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Duncan, Weinberg, Genzer & Pembroke, P.C.

WALLACE L. DUNCAN (1937-2008)EDWARD WEINBERG (1918-1995)ROBERT WEINBERGJEFFREY C. GENZERTHOMAS L. RUDEBUSCHMICHAEL R. POSTARELI D. EILBOTT*LISA S. GASTPETER J. SCANLONKATHLEEN L. MAZUREDEREK A. DYSONBHAVEETA K. MODYKRISTEN CONNOLLY McCULLOUGHSETH T. LUCIAJOSHUA E. ADRIANMATTHEW R. RUDOLPHIJASON T. GRAYNATALIE M. KARASGREGORY D. JONES**

_____

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JAMES D. PEMBROKE+

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+OF COUNSEL

VIA ELECTRONIC FILINGHonorable Kimberly D. Bose, SecretaryFederal Energy Regulatory Commission888 First Street, N.E., Room 1-AWashington, DC 20426

Re: New York Association of Public Power v. Niagara Mohawk PowerCorporation d/b/a National Grid, Docket No. EL12-_____-000

Dear Secretary Bose:

Pursuant to section 206 of the Federal Power Act (“FPA”)1 and Rule 206 of theRules of Practice and Procedure of the Federal Energy RegulatoryCommission (“Commission”),2 the New York Association of Public Power (“NYAPP” or“Complainant”) hereby files a complaint (“Complaint”) against Niagara Mohawk PowerCorporation d/b/a National Grid (“NMPC”) seeking an order to reduce the 11.5 percent return onequity (“ROE”) used in calculating rates for transmission service under the New YorkIndependent System Operator, Inc.’s (“NYISO”) Open Access Transmission Tariff (“OATT”) toa just and reasonable level at 9.49 percent, inclusive of a 50 basis point adder for participation inthe NYISO, with a corresponding overall weighted cost of capital of 6.73 percent.

Please find the following materials attached hereto:

1 16 U.S.C. §§ 824e and 825e.

2 18 C.F.R. § 385.206 (2010).

20120911-5105 FERC PDF (Unofficial) 9/11/2012 4:45:31 PM

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Complaint

Exhibit No. NYP-1 Testimony of Jonathan A. Lesser

Exhibit No. NYP-2 Curriculum Vitae of Jonathan A. Lesser

Exhibit No. NYP-3 List of Previous Commission Testimony

Exhibit No. NYP-4 Pages 245-247 from Principles of Utility CorporateFinance

Exhibit No. NYP-5 National Grid plc, “Results for the year ended 31 March2012”

Exhibit No. NYP-6, Sch. 1 Utility Proxy Group Screening

Exhibit No. NYP-6, Sch. 2 “Sustainable” Earnings Growth Estimates

Exhibit No. NYP-6, Sch. 3 I/B/E/S Earnings Growth Estimates

Exhibit No. NYP-6, Sch. 4 Avg. Monthly High-Low Stock Prices and DividendYields

Exhibit No. NYP-6, Sch. 5 DCF Analysis Results

Exhibit No. NYP-7 Pages 188-190 from Principles of Utility Corporate Finance

Exhibit No. NYP-8, Sch. 1 Attachment 1, Schedule 8 from NMPC OATTFiling of June 14, 2012, as filed

Exhibit No. NYP-8, Sch. 2 Attachment 1, Schedule 8 from NMPC OATTFiling of June 14, 2012, as adjusted

Exhibit No. NYP-9 Service List

Exhibit No. NYP-10 Form of Notice

Should you have any questions or concerns, please do not hesitate to contact me.

Respectfully Submitted/s/ Thomas L. RudebuschThomas L. RudebuschMatthew R. RudolphiDuncan, Weinberg, Genzer& Pembroke, P.C.

1615 M. Street, NW, Suite 800Washington, DC 20036(202) [email protected]@dwgp.com

Attorneys for New York AssociationOf Public Power

cc: service list


UNITED STATES OF AMERICABEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

New York Association of Public Power, ))

Complainant, ))

v. ) Docket No. EL12-_____-000)

Niagara Mohawk Power Corporation )d/b/a National Grid, and )

)The New York Independent System )Operator, Inc. )

)Respondents. )

(filed September ___, 2012)

COMPLAINT OF THE NEW YORK ASSOCIATION OF PUBLIC POWERCHALLENGING BASE RETURN ON EQUITY

Pursuant to section 206 of the Federal Power Act (“FPA”)1 and Rule 206 of the

Rules of Practice and Procedure of the Federal Energy Regulatory Commission (“Commission”

or “FERC”),2 the New York Association of Public Power (“NYAPP” or “Complainant”) hereby

files this complaint against Niagara Mohawk Power Corporation d/b/a National Grid (“NMPC”)

seeking an order to reduce the 11.5 percent return on common equity (“ROE”) used in

calculating rates for transmission service under the New York Independent System Operator, Inc.

(“NYISO”) Open Access Transmission Tariff (“OATT”) to a just and reasonable level at 9.49

percent, inclusive of a 50 basis point adder for participation in the NYISO, with a corresponding

overall weighted cost of capital (“WACC”) of 6.73 percent.

1 16 U.S.C. § 824e

2 18 C.F.R. § 385.206 (2010).


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As discussed below, the NMPC ROE currently reflected in the NYISO OATT

rate is unjust and unreasonable. The Complainant requests that the Commission: (1) institute

paper hearing procedures to investigate the ROE and establish a just and reasonable equity return

to be reflected in rates for transmission service provided over facilities owned by NMPC under

the NYISO OATT; (2) establish the earliest possible refund effective date (i.e., the date of this

Complaint), consistent with Commission policy; and (3) direct NMPC to make refunds reflecting

the difference between transmission rates reflecting an 11.5 percent ROE and rates reflecting a

just and reasonable ROE.

I. COMMUNICATIONS

All correspondence and communications to the Complainant in this docket should

be addressed to the following individuals, whose names should be entered on the official service

list maintained by the Secretary in connection with these proceedings:

Paul J. Pallas, President [email protected] York Association of Public PowerP.O. Box 950Rockville Centre,New York 11571-0950(516) 678-9305

Thomas L. Rudebusch, Esq. [email protected], Weinberg, Genzer& Pembroke, P.C.

1615 M Street, N.W.Suite 800Washington, D.C. 20036(202) 467-6370


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II. THE PARTIES

A. Complainant

1. NYAPP is an unincorporated association of nine municipal electric utilities and

four rural electric cooperatives located throughout New York State, serving approximately 500

MW of load. NYAPP was founded in 2005 in response to emerging opportunities and

challenges on both the national and state levels in the electric utility industry. NYAPP’s

Members are “Load Serving Entities” as defined in the Commission’s Regulations, 18 C.F.R. §

41.2(b)(2) and in Section 217(a)(2) of the Federal Power Act. Several NYAPP Members are

located on transmission facilities owned by NMPC, including: Green Island Power Authority,

Jamestown Board of Public Utilities, Salamanca Board of Public Utilities, Oneida-Madison

Electric Cooperative, Inc. and City of Sherrill Power & Light. These NYAPP Members pay the

NMPC Wholesale Transmission Service Charge (“TSC”) under the NYISO OATT.

