire actual cost of such line extension:

Residential Service Customer

All other Core Customers ($/Therm)

$ 900.00 $ 850.00 ~ $0.391

times the Utility ' s estimate of the annual Therm consumption of the Customer.

Non-Core Transportation Customers: Determined on an individual basis .

A. Applicant requesting installation of a gas service will receive a meter and regulator free of charge, but will be responsible for the cost of the service pipeline connecting the meter to the distribution main. Customer contributions toward the cost of the gas service are nonrefundable.

B. The Applicant for service shall furnish all necessary rights-of-way.

6-2 Extension Beyond Free Limit (See Rule No. 6-11)

A. Where a main extension cost exceeds the free limit specified above in Rule No. 6-1 , the Utility will require the Applicant for Service to pay the difference between the cost of the project and the main extension allowance. Whenever this customer cost is collected as an advance, if additional requests for service (new line taps) from this protected extension are received within 60 months from the date the extension is completed, the Utility will:

1. Collect from the new line tap an advance or contribution representing an amount equal to the average advance for all line taps on the main line extension, in addition to the new line tap.

2. Refund to previously connected line taps of the existing line, their successors or assignees, or the current owner(s) of the property such an amount as is required to reduce the average cost of the line tap to the average advance with all connected line taps sharing equally in the cost of the original protected line.

The Customer(s) of each line tap, as a group, will share any required advance for their line tap extension, equitably, in addition to the cost of their individual line extension. Additional advances and refunds associated with such line taps will be treated as specified in Rule No. 6-2 A above.

(continued)

JS-1

Department of Public Service Regulation 1 Montana Public Service Commission 2

Docket No. D2016.9.68 3 Natural Gas General Filing - Phase Two 4

NorthWestern Energy 5 6

7 8

PREFILED DIRECT TESTIMONY 9

OF JOE SCHWARTZENBERGER 10

ON BEHALF OF NORTHWESTERN ENERGY 11

12

Table of Contents 13

Description Starting Page No. 14

Witness Information 2 15

Purpose of Testimony 4 16

Ratemaking Elements 5 17

Overview of NorthWestern’s Allocated Cost of Service and RD Proposals 7 18

Embedded Cost of Service Study and Revenue Moderation 8 19

Natural Gas Supply Marginal Cost of Service Study 13 20

Rate Design Proposals 15 21

Bill Impacts 18 22

Natural Gas Tariff Changes 21 23

Revised ECOS 22 24

Future Use of the ECOS Method for Production and Delivery Services 23 25 26

Exhibits 27

Natural Gas Revenue Moderation Exhibit__(JS-1) 28

Bill Impacts Exhibit__(JS-2) 29

Computation of Free Primary Line Extension Allowances Exhibit__(JS-3) 30

31

JS-2

Witness Information 1

Q. Please state your name and business address. 2

A. My name is Joe Schwartzenberger. My business address is 11 East Park 3

Street, Butte, Montana 59701. 4

5

Q. By whom are you employed and in what capacity? 6

A. I am NorthWestern Energy’s (“NorthWestern” or “Company”) Director of 7

Regulatory Affairs. 8

9

Q. Please summarize your education and employment experience. 10

A. I attended Montana State University (“MSU”), receiving a Bachelor of Science 11

degree in Mechanical Engineering Technology in 1982. I also received a 12

Master of Business Administration degree from the University of Montana in 13

2000. During my career, I have attended various seminars and sessions 14

regarding engineering, business, utility, and regulatory subjects including the 15

University of Idaho Utility Executive Course and the American Gas 16

Association Executive Leadership Program for Energy Professionals. I am a 17

registered Professional Engineer in Montana. 18

19

After graduating MSU, I was employed by Bechtel Power Corporation as a 20

field engineer in Colstrip, Montana and began my career with the Montana 21

Power Company (“MPC”) in 1986 as a Plant Engineer in Colstrip. I relocated 22

to Butte, Montana with MPC and progressed through a number of 23

JS-3

engineering positions becoming Manager of Technical Services in 1993 with 1

responsibility for providing technical support for MPC’s Demand-Side 2

Management (“DSM”) programs. In 1997, I was promoted to Director of 3

Operations with responsibility for managing an unregulated energy services 4

subsidiary of MPC. In 2002, I transferred to MPC’s Government and 5

Regulatory Affairs Department as Manager of Regulatory Support Services 6

with primary responsibility for NorthWestern’s Universal System Benefits 7

(“USB”) and DSM programs. I was promoted to my current position in 2004. 8

9

Q. What are your responsibilities as Director of Regulatory Affairs? 10

A. In my capacity as director I am responsible for state and federal regulatory 11

activities, DSM and USB programs, and electric load research – collecting, 12

analyzing and managing electric load data to meet various internal and 13

external needs in Montana. 14

15

I regularly participate in the preparation and/or consideration of the testimony, 16

exhibits, and workpapers in NorthWestern’s proceedings before the Montana 17

Public Service Commission (“MPSC” or “Commission”) and the Federal 18

Energy Regulatory Commission (“FERC”). As relates specifically to this 19

testimony, I sponsored allocated cost of service and rate design (“RD”) 20

testimony in Docket No. D2012.12.94, NorthWestern’s last natural gas utility 21

general rate filing. 22

23

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Purpose of Testimony 1

Q. What is the purpose of your testimony in this proceeding? 2

A. I am NorthWestern’s policy witness for the natural gas allocated cost of 3

service and RD proposals in this filing which are based on the natural gas 4

transmission, distribution, and storage (“Delivery Services”) and natural gas 5

production (“Production Services”) revenue requirements presented in 6

NorthWestern’s rebuttal filing in Phase One of this docket (“Rebuttal Revenue 7

Requirement”) 1. My testimony: 8

1. Describes how the Rebuttal Revenue Requirement and the allocated 9

cost of service and RD elements contained in this filing are related; 10

2. Provides an overview of the allocated cost of service and RD 11

components included in this filing; 12

3. Introduces NorthWestern’s embedded cost of service (“ECOS”) 13

proposal including Delivery and Production Services; 14

4. Presents NorthWestern’s proposed revenue moderation of the ECOS 15

results; 16

5. Briefly discusses NorthWestern’s natural gas supply marginal cost of 17

service (“MCOS”) study and provides recommendations for use of the 18

results; 19

6. Introduces NorthWestern’s RD proposals; 20

1 The revenues reflecting NorthWestern’s Delivery Services rebuttal revenue requirement are included on Exhibit__(PJD-41), page 1, column P, lines 7-48, included with the Phase One Prefiled Rebuttal Testimony of Patrick J. DiFronzo. The revenues reflecting NorthWestern’s natural gas Production Services rebuttal revenue requirement are included on Exhibit__(PJD-42), page 1, column R, lines12-34, included with the Phase One Prefiled Rebuttal Testimony of Patrick J. DiFronzo.

JS-5

7. Presents the billing impacts of NorthWestern’s RD proposals that 1

reflect NorthWestern’s Rebuttal Revenue Requirement and revenue 2

moderation; 3

8. Proposes an update to the residential and general service Free Main 4

Line Extension Allowances in NorthWestern’s Natural Gas Line 5

Extension Policy to reflect the related RD proposals; and 6

9. Proposes the use of the ECOS allocation method for Production and 7

Delivery Services in future proceedings before the Commission. 8

9

Ratemaking Elements 10

Q. Please describe how the Rebuttal Revenue Requirement and the 11

allocated cost of service and RD proposals contained in this filing are 12

related. 13

A. Four specific ratemaking steps are incorporated in this proceeding, all of 14

which are regular components of general rate filings. These steps and the 15

resulting breakout of costs by non-interruptible customer rate class for 16

combined Delivery and Production Services are illustrated on page 1 of 17

Exhibit__(JS-1). A general description of each step follows: 18

Revenue Requirement – This step determines the test year natural gas 19

system revenue requirement based on operating expenses, taxes, 20

interest paid on debts owed, depreciation expense, and return on rate 21

base. Historic actual information is adjusted for known and 22

measurable changes occurring 12 months beyond the actual year. 23

JS-6

The Rebuttal Revenue Requirement presented in Phase One of this 1

docket is the basis for NorthWestern’s ECOS and RD proposals in this 2

filing. 3

4

Allocated Cost of Service – This step allocates the respective costs of 5

providing utility services that make up the total revenue requirement to 6

the various utility customer classes (e.g., Residential and General 7

Service) based on their use of Natural Gas Delivery Services and 8

Production Services. NorthWestern’s ECOS presented in this filing 9

reflects the use of embedded (accounting) cost allocation techniques, 10

and its MCOS for natural gas supply reflects the use of marginal cost 11

allocation techniques. These cost allocation methods are discussed in 12

the testimony of Paul M. Normand (“Normand Direct Testimony – 13

Phase Two”) of Management Applications Consulting. 14

15

Customer Class Revenue Moderation – This step adjusts the ECOS 16

class revenue requirements at equalized rate of return revenue levels 17

to mitigate the impacts some customer classes would experience if 18

rates were designed to collect the ECOS class revenue requirements. 19

Moderation can be thought of as the initial step in RD as it establishes 20

class revenue targets to be recovered via the proposed rates. 21

22

JS-7

Rate Design – This final step establishes the individual rates that are 1

ultimately used to bill customers. Rates are designed to collect the 2

moderated revenues on a class-by-class basis. The Delivery and 3

Production Services RD proposals included in this filing were guided 4

by the results of the ECOS studies. 5

6

Overview of NorthWestern’s Allocated Cost of Service and RD Proposals 7

Q. Please provide a brief overview of NorthWestern’s allocated cost of 8

service and RD proposals in this filing. 9

A. The allocated cost of service and RD proposals are presented in my 10

testimony and exhibits and in the Normand Direct Testimony – Phase Two, 11

along with Statement L and supporting workpapers, and Statement M and 12

supporting workpapers. This material is comprised of ECOS and MCOS/RD 13

analyses, results, and proposals for Delivery and Production Services. 14

15

Q. What are NorthWestern’s primary objectives for the Allocated Cost of 16

Service and RD portion of this filing? 17

A. NorthWestern’s primary objectives are the proper allocation of the costs of 18

providing Delivery and Production Services among the various customer 19

classes based on cost causation and the development of rate design 20

structures that recover these costs on that basis to the extent reasonable. As 21

a practical matter, costs should be allocated between classes of customers, 22

and rates should be designed to assure that customers make appropriate 23

JS-8

contributions to the costs they cause, while being mindful of other factors 1

important to sound rate design including bill impacts, for example. 2

3

Embedded Cost of Service Study and Revenue Moderation 4

Q. How generally was the ECOS study included in this filing developed? 5

A. Mr. Normand developed the ECOS study for purposes of determining 6

revenue requirement responsibility and the costs of the various components 7

of the services NorthWestern provides at equalized rate of return. His 8

testimony presents the methodologies used, the analyses he conducted, and 9

the associated results. 10

11

Q. Did NorthWestern use the ECOS results as the basis for class revenue 12

moderation and RD for this filing? 13

A. Yes. The Normand Direct Testimony – Phase Two discusses the application 14

of the ECOS model and changes/improvements that have been made to it for 15

purposes of this filing including incorporation of NorthWestern’s natural gas 16

production assets: Battle Creek, Bear Paw (NFR), and South Bear Paw 17

(Devon). 18

19

The ECOS moderation analysis is presented on page 2 of Exhibit__(JS-1) 20

and discussed further below. The ECOS study allocates the requested 21

Rebuttal Revenue Requirement among the customer classes based on costs 22

such that the sum of all of the revenue requirement responsibilities by 23

JS-9

customer class is equal to the Rebuttal Revenue Requirement. The ECOS 1

class revenue requirement responsibilities are then moderated to establish 2

revenue targets for each rate class. Because the moderated class revenues 3

are different than the ECOS class revenues, they result in revenue subsidies 4

for certain customer classes. The sum of the moderated class revenue 5

responsibilities also equals the Rebuttal Revenue Requirement. 6

7

Q. What is meant by moderation and why is it necessary? 8

A. NorthWestern’s moderation proposal simply modifies Mr. Normand’s full 9

ECOS class revenue requirement results to mitigate customer bill impacts. A 10

comparison of the revenue requirement responsibilities by customer class 11

resulting from the ECOS study to current rate revenues revealed some large 12

disparities and that some classes are being subsidized by other classes. 13

Revenue moderation gives consideration to the overall billing impact of 14

establishing class revenue targets for rate design which will, in total, equal the 15

full ECOS results. Consistent with prior practice, NorthWestern moderated 16

the ECOS study results to mitigate significant bill impacts by class. 17

18

Cost of service allocation studies embody a process aimed at assigning costs 19

to customers based on the services they receive. If one believes that rates 20

should be based solely on the concept that the “cost causer pays,” it would be 21

appropriate to use the ECOS study results at equalized rate of return to 22

establish rates in one step in this filing. Most, including NorthWestern, agree 23

JS-10

that while assigning costs to the cost causer is an important consideration in 1

setting rates, there are other considerations, such as bill impacts, that are 2

also important. The ECOS results suggest that significant changes in 3

revenue responsibilities for certain classes are in order. Over time, 4

NorthWestern believes it is important and proper to work toward achieving 5

rates that reflect costs in order to reduce inter-class subsidies. However, 6

given the large rate adjustments that would be required to achieve this 7

objective in a single rate case, NorthWestern recommends taking incremental 8

steps toward this objective and moderated the ECOS study results to that 9

end. 10

11

For example, the Distribution Business Unit (“DBU”) Firm Transportation 12

Service customer class would experience an increase of approximately 30% 13

over current rates if the results from the ECOS study were used. With 14

moderation, NorthWestern proposes that this customer class instead receive 15

a 9.81% increase, as shown on page 2 of Exhibit__(JS-1). I describe 16

NorthWestern’s overall approach to moderation below. 17

18

Q. Have you prepared an exhibit that reflects the combined effect by 19

customer rate class of the Rebuttal Revenue Requirement and the ECOS 20

and moderation proposals contained in this filing? 21

JS-11

A. Yes, page 2 of Exhibit__(JS-1) presents the proposed by-class cost 1

allocations before and after moderation. The following table can be used as a 2

guide to review this page: 3

Natural Gas Production and Delivery Services ECOS Revenue Moderation

Current Rate Revenues by class compared

to Proposed Rebuttal Revenue

Requirement Revenues by class resulting

from a uniform percent increase, including

dollar and percent differences.

Columns E, G, I, and J; Lines 7

to 21

Proposed ECOS Revenues compared to

Current Rate Revenues with related dollar

and percent differences. Columns N and O

present the combined impact of the

Rebuttal Revenue Requirement increase

and ECOS reallocations by class before

any moderation.

Columns E, L, N, and O; Lines

7 to 21

Proposed ECOS impacts only, including

dollar and percent differences.

Columns G, L, Q, and R; Lines

7 to 21

Proposed Embedded Moderated Revenues

compared to Current Rate Revenues with

related dollar and percent differences.

Columns E, N, O, and Q; Lines

23 to 38

Q. What general guidelines did NorthWestern use in establishing the 4

proposed moderated revenues? 5

A. As discussed above, the primary goal of moderation is to mitigate the billing 6

impacts that would otherwise result from implementation of the ECOS study 7

JS-12

results. The general guidelines NorthWestern used for moderation in this 1

filing were: 2

1. Consideration of bill impacts from the collective effects of the Rebuttal 3

Revenue Requirement, moderation, and RD proposals as described 4

below; 5

2. Consistent with Item 1 above, capping the maximum increase for any 6

class at 1.4 times the 7.01% overall system increase in revenue 7

requirement, or 9.81%; and 8

3. Providing no class a rate decrease even if the ECOS study showed a 9

decrease was necessary to achieve the cost of service. 10

11

Collectively, these guidelines move toward cost of service while maintaining 12

the basic goal of mitigating customer bill impacts. 13

14

Q. How did you perform moderation based on these guidelines? 15

A. Current rate revenues for the DBU Firm Transportation Service class are 16

about 30% less than its ECOS revenues at equalized rate of return. I applied 17

a 9.81% revenue increase to this class because, of all classes, it is farthest 18

from its cost of service. Refer to column G, line 29 on page 2 of Exhibit__(JS-19

1). I then distributed the resulting revenue deficiency of approximately $9 20

million to the remaining classes based on the shape of the ECOS revenues 21

for those classes. Refer to columns I, J, and L, lines 24 through 33, and 22

column L, lines 8 through 16. The resulting moderated class revenues and 23

JS-13

dollar and percent changes as compared to current rate revenues are 1

included in columns N, O, and Q, lines 23 through 32. 2

3

Current rate revenues for Firm Storage Natural Gas Service are above its 4

costs by about 10%. Consistent with the guidelines, this customer class did 5

not receive a decrease. 6

7

Natural Gas Supply Marginal Cost of Service Study 8

Q. Has NorthWestern included a MCOS study for Delivery Services? 9

A. No. Order No. 7249e in Docket No. D2012.9.94, at ¶ 61 “authorizes 10

NorthWestern to use its ECOS model for Delivery Services in its next cost of 11

service case.” This is that filing for the natural gas utility. 12

13

Q. Why did NorthWestern conduct a separate MCOS study for natural gas 14

supply? 15

A. NorthWestern conducted a MCOS study based on its interpretation of 16

Administrative Rule of Montana 38.5.176. While the Commission authorized 17

NorthWestern to use its ECOS model for Delivery Services in this filing, it did 18

not waive the requirement for a natural gas supply MCOS study. The MCOS 19

study is presented in the Normand Direct Testimony – Phase Two, which 20

discusses the methodologies Mr. Normand used and the analyses he 21

conducted. 22

23

JS-14

Q. Are NorthWestern’s RD proposals for Production Services based on the 1

MCOS study? 2

A. No. Mr. Normand discusses the results of the MCOS study and his 3

recommendation regarding use of them for RD. NorthWestern notes that the 4

differences between classes in natural gas supply winter marginal unit prices, 5

as adjusted to NorthWestern’s rebuttal revenue levels, are very small, about a 6

1% difference between the lowest and highest prices. The MCOS results do 7

indicate that winter marginal unit prices with demand and supply components 8

combined are about 55% higher than summer marginal unit prices (an 9

average of $0.312 per therm in the winter vs. $0.202 per therm in the 10

summer) as a result of estimated marginal demand costs in the winter only. 11

12

However, the winter unit prices are only about 12% higher than the proposed 13

all-in natural gas supply rate of $0.278 per therm (rounded to three decimals). 14

This all-in rate is the sum of the proposed Production Services with and 15

without property tax rate components in this filing and the April 1, 2017 16

purchase gas supply (natural gas tracker) rate component. NorthWestern 17

does not believe that this relatively small difference indicates the need to 18

increase the price customers pay for natural gas in the winter when, by virtue 19

of increased consumption for space heat and a tendency toward higher 20

purchase gas supply costs in the winter in normal years, natural gas bills for 21

most customers already rise dramatically. 22

23

JS-15

Rate Design Proposals 1

Q. How were rates developed in this filing? 2

A. Mr. Normand developed the rate designs based on his ECOS results and 3

NorthWestern’s revenue moderation. His testimony presents the criteria that 4

guided his general approach to rate design, the methodologies he used to 5

develop the rates, and the rates themselves. In particular, the proposed 6

rates, in combination with NorthWestern’s moderated class revenue targets, 7

result in improved price signals to customers while maintaining reasonable bill 8

impacts. 9

10

Q. Did NorthWestern make any specific requests of Mr. Normand regarding 11

rate design? 12

A. Yes. We specifically requested that the property tax components of 13

Production and Delivery Services rates be designed to collect the total 14

property taxes that are included in the Rebuttal Revenue Requirement less 15

any property taxes that are not addressed in the property tax tracker (e.g. 16

tribal taxes). NorthWestern also requested that the property tax rate 17

components be designed to collect the by-class property taxes determined by 18

the ECOS to the maximum extent practical. In Order No. 7501 entered in 19

Docket No. D2016.1.9, the Commission affirmed the benefits of transparent 20

rates that create a visible, calculable cost associated with property taxes for 21

customers. ¶ 6. The proposed RD furthers transparency relative to these 22

costs. 23

JS-16

NorthWestern also requested that Mr. Normand design one Production 1

Services rate (including with and without property tax components) for all core 2

classes. This is consistent with the Stipulation2 regarding future ratemaking 3

treatment for the production assets, and customers are familiar with a single 4

natural gas supply rate, which is easier to understand and administer. 5

6

Finally, NorthWestern requested that the increases in rates for DBU 7

Interruptible Transportation and Transmission Business Unit (“TBU”) 8

Interruptible Transportation services be the same as the increases to their 9

firm service class counterparts. This approach to rate design for the 10

interruptible transportation classes is consistent with the approach approved 11

in Docket No. D2012.9.94 and in Consolidated Docket Nos. D2007.7.82 and 12

D2009.9.129. 13

14

Q. Mr. Normand’s proposed customer service charges represent a 15

significant increase for some customer classes. Do you agree with his 16

recommendations? 17

A. Yes. As Mr. Normand explains, the ECOS results indicate the need to 18

increase customer service charges for all classes, and the increases reduce 19

intra-class subsidies. To put the proposed increases in perspective, it is 20

worth noting that in accordance with Order No. 7501, on January 1, 2017, 21

NorthWestern implemented a new rate design that, among other changes, 22

2 Stipulation and Settlement Agreement of NorthWestern Energy and the Montana Consumer Counsel presented to the MPSC in Phase One of this docket.

JS-17

removed all property taxes from customer service charges. The Commission 1

noted in ¶ 8 of Order No. 7501: 2

“…that by removing taxes from the monthly service fee that all 3

customers pay and calculating this amount as part of a volumetric rate 4

for taxes, that some customers within a particular class will pay less, 5

and some will pay more, as a result of adopting Option (a). However, 6

based on the evidence submitted by Mr. DiFronzo, the Commission 7

finds that the revenue shifting caused by the transfer of cost recovery 8

from monthly fixed charges to volumetric rates will have a minor impact 9

relative to the total bill amounts. Test. DiFronzo at Exh. PJD-2 & PJD-10

5. This effect may be addressed in future general natural gas and 11

electric rate cases.” 12

13

For example, the January 2017 change in rate design for the residential class 14

reduced the customer service charge from $7.35 per month to the current 15

charge of $5.80 per month, a 21% decrease. As detailed in his testimony, Mr. 16

Normand proposes a residential customer service charge of $8.25 per month. 17

The majority of the increase associated with Mr. Normand’s proposed 18

monthly service charge basically reverses the intra-class subsidies resulting 19

from the January 2017 decrease and the associated bill impacts. 20

21

22

23

JS-18

Bill Impacts 1

Q. Have you prepared monthly customer billing impacts resulting from 2

NorthWestern’s proposals in this filing? 3

A. Yes. As described above, NorthWestern believes rates should move toward 4

costs, but it is also sensitive to maintaining reasonable billing impacts. A 5

billing impact analysis is necessary to determine if the combined impacts of 6

the Rebuttal Revenue Requirement, moderation, and RD are reasonable 7

across the spectrum of usage levels. Because RD can impact customers 8

within the same class differently depending on their usage levels, it is 9

important that such an analysis consider a broad range of usage levels within 10

each class. 11

12

Q. What were NorthWestern’s objectives regarding overall bill impacts? 13

A. NorthWestern’s objectives were: 1) to limit bill impacts to less than a 10% 14

increase for the majority of customers most of the time, and 2) for customers 15

who will experience an impact of greater than 10%, to limit the actual dollar 16

impact to a reasonable amount. These objectives were achieved. 17

18

Regarding the second objective, low-use residential customers, those 19

customers who use up to 20 therms per month for example, experience bill 20

impacts that are greater than 10%, but the associated actual dollar impacts 21

range from $2.40 to $2.42 per month. As Mr. Normand explains, these 22

increases are primarily the result of partially moving the recovery of the fixed 23

JS-19

cost of meters and services into the customer service charge. In this context, 1

“low use” is largely a function of season because the large majority of 2

NorthWestern’s residential natural gas customers consume natural gas for 3

their space heating needs. Refer to page 1 of Exhibit__(JS-2), columns E, G, 4

and H, lines 34 through 51. In August 2016, 76% of customers consumed 20 5

therms or less while in February 2017, owing primarily to space heating 6

needs, only 3% of customers consumed 20 therms or less. The average 7

natural gas water heater on NorthWestern’s system consumes approximately 8

17 therms per month. 9

10

Q. Please describe the bill impact sheets included In Exhibit__(JS-2). 11

A. Exhibit__(JS-2) presents the bill impacts for each rate class that result from 12

the proposed rates in this filing. This exhibit computes the billed amount 13

using current rates to the billed amount using proposed rates for each rate 14

class and computes dollar and percentage differences. For comparison 15

purposes, the proposed natural gas supply rates include the purchase gas 16

supply rate component from the April 1, 2017 natural gas supply tracker. 17

18

Refer to the table starting on line 7 of page 1 of Exhibit__(JS-2) showing the 19

billing impacts for a Natural Gas Residential Customer using 100 therms per 20

month. Columns G and H present current rate information; columns J and K 21

present proposed rate information, and columns M and N present the dollar 22

JS-20

and percent differences between current and proposed rates by rate 1

component and for the entire bill. 2

3

Below these computations, starting on line 34, are tables of billing impacts for 4

selected monthly natural gas usages. The Total Bill Impact and Percent 5

Change in columns K and M are calculated for each usage value in column J. 6

The detailed bill amounts by rate component (shown in columns H and K, 7

lines 7 through 27) are based on 100 therms by using the usage value in 8

column B, line 10. To illustrate both a summer and a winter month, the 9

number of customers for August 2016 and February 2017 are provided for 10

each usage range shown in column H. August 2016 customers are shown in 11

column E and February 2017 customers are in column G. 12

13

While not identical, the bill impact analyses for the other customer classes 14

include similar layouts and computations. 15

16

Q. Please summarize the bill impacts resulting from the revenue 17

requirement, moderation, and RD proposals in this filing. 18

A. Following are a few key statistics: 19

1. Residential customers using 10 therms per month will receive an increase 20

on their total bill of 19.35% or $2.42, and customers using 20 therms per 21

month will receive an increase on their total bill of 12.50% or $2.40. 22

JS-21

2. Residential customers using 100 therms per month will receive an 1

increase of 2.98% on their total bill or $2.17. 2

3. Residential customers using 200 therms per month will receive an 3

increase of 1.35% on their total bill or $1.88. 4

4. Bill increases for General Service customers range from approximately 5

3.6% to 8.9% on their total bill. A separate bill impact analysis sheet is 6

included for each of the seven different monthly service charges for this 7

customer class. 8

5. Bill increases for Firm Utility Gas Contract Service customers range from 9

approximately 2.7% to 9.5% on their total bill. 10

6. TBU Firm Transportation Service customers receive a total bill increase 11

ranging from approximately 3.8% to 6.4%. 12

7. DBU Firm Transportation Service customers receive a total bill increase 13

ranging from approximately 4.4% to 8.1%. 14

15

Natural Gas Tariff Changes 16

Q. Is a marked-up copy of the tariffs that NorthWestern proposes to 17

implement included in this filing? 18

A. Yes. Each sheet of each natural gas tariff with proposed revisions is provided 19

behind the tab labeled “Marked-Up Tariffs” included with this filing. The 20

specific information that NorthWestern proposes to change is red-lined. 21

22

Q. Please describe the nature of the proposed changes. 23

JS-22

A. On each tariff sheet behind the Marked-Up Tariffs tab, the current rates have 1

been crossed out. Next to, or under, each of the current rates, the 2

corresponding proposed rate has been inserted. Rates that are not impacted 3

by this filing remain unchanged. 4

5

Note that NorthWestern is proposing to update the free main line extension 6

allowances for core customers in Rule 6, Line Extensions, to reflect the RD 7

proposals in this filing. The proposed allowance for residential customers is 8

$850, and the proposed rate to determine the allowance for all other core 9

customers is $0.391 per therm. Refer to Exhibit__(JS-3) for supporting 10

computations. The changes are reflected on the affected marked up Rule 6 11

tariff sheet. 12

13

Revised ECOS 14

Q. Did NorthWestern provide an ECOS in this filing that reflects the 15

Stipulation? 16

A. There was inadequate time to develop an ECOS that reflects the entirety of 17

the Stipulation prior to this filing nor has the Commission issued a Phase One 18

order. However, Mr. Normand did develop an ECOS that is based on 19

NorthWestern’s Phase One Rebuttal Filing, but reallocates the Administrative 20

and General and Common Plant Costs from the natural gas production 21

function to the delivery services functions by customer class. Mr. Normand 22

JS-23

discusses the revised ECOS and presents the summary results including a 1

comparison to his ECOS study included in Statement L. 2

3

Q. Has NorthWestern included moderation and RD proposals based on the 4

revised ECOS? 5

A. No. As I noted above, the revised ECOS does not reflect the Stipulation in its 6

entirety, and the Commission has not yet ruled on it. NorthWestern expects 7

to update its ECOS, moderation, and rate design proposals as necessary 8

after the Commission issues an order. 9

10

Future Use of the ECOS Method for Production and Delivery Services 11

Q. Do you have any other requests of the Commission? 12

A. Yes. NorthWestern believes the ECOS model included in this filing produces 13

reasonable results for both Delivery and Production Services and that a 14

natural gas supply MCOS provides comparative information for natural gas 15

supply pricing considerations. Therefore, NorthWestern respectfully requests 16

that the Commission allow NorthWestern, on a permanent basis, to employ 17

an embedded cost approach to allocating its Production and Delivery 18

Services costs and to allow the continued use of the ECOS model as it may 19

be improved from time to time as a result of this and future natural gas utility 20

proceedings before the Commission. Absent Commission direction to the 21

contrary, NorthWestern will also provide a natural gas supply MCOS study in 22

future proceedings to inform pricing decisions. 23

JS-24

Q. Does this conclude your testimony? 1

A. Yes, it does. 2

Docket D2016.9.68Exhibit__(JS-1)

Page 1 of 2

$141,837,172

Natural Gas Revenue Requirement

Natural Gas Revenue Requirement

$80,963,615

$39,600,473

$694,857

$3,138,126

$14,272,008 $3,168,093

Embedded Allocated Cost of ServiceResidential Natural GasService

General Natural Gas Service

Firm Utility Gas ContractService

DBU Firm TransportationNatural Gas Service

TBU Firm TransportationNatural Gas Service

Firm Storage Natural GasService

$79,597,459

$41,303,388

$627,108 $2,644,856

$13,937,248 $3,727,113

Moderated Class RevenuesResidential Natural GasService

General Natural Gas Service

Firm Utility Gas ContractService

DBU Firm TransportationNatural Gas Service

TBU Firm TransportationNatural Gas Service

Firm Storage Natural GasService

Natural Gas Revenue Requirement, Embedded Allocated Cost of Service, Moderation, and Rate Design Flow Diagram

Rate Design

Docket No. D2016.9.68Exhibit__(JS-1)

Page 2 of 2

5/30/2017Exhibit__(JS-01) Prod Trans Dist Stor Moderation Rebuttal Final

1234567891011121314151617181920212223242526272829303132333435363738394041424344

454647484950515253

A B C D E F G H I J K L M N O P Q R

Revenues @Revenues @ Proposed Embedded ECOS ECOS

Current Rates1,5 Uniform Design Rates2,5 $ Difference % Difference ECOS Revenues3,5 $ Difference % Difference $ Difference % DifferenceResidential Natural Gas Service 74,315,199$ 79,704,811$ 5,389,611$ 7.25% 80,963,615$ 6,648,415$ 8.95% 1,258,804$ 1.69%General Natural Gas Service 38,719,759$ 41,604,490$ 2,884,731$ 7.45% 39,600,473$ 880,714$ 2.27% (2,004,017)$ -5.18%Firm Utility Gas Contract Service 581,773$ 653,811$ 72,037$ 12.38% 694,857$ 113,084$ 19.44% 41,046$ 7.06%DBU Firm Transportation Natural Gas Service 2,408,640$ 2,528,001$ 119,361$ 4.96% 3,138,126$ 729,485$ 30.29% 610,125$ 25.33%TBU Firm Transportation Natural Gas Service 13,006,109$ 13,649,527$ 643,418$ 4.95% 14,272,008$ 1,265,900$ 9.73% 622,482$ 4.79%Firm Storage Natural Gas Service 3,520,419$ 3,696,533$ 176,114$ 5.00% 3,168,093$ (352,326)$ -10.01% (528,440)$ -15.01%

Subtotal 132,551,900$ 141,837,172$ 9,285,272$ 7.01% 141,837,172$ 9,285,272$ 7.01% 0$ 0.00%Plus:DBU Interruptible Transportation4 34,448$ 36,166$ 1,717$ 36,166$ 1,717$ 4.98% -$ 0.00%TBU Interruptible Transportation4 2,442,349$ 2,576,338$ 133,989$ 2,576,338$ 133,989$ 5.49% -$ 0.00%Rounding -$ -$ -$ -$ 0.00%

Total 135,028,698$ 144,449,675$ 9,420,978$ 144,449,675$ 9,420,978$ 6.98% -$ 0.00%

Proposed Proposed Proposed ModeratedRevenues @ Rev Deficiency Embedded Moderated Moderated Percent of

Current Rates1,5 Cap Cap Differential Distribution Balance Moderated Revenues $ Change % Change Embedded CostsResidential Natural Gas Service 74,315,199$ 74,315,199$ 58.37% 5,282,259$ 79,597,459$ 5,282,259$ 7.11% 98.31%General Natural Gas Service 38,719,759$ 38,719,759$ 28.55% 2,583,629$ 41,303,388$ 2,583,629$ 6.67% 104.30%Firm Utility Gas Contract Service 581,773$ 581,773$ 0.50% 45,334$ 627,108$ 45,334$ 7.79% 90.25%DBU Firm Transportation Natural Gas Service 2,408,640$ 9.81% 2,644,856$ -$ 2,644,856$ 236,216$ 9.81% 84.28%TBU Firm Transportation Natural Gas Service 13,006,109$ 13,006,109$ 10.29% 931,140$ 13,937,248$ 931,140$ 7.16% 97.65%Firm Storage Natural Gas Service 3,520,419$ 3,520,419$ 2.28% 206,694$ 3,727,113$ 206,694$ 5.87% 117.65%

132,551,900$ 132,788,115$ 100.00% 9,049,056$ 141,837,172$ 9,285,272$ 7.01% 100.00%Revenue Deficiency: 9,049,056$

Plus:DBU Interruptible Transportation4 34,448$ 37,828$ 3,379$ 9.81%TBU Interruptible Transportation4 2,442,349$ 2,617,222$ 174,872$ 7.16%Rounding -$ -$ 0.00%

Total 135,028,698$ 144,492,221$ 9,463,523$ 7.01%

1 Source for Core and Firm Transportation and Storage Services: Statement L, Part 1, Page 1, Table 1.

2

3 Source for Core and Firm Transportation and Storage Services: Statement L, Part 1, Page 1, Table 2

4

5 Includes Natural Gas Production and Delivery Services Revenues for Core Services.

NorthWestern Energy - Natural Gas Utility

Proposed Embedded Cost of Service Moderation Based on NorthWestern's Rebuttal FilingProduction and Delivery Services

Source for Core and Firm Transportation and Storage Services: Exhbits_(PJD-41) and (PJD-42) included with the Phase 1 Prefiled Rebuttal Testimony of Patrick J. DiFronzo.

Source for DBU and TBU Interruptible Transportation current rate revenues: Exhibit_(PJD-41) included with the Phase 1 Prefiled Rebuttal Testimony of Patrick J. DiFronzo

Docket No. D2016.9.68

Exhibit_(JS-2)

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A B C D E F G H I J K L M N

Residential Services - Bill Amount

Usage in therms 100 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Bill PercentageRate Amount Rate Amount Rate Amount Change Change

Monthly Service Charge per Meter 5.80$ 5.80$ 5.80$ 5.80$ $8.25 8.25$ 2.45$ 42.24%

Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1668809$ 16.69$ 0.1668809$ 16.69$ 0.1078602$ 10.79$ (5.90)$ -35.35% Taxes Distribution 0.0782676$ 7.83$ 1 0.0702596$ 7.03$ 0.0723782$ 7.24$ 0.21$ 2.99% Transmission Charge 0.0988201$ 9.88$ 0.0988201$ 9.88$ 0.1286042$ 12.86$ 2.98$ 30.16% Taxes Transmission 0.0323192$ 3.23$ 1 0.0282472$ 2.82$ 0.0467994$ 4.68$ 1.86$ 65.96% Storage Charge 0.0300756$ 3.01$ 0.0300756$ 3.01$ 0.0170723$ 1.71$ (1.30)$ -43.19% Taxes Storage 0.0098361$ 0.98$ 1 0.0085968$ 0.86$ 0.0050338$ 0.50$ (0.36)$ -41.86% Gas Supply Charge 0.2555100$ 25.55$ 0.2555100$ 25.55$ 0.2756188$ 27.56$ 2.01$ 7.87% Taxes Supply 0.0001000$ 0.01$ 0.0001000$ 0.01$ 0.0022961$ 0.23$ 0.22$ 100.00% DBU GTAC Amortization 0.0000203$ -$ 0.0000203$ -$ 0.0000203$ -$ -$ 0.00% TBU GTAC Amortization (0.0014935)$ (0.15)$ (0.0014935)$ (0.15)$ (0.0014935)$ (0.15)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 1.28$ 0.0127763$ 1.28$ 0.0127763$ 1.28$ -$ 0.00%

Total Commodity 0.6831126$ 68.31$ 0.6697933$ 66.98$ 0.6669661$ 66.70$ (0.28)$ -0.41%

Total Bill (Price per therm Incl. Service Charge) 74.11$ 72.78$ 74.95$ 2.17$ 2.98%

1Rates exclude the tax tracker deferred balance from Docket No. D2016.12.97 Tax Tracker approved by law.