B. Respondents

2. NMPC is a New York combination gas and electric utility company, primarily

engaged in the business of transmission and distribution of electricity as well as the distribution

and transportation of natural gas in New York. NMPC is the wholly-owned principal utility

subsidiary of Niagara Mohawk Holdings, Inc., which in turn is wholly-owned by National Grid

USA (“National Grid”). National Grid is an indirect, wholly-owned subsidiary of National Grid

plc, a company incorporated in England and Wales.3 The United States business of National

Grid plc is conducted through National Grid. NMPC’s physical assets include over 6,000 miles

of transmission lines. All of NMPC’s bulk electric transmission facilities are subject to the

3 Through various subsidiaries and investments, National Grid plc is engaged in utility and non-utility operationsprincipally in the United States and the United Kingdom. National Grid plc is not a public utility under the FPAbecause it does not directly own or operate FPA-jurisdictional facilities (or any other electric facilities), nordoes it directly engage in the sale, transmission, or distribution of electric power in the U.S.


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operational control of the NYISO. As such, NMPC recovers its transmission revenue

requirement pursuant to provisions of the NYISO OATT. Under the NYISO OATT, NYISO

Transmission Owners, including NMPC, retain the authority to make FERC filings to revise their

individual company revenue requirements.4 NMPC calculates its TSC on a monthly basis and

bills transmission service customers in accordance with the NYISO OATT. Accordingly, NMPC

is the real party in interest for purposes of this Complaint.5

3. The NYISO is a non-profit company that serves as the independent system

operator for the state of New York. NYISO administers the New York energy markets and

operates the New York bulk power system pursuant to the NYISO Market Administration and

Control Area Services Tariff and the NYISO OATT. The NYISO is deemed to provide all

transmission service in the New York Control Area. NMPC collects its TSC from transmission

service customers under the terms of the NYISO OATT. NYAPP has named the NYISO as a

respondent only because NMPC’s ROE is a stated value in the NYISO OATT,6 and any change

in the stated ROE would required a tariff revision filing by the NYISO.

4 See NYISO OATT, Attachment H, “Annual Transmission Revenue Requirement for Point-to-PointTransmission and Network Integration Transmission Service,” Section 14.1.2.1.2.

5 See, e.g., NSTAR Elec. & Gas Corp. v. FERC, 481 F.3d 794, 803-804 (D.C. Cir. 2007); NRG Power Marketing,Inc. v. New York Ind. Sys. Operation, Inc., 91 FERC ¶ 61,346 at p. 62,165 (2000).

6 See NYISO OATT, Attachment H-1, Schedule 8, line nos. 10 and 19.


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III. INTRODUCTION

4. NMPC recovers its annual transmission revenue requirement through the NMPC

TSC included in the NYISO OATT. The TSC is calculated using a formula rate contained in the

NYISO OATT.7 By June 14th of each year, NMPC recalculates the components that determine

its annual transmission revenue requirement by applying the data inputs called for in the formula

rate. This annual update is posted on the NYISO website and NMPC files it as an informational

filing with the Commission. Certain components of the formula, including the authorized ROE,

are stated values that can only be changed by the Commission pursuant to Section 205 or 206 of

the Federal Power Act.8

5. NMPC’s current ROE is 11.5 percent, inclusive of NMPC’s participation in the

NYISO, a figure which was established by settlement in Docket No. ER08-552 and accepted by

the Commission on June 22, 2009.9 This Complaint only challenges the ROE and does not

address any incentive adders applicable to NMPC’s rates, including the 50 basis point adder for

NMPC’s participation in the NYISO.

6. Due to changes in the capital markets since the NMPC Formula Rate Settlement,

the 11.5 percent ROE is no longer just and reasonable. The attached testimony and exhibits of

Jonathan A. Lesser, PhD, demonstrates that the current ROE is excessive and that a just and

reasonable ROE for NMPC under current market conditions does not exceed 9.49 percent,

inclusive of the 50 basis point adder for participation in the NYISO.

7. Based on this evidence, this Complaint provides sufficient evidence to

demonstrate that the existing ROE is unjust and unreasonable. The Commission should institute

7 See NYISO OATT, Attachment H, Section 14.1.9.

8 See NYISO OATT, Attachment H, Section 14.1.9.3.

9 See Niagara Mohawk Power Corp., 127 FERC ¶ 61,289 (2009) (“TSC Formula Rate Order”).


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an investigation into this matter and find that the ROE proposed by the Complainant is just and

reasonable. This investigation should utilize a paper hearing process. The Commission

routinely decides complex and controversial cases on the basis of the record in a paper hearing,

including determination of an appropriate ROE for providing transmission service.10

IV. BACKGROUND

8. On February 11, 2008, as supplemented on May 30, 2008, NMPC submitted a

filing under Section 205 of the Federal Power Act to replace its stated rates for its TSC with

formula rates to become effective May 1, 2008. On July 29, 2008, the Commission accepted and

suspended the proposed formula rates, to become effective October 1, 2008, subject to refund,

and established hearing and settlement judge procedures.11

9. On April 6, 2009, NMPC, on behalf of the Settling Parties,12 filed the Settlement

intending to resolve all issues set for hearing in that proceeding. Among other things, the

Settlement set forth the terms of a formula rate for the calculation of NMPC’s transmission

service charge under the NYISO OATT (the “Settlement TSC Formula Rate”), as well as

procedures for the annual adjustment of certain data inputs to the formula rate. On April 8, 2009,

the Commission’s Chief Administrative Law Judge granted NMPC’s motion for interim rate

relief and allowed the Settlement TSC to be implemented on an interim basis effective as of

January 1, 2009 (“Settlement Effective Date”) pending approval by the Commission. In a letter

10 See, e.g., Southern Cal. Edison Co., 131 FERC ¶ 61,020 (2010); Northern Natural Gas Co., 125 FERC ¶ 61,127at P 13 (2008); Nevada Power Co. and Sierra Pacific Power Co. v. Enron Power Marketing, Inc., 125 FERC ¶61,312 at P 29, n.67 (2008); and Southern Cal. Edison Co., 92 FERC ¶ 61,070 (2000).

11 Niagara Mohawk Power Corp., Order Accepting and Suspending Formula Rate Subject to Refund andEstablishing Hearing and Settlement Judge Procedures, 124 FERC ¶ 61,106 (2008)(“July 29 Order”). CertainSettling Parties requested rehearing of aspects of the July 29 Order. On February 25, 2009, the Commissionissued an Order that denied rehearing in part and granted rehearing in part. 126 FERC ¶ 61,173 (2009).

12 The signatories consist of NMPC, NYAPP and the following entities: Allegheny Electric Cooperative, Inc., theCity of Cleveland, Ohio, Multiple Intervenors, Municipal Electric Utilities Association of New York State, NewYork Municipal Power Agency, New York State Electric & Gas Corporation, and Rochester Gas & ElectricCorporation (“Settling Parties”).


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order issued June 22, 2009, the Commission issued the TSC Formula Rate Order, approving the

Settlement and on July 24, 2009, NMPC issued required refunds to customers.

10. In accordance with the NYISO OATT, NMPC is directed to calculate each year

new values for its transmission Revenue Requirements (“RR”), control center costs (“CCC”) and

billing units (“BU”) components of the Settlement TSC Formula Rate based on updated Data

Inputs. NMPC is further directed to prepare an Annual Update that reflects the revised Data

Inputs, the resulting RR, CCC, and BU components, and certain supporting information.

According to Section 14.1.9.4 in Attachment H to the NYISO OATT, NMPC’s ROE is a stated

rate of 11.5 percent inclusive of a 50 basis point adder for NMPC’s participation in the NYISO.

This Complaint challenges NMPC’s state ROE and is not a part of the Annual Update review

process.

V. DISCUSSION

A. Applicable Standards

11. All rates for jurisdictional service under the FPA must be just and reasonable.13

Where a complainant challenges a previously-approved rate under section 206 of the FPA and

proposes a new one, the Commission has stated that complainants must satisfy a two-part burden

of proof by showing that: (1) the existing rate is unjust and unreasonable; and (2) a proposed

replacement rate is just and reasonable.14 This Complaint provides sufficient evidence both to

institute an investigation into the justness and reasonableness of the ROE and to find that the new

rate proposed in this Complaint is just and reasonable.

12. A just and reasonable rate of return for a utility is one that does not exceed the

level required to assure confidence in the financial integrity of the enterprise, so as to maintain

13 16 U.S.C. §§ 824d and 824e.

14 See, e.g., Louisiana Pub. Serv. Comm’n v. Entergy Corp., 132 FERC ¶ 61,003 at P 28 (2010).


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its credit and to attract capital, and must be commensurate with returns on investments in

enterprises with comparable risks.15 The Commission has a well developed policy for

establishing a just and reasonable ROE for transmission service, based on applying a discounted

cash flow (“DCF”) analysis to a proxy group of comparable risk companies.16 As described

below, the Complainant has applied the Commission’s well-established ROE methodology to

identify the appropriate ROE under current conditions for NMPC.

B. NYAPP’s ROE Analysis

13. In order to determine whether the current ROE of 11.5 percent remains just and

reasonable, Dr. Lesser performed a DCF analysis in compliance with the Commission’s current

policies.17 Dr. Lesser began his analysis by selecting a group of proxy companies with risk

profiles representative of the risks of NGPC. Pursuant to Commission precedent, Dr. Lesser

selected a national group of electric utilities that met the following criteria: (1) are covered by the

Value Line Investment Survey (“Value Line”); 2) neither announced a merger or acquisition

within the six-month analysis period nor were involved in an ongoing merger or acquisition

during that period; 3) have paid constant or increasing dividends for at least the past two years;

4) are covered by at least two generally recognized utility industry analysts, and which have

long-term (5-year) earnings growth forecasts reported by Institutional Brokers; 5) have annual

revenues of at least $1 billion; and 6) have an investment grade corporate credit rating within one

“notch” of NMPC, which is currently rated “A-” by Standard and Poor’s (i.e., utilities having

15 See Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944); Bluefield Water Works &Improvement Co. v. Public Serv. Comm’n, 262 U.S. 679, 692-93 (1923).

16 See, e.g., Northern Pass Transmission LLC, 134 FERC ¶ 61,095 (2011); Potomac Appalachian TransmissionHighline, L.L.C. (“PATH”), 133 FERC ¶ 61,152 (2010); Atlantic Path 15, LLC, 133 FERC ¶ 61,153 (2010);Southern Cal. Edison, 131 FERC ¶ 61,020 (2010); Golden Spread Elec. Coop., 123 FERC ¶ 61,047 (2008).

17 Exhibit No. NYP -1 at 13-23.


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credit ratings between “BBB+” and “A”).18 This yielded a proxy group of sixteen electric

utilities.19

14. Dr. Lesser began with the forty-nine electric utilities currently covered by Value

Line. From those, Dr. Lesser initially eliminated six because of their ongoing or recently

completed merger or acquisition activity: Central Vermont Public Service; Duke Energy;

Progress Energy; NStar; Northeast Utilities; and CH Energy Group. Dr. Lesser then eliminated

two utilities that lacked sufficient dividend history: El Paso Electric offered no dividends for

several years prior to that offered in June 2011 and Empire District Electric suspended its

dividend in the third quarter of 2011. As a next step Dr. Lesser eliminated three utilities with

2010 annual revenues of less than $1 billion. Finally, Dr. Lesser eliminated utilities with

corporate ratings more than one notch above or below NMPC, which includes those with credit

ratings of “A+” or above and utilities with credit ratings of “BBB” or below.

15. This left the following sixteen utilities, which make up the proxy group: Alliant

Energy, CenterPoint Energy, Consolidated Edison, Dominion Resources, DTE Energy, Integrys

Energy, NextEra, OGE Energy, Pepco Holdings, SCANA Corp., Sempra Energy, Southern

Company, TECO Energy, Vectren Corp., Wisconsin Energy, and Xcel Energy.

16. The selection of the proxy group is consistent with the Commission’s established

rules, and the selected proxy group utilities are comparable in risk to NMPC. Dr. Lesser derives

stockholders’ required rate of return for the proxy group using FERC’s one-stage DCF model.

Dr. Lesser calculated the sustainable earnings growth estimates for each of the proxy companies

using three steps. First Dr. Lesser used Value Line data to estimate the average earnings per

18 So. Cal. Edison Co., 131 FERC ¶ 61,020 (2010) (“So. Cal. Edison Co. I”) at P 51, reh’g denied, 137 FERC ¶61,016 (2011) (“So. Calif. Edison Co. II”).

19 Exhibit No. NYP-1 at 14.


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share, dividends per share, and book value per share to calculate the internal growth. Then Dr.

Lesser calculated the external growth by taking the average market value of each company’s

stock over the previous six months and dividing by the average book value. Finally Dr. Lesser

calculated the external growth by using the Value Line forecast of outstanding shares in the

2015-2017 time frame to determine the annual rate of share growth as well as the forecast change

in capital structure and total capitalization to reflect the growth adjustment factor.

17. Dr. Lesser relied on the I/B/E/S earnings growth rates as forecasted as of July 31,

2012, available from Thompson Reuters or Yahoo!Finance, since the six month period used to

determine dividend yields was February 1, 2012 through July 31, 2012. Dr. Lesser relied on the

adjusted daily closing stock prices as published by Yahoo!Finance to estimate the low and high

stock prices for each month and relied on the quarterly dividend payment data published by

Value Line for each of the proxy companies to estimate the high and low dividend yields.