Summer Month Winter MonthAugust 2016 February 2017Number of Number of Range of Total PercentCustomers Customers Usage Usage Therms Bill Impact Change

100 2.17$ 2.98%70,747 2,984 0 - 10 10 2.42$ # 19.35%56,667 2,237 11 - 20 20 2.40$ # 12.50%37,215 9,958 21 - 50 50 2.30$ # 5.85%2,700 42,816 51 - 100 100 2.17$ # 2.98%

283 55,785 101 - 150 150 2.02$ # 1.90%46 19,019 151 - 175 175 1.98$ # 1.61%31 12,848 176 - 200 200 1.88$ # 1.35%48 19,629 201 - 300 300 1.61$ # 0.78%28 4,355 301 - 500 500 1.04$ # 0.31%7 434 501 - 750 750 0.31$ # 0.06%3 80 751 - 1000 1000 (0.39)$ # -0.06%7 49 1001 - 2500 2500 (4.62)$ # -0.28%

5 2501 - 5843 5843 (14.07)$ # -0.36%

Current Rates Approved Including Deferred Tax Portion in Rates

Proposed RatesRate Moderation

Current Rates Approved Excluding Deferred Tax Portion in Rates

Residential Class

J:\Bill Impact All Customers rebuttal final


Exhibit_(JS-2)

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General Service - Bill Amount


Monthly Service Charge per Meter 15.05$ 15.05$ 15.05$ 15.05$ 16.60$ 16.60$ 1.55$ 10.30%

Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1612889$ 16.13$ 0.1612889$ 16.13$ 0.1208280$ 12.08$ (4.05)$ -25.11% Taxes Distribution 0.0764174$ 7.64$ 1 0.0685129$ 6.85$ 0.0568862$ 5.69$ (1.16)$ -16.93% Transmission Charge 0.0954721$ 9.55$ 0.0954721$ 9.55$ 0.1440660$ 14.41$ 4.86$ 50.89% Taxes Transmission 0.0313002$ 3.13$ 1 0.0273545$ 2.74$ 0.0445858$ 4.46$ 1.72$ 62.77% Storage Charge 0.0289909$ 2.90$ 0.0289909$ 2.90$ 0.0196397$ 1.96$ (0.94)$ -32.41% Taxes Storage 0.0095047$ 0.95$ 1 0.0083066$ 0.83$ 0.0049248$ 0.49$ (0.34)$ -40.96% Gas Supply Charge 0.2555100$ 25.55$ 0.2555100$ 25.55$ 0.2756188$ 27.56$ 2.01$ 7.87% Taxes Supply 0.0001000$ 0.01$ 0.0001000$ 0.01$ 0.0022961$ 0.23$ 0.22$ 100.00% DBU GTAC Amortization 0.0000215$ -$ 0.0000215$ -$ 0.0000215$ -$ -$ 0.00% TBU GTAC Amortization (0.0015870)$ (0.16)$ (0.0015870)$ (0.16)$ (0.0015870)$ (0.16)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 1.28$ 0.0127763$ 1.28$ 0.0127763$ 1.28$ -$ 0.00%

Total Commodity 0.6697950$ 66.98$ 0.6567467$ 65.68$ 0.6800562$ 68.00$ 2.32$ 3.46%




100 3.87$ 4.79%11,590 1,334 0 - 10 10 1.80$ # 8.33%1,549 334 11 - 20 20 2.01$ # 7.13%1,133 1,285 21 - 50 50 2.69$ # 5.62%

389 2,818 51 - 100 100 3.87$ # 4.79%131 2,551 101 - 150 150 5.03$ # 4.43%22 1,032 151 - 175 175 5.62$ # 4.32%23 900 176 - 200 200 6.22$ # 4.25%54 2,416 201 - 300 300 8.56$ # 4.04%44 1,808 301 - 500 500 13.18$ # 3.84%6 515 501 - 750 750 19.02$ # 3.75%

- 116 751 - 1000 1000 24.88$ # 3.70%- 49 1001 - 2000 2000 48.17$ # 3.63%- 4 2001 - 2558 2558 61.16$ # 3.61%




General Service Meters 0 - 300 cuft/hr



Exhibit_(JS-2)

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Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1612889$ 80.64$ 0.1612889$ 80.64$ 0.1208280$ 60.41$ (20.23)$ -25.09% Taxes Distribution 0.0764174$ 38.21$ 1 0.0685129$ 34.26$ 0.0568862$ 28.44$ (5.82)$ -16.99% Transmission Charge 0.0954721$ 47.74$ 0.0954721$ 47.74$ 0.1440660$ 72.03$ 24.29$ 50.88% Taxes Transmission 0.0313002$ 15.65$ 1 0.0273545$ 13.68$ 0.0445858$ 22.29$ 8.61$ 62.94% Storage Charge 0.0289909$ 14.50$ 0.0289909$ 14.50$ 0.0196397$ 9.82$ (4.68)$ -32.28% Taxes Storage 0.0095047$ 4.75$ 1 0.0083066$ 4.15$ 0.0049248$ 2.46$ (1.69)$ -40.72% Gas Supply Charge 0.2555100$ 127.76$ 0.2555100$ 127.76$ 0.2756188$ 137.81$ 10.05$ 7.87% Taxes Supply 0.0001000$ 0.05$ 0.0001000$ 0.05$ 0.0022961$ 1.15$ 1.10$ 100.00% DBU GTAC Amortization 0.0000215$ 0.01$ 0.0000215$ 0.01$ 0.0000215$ 0.01$ -$ 0.00% TBU GTAC Amortization (0.0015870)$ (0.79)$ (0.0015870)$ (0.79)$ (0.0015870)$ (0.79)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 6.39$ 0.0127763$ 6.39$ 0.0127763$ 6.39$ -$ 0.00%

Total Commodity 0.6697950$ 334.91$ 0.6567467$ 328.39$ 0.6800562$ 340.02$ 11.63$ 3.47%




500 13.68$ 3.93%1,867 231 0 - 10 10 2.30$ # 8.71%

449 37 11 - 20 20 2.51$ # 7.61%559 71 21 - 50 50 3.19$ # 6.05%281 131 51 - 100 100 4.37$ # 5.11%117 169 101 - 150 150 5.53$ # 4.67%45 117 151 - 175 175 6.12$ # 4.54%35 119 176 - 200 200 6.72$ # 4.45%74 498 201 - 300 300 9.06$ # 4.18%

103 981 301 - 500 500 13.68$ # 3.93%29 705 501 - 750 750 19.52$ # 3.81%7 274 751 - 1000 1000 25.38$ # 3.75%7 200 1001 - 2000 2000 48.67$ # 3.65%

- 21 2001 - 3613 3613 86.27$ # 3.61%




General Service Meters 301 - 1,000 cuft /hr



Exhibit_(JS-2)

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Usage in therms 2,000 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Bill PercentageRate Amount Rate Amount Rate Amount Change Change



Total Commodity 0.6697950$ 1,339.58$ 0.6567467$ 1,313.49$ 0.6800562$ 1,360.11$ 46.62$ 3.48%

Total Bill (Price per therm Incl. Service Charge) 1,371.58$ 1,345.49$ 1,395.36$ 49.87$ 3.71%



2000 49.87$ 3.71%1,465 154 0 - 20 20 3.71$ # 8.22%

717 66 21 - 75 75 4.99$ # 6.14%155 32 76 - 100 100 5.57$ # 5.70%218 62 101 - 150 150 6.73$ # 5.16%134 92 151 - 200 200 7.92$ # 4.85%211 204 201 - 300 300 10.26$ # 4.48%259 537 301 - 500 500 14.88$ # 4.13%192 706 501 - 750 750 20.72$ # 3.95%101 519 751 - 1000 1000 26.58$ # 3.86%70 1,007 1001 - 2000 2000 49.87$ # 3.71%3 205 2001 - 3000 3000 73.18$ # 3.66%3 41 3001 - 4000 4000 96.47$ # 3.63%1 16 4001 - 5035 5035 120.63$ # 3.61%




General Service Meters 1,001 - 2000 cuft/hr



Exhibit_(JS-2)

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Total Commodity 0.6697950$ 1,339.58$ 0.6567467$ 1,313.49$ 0.6800562$ 1,360.11$ 46.62$ 3.48%




2000 52.12$ 3.81%230 28 0 - 20 20 5.96$ # 8.91%139 2 21 - 50 50 6.64$ # 7.67%132 4 51 - 100 100 7.82$ # 6.55%155 21 101 - 250 250 11.31$ # 5.19%127 59 251 - 500 500 17.13$ # 4.48%180 149 501 - 1000 1000 28.83$ # 4.06%121 385 1001 - 2000 2000 52.12$ # 3.81%28 265 2001 - 3000 3000 75.43$ # 3.73%7 233 3001 - 5000 5000 122.06$ # 3.66%3 56 5001 - 7500 7500 180.32$ # 3.62%

- 6 7501 - 10000 10000 238.59$ # 3.60%- 7 10001 - 12500 12500 296.88$ # 3.59%- 3 12501 - 13429 13429 318.52$ # 3.59%




General Service Meters 2,001 - 5,000 cuft/hr



Exhibit_(JS-2)

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Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1612889$ 806.44$ 0.1612889$ 806.44$ 0.1208280$ 604.14$ (202.30)$ -25.09% Taxes Distribution 0.0764174$ 382.09$ 1 0.0685129$ 342.56$ 0.0568862$ 284.43$ (58.13)$ -16.97% Transmission Charge 0.0954721$ 477.36$ 0.0954721$ 477.36$ 0.1440660$ 720.33$ 242.97$ 50.90% Taxes Transmission 0.0313002$ 156.50$ 1 0.0273545$ 136.77$ 0.0445858$ 222.93$ 86.16$ 63.00% Storage Charge 0.0289909$ 144.95$ 0.0289909$ 144.95$ 0.0196397$ 98.20$ (46.75)$ -32.25% Taxes Storage 0.0095047$ 47.52$ 1 0.0083066$ 41.53$ 0.0049248$ 24.62$ (16.91)$ -40.72% Gas Supply Charge 0.2555100$ 1,277.55$ 0.2555100$ 1,277.55$ 0.2756188$ 1,378.09$ 100.54$ 7.87% Taxes Supply 0.0001000$ 0.50$ 0.0001000$ 0.50$ 0.0022961$ 11.48$ 10.98$ 100.00% DBU GTAC Amortization 0.0000215$ 0.11$ 0.0000215$ 0.11$ 0.0000215$ 0.11$ -$ 0.00% TBU GTAC Amortization (0.0015870)$ (7.94)$ (0.0015870)$ (7.94)$ (0.0015870)$ (7.94)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 63.88$ 0.0127763$ 63.88$ 0.0127763$ 63.88$ -$ 0.00%

Total Commodity 0.6697950$ 3,348.96$ 0.6567467$ 3,283.71$ 0.6800562$ 3,400.27$ 116.56$ 3.48%




5000 123.31$ 3.68%125 7 0 - 250 250 12.56$ # 5.46%31 4 251 - 500 500 18.38$ # 4.66%37 14 501 - 1000 1000 30.08$ # 4.16%41 45 1001 - 2000 2000 53.37$ # 3.87%26 46 2001 - 3000 3000 76.68$ # 3.77%7 92 3001 - 5000 5000 123.31$ # 3.68%2 73 5001 - 7500 7500 181.57$ # 3.64%3 28 7501 - 10000 10000 239.84$ # 3.62%

- 11 10001 - 15000 15000 356.40$ # 3.59%- 2 15001 - 20000 20000 472.94$ # 3.58%- - 20001 - 25000 25000 589.48$ # 3.58%- - 25001 - 27500 27500 647.77$ # 3.57%- 1 27501 - 31248 31248 735.14$ # 3.57%







Exhibit_(JS-2)

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Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1612889$ 1,612.89$ 0.1612889$ 1,612.89$ 0.1208280$ 1,208.28$ (404.61)$ -25.09% Taxes Distribution 0.0764174$ 764.17$ 1 0.0685129$ 685.13$ 0.0568862$ 568.86$ (116.27)$ -16.97% Transmission Charge 0.0954721$ 954.72$ 0.0954721$ 954.72$ 0.1440660$ 1,440.66$ 485.94$ 50.90% Taxes Transmission 0.0313002$ 313.00$ 1 0.0273545$ 273.55$ 0.0445858$ 445.86$ 172.31$ 62.99% Storage Charge 0.0289909$ 289.91$ 0.0289909$ 289.91$ 0.0196397$ 196.40$ (93.51)$ -32.26% Taxes Storage 0.0095047$ 95.05$ 1 0.0083066$ 83.07$ 0.0049248$ 49.25$ (33.82)$ -40.71% Gas Supply Charge 0.2555100$ 2,555.10$ 0.2555100$ 2,555.10$ 0.2756188$ 2,756.19$ 201.09$ 7.87% Taxes Supply 0.0001000$ 1.00$ 0.0001000$ 1.00$ 0.0022961$ 22.96$ 21.96$ 100.00% DBU GTAC Amortization 0.0000215$ 0.22$ 0.0000215$ 0.22$ 0.0000215$ 0.22$ -$ 0.00% TBU GTAC Amortization (0.0015870)$ (15.87)$ (0.0015870)$ (15.87)$ (0.0015870)$ (15.87)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 127.76$ 0.0127763$ 127.76$ 0.0127763$ 127.76$ -$ 0.00%

Total Commodity 0.6697950$ 6,697.95$ 0.6567467$ 6,567.48$ 0.6800562$ 6,800.57$ 233.09$ 3.48%




10000 243.74$ 3.65%17 2 0 - 300 300 17.66$ # 5.86%4 - 301 - 500 500 22.28$ # 5.15%1 2 501 - 1000 1000 33.98$ # 4.47%7 2 1001 - 2000 2000 57.27$ # 4.04%

- 1 2001 - 3000 3000 80.58$ # 3.88%6 10 3001 - 5000 5000 127.21$ # 3.76%2 5 5001 - 7500 7500 185.47$ # 3.69%1 13 7501 - 10000 10000 243.74$ # 3.65%3 4 10001 - 15000 15000 360.30$ # 3.62%

- 6 15001 - 25000 25000 593.38$ # 3.59%- - 25001 - 35000 35000 826.49$ # 3.58%- 1 35001 - 40000 40000 943.02$ # 3.58%- 2 40001 - 45197 45197 1,064.16$ # 3.57%







Exhibit_(JS-2)

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Commodity Charges: (Monthly $/Therm) Distribution Charge 0.1612889$ 41,235.12$ 0.1612889$ 41,235.12$ 0.1208280$ 30,890.89$ (10,344.23)$ -25.09% Taxes Distribution 0.0764174$ 19,536.87$ 1 0.0685129$ 17,516.01$ 0.0568862$ 14,543.52$ (2,972.49)$ -16.97% Transmission Charge 0.0954721$ 24,408.40$ 0.0954721$ 24,408.40$ 0.1440660$ 36,831.92$ 12,423.52$ 50.90% Taxes Transmission 0.0313002$ 8,002.21$ 1 0.0273545$ 6,993.45$ 0.0445858$ 11,398.80$ 4,405.35$ 62.99% Storage Charge 0.0289909$ 7,411.81$ 0.0289909$ 7,411.81$ 0.0196397$ 5,021.09$ (2,390.72)$ -32.26% Taxes Storage 0.0095047$ 2,429.97$ 1 0.0083066$ 2,123.67$ 0.0049248$ 1,259.07$ (864.60)$ -40.71% Gas Supply Charge 0.2555100$ 65,323.69$ 0.2555100$ 65,323.69$ 0.2756188$ 70,464.71$ 5,141.02$ 7.87% Taxes Supply 0.0001000$ 25.57$ 0.0001000$ 25.57$ 0.0022961$ 587.02$ 561.45$ 100.00% DBU GTAC Amortization 0.0000215$ 5.50$ 0.0000215$ 5.50$ 0.0000215$ 5.50$ -$ 0.00% TBU GTAC Amortization (0.0015870)$ (405.73)$ (0.0015870)$ (405.73)$ (0.0015870)$ (405.73)$ -$ 0.00% Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$ 0.00% USBC 0.0127763$ 3,266.39$ 0.0127763$ 3,266.39$ 0.0127763$ 3,266.39$ -$ 0.00%

Total Commodity 0.6697950$ 171,239.80$ 0.6567467$ 167,903.88$ 0.6800562$ 173,863.18$ 5,959.30$ 3.48%

Total Bill (Price per therm Incl. Service Charge) 171,366.60$ 168,030.68$ 174,002.93$ 5,972.25$ 3.55%



255660 5,972.25$ 3.55%1 1 0 - 300 300 19.96$ # 6.16%

- - 301 - 500 500 24.58$ # 5.40%- - 501 - 1000 1000 36.28$ # 4.63%- - 1001 - 2000 2000 59.57$ # 4.14%- - 2001 - 3000 3000 82.88$ # 3.95%- - 3001 - 5000 5000 129.51$ # 3.80%- - 5001 - 7500 7500 187.77$ # 3.72%- - 7501 - 10000 10000 246.04$ # 3.68%- - 10001 - 15000 15000 362.60$ # 3.63%- - 15001 - 25000 25000 595.68$ # 3.60%- - 25001 - 35000 35000 828.79$ # 3.59%- - 35001 - 40000 40000 945.32$ # 3.58%

1 1 40001 - 255660 255660 5,972.25$ # 3.55%




General Service Meters > 30,000 cuft/hr



Exhibit_(JS-2)

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A B C D E F G H I J K L

CustomerD

Transmission MDDQ 450Storage MDDQ 260

Total Usage in Therms 9,014 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total BillMeter 2 Rate Amount Rate Amount Rate Amount Bill Impact Percent

Monthly Service Charge per Meter 262.10$ 262.10$ 262.10$ 262.10$ 384.40$ 384.40$ 122.30$

Commodity Charges: (Monthly $/Therm) Transmission Charge 0.0058992$ 53.18$ 0.0058992$ 53.18$ 0.0055339$ 49.88$ (3.29)$ Taxes Transmission 0.0031253$ 28.17$ 0.0028530$ 25.72$ 0.0037662$ 33.95$ 8.23$ Storage Charge 0.0014239$ 12.84$ 0.0014239$ 12.84$ 0.0003824$ 3.45$ (9.39)$ Taxes Storage 0.0004643$ 4.19$ 0.0004059$ 3.66$ 0.0002028$ 1.83$ (1.83)$ Gas Supply Charge 0.2555100$ 2,303.21$ 0.2555100$ 2,303.21$ 0.2756188$ 2,484.47$ 181.26$ Taxes Supply 0.0001000$ 0.90$ 0.0001000$ 0.90$ 0.0022961$ 20.70$ 19.80$ TBU GTAC Amortization (0.0014680)$ (13.23)$ (0.0014680)$ (13.23)$ (0.0014680)$ (13.23)$ -$ Storage GTAC Amortization -$ -$ -$ -$ -$ -$ -$

Total Commodity 0.2650547$ 2,389.26$ 0.2647240$ 2,386.27$ 0.2863322$ 2,581.05$ 194.78$

Reservation Charges: (Monthly $/MDDQ) Transmission Reservation 0.4949175$ 222.71$ 0.4949175$ 222.71$ 0.4642679$ 208.92$ (13.79)$ Taxes Transmisson Reservation 0.1614102$ 72.63$ 0.1410862$ 63.49$ 0.3159685$ 142.19$ 78.70$ Storage Reservation 0.3936150$ 102.34$ 0.3936150$ 102.34$ 0.1057050$ 27.48$ (74.86)$ Taxes Storage Reservation 0.1283718$ 33.38$ 0.1122079$ 29.17$ 0.0560650$ 14.58$ (14.60)$

Total Reservation 1.1783145$ 431.06$ 1.1418266$ 417.72$ 0.9420064$ 393.17$ (24.55)$

Total Bill (Price Incl. Service Charge) 3,082.42$ 3,066.08$ 3,358.61$ 292.53$ 9.54%


A B C DTransmission MDDQ 23,250 2,300 1,510 450

Storage MDDQ 12,790 1,250 830 260Total Usage in Therms 150,502 21,844 4,213 9,014

Meters Rated @ Cu. Ft. per hour Meter 2 2 1 21 = 10001 - 300002 = > 30000 Bill Impact -$ -$ -$ 292.53$

Bill Percent 0.00% 0.00% 0.00% 9.54%

Bill Impact 2,327.34$ 495.98$ 70.67$ 292.53$ Bill Percent 3.79% 6.09% 2.72% 9.54%

Firm Utility Gas Contract Service

Range of Impact

Customers

Firm Utility - Bill Amount Proposed RatesRate Moderation





Exhibit_(JS-2)

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Customer Size SmallReservation MDDQ 1,150

Storage MDDQ 0Firm Usage in Therms 20,450

Storage Injection 0Storage Withdrawal 0

Storage Capacity 0Interruptible Usage in Therms 0 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total Bill

Meter 2 Rate Amount Rate Amount Proposed Amount Bill Impact PercentMonthly Service Charge per Meter 136.90$ 136.90$ 136.90$ 136.90$ 180.60$ 180.60$ 43.70$

Commodity Charges: (Monthly $/Therm) Firm TBU Commodity 0.0058992$ 120.64$ 0.0058992$ 120.64$ 0.0056473$ 115.49$ (5.15)$ Taxes Firm TBU Commodity 0.0020959$ 42.86$ 0.0018460$ 37.75$ 0.0022812$ 46.65$ 8.90$ Interruptible TBU Commodity 0.0307375$ -$ 0.0307375$ -$ 0.0337450$ -$ -$ Taxes Interruptible TBU Commodity 0.0104419$ -$ 0.0091410$ -$ 0.0086686$ -$ -$ Storage Injection 0.0019208$ -$ 0.0019208$ -$ 0.0020371$ -$ -$ Taxes Storage Injection 0.0006292$ -$ 0.0005499$ -$ 0.0005212$ -$ -$ Storage Withdrawal 0.0019208$ -$ 0.0019208$ -$ 0.0020371$ -$ -$ Taxes Storage Withdrawal 0.0006292$ -$ 0.0005499$ -$ 0.0005212$ -$ -$ Storage Capacity 0.0018246$ -$ 0.0018246$ -$ 0.0019351$ -$ -$ Taxes Storage Capacity 0.0005980$ -$ 0.0005226$ -$ 0.0004951$ -$ -$ TBU GTAC Amortization (0.0007528)$ (15.39)$ (0.0007528)$ (15.39)$ (0.0007528)$ (15.39)$ -$ USBC 0.0066409$ 135.81$ 0.0066409$ 135.81$ 0.0066409$ 135.81$ -$

Total Commodity 0.0625852$ 283.92$ 0.0608004$ 278.81$ 0.0637771$ 282.56$ 3.75$

Reservation Charges: (Monthly $/MDDQ) Firm TBU Reservation 0.7784823$ 895.25$ 0.7784823$ 895.25$ 0.7452341$ 857.02$ (38.24)$ Taxes Firm TBU Reservation 0.2538910$ 291.97$ 0.2219222$ 255.21$ 0.3010417$ 346.20$ 90.99$ Storage Reservation 0.3716631$ -$ 0.3716631$ -$ 0.3941710$ -$ -$ Taxes Storage Reservation 0.1217889$ -$ 0.1064379$ -$ 0.1008486$ -$ -$

Total Reservation 1.5258253$ 1,187.23$ 1.4785055$ 1,150.47$ 1.541295$ 1,203.22$ 52.75$



Small Medium LargeReservation MDDQ 1,150 20,000 110,000

Storage MDDQ 40,000Firm Usage in Therms 20,450 620,000 3,299,740

Storage Injection 80,000Storage Withdrawal

Storage Capacity 640,000Interruptible Usage in Therms 1,690 114,540

Meters Rated @ Cu. Ft. per hour Meter 2 2 31 = 5000 - 100002 = 10001 - 30000 Bill Impact 100.20$ -$ -$ 3 = > 30000 Bill Percent 6.40% 0.00% 0.00%

Bill Impact 100.20$ 1,079.06$ 6,774.87$ Bill Percent 6.40% 3.76% 3.73%

Non-Core TBU Transportation Service

Range of Impact

TBU Transportation - Bill Amount

Rate ModerationCurrent Rates Approved Including

Deferred Tax Portion in RatesCurrent Rates Approved Excluding

Deferred Tax Portion in RatesProposed Rates



Exhibit_(JS-2)

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Customer Size LargeReservation MDDQ 5,000

Storage MDDQ 0Firm Usage in Therms 284,300

Storage Injection 0Storage Withdrawal 0

Storage Capacity 0Interruptible Usage in Therms 57,080 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total Bill

Meter 4 Rate Amount Rate Amount Proposed Amount Bill Impact PercentMonthly Service Charge per Meter 177.55$ 177.55$ 177.55$ 177.55$ 229.10$ 229.10$ 51.55$

Commodity Charges: (Monthly $/Therm) Firm TBU Commodity 0.0058992$ 1,677.14$ 0.0058992$ 1,677.14$ 0.0056473$ 1,605.51$ (71.63)$ Taxes Firm TBU Commodity 0.0020959$ 595.86$ 0.0018460$ 524.82$ 0.0022812$ 648.56$ 123.74$ Interruptible TBU Commodity 0.0307375$ 1,754.50$ 0.0307375$ 1,754.50$ 0.0337450$ 1,926.17$ 171.67$ Taxes Interruptible TBU Commodity 0.0104419$ 596.02$ 0.0091410$ 521.77$ 0.0086686$ 494.81$ (26.96)$ Interruptible DBU Commodity 0.0202481$ 1,155.76$ 0.0202481$ 1,155.76$ 0.0222344$ 1,269.14$ 113.38$ Taxes Interruptible DBU Commodity 0.0066037$ 376.94$ 0.0057722$ 329.48$ 0.0057117$ 326.02$ (3.46)$ Storage Injection 0.0019208$ -$ 0.0019208$ -$ 0.0020371$ -$ -$ Taxes Storage Injection 0.0006292$ -$ 0.0005499$ -$ 0.0005212$ -$ -$ Storage Withdrawal 0.0019208$ -$ 0.0019208$ -$ 0.0020371$ -$ -$ Taxes Storage Withdrawal 0.0006292$ -$ 0.0005499$ -$ 0.0005212$ -$ -$ Storage Capacity 0.0018246$ -$ 0.0018246$ -$ 0.0019351$ -$ -$ Taxes Storage Capacity 0.0005980$ -$ 0.0005226$ -$ 0.0004951$ -$ -$ TBU GTAC Amortization (0.0007528)$ (214.02)$ (0.0007528)$ (214.02)$ (0.0007528)$ (214.02)$ -$ USBC 0.0066409$ 2,267.07$ 0.0066409$ 2,267.07$ 0.0066409$ 2,267.07$ -$

Total Commodity 0.0894370$ 8,209.27$ 0.0868207$ 8,016.52$ 0.0917232$ 8,323.26$ 306.74$

Reservation Charges: (Monthly $/MDDQ) Firm TBU Reservation 0.7784823$ 3,892.41$ 0.7784823$ 3,892.41$ 0.7452341$ 3,726.17$ (166.24)$ Taxes Firm TBU Reservation 0.2538910$ 1,269.46$ 0.2219222$ 1,109.61$ 0.3010417$ 1,505.21$ 395.60$ Firm DBU Reservation 0.6158065$ 3,079.03$ 0.6158065$ 3,079.03$ 0.5683701$ 2,841.85$ (237.18)$ Taxes Firm DBU Reservation 0.2374280$ 1,187.14$ 0.2101666$ 1,050.83$ 0.2932334$ 1,466.17$ 415.33$ Storage Reservation 0.3716631$ -$ 0.3716631$ -$ 0.3941710$ -$ -$ Taxes Storage Reservation 0.1217889$ -$ 0.1064379$ -$ 0.1008486$ -$ -$ DBU GTAC Amortization 0.0001412$ 0.71$ 0.0001412$ 0.71$ 0.0001412$ 0.71$ -$

Total Reservation 2.3790598$ 9,428.04$ 2.3044786$ 9,131.89$ 2.4028990$ 9,539.40$ 407.51$



Small Medium LargeReservation MDDQ 240 1,520 5,000

Storage MDDQ Firm Usage in Therms 3,340 19,670 284,300

Storage Injection Storage Withdrawal

Storage Capacity Interruptible Usage in Therms 57,080

Meters Rated @ Cu. Ft. per hour Meter 1 3 41 = 2000 - 50002 = 5001 - 10000 Bill Impact -$ -$ 765.80$ 3 = 10001 - 30000 Bill Percent 0.00% 0.00% 4.42%4 = > 30000

Bill Impact 48.42$ 171.88$ 765.80$ Bill Percent 8.05% 5.18% 4.42%

Non-Core DBU Transportation Service

Range of Impact

DBU Transportation - Bill Amount

Rate ModerationCurrent Rates Approved Including

Deferred Tax Portion in RatesCurrent Rates Approved Excluding

Deferred Tax Portion in RatesProposed Rates


Docket No. D2016.9.68Exhibit__(JS-3)

Page 1 of 1

J:\Exhibit__(JS-03) Main Line Ext Allowance Rebuttal Final 5/30/2017

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1011121314151617181920212223

A B C D

Free Main Line Extension Allowance

Natural Gas Utility ResidentialCustomer Usage* 124,805,570No. Customers* 166,071Annual Ave Usage Therms 752 * Source: Exhibit__(PJD-41) attached to the DiFronzo Prefiled Rebuttal Testimony - Phase 1

Residential Gen ServNumber of years to recover free line extension 3.0Total TD&S Rate 0.3777481$ 0.3909305$

Ave Annual Usage Therm 752Free Extension Allowance 852$ Free Extension Allowance per Therm 0.391$

Natural Gas Free Allowance Amounts (per tariffs)Residential (Flat Rate per Service) 850.00$ (rounded to nearest $10)General Service (per Therm) 0.391$

STATE OF MONTANA Department of Public Service Regulation

PUBLIC SERVICE COMMISSION

DOCKET NO. D2016.9.68

ALLOCATED COSTS OF SERVICE BY CLASS

PREFILED DIRECT TESTIMONY OF PAUL M. NORMAND

MANAGEMENT APPLICATIONS CONSULTING, INC.

ON BEHALF OF

NORTHWESTERN ENERGY

May 31, 2017

Department of Public Service Regulation Montana Public Service Commission

Docket No. D2016.9.68 Natural Gas General Filing - Phase Two

NorthWestern Energy

PREFILED DIRECT TESTIMONY

OF PAUL M. NORMAND

ON BEHALF OF NORTHWESTERN ENERGY

TABLE OF CONTENTS

I. POSITION AND QUALIFICATIONS ...................................................................1

II. EMBEDDED COST OF SERVICE STUDY ..........................................................3

GENERAL DESCRIPTION OF ECOS STUDY ................................................................3

NATURAL GAS DELIVERY SERVICES ECOS STUDY ..................................................9

III. MARGINAL COST STUDY – GAS SUPPLY.....................................................21

IV. NATURAL GAS DELIVERY SERVICE RATE DESIGN ..................................25

GENERAL OVERVIEW OF PROCESS ..........................................................................25

DESCRIPTION OF NORTHWESTERN’S PROPOSED RATE DESIGN ..............................27

CORE RATES ........................................................................................................33

NON-CORE RATES ..................................................................................................35

V. SUMMARY – ECOS STUDY AND RATE DESIGN..........................................37

VI. SUMMARY – MARGINAL COST STUDY – GAS SUPPLY ............................38

VII. REVISED ECOS FOR PROPOSED STIPULATION ADJUSTMENT ...............39

LIST OF EXHIBITS

Exhibit Description

Exhibit__(PMN-1) Comparison of Rate Structure Pricing at Present and Proposed Rates

Exhibit__(PMN-2) Glossary of Terms

Exhibit__(PMN-3) Marginal Cost Study – Gas Supply – Summary Results

Exhibit__(PMN-4) Rebuttal ECOS Excluding A&G and Common Plant Costs

PMN-1

I. POSITION AND QUALIFICATIONS 1

Q. Please state your name and business address. 2

A. My name is Paul M. Normand, and my business address is Management Applications 3

Consulting, Inc. (“MAC”), 1103 Rocky Drive, Suite 201, Reading, PA 19609-1157. 4

5

Q. Are you the same Paul M. Normand who submitted prefiled direct testimony on 6

behalf of NorthWestern Energy (“NorthWestern” or “Company”) presenting and 7

sponsoring the cash working capital net lag days in the revenue requirement, Phase 8

One, portion of this docket? 9

A. Yes, I am. 10

11

Q. What is the purpose of your prefiled direct testimony in this Phase Two portion of 12

the docket? 13

A. The purpose of my Phase Two Prefiled Direct Testimony is to present and support 14

NorthWestern’s natural gas Embedded Cost of Service (“ECOS”) study, natural gas 15

supply marginal cost study, and proposed rate design. Statement L presents the ECOS 16

study for NorthWestern’s natural gas transmission, distribution, storage, and production 17

assets (collectively “natural gas utility”). The ECOS study I sponsor comports with 18

standards for conventional class cost of service studies commonly relied upon in the 19

utility industry. Statement L also includes the marginal cost study for NorthWestern’s 20

natural gas supply. Statement M, which is also included in this filing, presents 21

NorthWestern’s proposed rate design. The ECOS study, natural gas supply marginal cost 22

study, and rate design proposals are based on NorthWestern’s rebuttal filing details 23

provided in Phase One of this docket. 24

PMN-2

Q. How is your direct testimony organized? 1

A. My Direct Testimony consists of five sections. This first section introduces and describes 2

the purpose and organization of my testimony. Section II describes the ECOS study 3

included in Statement L. The ECOS study serves as the primary reference point to assess 4

the distribution of proposed class revenue targets in this filing. Section III describes the 5

natural gas supply marginal cost study also included in Statement L. Section IV 6

discusses my proposed rate design pricing based on my ECOS results using the target 7

class revenues developed by NorthWestern witness Joe Schwartzenberger in his prefiled 8

direct testimony and exhibits. Section V summarizes the ECOS study and rate design 9

proposals based on the moderated class revenue targets. 10

11

Q. Briefly describe the exhibits you are sponsoring in your testimony. 12

A. My testimony includes three exhibits. Exhibit__(PMN-1) compares the rate structure 13

pricing at present rates with those from the final proposed rates. (Reference Statement M 14

Pages 2 and 3.) Exhibit__(PMN-2) presents a Glossary of Terms used in my testimony. 15

Exhibit__(PMN-3) presents the Marginal Cost Study – Gas Supply – Summary Results 16

(Reference Statement L, Table 10). Exhibit__(PMN-4) presents a revised ECOS 17

excluding A&G and Common Plant costs and reallocating to Delivery Service. 18

19

PMN-3

II. EMBEDDED COST OF SERVICE STUDY 1

GENERAL DESCRIPTION OF ECOS STUDY 2

Q. Has NorthWestern prepared an ECOS study for use in developing natural gas 3

utility rates? 4

A. Yes. The ECOS study is included in Statement L. The ECOS study relies upon the 2015 5

test year as set forth in Exhibit__(PJD-41) and Exhibit__(PJD-42) attached to the 6

Prefiled Rebuttal Testimony of Patrick J. DiFronzo in Phase One of this filing. The costs 7

employed by this study match NorthWestern’s natural gas utility’s total test period 8

rebuttal revenue requirement. 9

10

Q. Why has NorthWestern filed an ECOS study in this rate increase application? 11

A. In Order No. 7249e in Docket No. D2012.9.94, NorthWestern’s previous general rate 12

case, the Montana Public Service Commission (“Commission”) authorized the use of 13

NorthWestern’s ECOS model for natural gas delivery services in its next cost of service 14

case. ¶ 61. This filing is that case for the Company’s natural gas utility. Accordingly, 15

NorthWestern has prepared and filed an ECOS study as the underlying cost basis upon 16

which to assess its proposed revenue distribution. The ECOS study will provide the 17

allocated costs and related revenue requirements by function and rate class at a uniform 18