18. In conformance with the methodology used in So. Cal. Edison Co. I for

determining the minimum threshold DCF value, Dr. Lesser calculated the average of the monthly

yields on BBB rated, long-term utility bonds for the six-month period from February 1, 2012

through July 31, 2012 as reported by Moody’s. The average yield on A rated bonds for this

period was 4.28% and the average yield on BBB rated bonds for this period was 5.01%. By

adding 100 basis points above the average, Dr. Lesser established a minimum threshold DCF

value of 5.28% for “A” and “A-” rate proxy group firms and 6.01% for “BBB+” rate proxy

group firms.

19. Dr. Lesser’s analysis shows the zone of reasonableness has a range between 6.38

percent and 10.75 percent. The current ROE of 11.5 percent is not within Dr. Lesser’s proxy

group zone of reasonableness under the Commission’s DCF model. The median average of the


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low and high values of the proxy group is 8.99 percent. Dr. Lesser explains that to establish a

median ROE, the Commission prefers to first determine the average of each proxy companies’

low and high DCF values and then calculate the median of the resulting range. Dr. Lesser also

has calculated the median of the larger sample of thirty-two values that includes the low and high

values for each company as 9.01 percent. Dr. Lesser explains that it is his opinion that this

median of the entire sample has greater statistical validity, but that the 2 bp difference in the

values, 8.99 percent vs. 9.01 percent, is de minimis. Dr. Lesser recommends an ROE value of

9.49% inclusive of the 50 basis point adder for membership in an ISO or RTO based on the

8.99% median calculation.

20. Dr. Lesser determined that the use of the median is appropriate because there is

no specific evidence that NMPC has a business and financial risk profile that differs significantly

from that of the firms in the proxy group.

C. The Current 11.5 Percent ROE under the NYISO Tariff Is Unjust AndUnreasonable

21. The DCF analysis performed by Dr. Lesser shows that as a result of significantly

changed economic circumstances since the ROE was established in the TSC Formula Rate

Order: (1) the current 11.5 percent ROE is unjust and unreasonable; and (2) the just and

reasonable ROE is 9.49 percent. Because the formula rates under the NYISO OATT are

intended to track the NMPC’s current costs, the revenues generated by this excessive fixed ROE

go straight to the NMPC’s bottom line at the expense of customers. Retaining the current ROE

would result in a substantial overpayment to NMPC by consumers relative to Dr. Lesser’s

recommended ROE.

22. Dr. Lesser has also calculated that the affect of using a 9.49% ROE on NMPC’s

overall WACC and the required before-tax investment return. Dr. Lesser relied on the NYISO


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tariff formula rate for calculating the cost of capital. The formula-based WACC is 7.73%. The

resulting value for the before-tax return is $136,652,963. Because the formula for capital

structure limits the percentage of common equity to no more than 50% of total capitalization and

NMPC has an actual amount of common equity of 61.33%, Dr. Lesser reduced the equity

capitalization percentage by 11.33% to reach the maximum of 50% and increased the long-term

debt percentage by 11.33% to 49.53% in accordance with the NYISO OATT.20 Dr. Lesser used

these capitalization percentages for common equity, long-term debt and preferred equity in

calculating the revised WACC value for NMPC. The resulting WACC for NMPC, using the

9.49% ROE and the formula-rate capitalization percentages and rates is an overall WACC of

6.73%. The impact of the 6.73% WACC Dr Lesser calculated on the before-tax investment

return results in a reduction of $19,080,537.

23. This represents a $19 million annual overpayment to NMPC by transmission

service customers. Such overpayments are unjust and unreasonable, because they are in excess

of what is

reasonably sufficient to assure confidence in the financialsoundness of the utility and should be adequate under efficient andeconomical management, to maintain and supports its credit, andenable it to raise the money necessary for the proper discharge ofits public duties.21

As the Supreme Court has made clear, not even “a little unlawfulness is permitted” in setting

jurisdictional rates.22 NYAPP respectfully submits that NMPC rates incorporating the existing

ROE are leading to far more than just “a little” overpayment.

20 See NYISO OATT, Attachment H-1, Schedule 8.

21 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 692 – 693 (1923).

22 FPC v. Texaco Inc., 417 U.S. 380 (1974).


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D. The Commission Should Institute an Investigation Regarding the NMPCROE through a Paper Hearing

24. The analysis performed by the Complainant, at a minimum, provides sufficient

information to show that the current NMPC ROE under the NYISO OATT is unjust and

unreasonable. Accordingly, the Commission should institute a proceeding under section 206 of

the FPA to investigate whether the ROE is excessive and to determine a just and reasonable

ROE.

25. The Complainant requests that the Commission conduct such investigation

through “paper hearing” procedures. The Commission routinely decides complex and

controversial cases on the basis of the record in a paper hearing when such a process is sufficient

to resolve all issues of material fact.23 Notably, the Commission has used paper hearings to

determine an appropriate ROE for transmission service,24 and even where the Commission has

established full evidentiary hearings on ROE issues, it has rejected arguments that establishing

an ROE always requires such trial-type procedures.25

26. In numerous recent decisions addressing ROEs for electric transmission

companies or projects, the Commission has clarified and refined its ROE policy to such a degree

that a trial-type evidentiary hearing is not necessary to address the issue. The Commission has

addressed issues such as whether given companies are appropriately included in the proxy group

based on a written record, that has not included either discovery or cross-examination. Likewise,

the Commission’s application of the DCF analysis is essentially mechanical and is (or should be)

based on public information that can be readily verified (or discredited) by the other paper

23 See, e.g., Northern Natural Gas Co., 125 FERC ¶ 61,127 at P 13 (2008); Nevada Power Co. and Sierra PacificPower Co. v. Enron Power Marketing, Inc., 125 FERC ¶ 61,312 at P 29, n.67 (2008).

24 See, e.g., Southern Cal. Edison Co., 131 FERC ¶ 61,020.

25 See PATH, 133 FERC ¶ 61,152 at P 54.


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hearing participants and the Commission.26 Here, a paper hearing would be sufficient for the

parties to develop the record on the appropriate ROE based on the Commission’s well-articulated

policies for calculating ROE. Importantly, a paper hearing would facilitate an earlier

Commission decision and expedite relief to customers who are currently paying transmission

rates reflecting an excessive ROE.

27. Alternatively, if the Commission is not inclined to grant relief on the basis of the

pleadings, NYISO asks that this matter be set for an evidentiary hearing.