Rate of Return (“ROR”). The ECOS plant results in this study are also used to derive the 19

allocated property taxes by rate class. As I describe in more detail below, in addition to 20

natural gas delivery services, and consistent with NorthWestern’s Phase One filing in this 21

docket, the ECOS study incorporates NorthWestern’s three natural gas production assets. 22

23

Q. Do you believe that an ECOS study is appropriate for use in allocating costs? 24

PMN-4

A. Yes, I believe that embedded costs of service provide a fair, transparent, and reasonable 1

basis for allocating costs including natural gas production costs. In fact, the use of ECOS 2

studies for allocating costs to customer classes and deriving revenue targets by cost 3

function and class of service on a uniform equalized basis is common in the utility 4

industry. These final class revenue requirements for rate design are often moderated to 5

address customer bill impact concerns as discussed in the Prefiled Direct Testimony of 6

Joe Schwartzenberger (“Schwartzenberger Direct Testimony”). 7

8

Q. Are the methodologies employed in performing the ECOS study you sponsor in this 9

filing the same as the methodologies used to conduct the ECOS study submitted in 10

NorthWestern’s filing in Docket No. D2012.9.94? 11

A. Yes. The methodologies are generally the same as previously used in Docket No. 12

D2012.9.94, NorthWestern’s most recent natural gas general rate case. However, as 13

described below, I made several modifications to the study to provide more summary 14

information, to improve the accuracy of the allocations, to incorporate NorthWestern’s 15

recently acquired gas production assets, and to improve the transparency of the study and 16

its results. These modifications include: 17

(a) Addition of functional allocations to NorthWestern’s three natural gas production 18

assets; and 19

(b) Detailed allocation of property taxes that supports the development of separate rate 20

components designed to collect property taxes from each customer class based on 21

plant allocations. All of the proposed volumetric transmission, distribution, storage, 22

and production rates include two parts: a property tax component and a component 23

PMN-5

without property taxes, and all monthly service charges exclude any recovery of 1

property taxes. 2

3

Q. Do the steps you employed in conducting the ECOS study follow the marginal cost 4

requirements that are set forth in ARM 38.5.176(2) through (5)? 5

A. Yes, they do. Even though the rules’ requirements specifically relate to marginal costs, 6

the steps I took in this ECOS study follow these requirements as well. The 7

NorthWestern ECOS model functionalizes costs as required by ARM 38.5.176(2). The 8

NorthWestern model classifies and allocates costs as required by ARM 38.5.176(3). The 9

model employs loss factors, allocates Operation and Maintenance (“O&M”) costs, and 10

employs Administrative and General (“A&G”) expense as well as general and common 11

plant allocation factors as required by ARM 38.5.176(4). The ECOS model employs the 12

time frames (i.e., design day demands, annual sales volumes, and winter sales volumes), 13

carrying charge calculations (i.e., NorthWestern’s proposed rate of return and taxes), and 14

proxy class cost estimates (i.e., meter and services investments based on the Company’s 15

data) as required by ARM 38.5.176(5). ARM 38.5.176(6) is not applicable to the ECOS, 16

since it addresses the use of a future time frame for a marginal cost study. 17

18

Q. Is NorthWestern required to follow the marginal cost requirements that are set 19

forth in ARM 38.5.176(2) through (5) in this filing? 20

A. No, as explained above, these requirements do not apply to delivery services costs, but I 21

employed them in my ECOS study. The Commission previously authorized an ECOS 22

study for natural gas delivery services in this case. However, NorthWestern is requesting 23

rate treatment for its natural gas production assets, and a marginal cost study for natural 24

PMN-6

gas supply is therefore required. To that end, NorthWestern has performed a marginal 1

cost study for natural gas supply. I discuss the marginal cost study and the results below; 2

the results are included in Statement L. 3

4

In Order No. 7046i issued in June 2011 in Docket No. D2009.9.129, the Commission 5

also authorized NorthWestern to file an ECOS analysis for delivery services in its next 6

rate case. In that order, it cautioned NorthWestern to “not neglect economic theories and 7

analysis” ¶ 234. I believe that the ECOS study’s adherence to the requirements of ARM 8

38.5.176(2) through (5) demonstrate that NorthWestern is continuing to consider 9

economic theories and analysis and is also promoting economically efficient 10

consumption decisions. 11

12

Q. Generally describe the process of conducting an ECOS study. 13

A. An ECOS study is usually performed in three steps – functionalization, classification, and 14

allocation. Functionalization identifies the operations level where the costs are incurred, 15

either directly or indirectly, with respect to the physical process of providing service. For 16

example, cost associated with distribution mains (distribution function) are segregated from 17

costs associated with transmission mains (transmission function). Similarly, storage 18

investment and costs are segregated from the costs of transmission mains, although a 19

portion of storage is used for transmission balancing and therefore is functionalized as 20

transmission-related. Classification separates costs according to the product characteristics 21

of service as denoted by the primary cost driver – i.e., capacity, commodity, and customer-22

related costs. Allocation uses this information, along with the knowledge that certain costs 23

are incurred exclusively for the benefit of certain customers (direct assignments), to 24

PMN-7

allocate or assign the specific cost components that have been functionalized and classified 1

to specific classes. To the extent practical, costs are allocated based on factors that reflect 2

the manner in which the costs arise. 3

4

Q. Please describe the process of cost functionalization. 5

A. After all of the individual cost components representing the total revenue requirement have 6

been gathered for the cost study, the various cost components are separated according to 7

the function they perform. These functions are: 8

• Production - costs associated with NorthWestern’s Battle Creek, Bear Paw (NFR), and 9

South Bear Paw (Devon) gas production plant. They have been separated into baseload 10

and peaking components, reflecting the manner in which the production facilities are 11

operated. NorthWestern injects a limited amount (9.8%) of natural gas into storage 12

during off-peak periods and uses storage gas as well as flow gas to meet its natural gas 13

demands during winter peak periods; 14

• Storage – costs associated with storing large quantities of natural gas for use during 15

periods of high winter demand. Normally, NorthWestern injects natural gas into 16

storage facilities during periods of low demand and withdraws from storage during 17

periods of high winter demand levels. As indicated below NorthWestern uses a portion 18

(13.2%) of its storage deliverability (25,000 Dekatherms (“Dkt”)) for balancing load 19

and supplies on the transmission system; 20

• Transmission – costs associated with large, high pressure mains that transport large 21

volumes of natural gas to load centers and natural gas storage facilities; 22

• Distribution – costs associated with distributing the natural gas from the transmission 23

system to the end users’ points of delivery; and 24

PMN-8

• Customer – costs associated with providing service to the customer, i.e., services, 1

regulators, metering, billing, etc. 2

3

For the most part, the unbundled costs of a utility such as NorthWestern are already 4

somewhat functionalized based on recorded data. In fact, the Federal Energy Regulatory 5

Commission (“FERC”) Uniform System of Accounts (“USOC”), which the Commission 6

requires NorthWestern to follow, provides for the recording of a major portion of costs by 7

accounts defined and arranged by functional level. 8

9

Q. Please describe the process of cost classification. 10

A. Cost classification is the process of further categorizing the functionalized costs according 11

to the cost-causing characteristic of the utility service provided. The three principal cost 12

classifications are capacity-related (demand) costs, commodity-related (volumetric) costs, 13

and customer-related costs. 14

15

Capacity-related costs (also referred to as demand-related costs) are those fixed costs 16

related to the maximum Dkt demand upon the system, normally the design day (88 Heating 17

Degree Days (“HDD”)) Dkt capacity requirements imposed by a natural gas customer on 18

the Company’s delivery network. Commodity-related costs are those costs related to the 19

therms1 the customer utilizes over a specified period, such as a month or year. Customer-20

related costs are those costs incurred due to the number of customers on the system. These 21

1 NorthWestern undertakes its analysis and reporting in dekatherms, but bills customers in therms. Consequently, the consumption data employed in the cost of service study is expressed in dekatherms and the consumption data employed in rate design is expressed in therms.

PMN-9

are costs closest to the customer premises (meters and services) which generally are not 1

available for use by anyone else and have no causal relationship to consumption volumes. 2

3

Q. Please describe the process of cost allocation. 4

A. Cost allocation is the assignment of functionalized and classified costs to customer classes. 5

Allocation factors reflecting capacity requirements, commodity volumes, and customer 6

costs rely on operating and accounting data to produce representative allocation factors in 7

the form of percentages that add up to 100 percent. These allocation factors applied to 8

specific plant, rate base items, and various expenses derive the total costs of providing 9

service for each class of customers. For example, NorthWestern designs its natural gas 10

mains to maintain natural gas deliverability during the very coldest days. As a result, it is 11

reasonable to assign the costs of natural gas mains on design day (88 HDD) demands by 12

class, as I have done in this case. In turn, it is possible to develop allocation factors for 13

each detailed cost item such that costs are allocated on the metric that best embodies the 14

manner in which costs arise. For example, actual meter costs are allocated according to the 15

number of customers by class weighted by their relative costs of meters. 16

17

NATURAL GAS DELIVERY SERVICES ECOS STUDY 18

Q. Please describe the natural gas delivery services ECOS study detail provided in 19

Statement L. 20

A. The Natural Gas Delivery Services ECOS study (first part of Statement L) consists of 16 21

pages. Pages 1 and 2 of the study provide tables that summarize the results of the cost 22

study. Page 1 compares current rate revenues to proposed revenue levels at Equalized 23

ROR with property taxes included in all functions (Columns B through G), and page 2 24

PMN-10

compares current rate revenues to proposed rate revenue levels based on the Rate Design 1

which includes the property taxes redistributed to all functions except the Customer 2

Function in column (G). These summary tables show the relationship between functional 3

revenues by class at both present and proposed rate levels (Equalized ROR and Rate 4

Design) with a percentage change for all functions and classes. Page 3 of the study lists the 5

functionalization factors. Page 4 shows the class allocation factors employed by 6

NorthWestern in Statement L. Pages 5 and 6 set forth the functionalization of the natural 7

gas revenue requirement components such as plant in service, accumulated depreciation, 8

and cash working capital to develop Rate Base for all functions. Pages 7 and 8 develop the 9

functionalization of O&M expense, revenue, and taxes to achieve an initial functional 10

revenue requirement. Pages 9 through 15 provide the detailed allocations of these 11

functionalized costs to customer classes, which result in an achieved class ROR level as 12

shown at the bottom of page 15. Column A of these pages of the cost study provides a 13

description of the costs allocated, column B shows total system costs, and columns C 14

through K include customer class descriptions. Column L details the allocation factors 15

used to allocate the total costs to classes; as discussed above, page 4 includes these factors. 16

Page 16 shows the detail functional allocator factor development for Labor-Related O&M 17

expenses used in the study. 18

19

Q. Please describe how you functionalized costs in the ECOS model. 20

A. First, I defined 11 cost functions: 21

1. Production - Battle Creek 22

2. Production - Bear Paw (NFR) 23

3. Production - South Bear Paw (Devon) 24

PMN-11

4. Transmission 1

5. Distribution - Other 2

6. Distribution - Customer Meters 3

7. Distribution - Customer Services 4

8. Storage 5

9. Customer Meter Reading 6

10. Customer Records 7

11. Customer Other 8

I either allocated or directly assigned each major item of revenue requirement to functions 9

as shown in column N on pages 5 through 8 of the study. Also shown in this column are 15 10

functionalization factors that I used when I could not directly assign costs to functions. 11

These indirect, or composite, functionalization factors include the following: 12

1. Functional Revenue 13

2. Functional Revenue excluding Production 14

3. Functional Plant Investment 15

4. Functional Plant Investment excluding Production 16

5. Functional Labor Expense 17

6. Functional Labor Expense excluding Production 18

7. Functional Expenses 19

8. Functional Expenses excluding Production 20

9. Meters and Services Expenses 21

10. Distribution Operations Labor Expense 22

11. Distribution Maintenance Labor Expense 23

12. Storage 24

PMN-12

13. Production - Battle Creek 1

14. Production - Bear Paw (NFR) 2

15. Production - South Bear Paw (Devon) 3

4

A list of all functional and class allocation factors is also provided on pages 3 and 4 of the 5

study as I previously discussed. At the completion of the functionalization effort, all costs 6

that comprise NorthWestern’s revenue requirement, including common costs, are assigned 7

to cost functions. 8

9

A detailed Functional Labor Expense allocator (page 16) was developed to more accurately 10

functionalize labor-related costs. This allocator was developed by functionalizing all labor-11

related O&M expenses by each account excluding Production and summing these allocated 12

amounts to create the labor expense allocation factor excluding Production which is 13

represented by the acronym FuncLaborXP. 14

15

Q. How did you use this FuncLaborXP allocator? 16

A. I used the FuncLaborXP allocator to spread Intangible, General, and Common plant to 17

functions as shown on page 5. 18

19

Q. Please describe the functionalization of storage plant that you incorporated into the 20

current ECOS study. 21

A. I functionalized storage plant investment into two components to recognize that a portion 22

of storage plant deliverability is reserved for balancing of the loads on NorthWestern’s 23

natural gas transmission lines. The ECOS study recognizes that NorthWestern reserves 24

PMN-13

25,000 Dkt per day of deliverability from the storage facilities for transmission load 1

balancing. This amounts to 13.6% of the deliverability of total storage facilities. 2

Consequently, I functionalized 13.6% of all storage plant investment to the transmission 3

function. 4

5

Q. Please describe how costs were classified in the ECOS study. 6

A. The classification of costs as capacity-, commodity-, and customer-related takes place 7

within the development of allocators used to assign costs to customer classes. Please refer 8

to pages 9 through 15 of the ECOS study, which show the classification and allocation 9

steps. On these pages, the costs included in the Production – Battle Creek, Production – 10

Bear Paw (NFR), Production – South Bear Paw (Devon), Storage, Transmission, and 11

Distribution Other functions are allocated to classes using the capacity-related allocation 12

factors (which are referred to in the ECOS study by the acronyms BattleCreekAlloc, 13

BearPawAlloc, DevonAlloc, StorageAlloc, TranDD, and DistDD), thus effectively 14

classifying these functionalized costs as capacity-related costs. Similarly, the costs 15

included in the Meters, Services, Meter Reading, Customer Records, and Customer Other 16

functions are allocated to customer classes using the MeterCost, Services, MeterRdg, 17

CustRecords, and Customer allocation factors, thereby producing costs that are classified as 18

customer-related costs. 19

20

Q. Please describe how you allocated costs in the ECOS study. 21

A. Once costs were functionalized and classified, I allocated costs to customer rate classes, as 22

shown on pages 9 through 15 of the study. The allocators used to allocate costs are shown 23

on pages 3 and 4 of the study. The 11 allocators listed on page 4 in column B are used to 24

PMN-14

allocate the majority of costs and rely on external information. These are the underlying 1

foundation to the cost of service study results and are described in more detail below. 2

1. BattleCreekAlloc, BearPawAlloc, and DevonAlloc – Each production plant 3

allocation factor reflects the operation of NorthWestern’s Battle Creek, Bear Paw 4

(NFR), and South Bear Paw (Devon) natural gas production facilities. The 5

production plants operate at full or near-full capacity throughout the year. In the 6

off-peak periods, the capacity delivered to the system exceeds the sales 7

requirements, with the excess delivered to storage. It is estimated that 9.8% of the 8

capacity is delivered to storage. To reflect the production capacity deliveries to 9

storage, a weighted allocation factor was developed. This allocator was weighted 10

90.2% based on July and August average volumes and 9.8% on winter volumes. 11

These two allocators were used for each of the production plants. 12

2. StorageAlloc – Storage plant was and is used to supplement flowing gas to serve 13

core customers. NorthWestern storage is also marketed directly to third-party 14

suppliers. NorthWestern contracts with core customers and third parties to provide 15

varying amounts of deliverability and capacity. Deliverability is the maximum 16

daily rate of withdrawal and is measured in Dkt per day. Capacity is the measure of 17

total volume that can be stored for later withdrawal and is measured in total Dkt. 18

NorthWestern has invested in three storage plants of varying deliverability, 19

capacity, and cost. The storage allocator reflects the operational characteristics of 20

NorthWestern’s Dry Creek, Box Elder, and Cobb storage fields for the last three 21

years. The storage allocator is based on a three-year average dispatch. Individual 22

plant investments were allocated in two steps: first to the months in which they 23

were dispatched on an average historical basis, and second to classes based on their 24

PMN-15

sales in those months adjusted to reflect only sales made from storage withdrawals. 1

These allocation factors reflect the historical storage and deliverability attributes of 2

NorthWestern’s storage plant. 3

3. TranDD – For transmission, the Transmission Design Day allocator is based on the 4

estimated design day demands imposed on the transmission system by each rate 5

class. The design day demands were computed through regression analyses of 6

monthly sales and heating degree data by establishing a base-use- and heating-use-7

per-degree-day factor and then extrapolating to the 88 heating degree days used for 8

the design day. This allocation methodology remains unchanged from 9

NorthWestern’s ECOS study submitted in Docket No. D2012.9.94. 10

4. DistDD – For distribution, the Distribution Design Day allocator is based on the 11

estimated design day demands imposed on the distribution system for each rate 12

class. The distribution allocation factor was developed from the TranDD allocator, 13

which zeroes out classes that are not served by the distribution system. This 14

allocation methodology remains unchanged from NorthWestern’s ECOS study 15

submitted in Docket No. D2012.9.94. 16

5. MeterCost – The meter allocator is based on typical metering cost per customer 17

including installation for each rate class. This is the most accurate approach to 18

developing meter costs for each rate class as the costs can vary somewhat between 19

service classes based on Company data. These estimated costs are then multiplied 20

by the number of customers in each class, which results in a total cost estimate by 21

customer class that is employed as the meter cost allocator to assign actual meter 22

costs in the ECOS study. The methodology for allocating meter costs to classes is 23

the same as employed in NorthWestern’s previous ECOS study. 24

PMN-16

6. Services – Similar to the MeterCost allocator, the services allocator is based on an 1

estimate of service cost per customer multiplied by the number of customers. The 2

actual calculation begins with the number of customers which is then slightly 3

reduced to reflect the number of services, which is typically less. Based on 4

Company records, certain locations have more than one customer but only one 5

service. Like meter costs, discussed above, this approach recognizes the varying 6

costs by customer classes and is the most representative of cost assignment. As in 7

the case of meters, the services allocation factor in this study is calculated in the 8

same manner as in NorthWestern’s previous ECOS study. 9

7. MeterRdg – The meter reading allocator was developed in a two-step process using 10

detailed cost accounting data. Meter reading costs were separately identified for 11

automated meter reading, manual meter reading, and readings taken from the gas 12

measurement system. The count for each type of meter reading was then identified 13

by rate class to develop the meter reading allocator. This allocation methodology 14

remains unchanged from NorthWestern’s previous filing. 15

8. CustRecords – Customer records expense is assigned to rate classes based on the 16

number of customers. The costs of the computerized customer records system are 17

similar for each customer and do not differ significantly by rate class, making 18

customer count the proper allocator. This allocation methodology remains 19

unchanged from NorthWestern’s previous filing. 20

9. Customer – The allocator for other customer costs is identical to the CustRecords 21

allocator, i.e. based on the number of customers. As is the case with the other 22

customer-related allocation factors, this allocation methodology remains unchanged 23

from NorthWestern’s previous filing. 24

PMN-17

Q. Please describe the resulting assignment of costs to customer classes in the ECOS 1

study. 2

A. As stated above, summary results of the ECOS study are shown on pages 1 and 2 of the 3

study with four separate tables on each page providing the following information: 4

• Table 1 – Total Actual Natural Gas Revenue for the Test Year at Current Rates 5

shows the revenues produced by rate class and function at current rates. Note that 6

revenues at current rates are presented for the Production, Storage, Transmission, 7

Distribution, and Customer functions and in total for each rate class. Table 1 is 8

identical on pages 1 and 2. I also show the customer-related revenues with and 9

without property taxes in columns (G) and (H), respectively. 10

• Table 2 on page 1, – Total Natural Gas Revenue at Equalized ROR, shows the 11

revenues that would be produced if all inter-class and inter-function subsidies were 12

eliminated, i.e. if all rates and classes produced the proposed system rate of return 13

on their allocated functional rate base. These revenues are the level of revenues that 14

would be produced by a fully cost-based rate. Table 2 on page 2, Total Proposed 15

Natural Gas Revenue from Rate Design, sets forth the revenues by function for each 16

class that would be produced by NorthWestern’s proposed rates in this filing, after 17

customer class revenue moderation as explained in the Schwartzenberger Direct 18

Testimony. 19

• Table 3 – shows the dollar difference between Table 1 and Table 2 on each page. 20

Table 3 on page 1, Natural Gas Revenue Change to Achieve Equalized ROR, shows 21

the changes in revenue that would result from moving all classes to a revenue level 22

equal to their respective allocated costs of service. On a class-by-class basis, 23

General Service and Firm Storage rates should be reduced and other firm service 24

PMN-18

rates should be increased in order to achieve cost-based rates. On a function-by-1

function basis, storage and distribution charges for most classes should be reduced 2

while production, transmission, and customer charges should be increased in order 3

to achieve cost-based rates. Table 3 on page 2, Natural Gas Revenue Change Rate 4

Design, sets forth the Company’s proposed changes in revenue by class and 5

function. This table reflects the effects of rate moderation upon proposed class 6

revenue and upon the functional rate components for each class of service. 7

• Table 4 – provides the percent difference between Table 1 and Table 3 for both 8

Pages 1 and 2. Table 4 on Page 1 provides the percent change from present revenue 9

that would be necessary for current rates to collect allocated costs of service at 10

equalized ROR. Table 4 on Page 2 provides the percent change in revenues by 11

class and by function proposed by NorthWestern. The proposed class revenues set 12

forth on this table reflect the increases proposed by NorthWestern as set forth on 13

Page 1 of Statement M, column (I). 14

15

Table A below summarizes the class-by-class results of the ECOS study at present and at 16

equalized ROR revenue levels (see also Statement M, page 1, column (F)) and the increase 17

that would be required. 18

PMN-19

Table A Equalized Class Revenue Requirement Comparison

Revenue at

Present Rates Revenue at

Equalized ROR Increase to

Equalized ROR Percent Increases

from Current Residential 74,315,199 80,963,615 6,648,415 8.95 General Service 38,719,759 39,600,473 880,714 2.27

Firm Utilities 581,773 694,857 113,084 19.44

DBU Transport Firm 2,408,640 3,138,126 729,485 30.29

DBU Transport Interruptible 0 0 0 0.00

TBU Transport Firm 13,006,109 14,272,008 1,265,900 9.73

TBU Transport Interruptible 0 0 0 0.00

Firm Storage 3,520,419 3,168,093 -352,326 -10.01 Total 132,551,900 141,837,172 9,285,272 7.01

Table B below summarizes the class-by-class results of the present and proposed revenue 1

levels as summarized in Statement M, page 1, column (I), using the moderated revenue 2

targets presented in the Schwartzenberger Direct Testimony. 3

Table B Proposed Class Revenue Requirement Comparison

Revenue at

Present Rates Revenue at

Proposed Rates Increase at

Proposed Rates Percent Increases

from Current Residential 74,315,199 79,597,459 5,282,218 7.11 General Service 38,719,759 41,303,388 2,583,505 6.67

Firm Utilities 581,773 627,104 45,331 7.79

DBU Transport Firm 2,408,640 2,644,856 236,216 9.81

DBU Transport Interruptible 0 0 0 0.00

TBU Transport Firm 13,006,109 13,937,356 931,248 7.16

TBU Transport Interruptible 0 0 0 0.00

Firm Storage 3,520,419 372,7174 206,755 5.87 Total 132,551,900 141,837,172 9,285,272 7.01

PMN-20

Q. Have you compared the unit costs resulting from the current ECOS study to the unit 1

costs derived from NorthWestern’s ECOS study filed in its last general rate case? 2

A. No, I have not. The primary reason is that, per Commission Order, in January 2017 3

NorthWestern disaggregated then-current volumetric production, distribution, 4

transmission, and storage rates into two parts: a property tax component and a component 5

without property tax. In addition, all property taxes were removed from the fixed 6

monthly customer charges and transferred for recovery through volumetric charges. This 7

significant change in rate design makes any comparison of the current ECOS study unit 8

costs to the ECOS study in NorthWestern’s last general rate case inconsistent and 9

inappropriate. The attached Exhibit__(PMN-1) does, however, provide a complete 10

comparison of present rates effective January 2017 that include separate property tax rate 11

components and proposed pricing for all rates and usage levels. 12

13

Q. What is the purpose of Exhibit__(PMN-2)? 14

A. Exhibit__(PMN-2) is a glossary of terms. Because terms may take on a unique meaning 15

when used to describe the design of utility rates, a glossary is provided to avoid any 16

possible confusion and to comply with Montana’s administrative rule ARM 38.5.176(1)(a). 17

18

PMN-21

III. MARGINAL COST STUDY – GAS SUPPLY 1

Q. Have you prepared a Marginal Cost Study for Gas Supply in this filing? 2

A. Yes, I have. The second part of Statement L presents details of the Marginal Cost Study 3

including ten tables that show the step-by-step development of the estimated marginal 4

costs. I attached the summary results (Table 10) as Exhibit__(PMN-3) to this testimony. 5

6

Q. Please describe the process you undertook to develop your Marginal Cost Study for 7

Gas Supply. 8

A. Marginal supply costs are classically defined as the cost to serve a small change in load. I 9

have measured long-run marginal costs where both fixed and variable costs can change in 10

response to load changes. As with most natural gas utilities, the costs to serve a small 11

change in load are a function of when that change occurs. I measured costs in three time 12

periods: 13

1. on the design day, 14

2. in winter (November through March), and 15

3. in summer (April through October). 16

17

Q. Why is the design day critical to the measurement of marginal supply costs? 18

A. NorthWestern must provide reliable service for its customers under a variety of weather 19

conditions including extremely cold days. The coldest day for which NorthWestern plans 20

to provide reliable service is called the design day. NorthWestern incurs sizeable fixed 21

costs to ensure supply availability under these most extreme weather conditions. It is not 22

prepared to serve loads in excess of this planned load, so the marginal supply cost to serve 23

PMN-22

any additional load on a design day must include the fixed costs to expand its existing 1

capability. 2

3

Q. How would NorthWestern serve additional design day load? 4

A. The Company is constantly evaluating alternatives to serve additional load. Some of these 5

alternatives can serve loads throughout the year. However, for the purposes of measuring 6

long-run marginal supply costs, I relied on a recent study to build a hypothetical new liquid 7

natural gas (“LNG”) vaporization facility. This peaking plant utilizes liquidized natural gas 8

trucked to the plant and vaporized as needed. Since the commodity costs for LNG are 9

much higher than flowing gases or gas stored in underground storage facilities, this supply 10

is only used under conditions that exceed peak load conditions. Conceptually, the use of a 11

peaking facility to measure long-run marginal costs is known as the Peaker Method and has 12

been well documented over the past 40 years. 13

14

Q. Please describe the Peaker Method in layman’s terms. 15

A. The Peaker Method measures marginal commodity costs as the supply cost on the margin 16

each day. It measures marginal capacity costs as the annualized cost to construct and 17

operate a peaking facility capable of providing the least cost alternative to expanding 18

design day capability. 19

20

Q. Please explain how a small change in summer loads would affect NorthWestern’s 21

costs. 22

A. Under normal weather conditions, NorthWestern would respond to a small change in 23

summer load by purchasing a slightly larger quantity of natural gas from the spot markets 24

PMN-23

at the AECO hub and transporting it across the NOVA system to the Company. Both of 1

these costs are variable – NorthWestern would not incur any additional fixed costs in the 2

long run. The summer marginal costs were measured as the load weighted average costs 3

projected for the summer months of 2018 using the readily available strip prices and then 4

adding the transportation charges. 5

6

Q. How did you measure winter marginal costs? 7

A. The calculation of winter marginal costs was very similar to the summer calculation. One 8

additional step was required. I examined the winter daily loads to determine if additional 9

supplies from the hypothetical new LNG vaporization facility would be required. 10

However, under normal weather conditions the peaking plant would not be dispatched and 11

pipeline supplies would remain on the margin. 12

13

Q. Please briefly summarize each of the ten tables you proposed in your Marginal Cost 14

Study – Gas Supply. 15

A. Table C below provides a brief description of what information each table in the study 16

develops. I also indicate where this information is used to aid in following the overall 17

study process that results in the final Table 10 prices set to recover the Company’s overall 18

production revenue requirement: 19

PMN-24

TABLE C

Table

Description of Activity

Results Flow to Table No.

1 Production Capacity Costs – Develops capacity costs on a Dkt basis.

6, page 1

2 Marginal Commodity Costs – Develops projected monthly commodity costs.

7

3 Uncollectible Accounts Expense – Develops class-specific uncollectible percentages excluding gas costs.

6, page 2

4 Development of A&G Loading Factors – Develops A&G Loading Factors related to new plant and plant-related factors.

Develops Common and General Plant Loading Factors and Loss Factors applied to unit capacity assets.

6

5 Development of Levelized Fixed Charge Rates – Develops Levelized Fixed Charge Rates to be applied to the capacity costs calculated on Table 1.

6

6 Summary of Marginal Capacity Costs – Develops the capacity costs per design day Dkt from the results of Tables 1 through 5.

8

7 Marginal Commodity Costs – Presents the calculated seasonal commodity costs previously developed from Table 2 and adjusts for losses and uncollectibles.

8

8 Summary of Marginal Cost Estimates – Presents the calculated marginal costs from Tables 6 and 7 and applies these costs to the billing determinants to derive full annual marginal costs.

9

9 Marginal Commodity Costs – Marginal unit cost per Dkt – Develops full marginal unit cost on a seasonal and annual basis for core rates.

10

10 Derivation of Marginal Prices – Equi-Proportionally Adjusted Costs – Presents Marginal Cost prices adjusted to revenue constraints from embedded cost of service seasonally and annually for core rates.

Final Results per Dkt

PMN-25

Q. Do you recommend that the Company utilize the marginal costs results that you 1

have calculated in your study and summarized on Exhibit ___(PMN-3)? 2

A. No. Based on my costs results, I do not recommend that the prices be applied to any 3

proposed rates for two primary reasons: First, the class price differentials are small with 4

seasonal costs being reasonably close to current prices, and second, the prices have all 5

been adjusted (reduced) to the Company’s total Rebuttal revenue levels. 6

7

IV. NATURAL GAS DELIVERY SERVICE RATE DESIGN 8

GENERAL OVERVIEW OF PROCESS 9

Q. Generally describe the rate design process. 10

A. Rate design generally relies upon a balancing of often-conflicting concerns and interests. 11

Customer impact considerations are very important in recognizing social concerns and 12

promoting consumer confidence in making informed, long-run choices. Revenue stability 13

considerations are also important in ensuring that a utility has an opportunity to earn a fair 14

and reasonable return on its investment. Ease of administration and understanding is 15

necessary to allow consistent, fair, and transparent application of rates. Because these 16

concerns and interests often conflict with one another, it is necessary to balance the relative 17

importance of one concern (or set of concerns) against other concerns. For example, cost-18

based rates may lead to undue customer impact as a result of large rate increases required 19

to set rates at a level that recover the costs of providing service. While some concerns are 20

more subjective than others, the difficulty of quantifying a concern makes it no less 21

important. 22

23

PMN-26

The objective of cost-based rates tends to drive the rate design process with consideration 1

given to notions of fairness, objectivity, and economic efficiency. In this case, 2

NorthWestern chose to adopt a rate-making process that I believe closely mirrors the 3

process typically employed within the utility industry. In this process, a cost-based 4

standard is established and present rates are compared to that standard. Next, criteria 5

limiting the relative rate adjustment impact upon consumers are established. Finally, rates 6

are moved toward full cost recovery subject to the constraints of the rate impact criteria. 7

The overall objective is to move rates for each class within a zone of reasonableness to the 8

overall Company ROR. 9

10

NorthWestern’s development of class revenue levels for natural gas consumers balances 11

movement toward cost-based rates with the recognition that large increases result in rate 12

impacts that may be considered unduly burdensome. However, rate design is a zero-sum 13

process because a reduction in the revenues recovered from one class results in an increase 14

to the rates of one or more other classes, given a specific revenue requirement level. The 15

process of rate moderation and the specific class revenue targets for rate design are 16

discussed more thoroughly in the Schwartzenberger Direct Testimony. 17

18

Once the revenue requirement targets for each rate class are determined, the next step in 19

the rate design process is an assessment and development of the overall structure and 20

price levels for a given class. The ECOS study, submitted in Statement L, provides costs 21

by function and classes, which allows the specific components of each rate to be 22

compared to the associated costs. Again, consideration of customer impact, revenue 23

stability, ease of application and understanding, as well as other practical concerns, may 24

PMN-27

temper the extent to which individual rate elements (i.e., customer, demand, and energy 1

charges) reflect their respective costs of service. Finally, once an initial draft set of rates 2

is established, customer bill impact analyses are undertaken to ascertain whether further 3

rate moderation is necessary. The Schwartzenberger Direct Testimony includes a 4

discussion of these analyses relating to customer bill impacts for the Company’s 5

proposed rates. 6

7

DESCRIPTION OF NORTHWESTERN’S PROPOSED RATE DESIGN 8

Q. Have you prepared schedules that support NorthWestern’s proposed natural gas 9

delivery service rates? 10

A. Yes, these workpapers are provided in Statement M of this filing. Page 1 of Statement M 11

sets forth (1) the normalized billing determinants used to develop the Natural Gas Delivery 12

rates (i.e., average number of customers, Maximum Daily Delivery Quantity (“MDDQ”), 13

and therm sales volumes); (2) the revenues produced by applying present rates to the 14

normalized test year billing determinants; (3) the class revenue requirements determined by 15

the ECOS study submitted in Statement L at an equalized class basis; (4) the moderated 16

revenue levels proposed by NorthWestern as provided in the Schwartzenberger Direct 17

Testimony; (5) the revenues produced by the proposed rates; and (6) the percentage 18

increases resulting from the proposed rates. 19

20

Page 2 of Statement M provides a single page summary of the proposed rates for each class 21

of service. Page 3 presents the same row-by-row details as page 2 except at present 22

approved pricing levels effective January 2017. Please note that the property tax recovery 23

has been shown separately for each rate, and there is no property tax recovery in any of the 24

PMN-28

service charge prices shown on pages 2 and 3. Page 4 details the overall increase in 1

Production which was applied uniformly to all core rates. Page 5 details the property tax 2

rates by class with the targeted revenue amounts by rate class in column (H). The 3

remaining pages 6 through 19 provide the detailed calculations of the proposed delivery 4

service rates for each of the individual rate classes. 5

6

Q. Please describe your general approach to the design of natural gas delivery service 7

rates. 8

A. My general approach to rate design was guided by several criteria that I believe are 9

consistent with Mr. Schwartzenberger’s rate moderation recommendations: 10

1. that individual rates should move toward their unit costs of service, as provided by 11

the ECOS study; 12

2. that rates by class should increase on a percentage basis to the Company’s overall 13

increase in a measured way; 14

3. that the magnitude of the change in individual rates should be capped or limited to 15

ensure reasonable customer impacts; 16

4. that property tax expenses be recovered in a separate proposed volumetric rate for 17

each customer class; 18

5. that emphasis should be placed on the recovery of the fixed costs as it relates to 19

customer-related costs for meters and services; 20

6. that to the maximum extent practical, the same design process should be used for all 21

proposed rates; and 22

7. that the rates should consider reasonable simplification where possible for 23

administrative ease and customer understanding. 24

PMN-29

The unit costs from the ECOS study provide the starting point for individual class rate 1

designs. In the process of designing individual rate components, separate changes to 2

service charge, commodity, and MDDQ rates will have varying impacts on the individual 3

members of the rate class. Thus, the movement of the individual rate components was 4

moderated to avoid undue impacts to individual customers within a given rate class similar 5

to the moderation of the overall increase among customer classes. 6

7

Q. Please summarize the fixed customer costs relating to proposed monthly customer 8

service charges for each class. 9

A. Table D below summarizes the customer-related cost recovery at existing rates (January 10

2017) after removing the property tax amount, at full-equalized cost of service, and at 11

proposed rate levels. The proposed pricing levels for the service charges were set at 50% 12

of the difference between the claimed (full cost of service) and the existing rates. Please 13

note that these monthly charges, which we have identified separately for each rate class, do 14

not include any recovery of property taxes as required by the Commission’s directive. The 15

monthly charges have been rounded to the nearest nickel. 16

17

PMN-30

Table D Comparison of Monthly Service Charges

(excludes property taxes)

Rate Existing Claimed Proposed Residential 5.80 10.66 8.25 Employee 4.35 8.00 6.15 General Services: 0 to 300 * 15.05 18.12 16.60 301 to 1 k 19.85 23.90 21.90 1 k to 2 k 32.00 38.52 35.25 2 k to 5 k 53.75 64.71 59.25 5 k to 10 k 66.00 79.47 72.75 10 k to 30 k 104.35 125.64 115.00 > 30 k 126.80 152.67 139.75 Utilities < 30 k 101.65 196.49 149.05 > 30 k * 262.10 506.66 384.40 DBU < 5 k 97.35 153.88 125.60 < 10 k 111.25 175.86 143.55 < 30 k * 152.90 241.68 197.30 > 30 k 177.55 280.65 229.10 TBU < 10 k 95.25 156.04 125.65 < 30 k 136.90 224.29 180.60 > 30 k * 303.75 497.63 400.70

* The level of average use associated with the calculated service charge. All other service charges 1 were derived based on the existing pricing levels to this level to determine the proposed charges. 2 Note: All data taken from Statement M. Existing service charges reflect a lower level charge after 3 removing the property tax component as of January 2017. 4

5

Q. Why have you set the proposed customer service charges at a more cost-based price 6

level in your rate design in this case? 7

A. In my opinion, the proposed service charges are both reasonable and certainly well below 8

cost. The proposed pricing rationale is threefold. First, the proposed pricing recovers these 9

fixed costs more equitably amongst customers. Volumetric use does not drive these costs; 10

therefore, the current recovery of these costs through volumetric charges is inappropriate. 11

Collection through the monthly service charge more properly recovers these costs from the 12

users of meters and services. Second, these proposed fixed monthly service charges go a 13

PMN-31

long way toward reducing the current high level of intra-class subsidy that exists in the 1

current volumetric recovery. Finally, the increase to the service charges helps to mitigate a 2

new layer of subsidy within each class introduced in January 2017. Removing the property 3

taxes from the approved monthly service charges that existed at that time means that 4

revenues collected to recover property tax expense are now recovered on a volumetric 5

basis. This shifts the recovery towards the higher volume users in each class and into the 6

winter period. 7

8

Q. Please describe the rate design process for the proposed natural gas delivery service 9

and production rates. 10

A. The proposed rates rely upon the results of the ECOS study in Statement L as moderated in 11

the Schwartzenberger Direct Testimony to establish class revenue objectives which also 12

embody class bill impact considerations as discussed in his testimony. 13

14

Prior to deriving final proposed volumetric pricing levels for each rate class, several steps 15

were initially undertaken to establish certain price levels and associated revenue recovery 16

for the following revenue segments: 17

18

PMN-32

STEP ACTIVITY

Class Revenue Targets Establish a moderated target revenue level to be recovered from each class through rate design.