E. The Commission Should Establish the Earliest Possible Refund EffectiveDate

28. In cases where the Commission institutes an investigation on a complaint under

section 206 of the FPA, section 206(b) requires the Commission to establish a refund effective

date that is no earlier than the date the complaint was filed, but no later than five months after the

filing date.27 The Commission’s general policy is to set the refund effective date at the earliest

possible date, i.e., the date a complaint is filed.28 Consistent with its general policy, the

Commission should establish the filing date of this Complaint as the refund effective date in its

investigation of the ROE in order to provide maximum protection to consumers.29

V. RULE 206 REQUIREMENTS

29. NYAPP hereby provides the further information required by Rule 206.30

26 See id. at P 55, n.83.

27 16 U.S.C. § 824e(b).

28 See, e.g., Old Dominion Electric Cooperative and North Carolina Electric Membership Corporation v. VirginiaElectric and Power Company, 133 FERC ¶ 61,009 at P 36 (2010) (citing Seminole Elec. Coop., Inc. v. Fla.Power & Light Co., 65 FERC ¶ 61,413, at p. 63,139 (1993); Canal Elec. Co., 46 FERC ¶ 61,153, at p. 61,539,reh'g denied, 47 FERC ¶ 61,275 (1989)).

29 See id.

30 18 C.F.R. § 385.206 (“Rule 206”).


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A. Good Faith Estimate of Financial Impact or Harm (Rule 206(b)(4)).

30. As described above and in Exhibit No. NYP-1, the Complainant estimates that

reducing the ROE from 11.5 percent to a just and reasonable level of 9.49 percent would reduce

transmission costs in New York by approximately $19 million annually.

B. Operational or Nonfinancial Impacts (Rule 206(b)(5))

31. The Complainant is not aware of any specific practical, operational or

nonfinancial impacts resulting from the excessive ROE.

C. Whether the Matters are Pending in Any Other FERC Proceeding or OtherForum (Rule 206(b)(6))

32. The matters raised in this Complaint are not currently pending in any other

Commission proceeding or in any other proceeding to which the Complainant is a party.

D. Documents Supporting the Complaint (Rule 206(b)(8))

33. In support of this Complaint, NYAPP has included the testimony, supporting

exhibits and workpapers of Jonathan A. Lesser, PhD, President of Continental Economics, Inc.31

E. Alternative Dispute Resolution (Rule 206(b)(9))

34. NYAPP submits that it is unlikely that alternative dispute resolution (“ADR”)

procedures under the Commission’s supervision would successfully resolve the issues raised in

the Complaint until after a complaint had been filed and FERC had established a refund effective

date. The Complainant is ready and willing to engage in ADR procedures for a limited time

frame after the refund effective date is established. While the Complainant hopes this matter can

be resolved through settlement, NYAPP is mindful that unproductive settlement discussions

could serve to delay the adjustment of the ROE to a just and reasonable level.

VI. SERVICE AND NOTICE

31 See Exhibit No. NYP-1.


- 16 -

35. In accordance with Rule 206(c), the Complainant has served a copy of this

Complaint upon each of the Respondents simultaneous with the filing of the Complaint. The

Complainant has also served copies of the Complaint upon the New York State Public Service

Commission.32

36. In addition, the Complainant has asked the NYISO to distribute the Complaint to

its e-mail distribution lists. Attached hereto as Exhibit NYP-10 is a Form of Notice suitable for

publication in the Federal Register in accordance with Rule 206(b)(10).

VII. CONCLUSION

Based on the foregoing, NYAPP requests the Commission to: (1) institute paper

hearing procedures to investigate the ROE used in calculating the transmission revenue

requirements for NMPC for service under the NYISO OATT and establish a just and reasonable

base return on equity; (2) establish the earliest possible refund effective date (i.e., the date of this

complaint), consistent with Commission policy; (3) direct NMPC to make refunds reflecting the

difference between transmission rates reflecting an 11.5 percent ROE and rates reflecting a just

and reasonable ROE, and (4) direct the NYISO to make a tariff filing to change the stated ROE

value to a just and reasonable ROE as determined in this proceeding.

Respectfully submitted,/s/ Thomas L. RudebuschThomas L. RudebuschMatthew R. RudolphiDuncan, Weinberg, Genzer& Pembroke, P.C.

1615 M. Street, NW, Suite 800Washington, DC 20036(202) [email protected]@dwgp.com

32 The complete list of parties that the Complainant served this Complaint is attached as Exhibit No. NYP-9.


Exhibit No. NYP-1

UNITED STATES OF AMERICA

BEFORE THE


)

Niagara Mohawk Power Company (d/b/a) ) Docket No. EL12-___-000

National Grid )

)

PREPARED DIRECT TESTIMONY

OF

JONATHAN A. LESSER

ON BEHALF OF

NEW YORK ASSOCIATION OF PUBLIC POWER

September 11, 2012


Exhibit No. NYP-1

TABLE OF CONTENTS

I. INTRODUCTION AND PURPOSE .................................................................................. 1

II. SUMMARY AND CONCLUSIONS .................................................................................. 4

III. INDEPENDENT ANALYSIS TO DETERMINE ALLOWED ROE ............................. 5

A. Summary of ROE Analysis.............................................................................................. 6

B. Economic and Regulatory Foundations ........................................................................... 6

C. The Commission’s DCF Methodology............................................................................ 8

D. Selection of the Proxy Group of Companies ................................................................. 13

E. DCF Estimates ............................................................................................................... 16

F. Adjustment for Business and Financial Risk ................................................................. 21

IV. DETERMINATION ON CAPITAL STRUCTURE AND OVERALL WACC FORNMPC.................................................................................................................................. 23


Exhibit No. NYP-1

-1-

I. INTRODUCTION AND PURPOSE1

Q. PLEASE STATE YOUR NAME, TITLE, AND BUSINESS ADDRESS.2

A. My name is Jonathan A. Lesser. I am the President of Continental Economics,3

Inc., an economic consulting firm that provides litigation, valuation, and strategic4

services to law firms, industry, and government agencies. My business address is 6 Real5

Place, Sandia Park, NM 87047.6

Q. PLEASE DESCRIBE YOUR PROFESSIONAL QUALIFICATIONS,7EMPLOYMENT EXPERIENCE, AND EDUCATIONAL BACKGROUND.8

A. I am an economist specializing in litigation and market analysis in the energy9

industry. I have over 25 years of experience in the energy industry working with utilities,10

consumer groups, competitive power producers and marketers, and government entities.11

I have provided expert testimony before numerous state utility commissions, before the12

Federal Energy Regulatory Commission (“FERC” or “the Commission”), before state13

legislative committees, and before international regulators.14

Before founding Continental Economics, I was a Partner in the Energy Practice15

with the consulting firm Bates White, LLC. Prior to that, I was the Director of Regulated16

Planning for the Vermont Department of Public Service. Previously, I was employed as a17

Senior Managing Economist at Navigant Consulting. Prior to that, I was the Manager,18

Economic Analysis, for Green Mountain Power Corporation. I also spent seven years as19

an Energy Policy Specialist with the Washington State Energy Office, and I worked for20

Idaho Power Corporation and the Pacific Northwest Utilities Conference Committee (an21

electric industry trade group), where I specialized in electric load and price forecasting.22