Customer Monthly Service Charge Establish service charges at a 50% increase between existing levels to full cost of service level (Table D) exclusive of property taxes.

Production Costs Remaining Establish recovery of production-related costs from core classes using uniform factors for each class for both the property tax and remaining Production revenue requirement components. This approach to introducing uniformity for these two production cost components simplifies the recovery process and customer understanding for rate design purposes.

Property Tax Recovery Establish a property tax revenue amount to be recovered from core rates (Statement M, page 5, column (H)) based on cost of service results. The final level of property tax recovery from each rate class is the target revenue level less the recovery from the uniform Production component.

Residual Revenue Requirement Once the proposed Customer Service charge, the Production Cost Recovery (for core classes), and the Property Tax revenues are determined, these total dollars are then summed and subtracted from each core class’s moderated revenue targets (as determined in the Schwartzenberger Direct Testimony) to determine the remaining (residual) revenues to be recovered. These remaining revenues are then recovered by increasing all remaining functions of core rate structure prices by the same percent based on the equalized ROR levels from the cost study.

PMN-33

CORE RATES 1

RESIDENTIAL – Pages 6 and 7 of Statement M provide the development of proposed 2

rates for Residential customers and Residential employees (a small group of Company 3

retirees who receive a 25% discount from the Residential rate). Lines 38 through 49 of 4

page 6 provide the component costs from the ECOS study. Based on this study, the unit 5

cost for the monthly service charge was almost twice ($10.66 vs. $5.80) the current 6

Residential service charge. The proposed service charge was set at 50% of this difference, 7

or $8.25. The rate design steps started with the class revenue targets less the recovery of 8

service charge, property tax, and production revenues to determine a residual amount of 9

revenues to be recovered from the functional unit pricing levels. Using the billing statistics 10

for each function, the unit pricing levels were adjusted to achieve the desired remaining 11

revenues. These results are presented in detail on Page 7 of Statement M, lines 78 through 12

98. Finally, the customer service charge was rounded to the nearest nickel and the 13

remaining charges to seven decimal places. These increases produce a Residential rate 14

structure that moves toward cost-based rates while maintaining the moderated Delivery 15

Service rate increase target of $79,597,459, or 7.11% for the Residential class. 16

17

GENERAL SERVICE (“GS”) – Pages 8 through 10 of Statement M provide the 18

development of proposed rates for GS customers. Because the ECOS study showed that 19

current GS rates exceed the costs to provide service to GS customers, a slightly lower-than-20

system average increase is proposed for this rate. As with the design of all classes, the 21

existing monthly Service (i.e., customer) charges are much less than costs. The proposed 22

service charges were increased in the same manner as the Residential rate described above 23

and rounded to the nearest five cents. Since there are several block usage pricing levels, 24

PMN-34

the service charge for the average use level was initially set based on the average use (< 1

300) with all other charges derived based on the existing level ratios to this block. The 2

component costs are set forth on Lines 37 through 39. The transmission cost is 132% of 3

the present transmission charge, while the present distribution and storage charges are 4

much higher than their respective costs of providing service. Since the rate design 5

procedure produces proposed rates that adjust each functional component charge in 6

proportion to the variance with embedded cost, the transmission charge was increased by a 7

large percentage and the distribution and storage charges were reduced. These price 8

comparisons are made with all property taxes removed. As a result of the moderated 9

revenue targets, the GS rate level is increased to $41,303,388, or a 6.67% increase, while 10

the equalized ROR costs are $39,600,473 (Schedule M, pages 1 and 8 to 10). 11

12

FIRM UTILITY GAS CONTRACT SERVICE – Pages 11 through 13 of Statement M 13

provide the development of proposed rates for Firm Utility Gas Contract Service. As with 14

all other rates, the Monthly Service Charges per meter were found to be below the 15

respective costs to serve and were increased in the same manner as residential and general 16

service at 50% of the difference between existing levels and full cost of service. Because 17

the present transmission charges are lower than the costs to provide transmission service 18

and the present storage charges are greater than the costs of providing service, the proposed 19

storage charges were modestly increased and the proposed transmission charges were 20

increased by a proportionately greater percentage. 21

22

23

PMN-35

NON-CORE RATES 1

DBU FIRM TRANSPORTATION – Pages 14 and 15 of Statement M provide the 2

development of rates for Non-Core Distribution Firm Transportation service using the 3

results of the ECOS study as moderated pursuant to Mr. Schwartzenberger’s 4

recommendations. Similar to the rates for other customer classes, the Monthly Service 5

Charges per meter were increased to 50% of the difference between the current level and 6

full cost of service and then rounded to the nearest five cents. The distribution charges 7

were substantially below costs to serve, so these rates were increased to $2,644,856 FIRM 8

(Statement M, page 14, line 1, and page 15, line 67). The Reservation rate was increased 9

6.70% resulting in a total proposed moderated increase of 9.81% for this class, or a 10

moderated increase of $236,216. 11

12

TBU FIRM TRANSPORTATION – Pages 16 through 18 of Statement M provide the 13

development of rates for Non-Core Transmission Firm Transportation service. The 14

Monthly Service Charges per meter were increased similar to all other service charges by 15

increasing to a level at 50% of the difference between current and full cost of service and 16

rounded to the nearest five cents in the same manner as the charges for the Non-Core 17

Distribution Firm Transportation service. Both the present Reservation rate and the 18

Commodity base rates were increased by 6.72%, which is the proposed moderated revenue 19

for this class excluding property taxes and increased 7.16% with property taxes included. 20

21

STORAGE SERVICE – Page 19 of Statement M provides the development of proposed 22

Storage service rates. Because the current rates charged for Storage are significantly higher 23

PMN-36

than the costs to provide this service, the rates for this class were increased by less than the 1

system average increase, or by 5.87%. 2

3

NON-CORE INTERRUPTIBLE SERVICE – Finally, as indicated on lines 28 through 31 4

of page 1 of Statement M, the proposed DBU Interruptible Transportation and the TBU 5

Interruptible Transportation rates are proposed to increase by the same percent as the 6

corresponding firm classes. 7

8

Q. How do the proposed rate components compare to the unit costs derived from 9

NorthWestern’s ECOS study? 10

A. While the movement toward cost-based rates was tempered by concerns of customer 11

impact, as described in the Schwartzenberger Direct Testimony, the proposed rate 12

structures and revenue recovery compare favorably to their related cost components 13

(Statement M, pages 6 and 7). Exhibit__(PMN-1) provides a comparison of the existing 14

unit pricing by rate class with the proposed unit charges for each class (Statement M, pages 15

1 and 2). 16

17

Q. Has NorthWestern calculated bill impacts associated with natural gas rate designs? 18

A. Yes. Natural gas bill impacts are discussed in the Schwartzenberger Direct Testimony. 19

20

Q. In your opinion, are the proposed natural gas production and delivery service rates 21

fair and reasonable? 22

A. Yes. Based on the analyses I have performed and on my experience, I believe that the 23

proposed production and natural gas delivery service rates described above and developed 24

PMN-37

and presented in Statement M reasonably recover the embedded costs of providing service; 1

that these rates do not impose any undue customer impact or hardship; and that these rates 2

reflect a consistent application of recognized ratemaking standards. Consequently, I 3

believe that the proposed natural gas rates are fair and reasonable and that the Commission 4

should approve these proposed rates. 5

6

V. SUMMARY – ECOS STUDY AND RATE DESIGN 7

Q. Please summarize your recommendations regarding the embedded costs of service 8

information and study submitted in Statement L of this rate filing. 9

A. NorthWestern engaged MAC to prepare an ECOS study for this filing and to assist in rate 10

design efforts. The cost allocation methodologies employed in the ECOS study in 11

Statement L closely follow the methodologies employed in NorthWestern’s most recent 12

rate filing in Docket No. D2012.9.94 including certain improvements as described above. I 13

believe that the procedures employed in conducting the ECOS study comport with standard 14

industry practices, reflect the operations and characteristics of NorthWestern and its 15

customer classes, and provide fair and reasonable estimates of the costs of providing 16

service to the various customer classes. In my opinion, this study is a reliable and useful 17

document for determining class costs of service as an important foundation in the design of 18

class revenue targets and proposed rates. I recommend that this study be used to establish 19

natural gas rates in this proceeding. 20

21

Q. Please summarize your recommendations regarding NorthWestern’s proposed rates. 22

A. NorthWestern has proposed rates that balance the results of the ECOS study with a 23

number of often competing pricing considerations. The proposed rates represent a 24

PMN-38

movement toward cost-based rates while simultaneously giving due consideration to 1

consumer impact. Mr. Schwartzenberger recommended a well-reasoned and balanced 2

approach to developing class revenue objectives with the rate moderation proposal made 3

in his testimony. Within the guidelines of Mr. Schwartzenberger’s rate moderation 4

proposal, I designed rates that take into account the information provided by the ECOS 5

study. As I have testified above, I believe that the rates proposed by NorthWestern are 6

fair and reasonable and are neither overly burdensome nor unduly discriminatory. I 7

recommend that this Commission approve the natural gas rates proposed by 8

NorthWestern. 9

10

VI. SUMMARY – MARGINAL COST STUDY – GAS SUPPLY 11

Q. Please summarize your recommendations regarding the marginal costs of service 12

information and study submitted in Statement L of this rate filing. 13

A. NorthWestern engaged MAC to prepare a marginal cost study for Gas Supply for this 14

filing. The marginal cost methodology employed ten separate tables that arrive at pricing 15

levels presented in Table 10 by season and customer class. I believe that the procedures 16

employed in preparing the marginal gas supply study reflect our best estimate of future 17

costs, the operations and characteristics of the Company and its core customer classes, and 18

provide a reasonable estimate of the costs of providing gas supply on a seasonal and annual 19

basis. In my opinion, this study is a reliable and useful document for comparing existing 20

pricing levels for the Company. 21

22

PMN-39

VII. REVISED ECOS FOR PROPOSED STIPULATION ADJUSTMENT 1

Q. Have you prepared an ECOS analysis which reflects the removal of Administrative 2

and General (A&G) expenses and Common Plant from the Production functional 3

costs? 4

A. Yes, I have. After modifying the specific allocation factors for A&G and Common plant to 5

exclude any assignment to the Production function, I reran the ECOS and recalculated the 6

resulting cost and revenue requirements at an equalized ROR basis which I have attached 7

as Exhibit__(PMN-4). 8

9

Q. Could you please briefly discuss your revised ECOS results presented in 10

Exhibit__(PMN-4)? 11

A. Certainly. Table 1 of this exhibit shows the class and functional revenue requirements at 12

the Company’s equalized ROR level which can be compared to and is the same as Table 1 13

of the filed Statement L Part 1, page 1. The revised ECOS results are shown in Table 2 for 14

all classes and functions with A&G and Common excluded from any allocation to 15

Production. The revenue requirements for these re-allocated costs have now been shifted 16

by functions and customer classes through the allocation process with the same overall 17

revenue requirement being achieved as shown in Table 2. All of the revenue differences 18

from the re-allocation process are presented in Table 3 by functions and classes. 19

20

Q. Does this complete your Phase Two direct testimony? 21

A. Yes, it does. 22

NorthWestern EnergyNatural Gas Utility Rate DesignSummary of Proposed Rates

Excl Prop Tax Line Description Service Charge Distribution Transmission Storage Production Total 1 Residential:

2 Residential Base Rate (Therm) $8.25 $0.1078602 $0.1286042 $0.0170723 $0.1265688 $0.3801055

3 Residential Property Tax Rate (Therm) $0.0723782 $0.0467994 $0.0050338 $0.0022961 $0.1265075

4 Employee Base Rate (Therm) $6.15 $0.0808951 $0.0964531 $0.0128042 $0.0949266 $0.2850790

5 Employee Property Tax Rate (Therm) $0.0542837 $0.0350996 $0.0037753 $0.0017221 $0.0948807

6

7 General Service:

8 0 to 300 $16.60

9 301 to 1,000 $21.90

10 1,001 to 2,000 $35.25

11 2,001 to 5,000 $59.25

12 5,001 to 10,000 $72.75

13 10,001 to 30,000 $115.00

14 > 30,000 $139.75

15 General Service Base Rate (Therm) $0.1208280 $0.1440660 $0.0196397 $0.1265688 $0.4111025

16 General Service Property Tax Rate (Therm) $0.0568862 $0.0445858 $0.0049248 $0.0022961 $0.1086929

17

18 Utilities:19 10,001 to 30,000 $149.05

20 > 30,000 $384.40

21 Base - Reservation Rate (MDDQ) $4.642679 $1.057050

22 Base‐ Commodity Rate (Therm) $0.0055339 $0.0003824 $0.1265688 $0.1324851

23 Property Tax - Reservation Rate (MDDQ) $3.159685 $0.560650

24 Property Tax ‐ Commodity Rate (Therm) $0.0037662 $0.0002028 $0.0022961 $0.0062651

25

26

27 DBU Firm Transportation28 < 5000 $125.60

29 5000 to 10000 $143.55

30 10001 to 30000 $197.30

31 > 30000 $229.10

32 Reservation Base Rate (MDDQ) $5.683701 $5.683701

33 Reservation Property Tax Rate (MDDQ) $2.932334 $2.932334

34 Interruptible Transportation Base Rate (Therm) $0.0222344 $0.0222344

35 Interruptible Transportation Base Rate Property Tax (Therm) $0.0057117 $0.0057117

36

37

38 TBU Firm Transportation39 5,001 to 10,000 $125.65

40 10,001 to 30,000 $180.60

41 > 30,000 $400.70



44 Commodity Base Rate (Therm) $0.0056473 $0.0056473

45 Commodity Property Tax Rate (Therm) $0.0022812 $0.0022812

46 Tenaska/Jetco Reservation Base Rate (MDDQ) $1.9339925 $1.9339925

47 Tenaska/Jetco Reservation Property Tax Rate (MDDQ) $0.7812478 $0.7812478

48 Tenaska/Jetco Commodity Rate (Therm) $0.0043491 $0.0043491

49 Tenaska/Jetco Commodity Property Tax Rate (Therm) $0.0017568 $0.0017568

50 Interruptible Transportation Base Rate (Therm) $0.0337450 $0.0337450

51 Interruptible Transportation Base Rate Property Tax (Therm) $0.0086686 $0.0086686

52

53

54 Storage55 Reservation Base Rate (MDDQ) $3.941710 $3.941710


57 Capacity Base Rate (Therm) $0.0019351 $0.0019351

58 Capacity Property Tax Rate (Therm) $0.0004951 $0.0004951

59 Injection Base Rate (Therm) $0.0020371 $0.0020371

60 Injection Property Tax Rate (Therm) $0.0005212 $0.0005212

61 Withdrawal Base Rate (Therm) $0.0020371 $0.0020371

62 Withdrawal Property Tax Rate (Therm) $0.0005212 $0.0005212

63

64

5/19/2017 3:08 PM NG Stmt M 2015 Rev rebuttal links.xlsx Summary

Docket No. D2016.9.68 Phase Two Exhibit__(PMN-1)

Page 1 of 2

NorthWestern EnergyNatural Gas Utility Rate Design

Summary of Present Rates

Excl Prop Tax Line Description Service Charge Distribution Transmission Storage Production Total 1 Residential:

2 Residential Base Rate $5.80 $0.1668809 $0.0988201 $0.0300756 $0.1055755 $0.4013521

3 Residential Property Tax Rate $0.0667590 $0.0254523 $0.0077462 $0.0018313 $0.1017888

4 Employee Base Rate $4.35 $0.1251607 $0.0741151 $0.0225567 $0.0793240 $0.3011565

5 Employee Property Tax Rate $0.0457266 $0.0190892 $0.0058097 $0.0013760 $0.0720015

6

7 General Service:

8 0 to 300 $15.05

9 301 to 1,000 $19.85

10 1,001 to 2,000 $32.00

11 2,001 to 5,000 $53.75

12 5,001 to 10,000 $66.00

13 10,001 to 30,000 $104.35

14 > 30,000 $126.80

15 General Service Base Rate $0.1612889 $0.0954721 $0.0289909 $0.0998876 $0.3856395

16 General Service Property Tax Rate $0.0639852 $0.0246462 $0.0074842 $0.0017327 $0.0978483

17

18 Utilities:19 10,001 to 30,000 $101.65

20 > 30,000 $262.10

21 Base - Reservation Rate (MDDQ) $4.95 $3.94

22 Base‐ Commodity Rate (Therm) $0.005899 $0.001424 $0.105765 $0.113089

23 Property Tax - Reservation Rate (MDDQ) $1.35 $1.01

24 Property Tax ‐ Commodity Rate (Therm) $0.001607 $0.000366 $0.001835 $0.003807

25

26

27 DBU Firm Transportation28 < 5000 $97.35 $97.35

29 5000 to 10000 $111.25 $111.25

30 10001 to 30000 $152.90 $152.90

31 > 30000 $177.55 $177.55

32 Reservation Base Rate $6.1580650 $6.1580650

33 Reservation Property Tax Rate $1.9166532 $1.9166532

34 Interruptible Transportation Base Rate $0.0202481 $0.0202481

35 Interruptible Transportation Base Rate Property Tax $0.0052014 $0.0052014

36

37

38 TBU Firm Transportation39 5,001 to 10,000 $95.25

40 10,001 to 30,000 $136.90

41 > 30,000 $303.75



44 Commodity Base Rate (Therm) $0.0058992 $0.0058992

45 Commodity Property Tax Rate (Therm) $0.0015303 $0.0015303

46 Tenaska/Jetco Reservation Base Rate (MDDQ) $2.0202766 $2.0202766

47 Tenaska/Jetco Reservation Property Tax Rate (MDDQ) $0.0000000 $0.0000000

48 Tenaska/Jetco Commodity Rate (Therm) $0.0045431 $0.0045431

49 Tenaska/Jetco Commodity Property Tax Rate (Therm) $0.0000000 $0.0000000

50 Interruptible Transportation Base Rate $0.0314903 $0.0314903

51 Interruptible Transportation Base Rate Property Tax $0.0080894 $0.0080894

52

53

54 Storage55 Reservation Base Rate (MDDQ) $3.7166310 $3.7166310


57 Capacity Base Rate (Dkt) $0.0018246 $0.0018246

58 Capacity Property Tax Rate (Dkt) $0.0004709 $0.0004709

59 Injection Base Rate (Dkt) $0.0019208 $0.0019208

60 Injection Property Tax Rate (Dkt) $0.0004955 $0.0004955

61 Withdrawal Base Rate (Dkt) $0.0019208 $0.0019208

62 Withdrawal Property Tax Rate (Dkt) $0.0004955 $0.0004955

63

64

5/19/2017 3:10 PM NG Stmt M 2015 Rev rebuttal links.xlsx Summary Present Rates

Docket No. D2016.9.68 Phase Two Exhibit__(PMN-1)

Page 2 of 2

Docket No. D2016.9.68 – Phase Two Exhibit__(PMN‐2)

Page 1 of 2

GLOSSARY OF TERMS

allocation ‐ the assignment or proration of costs that have been functionalized and classified to

customer classes.

capacity costs ‐ costs that vary with the rate of output and are generally considered to be fixed costs.

classification ‐ the process of further categorizing functionalized costs according to the cost causing

characteristic of the utility service being provided. The three principal cost classifications are

demand or capacity‐related costs, commodity‐related costs and customer‐related costs.

commodity costs ‐ costs that vary as the total volume of output (i.e., dekatherms) varies and which are

generally considered to be variable costs.

core customers ‐ customers who choose to allow the utility to procure, transport, balance and schedule

natural gas supplies.

customer costs ‐ costs such as meters and billing that vary as the number of customers served varies and

are typically closest to the customer.

dekatherm ‐ a unit of energy equal to 10 therms or one million British thermal units (MMBtu). Also

spelled as decatherm.

design day demand ‐ the maximum demand for which the transmission and distribution systems are

designed to meet. NorthWestern assumes a design day demand associated with an 88 heating

degree day event.

direct assignment ‐ the allocation of costs directly to a customer or class based upon that customer's

exclusive use or benefit from the facilities giving rise to such costs.

ECOS ‐ an acronym for embedded cost of service. See embedded cost of service. The results determine

cost by function and customer class at equalized revenue requirement levels.

embedded cost of service ‐ a type of cost allocation study in which all costs that comprise the utility's

revenue requirement, including common costs, are allocated to customer classes.

flowing gas ‐ natural gas supplies that are directly injected into the transmission system from sources

other than storage.

functionalization ‐ the arrangement of costs according to major functions, such as production, storage,

transmission, or distribution.

heating degree day ‐ a generally accepted measure of cumulative temperature produced by the National

Oceanic and Atmospheric Administration. A heating degree day (HDD) is the sum of the hourly

temperature deviations below 65 degrees (Fahrenheit) over the course of a day.

Docket No. D2016.9.68 – Phase Two Exhibit__(PMN‐2)

Page 2 of 2

marginal cost ‐ the change in costs associated with a change in output.

normalized billing determinants ‐ billing determinants (usage) that has been adjusted to reflect the level

that would occur under normal temperature conditions.

revenue distribution ‐ the level of revenues to be recovered from a given customer class.

revenue moderation ‐ adjusting ECOS revenue requirement levels at full cost to serve to lower revenue

target to incorporate bill impacts and reflect gradualism.

subsidy ‐ in the context of rate design, the amount by which rate revenues are less than the allocated

costs of service for one class because revenue levels are being recovered by different class in

excess of cost of service.

unbundled utility ‐ a utility whose functional operations (production, storage, transmission, distribution)

operate independently of one another.

Uniform System of Accounts ("USOC") ‐ a prescribed set of accounts established by the Federal Energy

Regulatory Commission uniformly applied to investor‐owned utilities for the purpose of

standardizing the recording of costs.

Docket No. D2016.9.68-Phase TwoExhibit__(PMN-3)

Page 1 of 1

Table - 10NorthWestern EnergyMarginal Cost Study - Gas SupplyDerivation of Marginal Prices Equi-Proportionately Constrained by Embedded Costs - Supply Service

Line Supply TotalNo. Description Residential Employee General Service Firm Utilities Company

D-RG-1 D-RG-2 D-GSG-1 D-FUGC-1(1) (2) (3) (4) (5) (6)

1 Production Revenue Requirements 24,612,597$ 2 Commodity Revenue Requirements 28,701,228$ 3 Total Supply Revenue Requirements 53,313,825$ 4 Total Marginal Annual Revenue Requirements 35,372,674$ 79,372$ 18,007,299$ 654,356$ 54,113,700$ 5 Difference (799,875)$ 6 % Difference -1.48%7 Equi-proportional Adjustment (522,857)$ (1,173)$ (266,173)$ (9,672)$ (799,875)$ 8 Marginal Cost Revenues 34,849,816$ 78,198$ 17,741,126$ 644,684$ 53,313,825$ 910 Marginal Unit Prices1112 WINTER CHARGES13 Gas Supply Demand Charge, Design Day, Dkt 0.5698$ 0.5731$ 0.5816$ 0.5216$ 14 Supply Commodity Charge $'s per Dkt 2.5666$ 2.5552$ 2.5306$ 2.5846$ 1516 SUMMER CHARGES17 Gas Supply Demand Charge, Design Day, Dkt -$ -$ -$ -$ 18 Supply Commodity Charge $'s per Dkt 2.0284$ 2.0153$ 2.0160$ 2.0171$ 1920 ANNUAL CHARGES21 Gas Supply Demand Charge, Design Day, Dkt 0.3987$ 0.3898$ 0.3978$ 0.3540$ 22 Supply Commodity Charge $'s per Dkt 2.4065$ 2.3848$ 2.3844$ 2.4066$

Notes:1 Production Revenues are at 2015 Proposed Rates Excluding Gas Costs and Other Operating Revenues2 Commodity Revenues source Docket No. D2015.7.53, Exhibit_(JMS-2), Page 2 of 3, Line 273 Source: Table 8, page 1 of 14 Source: Table 9, page 1 * (1 + line 6). Design Day costs converted to Dkt based on 2015 volumes.

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A B C D E F G H

Revenue W/O TaxCustomer Class By Class Production Storage Transmission Distribution Customer Customer

Residential 80,963,615 14,421,766 2,625,810 20,911,426 17,039,121 25,965,490 21,248,670General Service 39,600,473 9,958,914 1,390,396 10,782,462 8,785,803 8,682,898 7,081,614Firm Utilities 694,857 231,915 44,922 392,978 0 25,042 20,598DBU Transport - Firm 3,138,126 0 0 0 2,502,647 635,479 529,185DBU Transport - Interrupt 0 0 0 0 0 0 0TBU Transport - Firm 14,272,008 0 0 14,074,781 0 197,227 162,214TBU Transport - Interrupt 0 0 0 0 0 0 0Firm Storage 3,168,093 0 3,168,093 0 0 0 0

Total 141,837,172 24,612,595 7,229,222 46,161,647 28,327,571 35,506,136 29,042,281



Total 141,705,254 20,225,585 7,362,977 47,406,846 29,184,408 37,525,437 31,061,582


Residential 80,346 -2,570,571 48,583 564,081 515,390 1,522,864 1,522,864General Service -739,791 -1,775,101 25,725 290,854 265,748 452,983 452,983Firm Utilities -28,680 -41,337 831 10,600 0 1,225 1,225DBU Transport - Firm 108,277 0 0 0 75,699 32,579 32,579DBU Transport - Interrupt 0 0 0 0 0 0 0TBU Transport - Firm 389,314 0 0 379,664 0 9,650 9,650TBU Transport - Interrupt 0 0 0 0 0 0 0Firm Storage 58,616 0 58,616 0 0 0 0

Total -131,917 -4,387,010 133,756 1,245,200 856,836 2,019,301 2,019,301Note: Difference of -$131,917 is due to two items. Rounding in the stipulation revenue requirements accounts of -$36,000 and the assignment of additional costs to Interruptible customers of -$96,000.


Residential 0.10% -17.82% 1.85% 2.70% 3.02% 5.86% 7.17%General Service -1.87% -17.82% 1.85% 2.70% 3.02% 5.22% 6.40%Firm Utilities -4.13% -17.82% 1.85% 2.70% 0.00% 4.89% 5.95%DBU Transport - Firm 3.45% 0.00% 0.00% 0.00% 3.02% 5.13% 6.16%DBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%TBU Transport - Firm 2.73% 0.00% 0.00% 2.70% 0.00% 4.89% 5.95%TBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Firm Storage 1.85% 0.00% 1.85% 0.00% 0.00% 0.00% 0.00%

Total -0.09% -17.82% 1.85% 2.70% 3.02% 5.69% 6.95%

Table 1. Total Proposed Natural Gas Revenue at Equalized ROR - Rebuttal

Table 2. Total Proposed Natural Gas Revenue at Equalized ROR - Stipulation

Table 3. Difference Rebuttal vs Stipulation Gas Revenue at Equalized ROR

Table 4. Percent Change Rebuttal vs Stipulation Gas Revenue at Equalized ROR

Docket No. D2016.9.68 - Phase Two Exhibit__(PMN-4)

Page 1 of 1

STATEMENT L – PART 1

EMBEDDED COST OF SERVICE STUDY

Natural Gas Embedded Cost Allocation Summary at Current Rates

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A B C D E F G H

Revenue Production Storage Transmission Distribution Customer Cust W/OCustomer Class By Class As Billed As Billed As Billed As Billed As Billed Tax Billed


Total 132,551,900 20,551,096 10,809,497 36,763,817 41,945,577 22,481,912 17,883,123



Total 141,837,172 24,612,595 7,229,222 46,161,647 28,327,571 35,506,136 29,042,281


Residential 6,648,415 1,024,327 -2,091,894 5,410,302 -9,138,139 11,443,819 9,691,595General Service 880,714 3,056,934 -1,086,968 2,624,107 -4,994,629 1,281,270 1,200,024Firm Utilities 113,084 -19,762 -49,087 170,283 0 11,650 9,942DBU Transport - Firm 729,485 0 0 0 514,762 214,724 194,399DBU Transport - Interrupt 0 0 0 0 0 0 0TBU Transport - Firm 1,265,900 0 0 1,193,138 0 72,761 63,199TBU Transport - Interrupt 0 0 0 0 0 0 0Firm Storage -352,326 0 -352,326 0 0 0 0

Total 9,285,272 4,061,499 -3,580,275 9,397,830 -13,618,006 13,024,225 11,159,158


Residential 8.95% 7.65% -44.34% 34.90% -34.91% 78.81% 83.86%General Service 2.27% 44.29% -43.88% 32.16% -36.24% 17.31% 20.40%Firm Utilities 19.44% -7.85% -52.21% 76.46% 0.00% 86.99% 93.31%DBU Transport - Firm 30.29% 0.00% 0.00% 0.00% 25.89% 51.03% 58.07%DBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%TBU Transport - Firm 9.73% 0.00% 0.00% 9.26% 0.00% 58.46% 63.83%TBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Firm Storage -10.01% 0.00% -10.01% 0.00% 0.00% 0.00% 0.00%

Total 7.01% 19.76% -33.12% 25.56% -32.47% 57.93% 62.40%

Table 4. Percent Change to Achieve Equalized ROR

Table 3. Natural Gas Revenue Change to Achieve Equalized ROR

Table 2. Total Proposed Natural Gas Revenue at Equalized ROR

Table 1. Total Actual Natural Gas Revenue for the Test Year at Current Rates

Docket No. D2016.9.68 Statement L - Part 1

Page 1 of 16

Natural Gas Embedded Cost Allocation Summary at Proposed Rates

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A B C D E F G H

Revenue Production Storage Transmission Distribution Customer Cust W/OCustomer Class By Class As Billed As Billed As Billed As Billed As Billed Tax Billed


Total 132,551,900 20,551,096 10,809,497 36,763,817 41,945,577 22,481,912 17,883,123


Residential 79,597,459 16,045,168 2,757,399 21,878,980 22,482,050 16,433,862 16,433,862General Service 41,303,388 8,266,013 1,668,403 12,813,104 12,070,229 6,485,639 6,485,639Firm Utilities 627,108 301,416 30,740 279,325 15,627 15,627DBU Transport - Firm 2,644,856 2,212,882 431,974 431,974DBU Transport - Interrupt 0TBU Transport - Firm 13,937,248 13,806,629 130,619 130,619TBU Transport - Interrupt 0Firm Storage 3,727,113 3,727,113

Total 141,837,172 24,612,597 8,183,655 48,778,038 36,765,161 23,497,720 23,497,720


Residential 5,282,259 2,647,728 -1,960,305 6,377,856 -3,695,210 1,912,191 4,876,787General Service 2,583,629 1,364,034 -808,961 4,654,749 -1,710,203 -915,989 604,048Firm Utilities 45,334 49,739 -63,269 56,629 0 2,235 4,972DBU Transport - Firm 236,216 0 0 0 224,997 11,219 97,188DBU Transport - Interrupt 0 0 0 0 0 0 0TBU Transport - Firm 931,140 0 0 924,987 0 6,153 31,603TBU Transport - Interrupt 0 0 0 0 0 0 0Firm Storage 206,694 0 206,694 0 0 0 0

Total 9,285,272 4,061,501 -2,625,842 12,014,221 -5,180,416 1,015,808 5,614,598

Revenue W/O TaxCustomer Class By Class Production Storage Transmission Distribution Customer

Residential 7.11% 19.76% -41.55% 41.14% -14.12% 42.20%General Service 6.67% 19.76% -32.65% 57.05% -12.41% 10.27%Firm Utilities 7.79% 19.76% -67.30% 25.43% 0.00% 46.66%DBU Transport - Firm 9.81% 0.00% 0.00% 0.00% 11.32% 29.03%DBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%TBU Transport - Firm 7.16% 0.00% 0.00% 7.18% 0.00% 31.92%TBU Transport - Interrupt 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%Firm Storage 5.87% 0.00% 5.87% 0.00% 0.00% 0.00%

Total 7.01% 19.76% -24.29% 32.68% -12.35% 31.40%

Table 4. Percent Change Rate Design

Table 1. Total Actual Natural Gas Revenue for the Test Year at Current Rates

Table 2. Total Proposed Natural Gas Revenue from Rate Design

Table 3. Natural Gas Revenue Change Rate Design


Page 2 of 16

Embedded Natural Gas Allocators

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Functional Allocators Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Total

FuncRevenue 2,478,027$ 4,909,537$ 17,225,032$ 38,629,958$ 49,362,240$ 8,135,575$ 6,171,830$ 11,355,864$ 615,600$ 1,466,318$ 1,487,190$ 141,837,172$ 1.7% 3.5% 12.1% 27.2% 34.8% 5.7% 4.4% 8.0% 0.4% 1.0% 1.0% 100.0%

FuncRevXP -$ -$ -$ 38,629,958$ 49,362,240$ 8,135,575$ 6,171,830$ 11,355,864$ 615,600$ 1,466,318$ 1,487,190$ 117,224,575$ 0.0% 0.0% 0.0% 33.0% 42.1% 6.9% 5.3% 9.7% 0.5% 1.3% 1.3% 100.0%

FuncPlant 12,395,450$ 16,080,164$ 61,756,259$ 264,163,225$ 150,194,784$ 61,506,790$ 68,245,025$ 35,436,563$ -$ -$ -$ 669,778,260$ 1.9% 2.4% 9.2% 39.4% 22.4% 9.2% 10.2% 5.3% 0.0% 0.0% 0.0% 100.0%

FuncPlantXP -$ -$ -$ 264,163,225$ 150,194,784$ 61,506,790$ 68,245,025$ 35,436,563$ -$ -$ -$ 579,546,387$ 0.0% 0.0% 0.0% 45.6% 25.9% 10.6% 11.8% 6.1% 0.0% 0.0% 0.0% 100.0%

FuncLabor 118,486$ 484,499$ 1,235,489$ 7,459,388$ 4,645,335$ 4,930,419$ 2,291,666$ 676,316$ 730,547$ 1,040,643$ 1,497,404$ 25,110,192$ 0.5% 1.9% 4.9% 29.7% 18.5% 19.6% 9.1% 2.7% 2.9% 4.1% 6.0% 100.0%

FuncLaborXP -$ -$ -$ 7,459,388$ 4,645,335$ 4,930,419$ 2,291,666$ 676,316$ 730,547$ 1,040,643$ 1,497,404$ 23,271,718$ 0.0% 0.0% 0.0% 32.1% 20.0% 21.2% 9.8% 2.9% 3.1% 4.5% 6.4% 100.0%

FuncExpense 1,128,742$ 3,052,716$ 8,267,582$ 15,901,951$ 10,557,139$ 8,483,887$ 4,033,081$ 1,794,351$ 1,153,430$ 2,850,633$ 2,825,980$ 60,049,492$ 2% 5% 14% 26% 18% 14% 7% 3% 2% 5% 5% 100.0%

FuncExpenseXP -$ -$ -$ 15,901,951$ 10,557,139$ 8,483,887$ 4,033,081$ 1,794,351$ 1,153,430$ 2,850,633$ 2,825,980$ 47,600,452$ 0% 0% 0% 33% 22% 18% 8% 4% 2% 6% 6% 100.0%

MeterServices -$ -$ -$ -$ -$ 61,506,790$ 68,245,025$ -$ -$ -$ -$ 129,751,815$ 0% 0% 0% 0% 0% 47% 53% 0% 0% 0% 0% 100.0%

DistOpLab -$ -$ -$ -$ 1,738,592$ 1,836,629$ 836,460$ -$ -$ -$ -$ 4,411,681$ 0% 0% 0% 0% 39% 42% 19% 0% 0% 0% 0% 100.0%

DistMnLab -$ -$ -$ -$ 553,007$ 689,522$ 330,983$ -$ -$ -$ -$ 1,573,512$ 0% 0% 0% 0% 35% 44% 21% 0% 0% 0% 0% 100.0%

Storage -$ -$ -$ 5,519,611$ -$ -$ -$ 35,193,443$ -$ -$ -$ 40,713,054$ 0% 0% 0% 14% 0% 0% 0% 86% 0% 0% 0% 100.0%

BattleCreek 12,395,450$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 12,395,450$ 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 100.0%

BearPaw -$ 16,080,164$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 16,080,164$ 0% 100% 0% 0% 0% 0% 0% 0% 0% 0% 0% 100.0%

Devon -$ -$ 61,756,259$ -$ -$ -$ -$ -$ -$ -$ -$ 61,756,259$ 0% 0% 100% 0% 0% 0% 0% 0% 0% 0% 0% 100.0%


Page 3 of 16

Embedded Natural Gas Allocators

5657585960616263646566676869707172737475767778798081828384858687888990

A B C D E F G H I J K LNWE ProposedClass Allocators res emp genserv fugc firmdbu interdbu firmtbu intertbu storage Total

Customer 165,787 284 23,359 4 224 - 32 - - 189,690 87.4% 0.1% 12.3% 0.0% 0.1% 0.0% 0.0% 0.0% 0.0% 100.0%

TranDD 146,065 323 75,481 2,751 - - 98,529 - - 323,150 45.2% 0.1% 23.4% 0.9% 0.0% 0.0% 30.5% 0.0% 0.0% 100.0%

DistDD 146,065 323 75,481 - 21,501 - - - - 243,371 60.0% 0.1% 31.0% 0.0% 8.8% 0.0% 0.0% 0.0% 0.0% 100.0%

StorageAlloc 36.24% 0.08% 19.23% 0.62% 0.00% 0.00% 0.00% 0.00% 43.82% 100.0%36.2% 0.1% 19.2% 0.6% 0.0% 0.0% 0.0% 0.0% 43.8% 100.0%

BattleCreekAlloc 58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%

BearPawAlloc 58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%

DevonAlloc 58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%58.5% 0.1% 40.5% 0.9% 0.0% 0.0% 0.0% 0.0% 0.0% 100.0%

MeterCost 50,569,775 86,654 23,818,889 113,091 2,494,805 - 891,005 - - 77,974,219 64.9% 0.1% 30.5% 0.1% 3.2% 0.0% 1.1% 0.0% 0.0% 100.0%

Services 172,009,899 294,747 42,048,422 - 521,864 - - - - 214,874,932 80.1% 0.1% 19.6% 0.0% 0.2% 0.0% 0.0% 0.0% 0.0% 100.0%

MeterRdg 279,785 479 349,155 827 45,629 - 6,472 - - 682,347 41.0% 0.1% 51.2% 0.1% 6.7% 0.0% 0.9% 0.0% 0.0% 100.0%

CustRecords 2,063,210 3,535 290,698 50 2,793 - 396 - - 2,360,682 87.4% 0.1% 12.3% 0.0% 0.1% 0.0% 0.0% 0.0% 0.0% 100.0%


Page 4 of 16

Embedded Natural Gas Allocations by Utility Function

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Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator13 Month Avg PlantProd Battle Creek 12,395,450$ 12,395,450 - - - - - - - - - - BattleCreekProd Bear Paw 16,080,164$ - 16,080,164 - - - - - - - - - BearPawProd Devon 61,756,259$ - - 61,756,259 - - - - - - - - DevonStorage 40,994,304$ - - - 5,557,741 - - - 35,436,563 - - - StorageTransmission 258,605,483$ 258,605,483 DirectDistribution - Other 150,194,784$ 150,194,784 DirectDistribution - Meters 61,506,790$ 61,506,790$ DirectDistribution - Services 68,245,025$ 68,245,025$ DirectIntangible 785,745$ - - - 251,858 156,845 166,470 77,376 22,835 24,666 35,136 50,558 FuncLaborXPGeneral 26,817,555$ - - - 8,595,951 5,353,130 5,681,651 2,640,840 779,364 841,858 1,199,202 1,725,558 FuncLaborXPCommon - TDS 28,643,835$ - - - 9,181,337 5,717,679 6,068,572 2,820,682 832,439 899,189 1,280,868 1,843,069 FuncLaborXPCommon - Battle Creek 640,212$ 640,212 - - - - - - - - - - BattleCreekCommon - Bear Paw 830,524$ - 830,524 - - - - - - - - - BearPawCommon - Devon 3,189,648$ - - 3,189,648 - - - - - - - - DevonTotal Plant 730,685,780$ 13,035,662 16,910,688 64,945,907 282,192,371 161,422,437 73,423,484 73,783,923 37,071,201 1,765,714 2,515,206 3,619,186

13 Month Accum DeprProd Battle Creek 3,189,723$ 3,189,723 - - - - - - - - - - BattleCreekProd Bear Paw 4,185,519$ - 4,185,519 - - - - - - - - - BearPawProd Devon 7,489,547$ - - 7,489,547 - - - - - - - - DevonStorage 23,257,894$ - - - 3,153,154 - - - 20,104,740 - - - StorageTransmission 102,291,706$ 102,291,706 DirectDistribution - Other 65,459,383$ 65,459,383 DirectDistribution - Meters 26,806,500$ 26,806,500$ DirectDistribution - Services 29,743,225$ 29,743,225$ DirectIntangible 194,383$ - - - 62,307 38,801 41,183 19,142 5,649 6,102 8,692 12,507 FuncLaborXPGeneral 14,466,492$ - - - 4,637,009 2,887,698 3,064,916 1,424,578 420,421 454,133 646,899 930,837 FuncLaborXPCommon - TDS 11,350,602$ - - - 3,638,260 2,265,726 2,404,774 1,117,743 329,868 356,319 507,566 730,347 FuncLaborXPCommon - Battle Creek 252,141$ 252,141 - - - - - - - - - - BattleCreekCommon - Bear Paw 327,093$ - 327,093 - - - - - - - - - BearPawCommon - Devon 1,256,207$ - - 1,256,207 - - - - - - - - Devon

290,270,415$ 3,441,864 4,512,612 8,745,754 113,782,436 70,651,609 32,317,373 32,304,687 20,860,678 816,554 1,163,157 1,673,692

13 Month Net Plant 440,415,365$ 9,593,799 12,398,077 56,200,153 168,409,935 90,770,828 41,106,111 41,479,236 16,210,523 949,160 1,352,050 1,945,494

Additional Ratebase ItemsGas Stored Underground 32,096,313$ - - - 4,351,410 - - - 27,744,903 - - - StorageCost of Refinancing Debt 4,044,903$ - - - 1,843,709 1,048,274 429,282 476,311 247,327 - - - FuncPlantXPGas Storage Sales (9,779,300)$ - - - (1,325,814) - - - (8,453,486) - - - StorageFAS 109 61,269,439$ - - - 27,927,243 15,878,539 6,502,476 7,214,840 3,746,341 - - - FuncPlantXPMPSC/MCC Taxes - TDS 162,444$ - - - 53,531 68,404 11,274 8,553 15,736 853 2,032 2,061 FuncRevXPMPSC/MCC Taxes - Battle Creek (349)$ (349) - - - - - - - - - - BattleCreekMPSC/MCC Taxes - Bear Paw -$ - - - - - - - - - - - BearPawMPSC/MCC Taxes - Devon -$ - - - - - - - - - - - Devon

87,793,450$ (349) - - 32,850,078 16,995,217 6,943,032 7,699,704 23,300,822 853 2,032 2,061


Page 5 of 16


12


Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator495051525354555657585960616263646566676869707172737475767778798081828384858687888990919293949596979899

100101102

Cust Contributed Capital - TDSAccum Deferred Inc Taxes

Regulatory Liability - MPSC Taxes 101,752$ - - - 33,531 42,847 7,062 5,357 9,857 534 1,273 1,291 FuncRevXPAccelerated Depreciation 37,012,813$ - - - 16,870,822 9,592,211 3,928,140 4,358,478 2,263,161 - - - FuncPlantXPCustomer Advances for Construction (2,657,343)$ (2,657,343) DirectNet Operating Loss (7,230,533)$ - - - (2,382,736) (3,044,714) (501,811) (380,685) (700,441) (37,971) (90,444) (91,731) FuncRevXPDeferred Revenue (5,436,426)$ - - - (1,791,509) (2,289,231) (377,297) (286,226) (526,641) (28,549) (68,002) (68,970) FuncRevXPAccrued Incentive Compensation (691,258)$ - - - (221,572) (137,984) (146,452) (68,071) (20,089) (21,700) (30,911) (44,479) FuncLaborXPInjuries & Damages (Workmen's Comp) (972,246)$ - - - (311,638) (194,073) (205,983) (95,741) (28,255) (30,521) (43,476) (62,559) FuncLaborXPCost of Refinancing Debt (197,470)$ - - - (90,009) (51,176) (20,957) (23,253) (12,074) - - - FuncPlantXPProperty Taxes 5,216$ - - - 2,378 1,352 554 614 319 - - - FuncPlantXPFAS 106 & FAS 112 Post Retirements Benefits (9,088,186)$ - - - (2,913,077) (1,814,119) (1,925,452) (894,953) (264,118) (285,297) (406,397) (584,773) FuncLaborXPEnvironmental Reserve (491,273)$ - - - (223,927) (127,318) (52,138) (57,850) (30,039) - - - FuncPlantXPRegulatory Asset FAS 109 61,269,439$ - - - 27,927,243 15,878,539 6,502,476 7,214,840 3,746,341 - - - FuncPlantXP

Personal Inj & Prop Damage Third Party Claims) 3,130,790$ - - - 1,003,526 624,946 663,299 308,302 90,986 98,282 140,000 201,449 FuncLaborXPCustomer Advances 6,813,187$ 6,813,187 Direct

81,568,462$ -$ -$ -$ 37,903,031$ 22,637,124$ 7,871,440$ 10,080,812$ 4,529,005$ (305,221)$ (497,958)$ (649,773)$

Cust Contributed Capital - ProductionAccum Deferred Inc Taxes

Regulatory Liability - MPSC Taxes (1,332)$ (245) (379) (708) DirectAccelerated Depreciation 2,045,524$ 415,907 268,420 1,361,197 DirectCustomer Advances for Construction (9,438)$ (1,733) (2,685) (5,020) DirectNet Operating Loss 1,812,360$ 379,599 (219,727) 1,652,488 DirectDeferred Revenue (105,363)$ (19,345) (29,977) (56,041) DirectAccrued Incentive Compensation (5,827)$ (1,070) (1,658) (3,099) DirectInjuries & Damages (Workmen's Comp) 9,575$ 1,758 2,724 5,093 DirectCost of Refinancing Debt (2,839)$ (521) (808) (1,510) DirectProperty Taxes -$ - - - DirectFAS 106 & FAS 112 Post Retirements Benefits (25,827)$ (4,742) (7,348) (13,737) DirectEnvironmental Reserve (2,342)$ (430) (666) (1,246) DirectRegulatory Asset FAS 109 -$ - - - Direct

Personal Inj & Prop Damage Third Party Claims) -$ - - - DirectCustomer Advances -$ - - - Direct

3,714,493$ 769,179 7,897 2,937,418 - - - - - - - -

Cust Contributed Capital - Total 85,282,955$ 769,179$ 7,897$ 2,937,418$ 37,903,031$ 22,637,124$ 7,871,440$ 10,080,812$ 4,529,005$ (305,221)$ (497,958)$ (649,773)$

Materials & Supplies 7,085,112$ - - - 3,229,467 1,836,172 751,937 834,314 433,222 - - - FuncPlantXP

Cash Working Capital -TDS (15,462,874)$ - - - (5,165,704) (3,429,457) (2,755,967) (1,310,135) (582,890) (374,689) (926,020) (918,012) FuncExpenseXPCash Working Capital - Prod Battle Creek (242,896)$ (242,896) - - - - - - - - - - BattleCreekCash Working Capital - Prod Bear Paw (635,404)$ - (635,404) - - - - - - - - - BearPawCash Working Capital - Prod Devon (1,722,784)$ - - (1,722,784) - - - - - - - - DevonTotal Cash Working Capital (18,063,958)$ (242,896) (635,404) (1,722,784) (5,165,704) (3,429,457) (2,755,967) (1,310,135) (582,890) (374,689) (926,020) (918,012)

Rate Base 431,947,014$ 8,581,375 11,754,776 51,539,952 161,420,745 83,535,635 38,173,673 38,622,306 34,832,671 880,546 926,019 1,679,316


Page 6 of 16


12



MPSC Revenue 141,837,172$ 2,478,027 4,909,537 17,225,032 38,629,958 49,362,240 8,135,575 6,171,830 11,355,864 615,600 1,466,318 1,487,190 Direct

Misc Revenue - TDS 613,520$ - - - 202,178 258,348 42,579 32,302 59,433 3,222 7,674 7,784 FuncRevXPBattle Creek - Misc, Off-Sys, Gathering 149,289$ 149,289 - - - - - - - - - - BattleCreekBear Paw - Misc, Off-Sys, Gathering 1,029,046$ - 1,029,046 - - - - - - - - - BearPawDevon - Misc, Off-Sys, Gathering 1,508,530$ - - 1,508,530 - - - - - - - - DevonInterruptible Revenue 2,612,504$ 2,576,338 36,166 DirectOff System Revenues 12,487$ - - - 4,115 5,258 867 657 1,210 66 156 158 FuncRevXPCMPL Revenue 170,464$ 170,464 DirectRounding (14,820)$ - - - (4,884) (6,241) (1,029) (780) (1,436) (78) (185) (188) FuncRevXP

Total Revenue 147,918,191$ 2,627,316$ 5,938,583$ 18,733,562$ 41,578,169$ 49,655,771$ 8,177,992$ 6,204,009$ 11,415,071$ 618,810$ 1,473,963$ 1,494,944$

O & M Expenses Prod Battle Creek 554,465$ 554,465 - - - - - - - - - - BattleCreek Prod Bear Paw 2,148,613$ - 2,148,613 - - - - - - - - - BearPaw Prod Devon 6,535,979$ - - 6,535,979 - - - - - - - - Devon Gas Supply Admin 503,955$ - - - 166,072 212,211 34,975 26,533 48,820 2,647 6,304 6,394 FuncRevXP Storage Operation 1,055,284$ - - - 143,069 - - - 912,215 - - - Storage Storage Maintenance 359,422$ - - - 48,728 - - - 310,694 - - - Storage Transmission Operation 7,766,588$ 7,766,588 Direct Transmission Maintenance 2,356,899$ 2,356,899 Direct Distribution Op - Supervision 2,181,949$ - - - - 859,881 908,368 413,700 - - - - DistOpLab Distribution Op - Meters 1,545,290$ 1,545,290 Direct Distribution Op - Cust Install 2,195,229$ - - - - - 1,040,613 1,154,615 - - - - MeterServices Dist Op - Cust Install - Battle Creek 71$ 71 - - - - - - - - - - BattleCreek Dist Op - Cust Install - Bear Paw 109$ - 109 - - - - - - - - - BearPaw Dist Op - Cust Install - Devon 205$ - - 205 - - - - - - - - Devon Distribution Op - Other 5,073,680$ 5,073,680 Direct Dist Op - Other - Battle Creek 9,396$ 9,396 - - - - - - - - - - BattleCreek Dist Op - Other - Bear Paw 14,560$ - 14,560 - - - - - - - - - BearPaw Dist Op - Other - Devon 27,220$ - - 27,220 - - - - - - - - Devon Distribution Mnt - Supervision 1,070,039$ - - - - 376,063 468,897 225,079 - - - - DistMnLab Distribution Mnt - Services 581,196$ 581,196 Direct Distribution Mnt - Meters 1,177,743$ 1,177,743 Direct Distribution Mnt - Other 679,753$ 679,753 Direct Customer Meter Reading 682,347 682,347 Direct Customer Records 2,360,682$ 33,772 52,333 97,836 2,176,741 Direct Customer Accounts 519,936$ 5,921 9,175 17,153 487,687 Direct Customer Service 1,588,712$ 39,857 61,764 115,466 1,371,625 Direct Sales Expense -$ - Direct A & G Expense - TDS Labor 14,911,685$ - - - 4,779,709 2,976,565 3,159,236 1,468,418 433,359 468,109 666,807 959,483 FuncLaborXP A & G Expense - TDS Revenue 62,468$ - - - 20,586 26,305 4,335 3,289 6,051 328 781 793 FuncRevXP A & G Expense - TDS Plant 1,360,874$ - - - 620,300 352,683 144,428 160,251 83,211 - - - FuncPlantXP A & G Expense - Battle Creek 485,261$ 485,261 - - - - - - - - - - BattleCreek A & G Expense - Bear Paw 766,161$ - 766,161 - - - - - - - - - BearPaw A & G Expense - Devon 1,473,723$ - - 1,473,723 - - - - - - - - DevonTotal O & M Expenses 60,049,492$ 1,128,742 3,052,716 8,267,582 15,901,951 10,557,139 8,483,887 4,033,081 1,794,351 1,153,430 2,850,633 2,825,980


Page 7 of 16


12



DepreciationDepreciation Expense - TDS 15,117,887$ - - - 6,890,889 3,917,940 1,604,449 1,780,221 924,388 - - - FuncPlantXPDepreciation Expense - Battle Creek 64,182$ 64,182 - - - - - - - - - - BattleCreekDepreciation Expense - Bear Paw 125,287$ - 125,287 - - - - - - - - - BearPawDepreciation Expense - Devon 264,206$ - - 264,206 - - - - - - - - DevonAmortize Natural Gas Plant - TDS 1,250,806$ - - - 570,130 324,158 132,747 147,290 76,481 - - - FuncPlantXPDepletion Natural Gas Plant - Battle Creek 498,089$ 498,089 - - - - - - - - - - BattleCreekDepletion Natural Gas Plant - Bear Paw 1,261,486$ - 1,261,486 - - - - - - - - - BearPawDepletion Natural Gas Plant - Devon 4,320,770$ - - 4,320,770 - - - - - - - - DevonAmortize Cushion Gas Def (420,516)$ - - - (57,011) - - - (363,505) - - - StorageAmortize Property Taxes -$ - - - - - - - - - - - FuncPlantAmortize USBC -$ - - - - - - - - - - - FuncRevenueAmortize Comp Absences -$ - - - - - - - - - - - FuncLaborAmortize DSIP -$ - - - - - - - - - - - FuncRevenueAmortize MPSC/MCC Taxes - TDS 108,296$ - - - 35,688 45,602 7,516 5,702 10,491 569 1,355 1,374 FuncRevXPAmortize MPSC/MCC Taxes - Battle Creek (232)$ (232) - - - - - - - - - - BattleCreekAmortize MPSC/MCC Taxes - Bear Paw -$ - - - - - - - - - - - BearPawAmortize MPSC/MCC Taxes - Devon -$ - - - - - - - - - - - DevonPension Differential - TDS (2,554,220)$ - - - (818,716) (509,855) (541,145) (251,525) (74,230) (80,182) (114,217) (164,350) FuncLaborXPPension Differential - Battle Creek (54,354)$ (54,354) - - - - - - - - - - BattleCreekPension Differential - Bear Paw (84,228)$ - (84,228) - - - - - - - - - BearPawPension Differential - Devon (157,463)$ - - (157,463) - - - - - - - - Devon

19,739,996$ 507,685 1,302,544 4,427,514 6,620,981 3,777,845 1,203,567 1,681,687 573,625 (79,614) (112,863) (162,976)

Taxes Other - TDS 824,546$ - - - 375,837 213,689 87,508 97,095 50,417 - - - FuncPlantXP Other - Battle Creek 20,567$ 20,567 - - - - - - - - - - BattleCreek Other - Bear Paw 26,790$ - 26,790 - - - - - - - - - BearPaw Other - Devon 95,245$ - - 95,245 - - - - - - - - Devon Payroll - TDS 1,906,611$ - - - 611,135 380,584 403,941 187,752 55,409 59,852 85,258 122,680 FuncLaborXP Payroll - Battle Creek 20,877$ 20,877 - - - - - - - - - - BattleCreek Payroll - Bear Paw 51,135$ - 51,135 - - - - - - - - - BearPaw Payroll - Devon 100,082$ - - 100,082 - - - - - - - - Devon Other Property - Tribal 426,759$ - - - 194,521 110,599 45,292 50,253 26,094 - - - FuncPlantXP Property - TDS 28,871,304$ - - - 13,159,838 7,482,264 3,064,088 3,399,767 1,765,346 - - - FuncPlantXP Property - Battle Creek 26,843$ 26,843 - - - - - - - - - - BattleCreek Property - Bear Paw 205,038$ - 205,038 - - - - - - - - - BearPaw Property - Devon 206,660$ - - 206,660 - - - - - - - - Devon Income -TDS 1,093,602$ - - - 498,475 283,417 116,063 128,778 66,869 - - - FuncPlantXP Income - Battle Creek 293,589$ 293,589 - - - - - - - - - - BattleCreek Income - Bear Paw 438,734$ - 438,734 - - - - - - - - - BearPaw Income - Devon 1,858,602$ - - 1,858,602 - - - - - - - - Devon

36,466,984$ 361,876 721,697 2,260,588 14,839,806 8,470,553 3,716,892 3,863,646 1,964,135 59,852 85,258 122,680

Total Operating Expense 116,256,472$ 1,998,303$ 5,076,957$ 14,955,684$ 37,362,737$ 22,805,537$ 13,404,346$ 9,578,415$ 4,332,111$ 1,133,669$ 2,823,028$ 2,785,684$ -

Adj Operating Income 31,661,719$ 629,013 861,626 3,777,878 4,215,432 26,850,234 (5,226,354) (3,374,406) 7,082,960 (514,860) (1,349,065) (1,290,740)

Rate of Return 7.33% 7.33% 7.33% 7.33% 2.61% 32.14% -13.69% -8.74% 20.33% -58.47% -145.68% -76.86%


Page 8 of 16

Embedded Natural Gas Allocation by Customer Class

123456789101112131415161718192021222324252627282930313233343536373839404142434445


Total res emp genserv fugc firmdbu interdbu firmtbu intertbu storage allocators13 Month Avg PlantProd Battle Creek 13,035,662$ 7,621,420 16,835 5,274,577 122,830 - - - - - BattleCreekAllocProd Bear Paw 16,910,688$ 9,886,990 21,839 6,842,516 159,343 - - - - - BearPawAllocProd Devon 64,945,907$ 37,971,223 83,874 26,278,850 611,961 - - - - - DevonAllocStorage 37,071,201$ 13,435,457 29,608 7,129,905 230,360 - - - - 16,245,872 StorageAllocTransmission 282,192,371$ 127,552,152 282,218 65,914,642 2,402,327 - - 86,041,033 - - TranDDDistri Other 161,422,437$ 96,881,734 214,357 50,065,207 - 14,261,139 - - - - DistDDCust Meters 73,423,484$ 47,618,420 81,596 22,428,770 106,491 2,349,203 - 839,004 - - MeterCostCust Services 73,783,923$ 59,064,895 101,210 14,438,620 - 179,198 - - - - ServicesCust Mtr Read 1,765,714$ 724,000 1,241 903,511 2,140 118,073 - 16,749 - - MeterRdgCust Records 2,515,206$ 2,198,263 3,767 309,726 53 2,976 - 422 - - CustRecordsCust Other 3,619,186$ 3,163,129 5,420 445,671 76 4,282 - 607 - - CustomerTotal Plant 730,685,780$ 406,117,681 841,965 200,031,995 3,635,581 16,914,871 - 86,897,815 - 16,245,872

13 Month Accum DeprProd Battle Creek 3,441,864$ 2,012,317 4,445 1,392,670 32,431 - - - - - BattleCreekAllocProd Bear Paw 4,512,612$ 2,638,340 5,828 1,825,923 42,521 - - - - - BearPawAllocProd Devon 8,745,754$ 5,113,286 11,295 3,538,766 82,408 - - - - - DevonAllocStorage 20,860,678$ 7,560,390 16,661 4,012,134 129,628 - - - - 9,141,864 StorageAllocTransmission 113,782,436$ 51,430,145 113,793 26,577,361 968,639 - - 34,692,498 - - TranDDDistri Other 70,651,609$ 42,403,339 93,820 21,912,613 - 6,241,836 - - - - DistDDCust Meters 32,317,373$ 20,959,265 35,915 9,872,031 46,872 1,034,003 - 369,288 - - MeterCostCust Services 32,304,687$ 25,860,280 44,313 6,321,636 - 78,458 - - - - ServicesCust Mtr Read 816,554$ 334,814 574 417,828 990 54,603 - 7,745 - - MeterRdgCust Records 1,163,157$ 1,016,586 1,742 143,233 25 1,376 - 195 - - CustRecordsCust Other 1,673,692$ 1,462,788 2,507 206,101 35 1,980 - 281 - - Customer

290,270,415$ 160,791,551 330,891 76,220,297 1,303,549 7,412,256 - 35,070,007 - 9,141,864

13 Month Net Plant 440,415,365$ 245,326,131 511,074 123,811,698 2,332,032 9,502,615 - 51,827,807 - 7,104,007

Additional Ratebase ItemsProd Battle Creek (349)$ (204) (0) (141) (3) - - - - - BattleCreekAllocProd Bear Paw -$ - - - - - - - - - BearPawAllocProd Devon -$ - - - - - - - - - DevonAllocStorage 23,300,822$ 8,444,755 18,610 4,481,447 144,791 - - - - 10,211,219 StorageAllocTransmission 32,850,078$ 14,848,375 32,853 7,673,139 279,655 - - 10,016,056 - - TranDDDistri Other 16,995,217$ 10,200,107 22,568 5,271,071 - 1,501,471 - - - - DistDDCust Meters 6,943,032$ 4,502,868 7,716 2,120,897 10,070 222,144 - 79,337 - - MeterCostCust Services 7,699,704$ 6,163,703 10,562 1,506,739 - 18,700 - - - - ServicesCust Mtr Read 853$ 350 1 437 1 57 - 8 - - MeterRdgCust Records 2,032$ 1,776 3 250 0 2 - 0 - - CustRecordsCust Other 2,061$ 1,801 3 254 0 2 - 0 - - Customer

87,793,450$ 44,163,530 92,315 21,054,092 434,514 1,742,377 - 10,095,402 - 10,211,219


Page 9 of 16


12


Total res emp genserv fugc firmdbu interdbu firmtbu intertbu storage allocators464748495051525354555657585960616263646566676869707172737475767778798081828384858687888990919293949596979899100101

Cust Contributed CapitalProd Battle Creek 769,179$ 449,707 993 311,230 7,248 - - - - - BattleCreekAllocProd Bear Paw 7,897$ 4,617 10 3,195 74 - - - - - BearPawAllocProd Devon 2,937,418$ 1,717,388 3,794 1,188,558 27,678 - - - - - DevonAllocStorage 4,529,005$ 1,641,416 3,617 871,064 28,143 - - - - 1,984,765 StorageAllocTransmission 37,903,031$ 17,132,331 37,906 8,853,410 322,672 - - 11,556,712 - - TranDDDistri Other 22,637,124$ 13,586,239 30,060 7,020,909 - 1,999,915 - - - - DistDDCust Meters 7,871,440$ 5,104,982 8,748 2,404,499 11,416 251,849 - 89,946 - - MeterCostCust Services 10,080,812$ 8,069,808 13,828 1,972,693 - 24,483 - - - - ServicesCust Mtr Read (305,221)$ (125,151) (214) (156,181) (370) (20,410) - (2,895) - - MeterRdgCust Records (497,958)$ (435,210) (746) (61,319) (11) (589) - (84) - - CustRecordsCust Other (649,773)$ (567,894) (973) (80,014) (14) (769) - (109) - - Customer

85,282,955 46,578,235 97,023 22,328,044 396,837 2,254,479 - 11,643,570 - 1,984,765

Materials & SuppliesProd Battle Creek -$ - - - - - - - - - BattleCreekAllocProd Bear Paw -$ - - - - - - - - - BearPawAllocProd Devon -$ - - - - - - - - - DevonAllocStorage 433,222$ 157,009 346 83,322 2,692 - - - - 189,853 StorageAllocTransmission 3,229,467$ 1,459,733 3,230 754,341 27,493 - - 984,671 - - TranDDDistri Other 1,836,172$ 1,102,025 2,438 569,489 - 162,220 - - - - DistDDCust Meters 751,937$ 487,665 836 229,695 1,091 24,058 - 8,592 - - MeterCostCust Services 834,314$ 667,878 1,144 163,265 - 2,026 - - - - ServicesCust Mtr Read -$ - - - - - - - - - MeterRdgCust Records -$ - - - - - - - - - CustRecordsCust Other -$ - - - - - - - - - Customer

7,085,112$ 3,874,310 7,994 1,800,112 31,275 188,304 - 993,263 - 189,853

Cash Working CapitalProd Battle Creek (242,896)$ (142,011) (314) (98,282) (2,289) - - - - - BattleCreekAllocProd Bear Paw (635,404)$ (371,495) (821) (257,101) (5,987) - - - - - BearPawAllocProd Devon (1,722,784)$ (1,007,242) (2,225) (697,084) (16,233) - - - - - DevonAllocStorage (582,890)$ (211,253) (466) (112,107) (3,622) - - - - (255,442) StorageAllocTransmission (5,165,704)$ (2,334,920) (5,166) (1,206,608) (43,976) - - (1,575,034) - - TranDDDistri Other (3,429,457)$ (2,058,275) (4,554) (1,063,647) - (302,981) - - - - DistDDCust Meters (2,755,967)$ (1,787,368) (3,063) (841,869) (3,997) (88,178) - (31,492) - - MeterCostCust Services (1,310,135)$ (1,048,778) (1,797) (256,378) - (3,182) - - - - ServicesCust Mtr Read (374,689)$ (153,635) (263) (191,727) (454) (25,055) - (3,554) - - MeterRdgCust Records (926,020)$ (809,331) (1,387) (114,031) (20) (1,096) - (155) - - CustRecordsCust Other (918,012)$ (802,332) (1,375) (113,045) (19) (1,086) - (154) - - Customer

(18,063,958)$ (10,726,641)$ (21,430)$ (4,951,880)$ (76,597)$ (421,578)$ -$ (1,610,390)$ -$ (255,442)$

Rate BaseProd Battle Creek 8,581,375$ 5,017,180 11,082 3,472,254 80,859 - - - - - Prod Bear Paw 11,754,776$ 6,872,538 15,181 4,756,296 110,761 - - - - - Prod Devon 51,539,952$ 30,133,307 66,561 20,854,442 485,641 - - - - - Storage 34,832,671$ 12,624,163 27,820 6,699,368 216,450 - - - - 15,264,871 Transmission 161,420,745$ 72,962,863 161,435 37,704,742 1,374,188 - - 49,217,516 - - Distri Other 83,535,635$ 50,136,012 110,929 25,908,597 - 7,380,097 - - - - Cust Meters 38,173,673$ 24,757,337 42,423 11,660,963 55,366 1,221,377 - 436,207 - - Cust Services 38,622,306$ 30,917,609 52,979 7,557,918 - 93,801 - - - - Cust Mtr Read 880,546$ 361,052 619 450,573 1,067 58,882 - 8,352 - - Cust Records 926,019$ 809,331 1,387 114,031 20 1,096 - 155 - - Cust Other 1,679,316$ 1,467,703 2,515 206,793 35 1,987 - 282 - - Rate Base 431,947,014$ 236,059,095 492,931 119,385,977 2,324,387 8,757,240 - 49,662,513 - 15,264,871


Page 10 of 16


12



MPSC Revenue 141,837,172$ 79,574,349 130,461 41,604,490 653,811 2,528,001 - 13,649,527 - 3,696,533

Misc RevenueProd Battle Creek 149,289$ 87,283 193 60,406 1,407 - - - - - BattleCreekAllocProd Bear Paw 1,029,046$ 601,641 1,329 416,379 9,696 - - - - - BearPawAllocProd Devon 1,508,530$ 881,976 1,948 610,392 14,214 - - - - - DevonAllocStorage 59,433$ 21,540 47 11,431 369 - - - - 26,046 StorageAllocTransmission 202,178$ 91,385 202 47,225 1,721 - - 61,645 - - TranDDDistri Other 258,348$ 155,054 343 80,127 - 22,824 - - - - DistDDCust Meters 42,579$ 27,615 47 13,007 62 1,362 - 487 - - MeterCostCust Services 32,302$ 25,858 44 6,321 - 78 - - - - ServicesCust Mtr Read 3,222$ 1,321 2 1,649 4 215 - 31 - - MeterRdgCust Records 7,674$ 6,707 11 945 0 9 - 1 - - CustRecordsCust Other 7,784$ 6,803 12 958 0 9 - 1 - - Customer

3,300,385$ 1,907,183 4,180 1,248,840 27,474 24,499 - 62,164 - 26,046

Interruptible RevenueTransmission 2,576,338$ 1,164,516 2,577 601,782 21,933 - - 785,531 - - TranDDDistri Other 36,166$ 21,706 48 11,217 - 3,195 - - - - DistDD

2,612,504$ 1,186,221 2,625 612,999 21,933 3,195 - 785,531 - -

Offsystem SalesProd Battle Creek -$ - - - - - - - - - BattleCreekAllocProd Bear Paw -$ - - - - - - - - - BearPawAllocProd Devon -$ - - - - - - - - - DevonAllocStorage 1,210$ 438 1 233 8 - - - - 530 StorageAllocTransmission 4,115$ 1,860 4 961 35 - - 1,255 - - TranDDDistri Other 5,258$ 3,156 7 1,631 - 465 - - - - DistDDCust Meters 867$ 562 1 265 1 28 - 10 - - MeterCostCust Services 657$ 526 1 129 - 2 - - - - ServicesCust Mtr Read 66$ 27 0 34 0 4 - 1 - - MeterRdgCust Records 156$ 137 0 19 0 0 - 0 - - CustRecordsCust Other 158$ 138 0 20 0 0 - 0 - - Customer

12,487$ 6,844 14 3,290 44 499 - 1,265 - 530


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CMPLTransmission 170,464$ 77,050 170 39,817 1,451 - - 51,975 - - TranDD

RoundingProd Battle Creek -$ - - - - - - - - - BattleCreekAllocProd Bear Paw -$ - - - - - - - - - BearPawAllocProd Devon -$ - - - - - - - - - DevonAllocStorage (1,436)$ (520) (1) (276) (9) - - - - (629) StorageAllocTransmission (4,884)$ (2,207) (5) (1,141) (42) - - (1,489) - - TranDDDistri Other (6,241)$ (3,745) (8) (1,936) - (551) - - - - DistDDCust Meters (1,029)$ (667) (1) (314) (1) (33) - (12) - - MeterCostCust Services (780)$ (625) (1) (153) - (2) - - - - ServicesCust Mtr Read (78)$ (32) (0) (40) (0) (5) - (1) - - MeterRdgCust Records (185)$ (162) (0) (23) (0) (0) - (0) - - CustRecordsCust Other (188)$ (164) (0) (23) (0) (0) - (0) - - Customer

(14,820)$ (8,123) (17) (3,905) (52) (592) - (1,502) - (629)

Total Revenue 147,918,191$ 82,743,526 137,433 43,505,531 704,660 2,555,602 - 14,548,960 - 3,722,480