Exhibit No. NYP-1

-2-

I hold MA and PhD degrees in economics from the University of Washington and1

a BS, with honors, in mathematics and economics from the University of New Mexico.2

My doctoral fields of specialization were applied microeconomics, econometrics and3

statistics, and industrial organization and antitrust. Exhibit No. NYP-2 is a copy of my4

current curriculum vitae.5

Q. ARE YOU A MEMBER OF ANY PROFESSIONAL ORGANIZATIONS?6

A. Yes. I am a member of the International Association for Energy Economics, the7

Energy Bar Association, and the Society for Benefit-Cost Analysis.8

Q. WHO IS SPONSORING YOUR TESTIMONY?9

A. My testimony is sponsored by New York Association of Public Power10

(“NYAPP”).11

Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE COMMISSION?12

A. Yes. I have testified before the Commission on a variety of matters, including13

allowed rate of return and capital structure for electric transmission activities within14

Regional Transmission Organizations (“RTOs”) and Independent System Operators15

(“ISOs”), natural gas pipeline rate proceedings, wholesale market design, and RTO cost16

allocation. A list of Commission proceedings in which I have participated is shown in17

Exhibit No. NYP-3.18

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?19

A. The purpose of my testimony is to provide an independent analysis of a just and20

reasonable allowed return on equity (“ROE”) and the effect of that ROE on the overall21

weighted average cost of capital (“WACC”) for Niagara Mohawk Power Corporation22

d/b/a National Grid (“NMPC”), as related to that company’s membership and23


Exhibit No. NYP-1

-3-

transmission operations in the New York Independent System Operator (“NYISO”). As1

my testimony shows, the current allowed return on equity of 11.5% is excessive, unjust,2

and unreasonable.3

Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED?4

A. In the next section of my testimony, I provide a summary of my findings. In5

Section III, I present my independent analysis of a just and reasonable allowed ROE for6

NMPC. In Section IV, I provide an analysis of NMPC’s WACC using a just and7

reasonable ROE.8

Q. ARE YOU SPONSORING ANY EXHIBITS?9

A. Yes, I am sponsoring the following exhibits and schedules:10

Hearing Exhibit and ScheduleNumber

Description

Exhibit No. NYP-2 Curriculum Vitae of Jonathan A. LesserExhibit No. NYP-3 List of Previous Commission Testimony

Exhibit No. NYP-4Pages 245-247 from Principles of UtilityCorporate Finance

Exhibit No. NYP-5National Grid plc, “Results for the year ended 31March 2012.”

Exhibit No. NYP-6, Sch. 1 Utility Proxy Group ScreeningExhibit No. NYP-6, Sch. 2 “Sustainable” Earnings Growth EstimatesExhibit No. NYP-6, Sch. 3 I/B/E/S Earnings Growth Estimates

Exhibit No. NYP-6, Sch. 4Avg. Monthly High-Low Stock Prices andDividend Yields

Exhibit No. NYP-6, Sch. 5 DCF Analysis Results

Exhibit No. NYP-7Pages 188-190 from Principles of UtilityCorporate Finance

Exhibit No. NYP-8, Sch. 1Attachment 1, Schedule 8 from NMPC OATTFiling of June 14, 2012, as filed

Exhibit No. NYP-8, Sch. 2Attachment 1, Schedule 8 from NMPC OATTFiling of June 14, 2012, as adjusted


Exhibit No. NYP-1

-4-

II. SUMMARY AND CONCLUSIONS1

Q. PLEASE SUMMARIZE YOUR ROE AND WACC ESTIMATES FOR NMPC.2

A. My estimates are shown in Table 1.3

Table 1: NMPC Weighted Average Cost of Capital and Components4

Line

No.WACC Component Rate

Pct. Of

Capitalization

Weighted

Cost

[1] Long-term Debt 3.96% 49.53% 1.96%

[2] Common Equity 9.49% 50.00% 4.75%

[3] Preferred Equity 3.66% 0.47% 0.02%

[4] Total 100.00% 6.73%

Sources:

1. Capital Structure, Cost of Debt, and Cost of Preferred Equity: "Informational Filing of Niagara

Mohawk Power Corporation of the Annual Update to the Formula Transmission Service Charge

Under the NYISO Open Access Transmission Tariff - Docket No. ER08-552-000, June 14,

2012,WP6.

2. Return on Common Equity: Table 4 (includes 50 bp adder).5

As Table 1 shows, I have determined an overall weighted average cost of capital of6

6.73%. This value is based on a recommended allowed return on equity of 9.49%7

(including a 50 basis point (“bp”) adder for RTO or ISO membership, consistent with8

Commission policy);1 (2) a capital structure of 49.53% long-term debt, 50.0% common9

equity, and 0.47% preferred equity, based on data reported in the NMPC 2011 FERC10

Form-1 Report and the formula rate on page 57 of Appendix H to the NYISO OATT on11

Schedule 8.212

1 Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ¶31,222, order on reh'g, Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 (2006), order on reh'g, 119FERC ¶ 61,062 (2007).

2 Available at:http://www.nyiso.com/public/webdocs/documents/tariffs/oatt/oatt_attachments/att_h.pdf, lastaccessed September 4, 2012.


Exhibit No. NYP-1

-5-

Q. PLEASE SUMMARIZE THE IMPACT OF YOUR REVISED ROE AND WACC1VALUES ON THE BEFORE-TAX RETURN FOR NMPC IN ITS JUNE 14, 20122FILING.33

A. As a result of my revised estimate of allowed ROE and WACC, I find that the4

before-tax return value for NMPC should be reduced by $19,080,537, from the5

$136,652,963 before-tax return value shown in NMPC’s June 14, 2012 filing to6

$117,572,426.7

III. INDEPENDENT ANALYSIS TO DETERMINE ALLOWED ROE8

Q. HOW IS THIS SECTION OF YOUR TESTIMONY ORGANIZED?9

A. In this section, I first provide a brief summary of the steps I took to perform my10

DCF analysis. Next, I discuss the economic and regulatory foundations that govern such11

analyses, and I discuss the business and financial risks faced by NMPC. Then, I provide12

a detailed discussion of each of the steps I performed, including selection of a proxy13

group of electric utilities based on the criteria previously established by the Commission,14

calculation of earnings growth rates, calculation of threshold DCF values and exclusion15

of individual companies if one or more of the DCF values fail to comport with the16

threshold values, and selection of a recommended ROE value based on the resulting zone17

of reasonableness.18

3 Informational Filing of Niagara Mohawk Power Corporation of the Annual Update to the FormulaTransmission Service Charge Under the NYISO Open Access Transmission Tariff, Docket No. ER08-552-000, June 14, 2012, Attachment 1, Schedule 8.