ExpensesProd Battle Creek 1,128,742$ 659,930 1,458 456,719 10,636 - - - - - BattleCreekAllocProd Bear Paw 3,052,716$ 1,784,799 3,942 1,235,211 28,765 - - - - - BearPawAllocProd Devon 8,267,582$ 4,833,718 10,677 3,345,284 77,902 - - - - - DevonAllocStorage 1,794,351$ 650,314 1,433 345,107 11,150 - - - - 786,346 StorageAllocTransmission 15,901,951$ 7,187,749 15,903 3,714,386 135,375 - - 4,848,537 - - TranDDDistri Other 10,557,139$ 6,336,133 14,019 3,274,299 - 932,688 - - - - DistDDCust Meters 8,483,887$ 5,502,181 9,428 2,591,584 12,305 271,444 - 96,945 - - MeterCostCust Services 4,033,081$ 3,228,529 5,532 789,225 - 9,795 - - - - ServicesCust Mtr Read 1,153,430$ 472,944 810 590,207 1,398 77,130 - 10,941 - - MeterRdgCust Records 2,850,633$ 2,491,422 4,269 351,031 60 3,373 - 478 - - CustRecordsCust Other 2,825,980$ 2,469,876 4,232 347,995 60 3,343 - 474 - - Customer

60,049,492$ 35,617,593 71,705 17,041,049 277,650 1,297,773 - 4,957,376 - 786,346

DepreciationProd Battle Creek 507,685$ 296,823 656 205,423 4,784 - - - - - BattleCreekAllocProd Bear Paw 1,302,544$ 761,545 1,682 527,044 12,273 - - - - - BearPawAllocProd Devon 4,427,514$ 2,588,587 5,718 1,791,490 41,719 - - - - - DevonAllocStorage 573,625$ 207,895 458 110,325 3,564 - - - - 251,382 StorageAllocTransmission 6,620,981$ 2,992,711 6,622 1,546,532 56,365 - - 2,018,751 - - TranDDDistri Other 3,777,845$ 2,267,369 5,017 1,171,699 - 333,760 - - - - DistDDCust Meters 1,203,567$ 780,567 1,338 367,655 1,746 38,508 - 13,753 - - MeterCostCust Services 1,681,687$ 1,346,211 2,307 329,086 - 4,084 - - - - ServicesCust Mtr Read (79,614)$ (32,644) (56) (40,738) (96) (5,324) - (755) - - MeterRdgCust Records (112,863)$ (98,641) (169) (13,898) (2) (134) - (19) - - CustRecordsCust Other (162,976)$ (142,439) (244) (20,069) (3) (193) - (27) - - Customer

19,739,996$ 10,967,983 23,327 5,974,550 120,349 370,703 - 2,031,702 - 251,382


Page 12 of 16


12



Other TaxesProd Battle Creek 20,567$ 12,025 27 8,322 194 - - - - - BattleCreekAllocProd Bear Paw 26,790$ 15,663 35 10,840 252 - - - - - BearPawAllocProd Devon 95,245$ 55,686 123 38,539 897 - - - - - DevonAllocStorage 76,512$ 27,730 61 14,715 475 - - - - 33,530 StorageAllocTransmission 570,358$ 257,804 570 133,225 4,856 - - 173,903 - - TranDDDistri Other 324,287$ 194,629 431 100,578 - 28,650 - - - - DistDDCust Meters 132,800$ 86,127 148 40,567 193 4,249 - 1,517 - - MeterCostCust Services 147,349$ 117,954 202 28,834 - 358 - - - - ServicesCust Mtr Read -$ - - - - - - - - - MeterRdgCust Records -$ - - - - - - - - - CustRecordsCust Other -$ - - - - - - - - - Customer

1,393,907$ 767,617 1,596 375,619 6,867 33,257 - 175,421 - 33,530

Payroll TaxesProd Battle Creek 20,877$ 12,206 27 8,447 197 - - - - - BattleCreekAllocProd Bear Paw 51,135$ 29,896 66 20,691 482 - - - - - BearPawAllocProd Devon 100,082$ 58,514 129 40,496 943 - - - - - DevonAllocStorage 55,409$ 20,082 44 10,657 344 - - - - 24,282 StorageAllocTransmission 611,135$ 276,235 611 142,749 5,203 - - 186,336 - - TranDDDistri Other 380,584$ 228,417 505 118,038 - 33,623 - - - - DistDDCust Meters 403,941$ 261,974 449 123,392 586 12,924 - 4,616 - - MeterCostCust Services 187,752$ 150,298 258 36,741 - 456 - - - - ServicesCust Mtr Read 59,852$ 24,541 42 30,626 73 4,002 - 568 - - MeterRdgCust Records 85,258$ 74,515 128 10,499 2 101 - 14 - - CustRecordsCust Other 122,680$ 107,221 184 15,107 3 145 - 21 - - Customer

2,078,705$ 1,243,899 2,443 557,443 7,831 51,252 - 191,555 - 24,282

Property TaxesProd Battle Creek 26,843$ 15,694 35 10,861 253 - - - - - BattleCreekAllocProd Bear Paw 205,038$ 119,878 265 82,964 1,932 - - - - - BearPawAllocProd Devon 206,660$ 120,825 267 83,620 1,947 - - - - - DevonAllocStorage 1,765,346$ 639,802 1,410 339,529 10,970 - - - - 773,635 StorageAllocTransmission 13,159,838$ 5,948,303 13,161 3,073,882 112,031 - - 4,012,462 - - TranDDDistri Other 7,482,264$ 4,490,669 9,936 2,320,626 - 661,033 - - - - DistDDCust Meters 3,064,088$ 1,987,198 3,405 935,991 4,444 98,036 - 35,013 - - MeterCostCust Services 3,399,767$ 2,721,554 4,664 665,293 - 8,257 - - - - ServicesCust Mtr Read -$ - - - - - - - - - MeterRdgCust Records -$ - - - - - - - - - CustRecordsCust Other -$ - - - - - - - - - Customer

29,309,844$ 16,043,923 33,142 7,512,767 131,577 767,327 - 4,047,475 - 773,635


Page 13 of 16


12



Income TaxesProd Battle Creek 305,427$ 161,406 67 141,751 2,204 - - - - - Prod Bear Paw 454,951$ 242,479 138 208,970 3,364 - - - - - Prod Devon 1,929,710$ 1,025,132 523 889,921 14,135 - - - - - Storage 694,323$ 144,549 (409) 134,679 1,415 - - - - 414,088 Transmission 256,695$ 37,931 (4,140) 345,863 (6,038) - - (116,920) - - Distri Other (160,885)$ (116,864) (3,161) 163,798 - (204,658) - - - - Cust Meters 104,098$ 23,907 (1,069) 112,164 (219) (29,844) - (842) - - Cust Services (7,267)$ (55,153) (1,481) 51,917 - (2,550) - - - - Cust Mtr Read 28,254$ 10,619 2 17,150 26 236 - 221 - - Cust Records 28,156$ 23,802 5 4,340 0 4 - 4 - - Cust Other 51,061$ 43,165 8 7,871 1 8 - 7 - -

3,684,524$ 1,540,974 (9,517) 2,078,423 14,888 (236,803) - (117,529) - 414,088

Total Operating Expense 116,256,469$ 66,181,988 122,697 33,539,852 559,162 2,283,508 - 11,285,999 - 2,283,264

Operating IncomeProd Battle Creek 647,235$ 351,998 331 289,844 5,061 - - - - - Prod Bear Paw 886,583$ 482,167 454 397,029 6,933 - - - - - Prod Devon 3,887,308$ 2,114,106 1,990 1,740,813 30,399 - - - - - Storage 2,898,514$ 885,692 832 559,226 13,549 - - - - 1,439,216 Transmission 11,590,912$ 5,118,961 4,826 3,147,383 86,019 - - 3,233,724 - - Distri Other 5,912,792$ 3,517,464 3,316 2,162,706 - 229,305 - - - - Cust Meters 2,781,672$ 1,736,936 1,268 973,392 3,466 37,949 - 28,660 - - Cust Services 2,804,522$ 2,169,131 1,584 630,893 - 2,914 - - - - Cust Mtr Read 65,406$ 25,331 18 37,611 67 1,830 - 549 - - Cust Records 66,387$ 56,781 41 9,519 1 34 - 10 - - Cust Other 120,391$ 102,972 75 17,262 2 62 - 19 - - Adj Operating Income 31,661,722$ 16,561,538 14,737 9,965,678 145,498 272,094 - 3,262,961 - 1,439,216

Rate of Return 7.33% 7.02% 2.99% 8.35% 6.26% 3.11% 0.00% 6.57% 0.00% 9.43%


Page 14 of 16


12



Revenue Req Equalized ROR 141,837,172 80,797,855 165,759 39,600,473 694,857 3,138,126 - 14,272,008 - 3,168,093 Prod Battle Creek 2,478,028 1,448,802 3,200 1,002,676 23,350 - - - - - Prod Bear Paw 4,909,536 2,870,405 6,340 1,986,529 46,261 - - - - - Prod Devon 17,225,032 10,070,773 22,245 6,969,708 162,305 - - - - - Storage 7,229,222 2,620,037 5,774 1,390,396 44,922 - - - - 3,168,093 Transmission 46,161,647 20,865,261 46,166 10,782,462 392,978 - - 14,074,781 - - Distri Other 28,327,571 17,001,504 37,617 8,785,803 - 2,502,647 - - - - Cust Meters 16,158,790 10,479,699 17,957 4,936,047 23,436 517,005 - 184,645 - - Cust Services 12,258,422 9,813,010 16,815 2,398,825 - 29,772 - - - - Cust Mtr Read 1,222,698 501,346 859 625,651 1,482 81,762 - 11,598 - - Cust Records 2,912,385 2,545,392 4,362 358,635 61 3,446 - 489 - - Cust Other 2,953,841 2,581,625 4,424 363,740 62 3,495 - 496 - -

Less: Property TaxesProd Battle Creek 26,843 15,694 35 10,861 253 - - - - - Prod Bear Paw 205,038 119,878 265 82,964 1,932 - - - - - Prod Devon 206,660 120,825 267 83,620 1,947 - - - - - Storage 1,765,346 639,802 1,410 339,529 10,970 - - - - 773,635 Transmission 13,159,838 5,948,303 13,161 3,073,882 112,031 - - 4,012,462 - - Distri Other 7,482,264 4,490,669 9,936 2,320,626 - 661,033 - - - - Cust Meters 3,064,088 1,987,198 3,405 935,991 4,444 98,036 - 35,013 - - Cust Services 3,399,767 2,721,554 4,664 665,293 - 8,257 - - - - Cust Mtr Read - - - - - - - - - - Cust Records - - - - - - - - - - Cust Other - - - - - - - - - -

29,309,844 16,043,923 33,142 7,512,767 131,577 767,327 - 4,047,475 - 773,635

Base Rate Req Equal ROR 112,527,327 64,753,932 132,617 32,087,706 563,280 2,370,799 - 10,224,534 - 2,394,458 Prod Battle Creek 2,451,185 1,433,108 3,166 991,815 23,097 - - - - - Prod Bear Paw 4,704,498 2,750,528 6,076 1,903,566 44,329 - - - - - Prod Devon 17,018,372 9,949,948 21,978 6,886,088 160,358 - - - - - Storage 5,463,876 1,980,235 4,364 1,050,867 33,952 - - - - 2,394,458 Transmission 33,001,809 14,916,958 33,005 7,708,580 280,947 - - 10,062,319 - - Distri Other 20,845,307 12,510,835 27,681 6,465,177 - 1,841,614 - - - - Cust Meters 13,094,702 8,492,501 14,552 4,000,056 18,992 418,968 - 149,632 - - Cust Services 8,858,655 7,091,457 12,152 1,733,531 - 21,515 - - - - Cust Mtr Read 1,222,698 501,346 859 625,651 1,482 81,762 - 11,598 - - Cust Records 2,912,385 2,545,392 4,362 358,635 61 3,446 - 489 - - Cust Other 2,953,841 2,581,625 4,424 363,740 62 3,495 - 496 - -


Page 15 of 16

Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator

Labor O & M Expenses Prod Battle Creek 105,419$ 105,419 - - - - - - - - - - BattleCreek - Prod Bear Paw 431,064$ - 431,064 - - - - - - - - - BearPaw - Prod Devon 1,099,229$ - - 1,099,229 - - - - - - - - Devon - Gas Supply Admin 369,690$ - - - 121,827 155,673 25,657 19,464 35,813 1,941 4,624 4,690 FuncRevXP - Storage Operation 377,311$ - - - 51,153 - - - 326,158 - - - Storage - Storage Maintenance 136,076$ - - - 18,448 - - - 117,628 - - - Storage - Transmission Operation 4,290,372$ 4,290,372 Direct - Transmission Maintenance 807,903$ 807,903 Direct - Distribution Op - Supervision 1,484,575$ - - - - 585,053 618,044 281,477 - - - - DistOpLab - Distribution Op - Meters 1,082,758$ 1,082,758 Direct - Distribution Op - Cust Install 1,590,331$ - - - - - 753,871 836,460 - - - - MeterServices - Distribution Op - Other 1,738,592$ 1,738,592 Direct - Distribution Mnt - Supervision 745,025$ - - - - 261,837 326,474 156,714 - - - - DistMnLab - Distribution Mnt - Services 330,983$ 330,983 Direct - Distribution Mnt - Meters 689,522$ 689,522 Direct - Distribution Mnt - Other 553,007$ 553,007 Direct - Customer Meter Reading 516,114$ 516,114.24 Direct - Customer Records 733,330$ 733,330$ Direct - Customer Accounts -$ - Direct - Customer Service 1,057,169$ 1,057,169 Direct - Sales Expense -$ - Direct - A & G Expense - Labor 5,476,904$ - - - 1,755,536 1,093,261 1,160,354 539,334 159,168 171,931 244,911 352,408 FuncLaborXP - A & G Expense - Prod Labor 202,763$ 13,068 53,435 136,260 A & G Expense - Gen Plant 1,292,055$ - - - 414,148 257,911 273,739 127,234 37,549 40,560 57,777 83,136 FuncLaborXP - Total Expenses 25,110,192$ 118,486$ 484,499$ 1,235,489$ 7,459,388$ 4,645,335$ 4,930,419$ 2,291,666$ 676,316$ 730,547$ 1,040,643$ 1,497,404$ -


Page 16 of 16

STATEMENT L – PART 2

MARGINAL COST STUDY – GAS SUPPLY

Table - 1Page 1 of 1

Table - 1NorthWestern EnergyMarginal Cost Study - Gas SupplyProduction Investment

Line CompanyNo. Description Total

(1) (2) (3) (4) (5) (6)

New LNG Plant Using Trucked LNG for Liquid Supply

1 Plant Construction Costs {1} 63,554,000$ 2 Owner's Costs (1 year) {1} 10%3 6,355,400$ 4 Land {2} 70 Acres5 {3} 4,234$ per Acre6 296,3677 Total Investment 6,651,767$ 8 Deliverability, MSCFD {1} 50,0009 Dkt Conversion 1.08

10 Dkt/Day 54,000

11 Investment/Dkt/D 123.18$

Notes:1 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 7 of 11.2 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 3 of 11, paragraph 3.3 Real estate estimate provided by the Company.


Page 1 of 22


Table - 2NorthWestern EnergyMarginal Cost Study - Gas Supply

Estimated Marginal Commodity Costs, $/Dkt

SupplyLine Residential Employee General Service Firm UtilitiesNo. Description D-RG-1 D-RG-2 D-GSG-1 D-FUGC-1

(1) (2) (3) (4) (5)

Load Weighted Marginal Commodity Cost

1 Winter Marginal Commodity Cost {1}, {2} 2.5509$ 2.5550$ 2.5286$ 2.5843$ 23 Summer Marginal Commodity Cost {1}, {2} 2.0160$ 2.0151$ 2.0144$ 2.0169$ 45 Annual Average Marginal Cost 2.3918$ 2.3846$ 2.3825$ 2.4064$

Notes:1 Weighted average of sales from Table 2, page 3 with

monthly marginal costs from Table 2, page 2.2 Winter includes months November through March, Summer includes all other months.


Page 2 of 22



Average Marginal Commodity Cost, $/Dkt

Line Description January February March April May June July AugustNo. Days in Month 31 28 31 30 31 30 31 31

(1) (2) (3) (4) (5) (6) (7) (8) (9)

1 OFF SYSTEM2 AECO Strip {1} 2.5989$ 2.6074$ 2.5150$ 1.9100$ 1.8310$ 1.8370$ 1.8500$ 1.8470$ 3 AECO Transportation {2} 0.1500$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 4 Delivered Prices for Off-System Purchases {3} 2.7489$ 2.7574$ 2.6650$ 2.0600$ 1.9810$ 1.9870$ 2.0000$ 1.9970$ 56 Monthly Marginal Cost, $/Dkt 2.7489$ 2.7574$ 2.6650$ 2.0600$ 1.9810$ 1.9870$ 2.0000$ 1.9970$

Notes:1 AECO strip price for 2018 as of 4/7/17.2 Based on TransCanada/Nova transportation rates. 3 Company estimates4 Under normal weather conditions, the daily marginal source of supply in the test year would be Off-system purchases from AECO delivered through the Nova system.

The hypothetical LNG facility would not be dispatched under normal weather conditions, only under extreme conditions


Page 3 of 22



Average Marginal Commodity Cost, $/Dkt

Line DescriptionNo. Days in Month

(1)

1 OFF SYSTEM2 AECO Strip {1}

3 AECO Transportation {2}

4 Delivered Prices for Off-System Purchases {3}

56 Monthly Marginal Cost, $/Dkt

Notes:1 AECO strip price for 2018 as of 4/7/17.2 Based on TransCanada/Nova transportation rates. 3 Company estimates4 Under normal weather conditions, the daily marginal so

The hypothetical LNG facility would not be dispatched u

September October November December Total/Average30 31 30 31

(10) (11) (12) (13) (14)

1.8460$ 1.8850$ 1.9730$ 2.1135$ 2.0678$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 0.1500$ 1.9960$ 2.0350$ 2.1230$ 2.2635$ 2.2178$

1.9960$ 2.0350$ 2.1230$ 2.2635$ 2.2178$


Page 4 of 22



Non-Choice Sales Data - Dkt

Line Description January February March April May June July AugustNo.

(1) (2) (3) (4) (5) (6) (7) (8) (9)

1 SALES DATA BY MONTH {1}

2 Residential 2,208,260 1,621,253 1,546,149 1,030,625 754,252 447,518 244,104 243,3153 Employee 4,836 3,697 3,539 2,449 1,932 1,215 527 5624 General Service 1,195,684 880,636 818,313 551,452 409,189 262,539 185,191 182,2285 Firm Utilities 35,588 37,749 29,994 22,247 15,624 9,631 4,207 3,746678910 TOTAL Company 3,444,369 2,543,335 2,397,995 1,606,773 1,180,998 720,902 434,029 429,850

Notes:1 Actual supply loads for 12 Months Ended December 2015.


Page 5 of 22



Non-Choice Sales Data - Dkt

Line DescriptionNo.

(1)

1 SALES DATA BY MONTH {1}

2 Residential3 Employee4 General Service5 Firm Utilities678910 TOTAL Company

Notes:1 Actual supply loads for 12 Months Ended December 20

September October November December Total Winter Summer AnnualNov-Mar Apr-Oct

(10) (11) (12) (13) (14) (15) (16) (17)

304,813 449,530 951,873 1,883,113 11,684,807 2.551 2.016 2.392661 1,044 2,070 4,055 26,584 2.555 2.015 2.385

200,693 251,563 501,988 986,270 6,425,748 2.529 2.014 2.3823,839 6,395 12,981 27,501 209,502 2.584 2.017 2.406

510,006 708,533 1,468,912 2,900,939 18,346,640


Page 6 of 22


Table - 2NorthWestern EnergyMarginal Cost Study - Gas SupplyOperations and Maintenance Budget Recap

Year 1 For MCS UseLine Filling By Truck ExcludingNo. Description Truck Variable Costs Comments

(1) (2) (3) (4) (5)

1 O&M Expenses, $1,000 {1}

2 Labor 511 372 Remove Indirect Costs3 Electric Utility 105 1054 Purchased LNG 754 Included with Tracker5 Liquefaction 0 06 Consumables 65 657 Maintenance 136 1368 Spare Parts Carrying Costs 16 Include with M&S Loader9 O&M Subtotal Lns 2 thru 8 1,587 678

10 Annual Volume, MMSCF {2} 600 60011 Annual Volume, MDkt 1.08 648 64812 Unit Cost (Less Losses), $Dkt Ln 9 / Ln 11 2.45 1.051314 Boil-Off Losses, $1,000 76315 Trucking Shrinkage, $1,000 1116 Annual O&M Budget Estimate, $1,000 Ln 9+14+15 2,361 67817 Unit Cost $/Dkt Ln 16 / Ln11 3.64 1.05181920 MSCFD {2} 50,000 50,00021 Dkt/D 1.08 54,000 54,00022 O&M Expense / Dkt Ln 16 / Ln21 43.72$ 12.55$ 232425 M&S Carrying Costs Ln 8 * 1000 16,00026 Assumed Cost of Capital {3} 7.17%27 Actual M&S Investment Ln 25 / Ln26 223,196 28 Plant Investment {4} 63,554,00029 M&S Rate Ln 27 / Ln28 0.35%

Notes:1 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 8 of 11

Truckload system for the trucking option has been selected as opposed to the liquefaction option since it is more economical.2 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 7 of 11


Page 7 of 22


Table - 3NorthWestern EnergyMarginal Cost Study - GasClass Weighted Uncollectible Accounts Expense

Line Customer Test Year Supply SupplyNo. Groups Supply Revenues Write-off

Uncollectible Exp Excl Gas Costs Percentage(1) (2) (3) (4)

(4)=(2)/(3)

1 Residential 96,373$ 16,017,956$ 0.60%2 Employee -$ 27,212$ 0.00%3 General Service 5,827$ 8,266,013$ 0.07%4 Firm Utilities -$ 301,416$ 0.00%56 Total 102,200$ 24,612,597$ 0.42%

Notes:1 Revenues and Uncollectible Expenses based on 2015 Test Year at Proposed Revenue Levels2 Class Uncollectible Expenses are based on write-offs.


Page 8 of 22


Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of A & G Loading Factors

LineNo. Description 2002 2003 2004 2005 2006 2007 2008 2009 2010

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1 Nonplant Related Expenses2 920- Administrative & General Salaries 8,509,704$ 6,603,170$ 7,519,790$ 6,701,756$ 7,127,534$ 8,116,970$ 8,607,119$ 8,737,187$ 7,983,696$ 3 921- Office Supplies & Expenses 1,749,790$ 1,188,070$ 1,919,137$ 2,024,993$ 1,739,271$ 1,936,926$ 2,151,603$ 2,176,526$ 2,177,746$ 4 922- Administrative Exp. Transferred-Cr. (2,180,236)$ (1,993,398)$ (2,569,935)$ (1,073,608)$ (1,867,952)$ (2,146,505)$ (2,153,515)$ (1,544,797)$ (1,822,736)$ 5 923- Outside Services Employed 1,966,550$ 2,077,231$ 1,879,190$ 2,968,686$ 1,691,523$ 1,660,023$ 1,380,301$ 1,855,175$ 2,054,109$ 6 925- Legal & Claim Department 1,267,588$ 1,065,677$ 2,967,799$ (48,698)$ 1,195,016$ 2,490,212$ 1,722,369$ 3,619,564$ 2,060,425$ 7 926- Employee Pensions & Benefits 808,880$ 119,120$ 1,923,599$ 3,214,242$ 550,031$ 658,478$ (1,775,436)$ 2,267,116$ (1,748,781)$ 8 930- Miscellaneous General Expenses 1,639,070$ 1,461,111$ 2,364,156$ 2,444,859$ 2,854,839$ 2,588,988$ 2,776,315$ 3,872,539$ 4,600,313$ 910 408-Payroll Taxes (Schedule 11) 1,333,552$ 1,081,039$ 1,306,747$ 1,317,530$ 1,285,405$ 1,447,586$ 1,564,646$ 1,603,559$ 1,640,447$ 11 Total Non-Plant 6,585,194$ 4,998,850$ 9,790,693$ 10,848,004$ 7,448,133$ 8,635,708$ 5,666,283$ 13,849,682$ 8,961,523$ 121314 Plant Related Expenses6 924- Property Insurance 233,493$ 170,940$ 176,381$ 201,550$ 235,077$ 212,871$ 168,559$ 225,650$ 189,439$ 16 928- Regulatory Commission Expenses 2,438$ 20,754$ 25,549$ 17,189$ 105,826$ 155,275$ 98,273$ 69,893$ 127,503$ 17 931- Rents 647,439$ 334,656$ 457,069$ 505,525$ 457,125$ 667,036$ 624,317$ 611,379$ 603,221$ 18 935- General Plant Maintenance 1,842,968$ 1,131,947$ 1,148,771$ 957,149$ 1,009,379$ 1,140,692$ 1,138,627$ 1,037,730$ 943,695$ 19 Total Plant Related Expenses 2,726,337$ 1,658,297$ 1,807,770$ 1,681,413$ 1,807,407$ 2,175,874$ 2,029,776$ 1,944,652$ 1,863,858$ 202122 Total Allocable O&M {1} 15,933,039$ 13,162,642$ 37,781,430$ 39,065,501$ 38,218,978$ 43,450,742$ 40,666,580$ 51,151,989$ 45,269,247$ 2324 A & G Loading Factor Nonplant Related Exp25 line 11 / line 22 41.33% 37.98% 25.91% 27.77% 19.49% 19.87% 13.93% 27.08% 19.80%26 Average 2002 - 2016 {2} = 24.05%272829 Total Gross Gas Plant $ 404,441,244$ 419,594,599$ 438,553,989$ 444,409,508$ 466,882,260$ 493,013,504$ 517,735,381$ 536,130,345$ 565,931,674$ 303132 A & G Loading Factor Plant Related Exp33 line 19 / line 29 0.67% 0.40% 0.41% 0.38% 0.39% 0.44% 0.39% 0.36% 0.33%34 Average 2002 - 2016 {2} = 0.38%

Notes:1 Total O&M less Gas Raw Materials Expense and Other Gas Supply Expense2 Average of years after implementation

of new accounting system.3 Source for Expenses is the Annual Reports


Page 9 of 22


Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of A & G Loading Factors

LineNo. Description

(1) (2)

1 Nonplant Related Expenses2 920- Administrative & General Salaries3 921- Office Supplies & Expenses4 922- Administrative Exp. Transferred-Cr.5 923- Outside Services Employed6 925- Legal & Claim Department7 926- Employee Pensions & Benefits8 930- Miscellaneous General Expenses910 408-Payroll Taxes (Schedule 11)11 Total Non-Plant121314 Plant Related Expenses6 924- Property Insurance16 928- Regulatory Commission Expenses17 931- Rents18 935- General Plant Maintenance19 Total Plant Related Expenses202122 Total Allocable O&M {1}

2324 A & G Loading Factor Nonplant Related Exp25 line 11 / line 2226 Average 2002 - 2016 {2} = 24.05%272829 Total Gross Gas Plant $303132 A & G Loading Factor Plant Related Exp33 line 19 / line 2934 Average 2002 - 2016 {2} = 0.38%

Notes:1 Total O&M less Gas Raw Materials Expense and Other Gas Sup2 Average of years after implementation

of new accounting system.3 Source for Expenses is the Annual Reports

2011 2012 2013 2014 2015 2016

(12) (13) (14) (15) (16) (17)

8,845,376$ 8,746,295$ 9,684,821$ 10,331,169$ 10,348,188$ 11,548,925$ 2,594,420$ 2,631,783$ 2,635,314$ 2,770,615$ 2,696,046$ 2,851,057$

(1,836,018)$ (1,838,638)$ (1,661,836)$ (1,726,369)$ (1,692,146)$ (1,784,559)$ 1,628,593$ 1,351,829$ 1,463,836$ 1,589,655$ 1,409,823$ 1,358,097$ 2,650,712$ 2,231,800$ 2,336,183$ 2,550,459$ 2,198,201$ 2,921,253$

(1,848,384)$ 887,278$ 1,563,001$ (802,423)$ 1,858,686$ 2,046,493$ 5,914,371$ 5,083,258$ 6,001,591$ 5,939,381$ 4,330,386$ 3,780,066$

1,774,818$ 1,824,006$ 2,009,470$ 2,175,806$ 2,049,977$ 2,314,717$ 10,878,512$ 12,171,316$ 14,347,559$ 12,497,124$ 12,850,973$ 13,487,124$

205,932$ 263,723$ 250,121$ 240,743$ 220,499$ 287,384$ 16,181$ 112,289$ 186,169$ 4,093$ 30,473$ 164,517$

724,323$ 700,919$ 722,640$ 798,753$ 734,793$ 659,371$ 1,000,919$ 1,033,831$ 1,176,019$ 1,170,786$ 1,215,402$ 1,096,043$ 1,947,355$ 2,110,762$ 2,334,949$ 2,214,375$ 2,201,167$ 2,207,315$

51,478,106$ 52,977,836$ 62,620,590$ 72,503,873$ 65,436,784$ 56,741,584$

21.13% 22.97% 22.91% 17.24% 19.64% 23.77%

588,248,608$ 633,997,764$ 706,651,296$ 732,397,584$ 769,973,286$ 803,924,170$

0.33% 0.33% 0.33% 0.30% 0.29% 0.27%


Page 10 of 22


Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of Miscellaneous Loading Factors

LineNo. Description 2002 2003 2004 2005 2006 2007 2008 2009 2010

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11)

1 Common & General Plant Loading Factor2 General Plant 16,248,186$ 16,256,615$ 16,211,644$ 16,090,516$ 14,316,057$ 13,993,685$ 14,281,276$ 11,532,635$ 12,821,131$ 3 Common Plant Assigned to Gas 14,134,647$ 13,447,245$ 14,012,437$ 26,963,375$ 26,165,336$ 27,218,466$ 27,975,885$ 28,682,658$ 29,507,288$ 4 Total General and Common 30,382,833$ 29,703,860$ 30,224,081$ 43,053,891$ 40,481,393$ 41,212,151$ 42,257,162$ 40,215,293$ 42,328,419$ 5 Total Gas Utility Plant 378,790,041$ 393,024,764$ 411,212,400$ 416,333,506$ 438,067,538$ 464,510,969$ 489,072,577$ 507,294,984$ 542,836,569$ 67 Gen Plant Factor line 4 / (line 5 - line 4) 8.72% 8.18% 7.93% 11.53% 10.18% 9.74% 9.46% 8.61% 8.46%8 Average 2002 - 2016 {2} = 8.75%91011 Loss Factor Calculation12 Total Sendout 35,854,801 32,975,423 34,826,477 35,365,202 36,276,641 35,868,783 40,030,783 39,495,030 37,746,90713 Total Sales 35,473,532 32,650,343 34,444,541 34,709,757 35,644,281 36,042,271 39,194,217 38,491,313 36,924,8391415 Loss Factor line 13 / line 12 98.94% 99.01% 98.90% 98.15% 98.26% 100.48% 97.91% 97.46% 97.82%16 Average 2002 - 2016 {2} = 98.51%

Notes:1 Source: Annual Reports2 Average of years after implementation

of new accounting system.


Page 11 of 22


Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of Miscellaneous Loading Factors

LineNo. Description

(1) (2)

1 Common & General Plant Loading Factor2 General Plant3 Common Plant Assigned to Gas4 Total General and Common5 Total Gas Utility Plant67 Gen Plant Factor line 4 / (line 5 - line 4)8 Average 2002 - 2016 {2} = 8.75%91011 Loss Factor Calculation12 Total Sendout13 Total Sales1415 Loss Factor line 13 / line 1216 Average 2002 - 2016 {2} = 98.51%

Notes:1 Source: Annual Reports2 Average of years after implementation

of new accounting system.

2011 2012 2013 2014 2015 2016

(12) (13) (14) (15) (16) (17)

14,615,330$ 17,348,030$ 19,763,030$ 21,923,030$ 24,023,030$ 26,123,030$ 29,507,288$ 29,507,288$ 29,507,288$ 29,507,288$ 29,507,288$ 29,507,288$ 44,122,618$ 46,855,318$ 49,270,318$ 51,430,318$ 53,530,318$ 55,630,318$

562,889,531$ 605,723,287$ 677,024,230$ 699,769,408$ 728,443,945$ 763,632,169$

8.51% 8.38% 7.85% 7.93% 7.93% 7.86%

42,065,045 41,359,939 43,130,092 45,604,243 42,887,720 42,405,35341,455,513 40,760,796 42,363,673 45,106,454 42,061,873 41,747,921

98.55% 98.55% 98.22% 98.91% 98.07% 98.45%


Page 12 of 22


Table - 5NorthWestern EnergyMarginal Cost Study - Gas SupplySummary of Levelized Fixed Charge Rates

Engineer's Economist'sLine Fixed Charge Fixed ChargeNo. Description Rate Rate

(1) (2) (3)

FIXED CHARGE RATE RESULTSOver

1 Levelized Cost for: Book Life2 Production Plant {1} 11.46% 9.48%34 INCREMENTAL COST OF CAPITAL {2}

5 Debt 4.67% 53.21%6 Preferred 0.00% 0.00%7 Common 10.01% 46.79%8 Other 0.00% 0.00%9 Weighted Cost of Incremental Capital 7.17%

101112 After Tax Cost of New Capital {3} 6.19%13 Incremental Tax Rate {4} 39.39%14 Tax Effected Cost of Capital {5} 10.24%15 Property Tax Rate {6} 3.19%16 MPSC & MCC Tax Rate {7} 0.30%17 Inflation Rate {8} 1.60%18 Property Tax Escalation Rate {8} 2.10%19 Commodity Escalation Rate {9} 2.10%20 Deferred Tax Rate 35.00%

Notes:1 Source: Table - 5, page 2.2 Weighted average current cost of raising capital in 2015.3 Wtd Cost of Capital (9) less tax savings on debt interest.4 Incremental tax rate assumed to be 35% Federal and 7% State tax which

results in a combined effective rate of 39.39%.5 Tax effected cost of capital plus tax component on return6 Current composite average tax rate.7 The state's 1.01% franchise tax is excluded since it is surcharged.8 Annual Energy Outlook 20179 Commodity price escalation factor assumed by MAC.


Page 13 of 22


Table - 5NorthWestern EnergyMarginal Cost Study - Gas SupplyLevelized Fixed Charge Analysis - Input Data

LNGLINE ProductionNO. VARIABLE Plant

(1) (2)

1 Plant Data2 PLANT BALANCE 6,651,767 3 CAPITALIZED COST $1,0004 BOOK LIFE 355 SALVAGE VALUE 5%6 MACRS LIFE 20789 Capital Structure

10 DEBT RATIO 53.21%11 PREFERRED RATIO 0.00%12 COMMON RATIO 46.79%13 OTHER _____________ 0.00%141516 Cost of Capital17 DEBT COST 4.67%18 PREFERRED COST 0.00%19 COMMON COST 10.01%20 OTHER 0.00%21 WTD COST OF CAPITAL 7.17%22 AFTER TAX COST / CAP 6.19%232425 Tax Data26 TAX RATE 39.39%27 ITC RATE 0.00%28 REVENUE TAX RATE 0.30%29 PROPERTY TAX RATE 3.19%30 PROPERTY INSURANCE 0.00%31 DEFERRED TAX RATE 35.00%32 PROPERTY TAX BASIS 233 1 = Original Cost34 2 = Depreciated Bal3536 Misc. Data37 INFLATION RATE 1.60%38 PROP TAX ESC RATE 2.10%39 RETURN BASIS 240 1 = Begin of Year41 2 = Avg Begin & End42 3 = End of Year

Notes:1 Source: Workpapers


Page 14 of 22


Table - 5NorthWestern EnergyMarginal Cost Study - Gas SupplyLevelized Fixed Charge Analysis - Production Plant

CURRENT PERCENT OF CONSTANT PERCENT OF

LINE LEVELIZED CAPITAL LEVELIZED CAPITAL

NO. ITEM DOLLARS INVESTMENT DOLLARS INVESTMENT

(1) (2) (3) (4) (5) (6)

1 INTEREST ON DEBT $14.99 1.50% $12.40 1.24%2 RETURN ON PREF $0.00 0.00% $0.00 0.00%3 RETURN ON COMMON $28.25 2.82% $23.38 2.34%45 RETURN lines 1 thru 3 $43.23 4.32% $35.78 3.58%6789 DEPRECIATION $27.14 2.71% $22.46 2.25%

1011 INCOME TAX $12.77 1.28% $10.57 1.06%12 DEFERRED TAXES $4.63 0.46% $3.83 0.38%1314 INCOME TAX lines 11 & 12 $17.40 1.74% $14.40 1.44%1516 REVENUE TAX $0.34 0.03% $0.28 0.03%17 PROPERTY TAX $26.44 2.64% $21.88 2.19%18 PROPERTY INSURANCE $0.00 0.00% $0.00 0.00%1920 OTHER lines 16 thru 18 $26.79 2.68% $22.17 2.22%212223 TOTAL REVENUE REQ'D lines 5+9+14+20 $114.56 11.46% $94.81 9.48%

-- Current Dollars -- -- Constant Dollars --(Engineer's FCR) (Economist's FCR)


Page 15 of 22


Table - 5NorthWestern EnergyDevelopment of Revenue Requirements StreamProduction Plant

ANNUAL % of PresentYear Rate Interest Return On Return On Tax Book Deferred Taxable Inc Tax Revenue Property Property Revenue Original Worth Of No. Base On Debt Preferred Common Deprec'N Deprec'N Tax Income Payable Tax Tax Insurance Reqm'Ts Investm'T Rev Req'Mt

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)1,000.00

1 984.62 24.47 0.00 46.12 37.50 27.14 3.63 64.98 25.59 0.48 31.89 0.00 159.31 $0.16 150.032 947.78 23.55 0.00 44.39 72.19 27.14 15.77 24.93 9.82 0.46 31.67 0.00 152.80 $0.15 135.513 905.82 22.51 0.00 42.43 66.77 27.14 13.87 27.50 10.83 0.45 31.44 0.00 148.66 $0.15 124.154 865.68 21.51 0.00 40.55 61.77 27.14 12.12 29.76 11.72 0.43 31.17 0.00 144.65 $0.14 113.765 827.23 20.56 0.00 38.74 57.13 27.14 10.50 31.76 12.51 0.42 30.89 0.00 140.76 $0.14 104.256 790.34 19.64 0.00 37.02 52.85 27.14 9.00 33.51 13.20 0.41 30.57 0.00 136.98 $0.14 95.537 754.89 18.76 0.00 35.36 48.88 27.14 7.61 35.02 13.79 0.40 30.23 0.00 133.29 $0.13 87.548 720.78 17.91 0.00 33.76 45.22 27.14 6.33 36.31 14.30 0.39 29.87 0.00 129.70 $0.13 80.229 687.42 17.08 0.00 32.20 44.62 27.14 6.12 34.38 13.54 0.38 29.47 0.00 125.93 $0.13 73.34

10 654.16 16.26 0.00 30.64 44.62 27.14 6.12 31.81 12.53 0.37 29.04 0.00 122.09 $0.12 66.9711 620.90 15.43 0.00 29.08 44.62 27.14 6.12 29.24 11.52 0.35 28.59 0.00 118.23 $0.12 61.0712 587.65 14.60 0.00 27.52 44.62 27.14 6.12 26.67 10.51 0.34 28.10 0.00 114.33 $0.11 55.6113 554.39 13.78 0.00 25.97 44.62 27.14 6.12 24.10 9.49 0.33 27.58 0.00 110.40 $0.11 50.5714 521.13 12.95 0.00 24.41 44.62 27.14 6.12 21.53 8.48 0.32 27.02 0.00 106.44 $0.11 45.9115 487.87 12.12 0.00 22.85 44.62 27.14 6.12 18.96 7.47 0.31 26.43 0.00 102.44 $0.10 41.6116 454.61 11.30 0.00 21.29 44.62 27.14 6.12 16.39 6.46 0.30 25.80 0.00 98.40 $0.10 37.6417 421.35 10.47 0.00 19.73 44.62 27.14 6.12 13.82 5.44 0.28 25.14 0.00 94.33 $0.09 33.9818 388.10 9.64 0.00 18.18 44.62 27.14 6.12 11.25 4.43 0.27 24.43 0.00 90.22 $0.09 30.6019 354.84 8.82 0.00 16.62 44.62 27.14 6.12 8.68 3.42 0.26 23.69 0.00 86.06 $0.09 27.4920 321.58 7.99 0.00 15.06 44.62 27.14 6.12 6.11 2.41 0.25 22.90 0.00 81.87 $0.08 24.6321 292.23 7.26 0.00 13.69 22.31 27.14 (1.69) 27.77 10.94 0.24 22.07 0.00 79.64 $0.08 22.5622 270.68 6.73 0.00 12.68 0.00 27.14 (9.50) 50.02 19.70 0.23 21.20 0.00 78.18 $0.08 20.8623 253.04 6.29 0.00 11.85 0.00 27.14 (9.50) 48.66 19.17 0.23 20.27 0.00 75.45 $0.08 18.9624 235.39 5.85 0.00 11.03 0.00 27.14 (9.50) 47.30 18.63 0.22 19.30 0.00 72.67 $0.07 17.1925 217.75 5.41 0.00 10.20 0.00 27.14 (9.50) 45.93 18.09 0.21 18.28 0.00 69.84 $0.07 15.5626 200.11 4.97 0.00 9.37 0.00 27.14 (9.50) 44.57 17.56 0.20 17.21 0.00 66.96 $0.07 14.0527 182.46 4.53 0.00 8.55 0.00 27.14 (9.50) 43.21 17.02 0.19 16.09 0.00 64.02 $0.06 12.6528 164.82 4.10 0.00 7.72 0.00 27.14 (9.50) 41.84 16.48 0.18 14.91 0.00 61.03 $0.06 11.3629 147.18 3.66 0.00 6.89 0.00 27.14 (9.50) 40.48 15.94 0.17 13.68 0.00 57.99 $0.06 10.1630 129.54 3.22 0.00 6.07 0.00 27.14 (9.50) 39.12 15.41 0.16 12.39 0.00 54.89 $0.05 9.0631 111.89 2.78 0.00 5.24 0.00 27.14 (9.50) 37.75 14.87 0.16 11.03 0.00 51.72 $0.05 8.0432 94.25 2.34 0.00 4.41 0.00 27.14 (9.50) 36.39 14.33 0.15 9.62 0.00 48.50 $0.05 7.1033 76.61 1.90 0.00 3.59 0.00 27.14 (9.50) 35.03 13.80 0.14 8.14 0.00 45.20 $0.05 6.2334 58.96 1.47 0.00 2.76 0.00 27.14 (9.50) 33.66 13.26 0.13 6.59 0.00 41.85 $0.04 5.4335 41.32 1.03 0.00 1.94 0.00 27.14 (9.50) 32.30 12.72 0.12 4.98 0.00 38.42 $0.04 4.7036 (8.75) (0.22) 0.00 (0.41) (50.00) 0.00 (17.50) 52.94 20.85 0.01 0.00 0.00 2.73 $0.00 0.3137 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $0.00 0.0038 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 $0.00 0.00

TOTAL $380.65 $0.00 $717.47 $950.00 $950.00 ($0.00) $1,183.71 $466.23 $9.92 $781.69 $0.00 $3,305.97 1,625

PRESENT

WORTH $212.53 $0.00 $400.58 $572.44 $384.92 $65.63 $459.79 $181.10 $4.87 $375.00 $0.00 $1,624.63

LEVELIZED

PAYMENT $14.99 $0.00 $28.25 $40.37 $27.14 $4.63 $32.42 $12.77 $0.34 $26.44 $0.00 $114.56


Page 16 of 22


Table - 6NorthWestern EnergyMarginal Cost Study - Gas SupplySummary of Marginal Capacity Costs

LineNo. Description Production Capacity

(1) (2) (3) (4)

1 PLANT INVESTMENT2 Long-Run Unit Costs - $/Design Day Dkt {1} 123.18$ 3 Common & General Plant Loading Factor {2} 8.75%4 Unit Costs + Loading Factor line 2 + (line 2 * line 3) 133.96$ 56 Fixed Charge Rate {3} 9.48%7 A&G Exp Plant-Related Loading Factor {4} 0.38%8 Total Rate line 6 + line 7 9.86%910 Annualized Cost line 4 * line 8 13.20$ 1112 OPERATING EXPENSES13 Production capacity costs {5} 12.55$ 14 A&G Exp Non-Plant Loading Factor {4} 24.05%15 Total O&M Expense line 13 * [1+ line 14] 15.57$ 1617 WORKING CAPITAL18 Materials & Supplies + Prepayments Rate {5} 0.35%19 M&S Cost line 4 * line 21 0.47$ 20 Working Cash O&M Allowance {6} [line 10 + line 15] * -18% (5.14)$

21 Total Working Capital line 19 + line 20 (4.67)$ 2223 Working Capital Rev. Req'd (23)*10.24% {7} (0.48)$ 2425 System Seasonal Capacity Related Cost26 $/Design Day Dkt line 10 + line 15 + line 23 28.29$ 2728 Loss Factor {4} 0.98529 Inflation Adjustment {8} 3.19%3031 Plant-related Costs [(10)+(23)]*[1+(29)]/(28) 13.33$ 32 O&M-related Costs (15)*[1+(29)]/(28) 16.31$ 33 Seasonal Capacity Cost, $ Design Day Dkt (26)*[1+(29)]/(28) 29.64$

Notes:1 Source: Table - 1, page 1.2 Source: Table - 4, page 2.3 Source: Table - 5, page 1.4 Source: Table - 4, page 1.5 Source: Table - 2, page 2.6 Working cash computed on the basis of -65.21 days net lag.7 Revenue requirement for working cash computed as the after tax cost of capital, i.e.

debt costs plus equity costs increased by taxes equals 10.24%.8 Inflation adjustment to restate marginal costs to 2018 dollars.


Page 17 of 22


Marginal Cost Study - Gas SupplySummary of Marginal Capacity Costs Adjusted for Uncollectibles

Line SupplyNo. Description Residential Employee General Service Firm Utilities


1 Uncollectible Ratio {1} 0.60% 0.00% 0.07% 0.00%23 Production Plant-related Costs4 Production Plant-related Costs {2} 29.64$ 29.64$ 29.64$ 29.64$ 5 Adjustment for Uncollectibles line 5 / (1-line 1) * line 1 0.18$ -$ 0.02$ -$

6 Total Production Capacity Costs Adjusted for Uncollectibles, 29.81$ 29.64$ 29.66$ 29.64$ $/Design Day Dkt

Notes:1 Source: Table - 3, page 1.2 Source: Table - 6, page 1.


Page 18 of 22


Table - 7NorthWestern EnergyMarginal Cost Study - Gas SupplySummary of Marginal Commodity Costs, $/Dkt

Line SupplyNo. Description Residential Employee General Service Firm Utilities

D-RG-1 D-RG-2 D-GSG-1 D-FUGC-1(1) (2) (3) (4) (5)

1 PLANT INVESTMENT2 Not Applicable -$ -$ -$ -$ 34 OPERATING EXPENSES56 Winter Weighted Average Gas {1} 2.5509$ 2.5550$ 2.5286$ 2.5843$ 78 Summer Weighted Average Gas {1} 2.0160$ 2.0151$ 2.0144$ 2.0169$ 9

10 Annual Weighted Average Gas {1} 2.3918$ 2.3846$ 2.3825$ 2.4064$ 111213 Loss Factor {2} 0.985 0.985 0.985 0.98514 Uncollectible Accounts Factor {3} 0.60% 0.00% 0.07% 0.00%151617 Loss Adjusted Marginal Commodity Cost1819 Winter Weighted Average Gas (6)/(13)/[1-(14)] 2.6051$ 2.5935$ 2.5685$ 2.6233$ 2021 Summer Weighted Average Gas (8)/(13)/[1-(14)] 2.0588$ 2.0455$ 2.0462$ 2.0473$ 2223 Annual Weighted Average Gas (10)/(13)/[1-(14)] 2.4427$ 2.4206$ 2.4201$ 2.4427$

Notes:1 Source: Table - 2, page 1.2 Source: Table - 4, page 2.3 Source: Table - 3, page 1.


Page 19 of 22


Table - 8NorthWestern EnergyMarginal Cost Study - Gas SupplySummary of Marginal Cost Estimates - Supply Service



1 WINTER CHARGES2 Gas Supply Demand Charge, $/Design Day Dkt {1} 29.815$ 29.635$ 29.656$ 29.635$ 3 Supply Commodity Charge $'s per Dkt {2} 2.605$ 2.594$ 2.569$ 2.623$ 45 SUMMER CHARGES6 Gas Supply Demand Charge, $/Design Day Dkt7 Supply Commodity Charge $'s per Dkt {2} 2.059$ 2.046$ 2.046$ 2.047$ 89 NORMALIZED BILLING DETERMINANTS (2015) {3}

10 Customers 165,787 284 23,359 4 189,43411 Winter Dkt 8,697,502 19,186 4,387,700 158,740 13,263,12812 Summer Dkt 3,732,496 9,020 2,026,778 75,161 5,843,45613 Annual Dkt 12,429,997 28,206 6,414,479 233,901 19,106,58414 Design Day Dkt Supply 168,729 377 87,337 2,836 259,2791516 REVENUES RESULTING FROM FULL MARGINAL COST PRICING1718 Winter19 Winter Supply Capacity Costs line 2 * line 14 5,030,579$ 11,161$ 2,590,075$ 84,048$ 7,715,863$ 20 Winter Supply Commodity line 3 * line 11 22,657,666$ 49,760$ 11,269,980$ 416,427$ 34,393,833$ 21 Total Winter line 19 + line 20 27,688,245$ 60,921$ 13,860,056$ 500,474$ 42,109,696$ 2223 Summer24 Summer Supply Capacity Costs line 6 * line 14 -$ -$ -$ -$ -$ 25 Summer Supply Commodity line 7 * line 12 7,684,429$ 18,451$ 4,147,244$ 153,882$ 12,004,005$ 26 Total Summer line 24 + line 25 7,684,429$ 18,451$ 4,147,244$ 153,882$ 12,004,005$ 2728 Supply Capacity Subtotal line 19 + line 24 5,030,579$ 11,161$ 2,590,075$ 84,048$ 7,715,863$ 29 Supply Commodity Subtotal line 20 + line 25 30,342,095$ 68,211$ 15,417,224$ 570,308$ 46,397,838$ 30 Total Marginal Annual Cost line 28 + line 29 35,372,674$ 79,372$ 18,007,299$ 654,356$ 54,113,700$

Notes:1 Source: Table - 6, page 2.2 Source: Table - 7, page 1.3 Source file Exhibit__(PJD-41) & (PJD-42) Revenue.xlxs, sheet NGBillDeterminants


Page 20 of 22


Table - 9NorthWestern EnergyMarginal Cost Study - Gas SupplyMarginal Unit Costs per Dkt - Supply Service



1 WINTER CHARGES $/Dkt $/Dkt $/Dkt $/Dkt2 Winter Supply Capacity Costs {1} 0.5784$ 0.5817$ 0.5903$ 0.5295$ 3 Winter Supply Commodity {2} 2.6051$ 2.5935$ 2.5685$ 2.6233$ 45 SUMMER CHARGES6 Summer Supply Capacity Costs {1} -$ -$ -$ -$ 7 Summer Supply Commodity {2} 2.0588$ 2.0455$ 2.0462$ 2.0473$ 89 ANNUAL CHARGES

10 Annual Supply Capacity Costs {1} 0.4047$ 0.3957$ 0.4038$ 0.3593$ 11 Annual Supply Commodity {2} 2.4427$ 2.4206$ 2.4201$ 2.4427$ 121314 NORMALIZED BILLING DETERMINANTS - FIRM SALES15 Customers {3} 165,787 284 23,359 4 189,43416 Winter Dkt 8,697,502 19,186 4,387,700 158,740 13,263,12817 Summer Dkt 3,732,496 9,020 2,026,778 75,161 5,843,45618 Total Annual Dkt 12,429,997 28,206 6,414,479 233,901 19,106,58419 Design Day Dkt Supply 168,729 377 87,337 2,836 259,279

Notes:1 Source: Table - 8 revenues divided by test year

normalized determinants.2 Source: Table - 73 Source: Table - 8


Page 21 of 22


Table - 10NorthWestern EnergyMarginal Cost Study - Gas SupplyDerivation of Marginal Prices Equi-Proportionately Constrained by Embedded Costs - Supply Service



1 Production Revenue Requirements 24,612,597$ 2 Commodity Revenue Requirements 28,701,228$ 3 Total Supply Revenue Requirements 53,313,825$ 4 Total Marginal Annual Revenue Requirements 35,372,674$ 79,372$ 18,007,299$ 654,356$ 54,113,700$ 5 Difference (799,875)$ 6 % Difference -1.48%7 Equi-proportional Adjustment (522,857)$ (1,173)$ (266,173)$ (9,672)$ (799,875)$ 8 Marginal Cost Revenues 34,849,816$ 78,198$ 17,741,126$ 644,684$ 53,313,825$ 910 Marginal Unit Prices1112 WINTER CHARGES13 Gas Supply Demand Charge, Design Day, Dkt 0.5698$ 0.5731$ 0.5816$ 0.5216$ 14 Supply Commodity Charge $'s per Dkt 2.5666$ 2.5552$ 2.5306$ 2.5846$ 1516 SUMMER CHARGES17 Gas Supply Demand Charge, Design Day, Dkt -$ -$ -$ -$ 18 Supply Commodity Charge $'s per Dkt 2.0284$ 2.0153$ 2.0160$ 2.0171$ 1920 ANNUAL CHARGES21 Gas Supply Demand Charge, Design Day, Dkt 0.3987$ 0.3898$ 0.3978$ 0.3540$ 22 Supply Commodity Charge $'s per Dkt 2.4065$ 2.3848$ 2.3844$ 2.4066$

Notes:1 Production Revenues are at 2015 Proposed Rates Excluding Gas Costs and Other Operating Revenues2 Commodity Revenues source Docket No. D2015.7.53, Exhibit_(JMS-2), Page 2 of 3, Line 273 Source: Table 8, page 1 of 14 Source: Table 9, page 1 * (1 + line 6). Design Day costs converted to Dkt based on 2015 volumes.


Page 22 of 22

5/25/2017 8:12 AM 1 of 19 NG Stmt M 2015 Rev rebuttal final Statement M

(A) (B) (C) (D) (E) (F) (H) (I) (J)

ACOSAverage Monthly Market Present Results Moderated Proposed Class

Line Customer Class Customers MDDQ (Therms) Revenue (2015) Revenues Revenues Impact1 Core - DBU2 RESIDENTIAL:3 Residential 165,787 124,523,505 74,195,111$ $80,797,855 $79,471,027 $79,469,320 7.11%4 Employee 284 282,064 120,088 165,759 126,432 128,138 6.70%5 Subtotal 166,071 124,805,570 $74,315,199 $80,963,615 $79,597,459 $79,597,459 7.11%67 GENERAL SERVICE 23,359 67,919,333 $38,719,759 $39,600,473 $41,303,388 $41,303,388 6.67%89 Total Core 189,430 192,724,903 $113,034,958 $120,564,088 $120,900,846 $120,900,846 6.96%

1011 Utilities 4 2,339,009 581,773$ $694,857 $627,108 $627,108 7.79%12 Transmission 2,751 13 Storage 1,513 1415 Non-Core16 DBU Transportation17 Firm Transportation 224 21,403 - 2,408,640$ $3,138,126 $2,644,856 $2,644,856 9.81%181920 TBU Transportation21 Firm Transportation 32 101,220 175,064,780 13,006,109$ $14,272,008 $13,937,248 $13,937,248 7.16%222324 Storage 45,740 347,748,510 3,520,419$ 3,168,093$ 3,727,113$ 3,727,113$ 5.87%2526 Total Without Interuptible 189,690 717,877,202 132,551,900$ 141,837,172$ 141,837,172$ 141,837,172$ 7.01%2728 DBU Transportation29 Interruptible Transportation 1,353,600 34,448$ -$ 37,828$ 37,828$ 9.81%30 TBU Transportation31 Interruptible Transportation 61,707,010 2,442,349$ -$ 2,617,222$ 2,617,222$ 7.16%3233 Rounding (0)$ 3435 Total Montana P,D, T & S 189,690 780,937,812 135,028,698$ 141,837,172$ 144,492,221$ 144,492,221$ 7.01%

NorthWestern Energy Natural Gas UtilityStatement M

Reconciliation and Moderation of Embedded Cost Allocation to Proposed Revenue Requirement

Docket No. D2016.9.68 Statement M Page 1 of 19

5/25/2017 8:12 AM 2 of 19 NG Stmt M 2015 Rev rebuttal final Summary


Summary of Proposed Rates

Excl Prop Tax Line Description Service Charge Distribution Transmission Storage Production Total

1 Residential:2 Residential Base Rate (Therm) $8.25 $0.1078602 $0.1286042 $0.0170723 $0.1265688 $0.38010553 Residential Property Tax Rate (Therm) $0.0723782 $0.0467994 $0.0050338 $0.0022961 $0.12650754 Employee Base Rate (Therm) $6.15 $0.0808951 $0.0964531 $0.0128042 $0.0949266 $0.28507905 Employee Property Tax Rate (Therm) $0.0542837 $0.0350996 $0.0037753 $0.0017221 $0.094880767 General Service:8 0 to 300 $16.609 301 to 1,000 $21.90

10 1,001 to 2,000 $35.2511 2,001 to 5,000 $59.2512 5,001 to 10,000 $72.7513 10,001 to 30,000 $115.0014 > 30,000 $139.7515 General Service Base Rate (Therm) $0.1208280 $0.1440660 $0.0196397 $0.1265688 $0.411102516 General Service Property Tax Rate (Therm) $0.0568862 $0.0445858 $0.0049248 $0.0022961 $0.10869291718 Utilities:19 10,001 to 30,000 $149.0520 > 30,000 $384.4021 Base - Reservation Rate (MDDQ) $0.4642679 $0.105705022 Base- Commodity Rate (Therm) $0.0055339 $0.0003824 $0.1265688 $0.132485123 Property Tax - Reservation Rate (MDDQ) $0.3159685 $0.056065024 Property Tax - Commodity Rate (Therm) $0.0037662 $0.0002028 $0.0022961 $0.0062651252627 DBU Firm Transportation28 < 5000 $125.6029 5000 to 10000 $143.5530 10001 to 30000 $197.3031 > 30000 $229.1032 Reservation Base Rate (MDDQ) $0.5683701 $0.568370133 Reservation Property Tax Rate (MDDQ) $0.2932334 $0.293233434 Interruptible Transportation Base Rate (Therm) $0.0222344 $0.022234435 Interruptible Transportation Base Rate Property Tax (Therm) $0.0057117 $0.0057117363738 TBU Firm Transportation39 5,001 to 10,000 $125.6540 10,001 to 30,000 $180.6041 > 30,000 $400.7042 Reservation Base Rate (MDDQ) $0.7452341 $0.745234143 Reservation Property Tax Rate (MDDQ) $0.3010417 $0.301041744 Commodity Base Rate (Therm) $0.0056473 $0.005647345 Commodity Property Tax Rate (Therm) $0.0022812 $0.002281246 Tenaska/Jetco Reservation Base Rate (MDDQ) $0.1933993 $0.193399347 Tenaska/Jetco Reservation Property Tax Rate (MDDQ) $0.0781248 $0.078124848 Tenaska/Jetco Commodity Rate (Therm) $0.0043491 $0.004349149 Tenaska/Jetco Commodity Property Tax Rate (Therm) $0.0017568 $0.001756850 Interruptible Transportation Base Rate (Therm) $0.0337450 $0.033745051 Interruptible Transportation Base Rate Property Tax (Therm) $0.0086686 $0.0086686525354 Storage55 Reservation Base Rate (MDDQ) $0.3941710 $0.394171056 Reservation Property Tax Rate (MDDQ) $0.1008486 $0.100848657 Capacity Base Rate (Therm) $0.0019351 $0.001935158 Capacity Property Tax Rate (Therm) $0.0004951 $0.000495159 Injection Base Rate (Therm) $0.0020371 $0.002037160 Injection Property Tax Rate (Therm) $0.0005212 $0.000521261 Withdrawal Base Rate (Therm) $0.0020371 $0.002037162 Withdrawal Property Tax Rate (Therm) $0.0005212 $0.00052126364


5/25/2017 8:12 AM 3 of 19 NG Stmt M 2015 Rev rebuttal final Summary Present Rates


Summary of Present Rates

Excl Prop Tax Line Description Service Charge Distribution Transmission Storage Production Total

1 Residential:2 Residential Base Rate $5.80 $0.1668809 $0.0988201 $0.0300756 $0.1055755 $0.40135213 Residential Property Tax Rate $0.0667590 $0.0254523 $0.0077462 $0.0018313 $0.10178884 Employee Base Rate $4.35 $0.1251607 $0.0741151 $0.0225567 $0.0793240 $0.30115655 Employee Property Tax Rate $0.0457266 $0.0190892 $0.0058097 $0.0013760 $0.072001567 General Service:8 0 to 300 $15.059 301 to 1,000 $19.85

10 1,001 to 2,000 $32.0011 2,001 to 5,000 $53.7512 5,001 to 10,000 $66.0013 10,001 to 30,000 $104.3514 > 30,000 $126.8015 General Service Base Rate $0.1612889 $0.0954721 $0.0289909 $0.0998876 $0.385639516 General Service Property Tax Rate $0.0639852 $0.0246462 $0.0074842 $0.0017327 $0.09784831718 Utilities:19 10,001 to 30,000 $101.6520 > 30,000 $262.1021 Base - Reservation Rate (MDDQ) $0.4949175 $0.393615022 Base- Commodity Rate (Therm) $0.0058992 $0.0014239 $0.1057654 $0.113088523 Property Tax - Reservation Rate (MDDQ) $0.1347796 $0.101113124 Property Tax - Commodity Rate (Therm) $0.0016066 $0.0003658 $0.0018346 $0.0038070252627 DBU Firm Transportation28 < 5000 $97.35 $97.3529 5000 to 10000 $111.25 $111.2530 10001 to 30000 $152.90 $152.9031 > 30000 $177.55 $177.5532 Reservation Base Rate $0.6158065 $0.615806533 Reservation Property Tax Rate $0.1916653 $0.191665334 Interruptible Transportation Base Rate $0.0202481 $0.020248135 Interruptible Transportation Base Rate Property Tax $0.0052014 $0.0052014363738 TBU Firm Transportation39 5,001 to 10,000 $95.2540 10,001 to 30,000 $136.9041 > 30,000 $303.7542 Reservation Base Rate (MDDQ) $0.7784823 $0.778482343 Reservation Property Tax Rate (MDDQ) $0.2019301 $0.201930144 Commodity Base Rate (Therm) $0.0058992 $0.005899245 Commodity Property Tax Rate (Therm) $0.0015303 $0.001530346 Tenaska/Jetco Reservation Base Rate (MDDQ) $0.2020277 $0.202027747 Tenaska/Jetco Reservation Property Tax Rate (MDDQ) $0.0000000 $0.000000048 Tenaska/Jetco Commodity Rate (Therm) $0.0045431 $0.004543149 Tenaska/Jetco Commodity Property Tax Rate (Therm) $0.0000000 $0.000000050 Interruptible Transportation Base Rate (Therm) $0.0314903 $0.031490351 Interruptible Transportation Base Rate Property Tax (Therm) $0.0080894 $0.0080894525354 Storage55 Reservation Base Rate (MDDQ) $0.3716631 $0.371663156 Reservation Property Tax Rate (MDDQ) $0.0959011 $0.095901157 Capacity Base Rate (Therm) $0.0018246 $0.001824658 Capacity Property Tax Rate (Therm) $0.0004709 $0.000470959 Injection Base Rate (Therm) $0.0019208 $0.001920860 Injection Property Tax Rate (Therm) $0.0004955 $0.000495561 Withdrawal Base Rate (Therm) $0.0019208 $0.001920862 Withdrawal Property Tax Rate (Therm) $0.0004955 $0.00049556364


5/25/2017 8:12 AM 4 of 19 NG Stmt M 2015 Rev rebuttal final Production

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J)

Line Average Sales PresentNo. Function Customers (Dkt) Revenues Costs w Tax $ Increase % Increase Prop. Rev. $ Increase % Increase

1 Revenue and Billing Information2 Residential 165,538 12,429,997 13,374,677$ $14,389,980 $1,015,303 7.59% $16,017,906 2,643,229$ 19.76%3 Employee 284 28,206 22,763 31,786 9,023 39.64% 27,261 4,499 19.76%4 Subtotal 165,823 12,458,204 13,397,440$ $14,421,766 $1,024,327 7.66% $16,045,168 $2,647,728 19.76%5 General Service 22,984 6,414,479 6,901,979$ 9,958,914$ 3,056,934$ 44.29% $8,266,013 1,364,034$ 19.76%6 Firm Utilities 4 233,901 251,677$ 231,915$ (19,762)$ -7.85% $301,416 49,739$ 19.76%7 Total 188,811 19,106,584 20,551,096$ 24,612,595$ 4,061,499$ 19.76% 24,612,597$ 4,061,501$ 19.76%891011 Rates and Revenue Battle Creek Bear Paw Devon Total Prod Battle Creek Bear Paw Devon Total Prod12 Present Rates 0.1237$ 0.1700$ 0.7823$ 1.0756$ 0.1297$ 0.2571$ 0.9019$ 1.2886$ -$ 13 Present Revenue14 Residential 1,537,591$ 2,113,100$ 9,723,987$ 13,374,677$ 1,612,703$ 3,195,133$ 11,210,071$ 16,017,906$ 15 Employee 2,617 3,596 16,549 22,763$ 2,745 5,438 19,079 27,261$ 16 Subtotal 1,540,208 2,116,696 9,740,536 13,397,440 1,615,448 3,200,570 11,229,149 16,045,167 17 General Service 793,471$ 1,090,461$ 5,018,047$ 6,901,979$ 832,233$ 1,648,843$ 5,784,938$ 8,266,013$ 18 Firm Utilities 28,934$ 39,763$ 182,981$ 251,677$ 30,347$ 60,124$ 210,945$ 301,416$ 19 Total 2,362,612$ 3,246,920$ 14,941,564$ 20,551,096$ 2,478,027$ 4,909,537$ 17,225,032$ 24,612,596$ 20212223 Change in Rates and Revenue Battle Creek Bear Paw Devon Total Prod Battle Creek Bear Paw Devon Total Prod24 Present Rates 0.0060$ 0.0871$ 0.1196$ 0.2130$ 4.89% 51.21% 15.28% 19.81%25 Present Revenue26 Residential 75,112$ 1,082,033$ 1,486,084$ 2,643,229$ 4.89% 51.21% 15.28% 19.76%27 Employee 128 1,842 2,529 4,499 4.89% 51.21% 15.28% 19.76%28 Subtotal 75,240 1,083,875 1,488,613 2,647,727 4.89% 51.21% 15.28% 19.76%29 General Service 38,762$ 558,381$ 766,891$ 1,364,034$ 4.89% 51.21% 15.28% 19.76%30 Firm Utilities 1,413$ 20,361$ 27,964$ 49,739$ 4.89% 51.21% 15.28% 19.76%31 Total 115,415$ 1,662,617$ 2,283,468$ 4,061,500$ 4.89% 51.21% 15.28% 19.76%

Natural Gas Utility Rate DesignNorthWestern Energy

-------------- Allocated -------------- --------------Moderated --------------

------------------------- Change ($) -------------------------- ------------------------- Change (%) --------------------------

------------------------- Present ------------------------ ------------------------- Proposed -----------------------

Natural Gas Production


5/25/2017 8:12 AM 5 of 19 NG Stmt M 2015 Rev rebuttal final Property Taxes

(A) (B) (C) (D) (E) (F) (G) (H)Interruptible Firm Adjusted Adj Prop Tax Proposed

Line Per Property Tax Prop Tax Property Tax Less: Production Target Revenue Property TaxNo. Function Cost of Service Prop Revenue Adjustment Target Revenue Property Tax Excl Prod Revenue1 Core - DBU2 RESIDENTIAL:3 Residential 16,043,923$ -$ (297,040)$ 15,746,883$ 285,403$ 15,461,480$ 15,752,649$ 4 Employee 33,142 0 (614)$ 32,528 486 32,043 26,7625 Subtotal 16,077,065$ -$ (297,653)$ 15,779,411$ 285,889$ 15,493,522$ 15,779,411$ 67 GENERAL SERVICE $7,512,767 $0 (139,093)$ $7,373,674 $147,282 $7,226,392 $7,373,67489 Total Core $23,589,831 $0 (436,746)$ $23,153,085 $433,170 $22,719,915 $23,153,085

1011 Utilities $131,577 $0 (2,436)$ 129,141$ $5,371 $123,770 $129,14112 Transmission 13 Storage 1415 Non-Core16 DBU Transportation17 Firm Transportation $767,327 $0 (14,206)$ $753,120 $0 $753,120 $753,120181920 TBU Transportation21 Firm Transportation $4,047,475 $0 (74,936)$ $3,972,539 $0 $3,972,539 $3,972,539222324 Storage 773,635$ -$ (14,323)$ 759,312$ -$ 759,312$ 759,312$ 2526 Total Without Interuptible 29,309,844$ -$ (542,647)$ 28,767,197$ 438,541$ 28,328,656$ 28,767,197$ 2728 DBU Transportation29 Interruptible Transportation -$ 7,731$ -$ 7,731$ -$ 7,731$ 7,731$ 30 TBU Transportation31 Interruptible Transportation -$ 534,916$ -$ 534,916$ -$ 534,916$ 534,916$ 32333435 Total Montana P,D, T & S 29,309,844$ 542,647$ (542,647)$ 29,309,844$ 438,541$ 28,871,303$ 29,309,844$


Property Taxes


5/25/2017 8:12 AM 6 of 19 NG Stmt M 2015 Rev rebuttal final Residential

(A) (B) (C) (D) (E) (F) (G)Line Average Sales PresentNo. Summary Customers (Dkt) Revenues Costs $ Increase % Increase

1 Residential 165,787 12,452,351 $74,195,111 $80,797,855 $6,602,744 8.90%2 Employee 284 28,206 120,088 165,759 45,671 38.03%3 Subtotal 166,071 12,480,557 $74,315,199 $80,963,615 $6,648,415 8.95%456 Revenues $ Increase % Increase Revenues % Increase % Increase7 Residential $79,471,027 $5,275,916 7.11% $79,469,320 $5,274,209 7.11%8 Employee $126,432 6,344 5.28% $128,138 $8,050 6.70%9 Subtotal $79,597,459 $5,282,259 7.11% $79,597,459 $5,282,259 7.11%

101112 Total Present13 Present Rates and Revenue Distribution Transmission Storage Production Rate14 Present Rates ($/Therm)15 Residential $5.8016 Rate w/o Property Tax $0.166881 $0.098820 $0.030076 $0.105575 $0.40135217 Property Tax Portion $0.066759 $0.025452 $0.007746 $0.001831 $0.10178918 Total Commodity Rate $0.233640 $0.124272 $0.037822 $0.107407 $0.50314119 Employee $4.3520 Rate w/o Property Tax $0.125161 $0.074115 $0.022557 $0.079324 $0.30115621 Property Tax Portion $0.045727 $0.019089 $0.005810 $0.001376 $0.07200222 Total Commodity Rate $0.170887 $0.093204 $0.028366 $0.080700 $0.37315823 Present Revenue24 Residential $11,542,241 $11,542,24125 Rate w/o Property Tax $20,780,595 $12,305,425 $3,745,119 $13,146,631 49,977,77026 Property Tax Portion 8,313,060 3,169,410 964,584 228,046 12,675,10027 Total Commodity Rate $11,542,241 $29,093,655 $15,474,835 $4,709,703 $13,374,677 $74,195,11128 Employee $14,834 $14,83429 Rate w/o Property Tax 35,303 20,905 6,362 $22,374 84,94530 Property Tax Portion 12,898 5,384 1,639 388 20,30931 Total Present Revenue $14,834 $48,201 $26,290 $8,001 $22,763 $120,0883233 Total Residential Present Revenue $11,557,075 $29,141,856 $15,501,124 $4,717,704 $13,397,440 $74,315,199343536 Cost of Service37 Costs by Component Distribution Transmission Storage Production Total Cost38 Residential $21,212,321 $21,212,32139 Base Cost w/o Property Tax 12,510,835 14,916,958 1,980,235 14,133,584 43,541,61140 Property Tax Portion 0 9,199,421 5,948,303 639,802 256,397 16,043,92341 Total Costs $21,212,321 $21,710,256 $20,865,261 $2,620,037 $14,389,980 $80,797,85542 Rate at EROR $10.6643 Employee $36,348 $36,34844 Base Cost w/o Property Tax 27,681 33,005 4,364 31,219 96,26945 Property Tax Portion 0 18,005 13,161 1,410 566 33,14246 Total Costs $36,348 $45,686 $46,166 $5,774 $31,786 $165,75947 Rate at EROR (75%) $8.0048 Base Cost w/o Property Tax $21,248,670 12,538,516 14,949,963 1,984,598 14,164,803 $64,886,55049 Property Tax Portion $0 $9,217,426 $5,961,464 $641,212 $256,963 $16,077,06550 Total Residential Present Revenue $21,248,670 $21,755,942 $20,911,426 $2,625,810 $14,421,766 $80,963,61551

NorthWestern Energy

---------------- Proposed --------------------------------- Moderated -----------------