Exhibit No. NYP-1

-6-

A. Summary of ROE Analysis1

Q. PLEASE SUMMARIZE YOUR INDEPENDENT ROE ANALYSIS.2

A. The starting point of any rate of return analysis is selection of an appropriate3

proxy group. I selected a proxy group of 16 electric utilities listed by the Value Line4

Investment Survey under its Electric Utility – West, Electric Utility – East, and Electric5

Utility – Central industry categories. I selected these 16 utilities based on the criteria6

established by FERC in Southern California Edison.4 Specifically, I applied the7

following six criteria to select a proxy group:8

1. Electric utilities that are covered by the Value Line Investment Survey (“Value9Line”);10

2. Electric utilities that neither announced a merger or acquisition within the six-month11analysis period nor were involved in an ongoing merger or acquisition during that12period;13

3. Electric utilities that have paid constant or increasing dividends for at least the past14two years;15

4. Electric utilities that are covered by at least two generally recognized utility industry16analysts, and which have long-term (5-year) earnings growth forecasts reported by17Institutional Brokers;18

5. Electric utilities that have annual revenues of at least $1 billion (NMPC’s revenues in192011 were $3.9 billion); and20

6. Electric utilities having an investment grade corporate credit rating within one21“notch” of NMPC, which is currently rated “A—” by Standard and Poor’s (i.e. utilities22having credit ratings between “BBB+” and “A”).23

B. Economic and Regulatory Foundations24

Q. WHAT IS THE COST OF CAPITAL?25

4 Southern Cal. Edison Co., 131 FERC ¶ 61,020, (2010) (“Southern Cal. Edison I”), P 51, reh’gdenied, 137 FERC ¶ 61,016 (2011) (“Southern Cal. Edison II”).


Exhibit No. NYP-1

-7-

A. The cost of capital can be defined as the expected rate of return in capital markets1

on alternative investments of equivalent, or “comparable” risk. In other words, it is the2

rate of return investors require based on the risk-return alternatives available in3

competitive capital markets. The cost of capital is a type of opportunity cost: it4

represents the rate of return that investors could expect to earn elsewhere without bearing5

more risk. “Expected” is used in the statistical sense: the mean of the distribution of6

possible outcomes. The higher the risk, the higher is the cost of capital.7

Q. WHY IS THE COST OF CAPITAL IMPORTANT IN RATE REGULATION?8

A. It has become routine in U.S. rate regulation to accept the “cost of capital” as the9

right expected rate of return on utility investment. That practice is normally viewed as10

consistent with the U.S. Supreme Court’s opinions in the Bluefield5 and Hope Natural11

Gas6 decisions, which suggest that a regulated utility’s allowed returns by commensurate12

with other firms having similar business and financial risks.13

From an economic perspective, rates are designed to provide investors a fair14

opportunity to earn the cost of capital at the lowest levels that compensate investors for15

the risks they bear. Over the long run, an expected return above the cost of capital makes16

customers overpay for service. Regulatory commissions normally try to prevent such17

outcomes unless there are offsetting benefits (e.g., from incentive regulation that reduces18

future costs). At the same time, an expected return below the cost of capital does a19

disservice not just to investors but, importantly, to customers as well. In the long run,20

such a return denies the company the ability to attract capital, maintain its financial21

5 Bluefield Water Works & Improvement Co. v. Public Serv. Comm’n of W. Va, 262 U.S. 679 (1923).

6 Federal Power Comm’n. v. Hope Natural Gas. Co., 320 U.S. 591 (1944).


Exhibit No. NYP-1

-8-

integrity, and expect a return commensurate with that of other enterprises attended by1

corresponding risks and uncertainties.2

Q. CAN THE COST OF CAPITAL BE DIRECTLY OBSERVED?3

A Although the cost of debt can be directly observed, the cost of equity cannot be.4

That is why different methodologies have been applied to estimate the cost of equity.5

Moreover, that is why using a proxy group of risk-comparable firms is a standard6

approach: a group of firms provides a more statistically robust set of information7

regarding the expected return needed to compensate investors fairly.8

C. The Commission’s DCF Methodology9

Q. PLEASE DESCRIBE THE DCF METHODOLOGY.710

A. One of the basic tenets of corporate finance is that the price of a stock today11

equals the discounted present value of all future cash flows from holding that stock in12

perpetuity. Those cash flows are just the expected future dividend payments. In applying13

the DCF methodology, we determine the discount rate that equates the discounted present14

value of those future dividend payments to the stock’s price today. Thus, the DCF15

methodology can be thought of as a stock valuation exercise in reverse.16

The standard DCF formula is as follows:17

31 20 2 3(1 ) (1 ) (1 ) (1 )

tt

C C C C

D DD DP

R R R R

(1)18

7 For a more detailed discussion, see L. Giacchino and J. Lesser, Principles of Utility CorporateFinance, (Vienna, VA: Public Utilities Reports, Inc. 2011) (“PUCF”), pp. 245-47 (attached hereto asExhibit No. NYP-4).


Exhibit No. NYP-1

-9-

where “P0” is the price of the stock today, “Dt” is the expected dividend payment at the1

end of period t, and “RC” is the cost of equity capital. If one assumes that the dividend2

payments will grow at a constant rate, “g,” forever, then equation (1) can be shown to3

reduce to:4

10

( )C

DP

R g

(2)5

Equation (2) can then be solved for r. Thus, we have:6

01 (1 )C

D x gDR g g

P P

, (3)7

where “D0” is the current dividend payment. Equation (3) is called the “Gordon growth8

model.”9

Q. ARE THERE ANY VARIANTS OF THE MODEL SHOWN IN EQUATION (3)?10

A. Yes. For example, sometimes, it is assumed that the initial dividend payment in11

the model is received immediately. In that case, “D1” in equation (3) is replaced with12

“D0.” There are also variants involving multiple growth rates, such as those representing13

short-term and long-term growth, which are called “multi-stage” DCF models.14

Q. DOES THE COMMISSION USE THE DCF MODEL SHOWN IN EQUATION (3)15FOR PURPOSES OF ESTIMATING THE ALLOWED RETURN ON EQUITY?16

A. No. The Commission uses a slightly modified version, essentially splitting the17

difference regarding when the initial dividend is received. Thus, the Commission model18

is written:819

8 Equation (4) is called a “one-stage” DCF model.


Exhibit No. NYP-1

-10-

0 0(1 2)(1 2)C

D x g DR g x g g

P P

(4)1

Q. IS THE DIVIDEND YIELD SIMPLY THE CURRENT DIVIDEND DIVIDED BY2THE CURRENT STOCK PRICE?3

A. No. The Commission uses an average of the past six months’ stock prices and4

dividend payments. Specifically, the Commission determines “low” and “high” dividend5

yields in each of the previous six months, and then averages the results of each6

separately. Thus, the “low” dividend yield in a given month equals the most recent7

dividend payment divided by the highest closing stock price of the month, and the “high”8

dividend yield equals the most recent dividend payment divided by the lowest closing9

stock price of the month. The Commission then calculates the average “low” and high”10

dividend yields for the six-month period. These become the D0/P values used in equation11