---------------- Allocated ----------------

ResidentialNatural Gas Utility Rate Design

Service Charge

Service Charge


5/25/2017 8:12 AM 7 of 19 NG Stmt M 2015 Rev rebuttal final Residential

(A) (B) (C) (D) (E) (F) (G)

NorthWestern Energy

ResidentialNatural Gas Utility Rate Design

52 Property Taxes per COS, Production per Rev Req, Service Charge COS Moderated53 Moderated Revenues Stmt H Prod Total Calculated54 Calculated Unit Rates and Revenue Distribution Transmission Storage Production Rate55 Calculated Rates ($/Therm)56 Residential $10.4857 Rate w/o Property Tax 0.091578 0.109191 0.014495 0.126569 $0.34183358 Property Tax Portion 0.073904 0.047786 0.005140 0.002296 $0.12912659 Total Commodity Rate 0.165482 0.156977 0.019635 0.128865 $0.47095960 Employee $7.8661 Rate w/o Property Tax 0.068684 0.081893 0.010871 0.094927 $0.25637562 Property Tax Portion 0.055428 0.035839 0.003855 0.001722 $0.09684463 Total Commodity Rate 0.124112 0.117733 0.014726 0.096649 $0.35321964 Calculated Revenue65 Residential $20,854,391 $20,854,39166 Rate w/o Property Tax $11,403,644 $13,596,828 $1,804,987 $15,732,503 42,537,96367 Property Tax Portion $9,202,768 $5,950,467 $640,035 $285,403 16,078,67368 Total Commodity Rate $20,854,391 $20,606,413 $19,547,296 $2,445,021 $16,017,906 $79,471,02769 Employee $26,801 $26,80170 Rate w/o Property Tax $19,373 $23,099 $3,066 $26,775 72,31471 Property Tax Portion 15,634 10,109 1,087 486 27,31672 Total Proposed Revenue $26,801 $35,007 $33,208 $4,154 $27,261 $126,4327374 Total Residential Proposed Revenue $20,881,192 $20,641,420 $19,580,504 $2,449,175 $16,045,167 $79,597,459757677 Total Proposed78 Proposed Rates and Revenue Distribution Transmission Storage Production Rate79 Proposed Rates ($/Therm)80 Residential $8.2581 Rate w/o Property Tax $0.107860 $0.128604 $0.017072 $0.126569 $0.38010582 Property Tax Portion $0.072378 $0.046799 $0.005034 $0.002296 $0.12650883 Total Commodity Rate $0.180238 $0.175404 $0.022106 $0.128865 $0.50661384 Employee $6.1585 Rate w/o Property Tax $0.080895 $0.096453 $0.012804 $0.094927 $0.28507986 Property Tax Portion $0.054284 $0.035100 $0.003775 $0.001722 $0.09488187 Total Commodity Rate $0.135179 $0.131553 $0.016580 $0.096649 $0.37996088 Proposed Revenue89 Residential $16,412,897 $16,412,89790 Rate w/o Property Tax $13,431,128 $16,014,244 $2,125,900 $15,732,503 47,303,77591 Property Tax Portion $9,012,793 $5,827,630 $626,822 $285,403 15,752,64992 Total Commodity Rate $16,412,897 $22,443,921 $21,841,874 $2,752,722 $16,017,906 $79,469,32093 Employee $20,965 $20,96594 Rate w/o Property Tax $22,818 $27,206 $3,612 $26,775 80,41195 Property Tax Portion $15,311 $9,900 $1,065 $486 26,76296 Total Proposed Revenue $20,965 $38,129 $37,106 $4,676 $27,261 $128,1389798 Total Residential Proposed Revenue $16,433,862 $22,482,050 $21,878,980 $2,757,399 $16,045,168 $79,597,459

Service Charge

Service Charge


5/25/2017 8:12 AM 8 of 19 NG Stmt M 2015 Rev rebuttal final Gen Ser

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)

Line PresentNo. Summary Revenues Costs Increase ($) Increase (%) Revenue Increase ($) Increase (%) Revenue Increase ($) Increase (%)

1 GS Total $38,719,759 $39,600,473 $880,715 2.27% $41,303,388 $2,583,629 6.67% $41,303,388 $2,583,629 6.67%234 Present Rates: Average Service Sales Monthly5 Customers Charge (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage

Revenue

6 GS Total 67,919,333 $0.225274 $0.120118 $0.036475 $0.381868 $15,300,470 $8,158,355 $2,477,364 $25,936,1897 0 to 300 * 15,114 $15.05 $2,729,041 2,729,0418 301 to 1,000 3,343 $19.85 796,400 796,4009 1,001 to 2,000 3,337 $32.00 1,281,114 1,281,114

10 2,001 to 5,000 1,243 $53.75 801,515 801,51511 5,001 to 10,000 286 $66.00 226,650 226,65012 10,001 to 30,000 32 $104.35 40,277 40,27713 > 30,000 4 $126.80 6,594 6,59414 Total 23,359 $5,881,590 $15,300,470 $8,158,355 $2,477,364 $31,817,77915 Average Production 6,901,97916 Total $38,719,75917 Product Rate $0.1016201819 Present Rates without Property Taxes: Average Service Sales Monthly

20 Customers Charge (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage Total

Revenue 21 GS Total 67,919,333 $0.161289 $0.095472 $0.028991 $0.285752 $10,954,635 $6,484,401 $1,969,043 $19,408,07822 0 to 300 * 15,114 $15.05 $2,729,041 2,729,04123 301 to 1,000 3,343 $19.85 796,400 796,40024 1,001 to 2,000 3,337 $32.00 1,281,114 1,281,11425 2,001 to 5,000 1,243 $53.75 801,515 801,51526 5,001 to 10,000 286 $66.00 226,650 226,65027 10,001 to 30,000 32 $104.35 40,277 40,27728 > 30,000 4 $126.80 6,594 6,59429 Total 23,359 $5,881,590 $10,954,635 $6,484,401 $1,969,043 $25,289,66930 Average Production 6,784,29631 Total $32,073,96532 Product Rate $0.0998883334 Present Rates Property Taxes: Sales Monthly35 (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage

Revenue

36 GS Total 67,919,333 $0.063985 $0.024646 $0.007484 $0.096116 $4,345,835 $1,673,953 $508,322 $6,528,11037 0 to 300 *38 301 to 1,00039 1,001 to 2,00040 2,001 to 5,00041 5,001 to 10,00042 10,001 to 30,00043 > 30,00044 Total $4,345,835 $1,673,953 $508,322 $6,528,11045 Average Production 117,68346 Total $6,645,79347 Product Rate $0.001733

NorthWestern Energy

------------ Present Commodity Charges ------------ --------------- Present Revenue ---------------

--------- Moderated Revenue --------- -------- Proposed Revenue -------------------- Allocated Costs ------------

General ServiceNatural Gas Utility Rate Design

------------ Present Commodity Charges w/o Taxes ------------ --------------- Present Revenue w/o Taxes---------------

------------ Present Commodity Charges Tax Rates------------ --------------- Present Revenue Taxes---------------



(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)

NorthWestern Energy


4849 Cost of Service Customer Costs 50 Costs by Component Distribution Transmission Storage Production Total Cost51 Base Cost w/o Property Tax $7,081,614 $6,465,177 $7,708,580 $1,050,867 $9,781,468 $32,087,70652 Property Tax Portion 0 3,921,910 3,073,882 339,529 177,445 7,512,76753 Total Costs $7,081,614 $10,387,087 $10,782,462 $1,390,396 $9,958,914 $39,600,47354 Distributed Service Costs55 0 to 300 * $3,285,84856 301 to 1,000 958,89057 1,001 to 2,000 1,542,50158 2,001 to 5,000 965,04859 5,001 to 10,000 272,89360 10,001 to 30,000 48,49561 > 30,000 7,93962 Total $7,081,614636465 Cost of Service ----------------------------------- Unit Commodity Costs ------------------------------------ ----------------------------------------- Cost Based Revenue ------------------------------------------66 Unit Costs and Revenue Service Charge Distribution Transmission Storage Production Total Service Charge Distribution Transmission Storage Production Total67 Unit Costs ($/Therm)68 Base Cost w/o Property Tax See detail below $0.095189 $0.113496 $0.015472 $0.144016 $0.368173 $7,081,614 $6,465,177 $7,708,580 $1,050,867 $9,781,468 $25,006,09269 Property Tax Portion $0.000000 $0.057744 $0.045258 $0.004999 $0.002613 $0.110613 0 3,921,910 3,073,882 339,529 177,445 7,512,76770 Total Costs $0.152933 $0.158754 $0.020471 $0.146629 $0.47878671 Monthly Service Charge at EROR72 0 to 300 * $18.12 $3,285,84873 301 to 1,000 $23.90 958,89074 1,001 to 2,000 $38.52 1,542,50175 2,001 to 5,000 $64.71 965,04876 5,001 to 10,000 $79.47 272,89377 10,001 to 30,000 $125.64 48,49578 > 30,000 $152.67 7,93979 Total $25.26 $7,081,614 $10,387,087 $10,782,462 $1,390,396 $9,958,914 $39,600,473808182 ------- Cost to Rate Reconciliation -------83 Present Cost of Service Moderated ---------------------------------- Moderated Revenue Objectives -----------------------------------84 Total Revenue $38,719,759 $39,600,473 $41,303,388 Service Charge Distribution Transmission Storage Production Total85 Less: Property Tax 6,528,111 7,512,767 7,482,603 Base Revenue $8,159,691 $7,449,410 $8,882,104 $1,210,847 $8,118,731 $33,820,78586 Production Costs (excl. Prop Tax) 0 9,781,468 8,118,731 Prop Tax Rev. 0 3,921,910 3,073,882 339,529 147,282 7,482,60387 Amount Req'd from Base Charges excl. Prod $32,191,648 $22,306,238 $25,702,053 Total Revenue $8,159,691 $11,371,321 $11,955,986 $1,550,376 $8,266,013 $41,303,38888



(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M)

NorthWestern Energy


89 Property Taxes per COS, Production per Rev Requirement, Service Charge COS Moderated Property Taxes per COS, Production per Statement H, Service Charge COS Moderated90 Moderated Revenues ---------------------------------------Calculated Unit Prices ---------------------------------------- ----------------------------------------- Calculated Unit Revenue ------------------------------------------91 Unit Costs and Revenue Service Charge Distribution Transmission Storage Production Total Service Charge Distribution Transmission Storage Production Total92 Unit Costs ($/Therm)93 Base Charge w/o Property Tax See detail below $0.109680 $0.130774 $0.017828 0.126569 $0.384851 $8,159,691 $7,449,410 $8,882,104 $1,210,847 $8,118,731 $25,661,09394 Property Tax $0.000000 $0.057744 $0.045258 $0.004999 0.002296 $0.110297 0 3,921,910 3,073,882 339,529 147,282 7,482,60395 Total Commodity Charge $0.167424 $0.176032 $0.022827 $0.128865 $0.49514896 Monthly Service Charge97 0 to 300 * $20.88 $3,786,07398 301 to 1,000 $27.54 1,104,86899 1,001 to 2,000 $44.39 1,777,325

100 2,001 to 5,000 $74.56 1,111,963101 5,001 to 10,000 $91.57 314,437102 10,001 to 30,000 $144.76 55,878103 > 30,000 $175.91 9,147104 Average $29.11 Prop. Revenue $8,159,691 $11,371,321 $11,955,986 $1,550,376 $8,266,013 $41,303,388105 Present Revenue $5,881,590 $15,300,470 $8,158,355 $2,477,364 $6,901,979 $38,719,759106 Revenue Change $2,278,101 -$3,929,149 $3,797,631 -$926,988 $1,364,034 $2,583,629107 % Change 38.7% -25.7% 46.5% -37.4% 19.8% 6.67%108109110 ---------------------------------------Proposed Rates ---------------------------------------- ----------------------------------------- Proposed Revenue ------------------------------------------111 Unit Costs Proposed Rates and Revenue Service Charge Distribution Transmission Storage Production Total Service Charge Distribution Transmission Storage Production Total112 Rate ($/Therm)113 Base Charge w/o Property Tax See detail below $0.120828 $0.144066 $0.019640 $0.126569 $0.411103 $6,485,639 $8,206,558 $9,784,869 $1,333,916 $8,118,731 $27,444,075114 Property Tax $0.000000 $0.056886 $0.044586 $0.004925 $0.002296 $0.108693 $3,863,670 $3,028,235 $334,487 $147,282 7,373,674115 Total Commodity Charge $0.177714 $0.188652 $0.024564 $0.128865 $0.519795116 Monthly Service Charge117 0 to 300 * $16.60 $3,010,626118 301 to 1,000 $21.90 878,562119 1,001 to 2,000 $35.25 1,411,375120 2,001 to 5,000 $59.25 883,595121 5,001 to 10,000 $72.75 249,824122 10,001 to 30,000 $115.00 44,390123 > 30,000 $139.75 7,267124 Average $23.14 Prop. Revenue $6,485,639 $12,070,229 $12,813,104 $1,668,403 $8,266,013 $41,303,388125 Present Revenue $5,881,590 $15,300,470 $8,158,355 $2,477,364 $6,901,979 $38,719,759126 Revenue Change $604,048 -$3,230,241 $4,654,749 -$808,961 $1,364,034 $2,583,629127 % Change 10.3% -21.1% 57.1% -32.7% 19.8% 6.67%

Docket No. D2016.9.68 Statement M

Page 10 of 19

5/25/2017 8:12 AM 11 of 19 NG Stmt M 2015 Rev rebuttal final Utilities

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N)

Line Average Sales Present Allocated Allocated Moderated Proposed RatesNo. Function Customers Transmission Storage Therms Revenues Costs % Increase Revenues Increase ($) Increase (%) Revenues Increase ($) Increase (%)

1 Summary Revenue and Billing Information:2 10,001 to 30,000 1 3 > 30,000 * 3 4 Utilities 4 33,012 18,156 2,339,009 $581,773 $694,857 19.44% $627,108 $45,334 7.79% $627,108 $45,334 7.79%566 Present Rates & Revenue:7 Monthly Service Charge per Meter Base Property Tax Total Base Property Tax Total Base Property Tax Total Base Property Tax Total8 10,001 to 30,000 $101.65 $101.65 $1,220 $0 $1,220 $2,358 $0 $2,358 $1,138 $0 $1,1389 > 30,000 * $262.10 $262.10 9,436 0 9,436 18,240 0 18,240 8,804 0 8,8049 Sub-total $10,655 $0 $10,655 $20,598 $0 $20,598 $9,942 $0 $9,942

10 196.49 Svc Chg @ EROR per cost of service11 Transmission Charges: 506.66 Svc Chg @ EROR per cost of service12 Reservation Rate (MDDQ) $4.9491750 $1.3477960 $6.2969710 $163,382 $44,493 $207,876 $259,068 $107,404 $366,472 $95,686 $62,911 $158,59612 Transm Commodity Rate (Therm) $0.0058992 $0.0016066 $0.0075058 13,798 3,758 17,556 21,879 9,071 30,950 8,081 5,313 13,39413 Sub-total $177,180 $48,251 $225,432 $280,947 $116,475 $397,422 $103,767 $68,224 $171,9901415 Storage Charges:15 Reservation Rate (MDDQ) $3.9361500 $1.0111310 $4.9472810 $71,465 $18,358 $89,823 $32,441 $10,481 $42,922 ($39,024) ($7,877) ($46,901)16 Storage Commodity Rate (Therm) $0.0014239 $0.0003658 $0.0017897 3,331 856 4,186 1,512 488 2,000 (1,819) (367) (2,186)17 Sub-total $74,795 $19,214 $94,009 $33,952 $10,970 $44,922 ($40,843) ($8,244) ($49,087)1818 Production Charges:19 Production Commodity Rate (Therm) $0.1057654 $0.0018346 $0.1076000 247,386 4,291 $251,677 $227,783 $4,132 $231,915 ($19,603) ($159) ($19,762)2021 Total $510,017 $71,756 $581,773 $563,280 $131,577 $694,857 $53,263 $59,821 $113,08421



MDDQ

Present Rates Present Revenue ECOS Allocated Costs Present Revenue and ECOS Differences


Page 11 of 19


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N)



2223 ------- Cost to Rate Reconciliation -------24 Present Cost of Service Moderated24 Total Revenue $581,773 $694,857 $627,10825 Less: Property Tax 71,756 131,577 132,81526 Production Costs (excl. Prop Tax) 4,291 227,783 296,04627 Amt Req'd from Base Charges excl. Prod $505,726 $335,497 $198,2472728 Property Taxes per COS, Production per Revenue Requirement, Service Charge COS Moderated29 Rate Development: Moderated Revenue Moderated Base Rate Change Moderated Prop Tax Change Moderated Total Change Unit Rates29 Monthly Service Charge per Meter ECOS Base Rev Property Tax Total Increase ($) Increase (%) Increase ($) Increase (%) Increase ($) Increase (%) Base Rev Property Tax Total 30 10,001 to 30,000 $2,358 $1,393 $0 $1,393 $174 14.2% $0 N/A $174 14.2% $116.11 $0.00 $116.1131 > 30,000 * 18,240 10,778 0 10,778 1,342 14.2% 0 N/A 1,342 14.2% $299.39 $0.00 $299.3931 Sub-total $20,598 $12,171 $0 $12,171 $1,516 14.2% $0 N/A $1,516 14.2% $415.50 $0.00 $253.573233 Transmission Charges:33 Reservation Rate (MDDQ) $259,068 $153,084 $107,404 $260,488 ($10,298) -6.3% $62,911 141.4% $52,613 25.3% $4.64 $3.25 $7.8934 Transm Commodity Rate (Therm) 21,879 12,929 9,071 21,999 (870) -6.3% 5,313 141.4% 4,443 25.3% $0.0055274 $0.0038780 $0.009405435 Sub-total $280,947 $166,013 $116,475 $282,488 ($11,168) -6.3% $68,224 141.4% $57,056 25.3% $0.070976 $0.049797 $0.1207723536 Storage Charges:37 Reservation Rate (MDDQ) $32,441 $19,169 $10,481 $29,651 ($52,295) -73.2% ($7,877) -42.9% ($60,172) -67.0% $1.06 $0.58 $1.6337 Storage Commodity Rate (Therm) 1,512 893 488 1,382 (2,437) -73.2% (367) -42.9% (2,804) -67.0% $0.0003819 $0.0002088 $0.000590838 Sub-total $33,952 $20,063 $10,970 $31,032 ($54,733) -73.2% ($8,244) -42.9% ($62,977) -67.0% $0.008577 $0.004690 $0.0132673939 Production Charges:40 Production Commodity Rate (Therm) $227,783 $296,046 $5,371 $301,416 48,660 N/A 1,079 25.2% $49,739 19.8% 0.126569 0.002296 $0.1288654142 Total $563,280 $494,292 $132,815 $627,108 ($15,725) -3.08% $61,059 85.09% $45,334 7.79% $0.211326 $0.056783 $0.26810843


Page 12 of 19


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N)



4445 Proposed Rates: Proposed Rates Proposed Revenue Proposed Revenue Change ($) Proposed Revenue Change (%)46 Monthly Service Charge per Meter Base Revenue Property Tax Total Base Revenue Property Tax Total Base Revenue Property Tax Total Base Revenue Property Tax Total 47 10,001 to 30,000 $149.05 $0.00 $149.05 $1,789 $0 $1,789 $569 $0 $569 46.63% N/A 46.63%48 > 30,000 * $384.40 $0.00 $384.40 13,838 0 13,838 $4,403 $0 $4,403 46.66% N/A 46.66%49 Sub-total $325.56 $0.00 $325.56 $15,627 $0 $15,627 $4,972 $0 $4,972 46.66% N/A 46.66%5051 Transmission Charges:52 Reservation Rate (MDDQ) 4.6426789$ 3.1596852$ 7.8023642$ $153,264 $104,308 $257,572 -$10,118 $59,814 $49,696 -6.19% 134.43% 23.91%53 Transm Commodity Rate (Therm) 0.0055339$ 0.0037662$ 0.0093001$ 12,944 8,809 21,753 -$855 $5,051 $4,197 -6.19% 134.42% 23.91%54 Sub-total $166,208 $113,117 $279,325 -$10,973 $64,865 $53,893 -6.19% 134.43% 23.91%5556 Storage Charges:57 Reservation Rate (MDDQ) 1.0570495$ 0.5606501$ 1.6176997$ $19,192 $10,179 $29,371 -$52,273 -$8,179 -$60,452 -73.15% -44.55% -67.30%58 Storage Commodity Rate (Therm) 0.0003824$ 0.0002028$ 0.0005852$ 894 474 1,369 -$2,436 -$381 -$2,817 -73.15% -44.56% -67.30%59 Sub-total $20,086 $10,654 $30,740 -$54,709 -$8,560 -$63,269 -73.15% -44.55% -67.30%6061 Production Charges:62 Production Commodity Rate (Therm) $0.126569 $0.002296 $0.1288649 $296,046 $5,371 $301,416 $48,660 $1,079 $49,739 19.67% 25.15% 19.76%6364 Total $0.132485 $0.006265 $0.1387502 $497,967 $129,141 $627,108 ($12,050) $57,385 $45,334 -2.36% 79.97% 7.79%656667686970


Page 13 of 19

5/25/2017 8:12 AM 14 of 19 NG Stmt M 2015 Rev rebuttal final DBU Transp

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L)

Line Average Sales Present Allocated Allocated Allocated Moderated Moderated ModeratedNo. Function Customers Transmission Distribution (Therms) Revenues Costs $ Increase % Increase Revenues $ Increase % Increase

1 Revenue and Billing Information:2 DBU - Firm Distribution 2,408,640$ $3,138,126 $729,485 30.29% $2,644,856 $236,216 9.81%3 Reservation 256,833 4567 < 5000 48 8 5000 to 10000 101 9 10001 to 30000 * 56

10 > 30000 19 11 Total 224 1213 Interruptible Transportation - DBU Commodity 1,353,600 34,448$ $0 $37,828 $3,379 9.81%1415 Tot Firm & Interruptible DBU Trans 1,353,600 2,443,089$ $3,138,126 $2,682,684 $239,595 9.81%161718 Rate Development: Present Rates Present Revenue Costs of Service COS Unit Costs per Month and per MDDQ19 Monthly Service Charge per Meter Base Property Tax Base Property Tax Total Base Property Tax Total Base Property Tax Total20 < 5000 $97.35 $56,076 $0 $56,076 $88,637 $0 $88,637 $153.88 $0.00 $153.8821 5000 to 10000 $111.25 135,175 0 135,175 213,666 0 213,666 $175.86 $0.00 $175.8622 10001 to 30000 * $152.90 103,054 0 103,054 162,894 0 162,894 $241.68 $0.00 $241.6823 > 30000 $177.55 40,482 0 40,482 63,989 0 63,989 $280.65 $0.00 $280.6524 Total $334,786 $0 $334,786 $529,185 $0 $529,18525 Average $124.32 $0.00 $124.32 $196.50 $0.00 $196.502627 Present Distribution Charges and Costs28 Reservation Rate (MDDQ) $6.1580650 $1.9166532 $1,581,594 $492,260 $2,073,854 $1,841,614 $767,327 $2,608,941 $7.17 $2.99 $10.1629 Average $6.1581 $1.9167 $8.0747 $7.1705 $2.9876 $10.15813031 Total Firm 1,916,381$ 492,260$ 2,408,640$ 2,370,799$ 767,327$ 3,138,126$ 3233 Interruptible Transportation - DBU Comm $0.0202481 $0.0052014 $27,408 $7,041 $34,448 $0 $0 $0 $0.000000 $0.000000 $0.0000003435 Total $1,943,788 $499,300 $2,443,089 $2,370,799 $767,327 $3,138,12636


Non Core DBU Firm and InterruptibleTransportation

MDDQ


Page 14 of 19

5/25/2017 8:12 AM 15 of 19 NG Stmt M 2015 Rev rebuttal final DBU Transp

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L)


Non Core DBU Firm and InterruptibleTransportation

37 Property Taxes per COS, Service Charge COS Moderated38 Proposed Rate Development: Moderated Revenue Moderated Rates Proposed Rates39 Facilities Charge Base Property Tax Total Base/Month Property Tax Total Base Property Tax Total40 < 5000 $70,484 $0 $70,484 $122.37 $0.00 $122.37 $125.60 $0.00 $125.6041 5000 to 10000 169,907 $0 169,907 139.84 0.00 139.84 $143.55 0.00 143.5542 10001 to 30000 * 129,533 $0 129,533 192.19 0.00 192.19 $197.30 0.00 197.3043 > 30000 50,884 $0 50,884 223.17 0.00 223.17 $229.10 0.00 229.1044 Total / Average $420,808 $0 $420,808 $156.26 $0.00 $156.264546 Proposed Distribution Charges and Costs47 Reservation Rate (MDDQ) $1,464,452 $759,595 $2,224,048 $5.701963 $2.957545 $8.659509 $5.683701 $2.932334 $8.6160354849 Total Firm 1,885,261$ 759,595$ 2,644,856$ 5051 Interruptible Transportation - DBU $30,097 $7,731 $37,828 $0.022234 $0.005712 $0.027946 $0.022234 $0.005712 $0.0279465253 Total $1,915,357 $767,327 $2,682,684545556 Proposed Rate Development: Proposed Revenue Proposed Revenue Increase ($) Proposed Revenue Increase (%)57 Facilities Charge Base Property Tax Total Base Property Tax Total Base Property Tax Total58 < 5000 $72,346 $0 $72,346 $16,270 $0 $16,270 29.01% N/A 29.01%59 5000 to 10000 174,413 0 174,413 39,238 0 39,238 29.03% N/A 29.03%60 10001 to 30000 * 132,980 0 132,980 29,926 0 29,926 29.04% N/A 29.04%61 > 30000 52,235 0 52,235 11,753 0 11,753 29.03% N/A 29.03%62 Total / Average $431,974 $0 $431,974 $97,188 $0 $97,188 29.03% N/A 29.03%6364 Proposed Distribution Charges and Costs65 Reservation Rate (MDDQ) $1,459,762 $753,120 $2,212,882 -$121,832 $260,860 $139,028 -7.70% 52.99% 6.70%6667 Total Firm 1,891,736$ 753,120$ 2,644,856$ (24,645)$ 260,860$ 236,216$ -1.29% 52.99% 9.81%6869 Interruptible Transportation - DBU Comm $30,097 $7,731 $37,828 $2,689 $691 $3,379 9.81% 9.81% 9.81%7071 Total $1,921,832 $760,851 $2,682,684 -$21,956 $261,551 $239,595 -1.15% 52.38% 9.81%727374757677


Page 15 of 19

5/25/2017 8:12 AM 16 of 19 NG Stmt M 2015 Rev rebuttal final TBU Transp

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L)

Line Average Sales Present Allocated Allocated Allocated Moderated Moderated ModeratedNo. Function Customers Transmission Distribution Therms Revenues Costs $ Increase % Increase Costs $ Increase % Increase

1 Revenue and Billing Information:2 TBU - Firm Transportation 13,006,109$ $14,272,008 $1,265,900 9.73% $13,937,248 $931,140 7.16%3 Reservation 1,179,639 164,814,780 4 Tenaska/Jetco Contract 35,000 10,250,000 5 1,214,639 175,064,780 6 Meter Sizes - TBU Firm7 5,001 to 10,000 2 8 10,001 to 30,000 6 9 > 30,000 * 24 10 Total 32 1112 TBU - Interruptible Transportation 61,707,010 2,442,349$ $0 $2,617,222 $174,872 7.16%1314 Total Firm & Interruptible TBU Trans 236,771,790 15,448,458$ 14,272,008$ $16,554,470 $1,106,012 7.16%151617 Rate Development: COS Unit Costs per Month and per MDDQ18 Monthly Service Charge per Meter Base Property Tax Base Property Tax Total Base Property Tax Total Base Property Tax Total19 5,001 to 10,000 $95.25 $2,286 $0 $2,286 $3,745 $0 $3,745 $156.04 $0.00 $156.0420 10,001 to 30,000 $136.90 9,857 0 9,857 $16,149 0 16,149 $224.29 $0.00 $224.2921 > 30,000 * $303.75 86,873 0 86,873 $142,321 0 142,321 $497.63 $0.00 $497.6322 Total $99,016 $0 $99,016 $162,214 $0 $162,21423 Average $259.20 $0.00 $259.20 $567.18 $0.00 $567.182425 Firm Transmission Charges:26 Reservation Rate (MDDQ) $7.7848230 $2.0193012 $9,183,281 $2,382,046 $11,565,327 $8,995,094 $3,618,193 $12,613,288 $7.63 $3.07 $10.6927 Tenaska/Jetco Reserv Chrg (MDDQ) $2.02 $0.00 70,710 0 70,710 69,261 $27,859 97,120 $1.98 $0.80 $2.7728 Commodity Rate (Therm) $0.0058992 $0.0015303 972,275 252,213 1,224,489 952,351 $383,074 1,335,426 $0.0057783 $0.0023243 $0.008102629 Tenaska/Jetco Comm Rate (Therm) $0.0045431 $0.0000000 46,567 0 46,567 45,613 $18,347 63,960 $0.0044500 $0.0017900 $0.006240030 Sub-Total Firm Trans. Excl. Service Charge $10,272,833 $2,634,260 $12,907,093 $10,062,319 $4,047,475 $14,109,7943132 Total Firm $10,371,849 $2,634,260 $13,006,109 $10,224,534 $4,047,475 $14,272,0083334 Interruptible Transportation Charges:35 Commodity Rate (Therm) $0.0314903 $0.0080894 $1,943,174 $499,175 $2,442,349 $0 $0 $0 $0.0000000 $0.0000000 $0.0000000363738 Total TBU - Non-Core Transportation $12,315,023 $3,133,435 $15,448,458 $10,224,534 $4,047,475 $14,272,00839


Non Core TBU Firm and Interruptible Transportation

MDDQ

Present Rates Present Revenue Costs of Service


Page 16 of 19


(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L)



40 Property Taxes per COS, Service Charge COS Moderated41 Proposed Rate Development: Moderated Revenue Moderated Rates Proposed Rates42 Monthly Service Charge per Meter Base Property Tax Total Base/Month Property Tax Total Base Property Tax Total43 5,001 to 10,000 $3,818 $0 $3,818 $159.10 $0.00 $159.10 $125.65 $0.00 $125.6544 10,001 to 30,000 16,465 0 16,465 $228.68 $0.00 $228.68 $180.60 $0.00 $180.6045 > 30,000 * 145,107 0 145,107 $507.37 $0.00 $507.37 $400.70 $0.00 $400.7046 Total / Average $165,390 $0 $165,390 $341.93 $0.00 $432.964748 Firm Transmission Charges:49 Reservation Rate (MDDQ) $9,171,183 $3,140,011 $12,311,194 $7.77 $2.66 $10.44 $7.45 $3.01 $10.4650 Tenaska/Jetco Reserv Chrg (MDDQ) 70,617 24,178 94,794 $2.02 $0.69 $2.71 $1.93 $0.78 $2.7251 Commodity Rate (Therm) 970,994 332,447 1,303,442 $0.0058914 $0.0020171 $0.0079085 $0.0056473 $0.0022812 $0.007928552 Tenaska/Jetco Comm Rate (Therm) 46,506 15,923 62,428 $0.0045372 $0.0015534 $0.0060906 $0.0043491 $0.0017568 $0.006105953 Sub-Total Firm Trans. Excl. Service Charge $10,259,300 $3,512,559 $13,771,8585455 Total Firm $10,424,690 $3,512,559 $13,937,2485657 Interruptible Transportation - TBU58 Commodity Rate (Therm) $2,082,306 $534,916 $2,617,222 $0.0337450 $0.0086686 $0.0424137 $0.0337450 $0.0086686 $0.04241375960 Total $12,506,995 $4,047,475 $16,554,47061


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(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L)



6263 Proposed Rate Development: Proposed Revenue Proposed Increase ($) Proposed Increase (%)64 Monthly Service Charge per Meter Base Property Tax Total Base Property Tax Total Base Property Tax Total65 5,001 to 10,000 $3,016 $0 $3,016 $730 $0 $730 31.92% N/A 31.92%66 10,001 to 30,000 13,003 0 13,003 3,146 0 3,146 31.92% N/A 31.92%67 > 30,000 114,600 0 114,600 27,727 0 27,727 31.92% N/A 31.92%68 Total / Average $130,619 $0 $130,619 $31,603 $0 $31,603 31.92% N/A 31.92%6970 Firm Transmission Charges:71 Reservation Rate (MDDQ) $8,791,072 $3,551,206 $12,342,277 ($392,209) $1,169,159 $776,950 -4.27% 49.08% 6.72%72 Tenaska/Jetco Reserv Chrg (MDDQ) 67,690 27,344 95,033 (3,020) 27,344 24,324 -4.27% 0.00% 34.40%73 Commodity Rate (Therm) 930,750 375,982 1,306,733 (41,525) 123,769 82,244 -4.27% 49.07% 6.72%74 Tenaska/Jetco Comm Rate (Therm) 44,578 18,008 62,586 (1,989) 18,008 16,019 -4.27% 0.00% 34.40%75 Sub-Total Firm Trans. Excl. Service Charge $9,834,090 $3,972,539 $13,806,629 ($438,743) $1,338,279 $899,537 -4.27% 50.80% 6.97%7677 Total Firm $9,964,709 $3,972,539 $13,937,248 ($407,140) $1,338,279 $931,140 -3.93% 50.80% 7.16%7879 Interruptible Transportation - TBU80 Commodity Rate (Therm) 2,082,306 534,916 2,617,222 $139,131 $35,741 $174,872 7.16% 7.16% 7.16%8182 Total $12,047,015 $4,507,455 $16,554,470 ($268,008) $1,374,020 $1,106,012 -2.18% 0.00% 7.16%838485868788


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5/25/2017 8:12 AM 19 of 19 NG Stmt M 2015 Rev rebuttal final Storage

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N) (O) (P)

Therms Therms Therms Allocated Allocated Moderated ModeratedLine Function MDDQ Capacity Injection Withdrawal Base Property Tax Total Base Property Tax Total $ Increase % Increase Costs % Increase

1 Revenue and Billing Information:2 Storage $2,798,334 $722,085 $3,520,419 $2,394,458 $773,635 $3,168,093 -$352,326 -10.01% $3,727,113 5.87%3 Reservation 548,885 347,748,510 32,006,830 32,459,880 45 Property Taxes per COS67 Rate Development: Base Property Tax Base Property Tax Total Base Property Tax Total Base Property Tax Total Base Property Tax Base Property Tax89 Reservation Charges:

10 Reservation Rate (MDDQ) $3.716631 $0.959011 $2,040,004 $526,387 $2,566,392 $2,153,106 $563,985 $2,717,091 5.54% 7.14% 5.87% $3.922687 $1.027510 $3.941710 $1.0084861112 Capacity Charges:13 Commodity Rate (Therm) $0.001825 $0.000471 634,502 $163,755 798,257 669,680 $175,416 845,096 5.54% 7.12% 5.87% $0.001926 $0.000504 $0.001935 $0.0004951415 Injection Charges:16 Commodity Rate (Therm) $0.001921 $0.000496 61,479 $15,859 77,338 64,887 $16,997 81,884 5.54% 7.17% 5.88% $0.002027 $0.000531 $0.002037 $0.0005211718 Withdrawal Charges:19 Commodity Rate (Therm) $0.001921 $0.000496 62,349 $16,084 78,433 65,806 $17,237 83,043 5.54% 7.17% 5.88% $0.002027 $0.000531 $0.002037 $0.0005212021 Total $2,798,334 $722,085 $3,520,419 $2,953,478 $773,635 $3,727,113 5.54% 7.14% 5.87%22232425 Rate Development: Base Property Tax Total Base Property Tax Total Base Property Tax Total2627 Reservation Charges:28 Reservation Rate (MDDQ) $2,163,547 $553,543 $2,717,091 123,543 $27,156 $150,699 6.06% 5.16% 5.87%2930 Capacity Charges:31 Commodity Rate (Therm) 672,927 172,168 845,096 38,425 8,414 46,839 6.06% 5.14% 5.87%3233 Injection Charges:34 Commodity Rate (Therm) 65,202 16,682 81,884 3,723 823 4,546 6.06% 5.19% 5.88%3536 Withdrawal Charges:37 Commodity Rate (Therm) 66,125 16,918 83,043 3,776 834 4,610 6.06% 5.19% 5.88%3839 Total $2,967,801 $759,312 $3,727,113 169,467 $37,227 $206,694 6.06% 5.16% 5.87%

Proposed RatesModerated RatesModerated % Increase

Proposed Revenue Proposed Rate Change ($) Proposed Rate Change (%)

Present Rates Present Revenue Moderated Revenue


Storage

Present Rates Allocated


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