(4).12

Q. HOW IS THE GROWTH RATE IN EQUATION (4) DETERMINED?13

A. The Commission methodology uses two types of earnings growth forecasts to14

estimate the value of “g.” The first is the most current five-year forecast of earnings15

growth published by Institutional Brokers (“I/B/E/S”) for each company in the proxy16

group. The second is what is known as the “sustainable” or “br + sv” earnings growth17

rate for each company.18

Q. HOW ARE THESE TWO GROWTH RATES USED?19

A. The two earnings growth rates are combined with the “low” and “high” dividend20

yields to determine overall “low” and “high” cost of equity estimates for each proxy21

group company.22


Exhibit No. NYP-1

-11-

Q. WHY ARE EARNINGS GROWTH FORECASTS USED WHEN THE GROWTH1RATE IN EQUATION (3) REFERS TO THE DIVIDEND GROWTH RATE?2

A. Earnings growth rates are used because, in the long run, dividend payments can3

only be derived from earnings. Thus, whereas earnings in a given quarter or year may be4

less than a company’s dividend payment, a company cannot sustain dividend payments5

that are greater than its earnings in the long run. So, if a securities analyst forecasts a6

company’s earnings to grow at, say, five percent per year, it is reasonable to assume that7

the company’s dividend payments will grow at that same rate.8

Q. DOES I/B/E/S PREPARE ITS OWN FORECASTS OF EARNINGS GROWTH?9

A No. I/B/E/S compiles the five-year earnings growth forecasts prepared by10

independent securities analysts.11

Q. HOW IS THE “SUSTAINABLE” EARNINGS GROWTH RATE ESTIMATED?12

A The sustainable or “br + sv” growth rate is based on a premise that a company can13

grow only if it plows back some of its earnings for investment purposes. A company that14

pays all of its earnings out as dividends has nothing left to invest, and thus cannot15

continue to increase those dividend payments.16

Estimating a “sustainable” growth rate requires several types of data. First, one17

must determine the company’s retention ratio, which equals the fraction of earnings not18

paid out as dividends. For example, if the firm pays out 60 cents of every dollar in19

earnings as dividends, its retention ratio “b” is 1 – 0.60 = 0.40. Second, one estimates the20

company’s actual and projected average year-end return on book equity “r” which equals21

earnings divided by the company’s book value of equity. These year-end returns on22

average common equity are then adjusted for projected growth in the amount of common23


Exhibit No. NYP-1

-12-

equity, as prescribed by the Commission in Southern California Edison Company,1

Opinion No. 445, 92 FERC ¶ 61,070 (2000).2

Q. HOW IS THIS LATTER ADJUSTMENT CALCULATED?3

A. This adjustment consists of: (1) calculating the proxy companies’ overall common4

equity amounts as reported by Value Line for the five-year period 2011 and 2015-17 and5

calculating the average growth rate in common equity, “GE,” for that five-year period;6

and (2) adjusting the average year-end “r” values for each proxy group company by the7

quantity { 2 (1 ) / (2 )}E EG G , again as set forth in Opinion No. 445.9 The product of8

the retention ratio and the return, i.e., [b ∙ r] equals the amount available for future9

investment and, under the Commission’s sustainable growth rate model, determines the10

future growth rate in earnings.11

The sustainable growth rate also accounts for the effects of external financing12

from issuing new shares of stock, and the profitability of those new shares. The13

profitability of equity is based on the difference between its market value (MV) and book14

value (BV). Specifically, the profitability “v” is defined as15

1MV BV MV

BV BV

. (5)16

Thus, if “s” equals the rate of growth in new shares issued, then the contribution of those17

new shares to earnings growth equals [s ∙ v]. Therefore, the overall sustainable growth18

rate “g” equals [b ∙ r] + [s ∙ v], hence the “br + sv” growth rate.19

Q. WHAT DATA DID YOU USE TO CALCULATE THE SUSTAINABLE GROWTH20RATES FOR YOUR PROXY GROUP?21

9 See 92 FERC ¶ 61,070, ¶ 61,263, fn. 38.


Exhibit No. NYP-1

-13-

A. I calculated sustainable growth rates using estimates taken from individual1

company reports published by Value Line. Specifically, I determined the average2

retention ratio and return on book equity based on data published in Value Line for the3

years 2011, 2012, and 2015-17. The use of the 2015-17 estimates provides a five-year4

forecast, consistent with the five-year earnings growth forecasts provided by I/B/E/S.5

Similarly, I calculated the projected growth rate in outstanding shares over that period6

and estimated equity profitability based on current share prices.7

Q. WHAT TIME PERIOD DID YOU USE TO ESTIMATE LOW AND HIGH8DIVIDEND YIELDS FOR YOUR COMPARABLE UTILITIES?9

A. I used the six-month period between February 1, 2012 and July 31, 2012.10

Q. WILL YOUR ANALYSIS REQUIRE UPDATING?11

A. Yes. Although the February 1, 2012 through July 31, 2012 period I have used is12

current at this time, the Commission’s policy is to update the cost of equity calculation at13

the time of the hearing in this proceeding. Thus, my analysis will require updating.14

D. Selection of the Proxy Group of Companies15

Q. HOW DID YOU SELECT YOUR PROXY GROUP OF COMPANIES FOR THE16DCF ANALYSIS?17

A. To select the proxy group, I used the criteria set forth in Southern California18

Edison.10 Specifically, I used the following criteria:19

1. Electric utilities that are covered by the Value Line;20

2. Electric utilities that neither announced a merger or acquisition within the six-month21analysis period nor were involved in an ongoing merger or acquisition during that22period;23

10 Southern Cal. Edison I at P 51.


Exhibit No. NYP-1

-14-

3. Electric utilities that have paid constant or increasing dividends for at least the past1two years;2

4. Electric utilities that are covered by at least two generally recognized utility industry3analysts, and which have long-term (5-year) earnings growth forecasts reported by4I/B/E/S;5

5. Electric utilities that have annual revenues of at least $1 billion (NMPC’s revenues in62011 were $3.9 billion, and the overall revenues of its corporate parent, National Grid7USA were just over $12 billion);11 and8

6. Electric utilities having an investment grade corporate credit rating within one9“notch” of NMPC, which is currently rated “A—” by Standard and Poor’s (i.e. utilities10having credit ratings between “BBB+” and “A”).11

Q. HOW DID YOU EVALUATE THE ELECTRIC UTILITIES COVERED BY12VALUE LINE FOR PURPOSES OF SELECTING YOUR PROXY GROUP?13

A Value Line currently covers 49 electric utilities, including some utilities that have14

both electric and natural gas distribution operations. Of that total, I eliminated six15

utilities because of ongoing or recently completed merger/acquisition activity during the16

six-month analysis period. These utilities are: Central Vermont Public Service, whose17

merger with Green Mountain Power was finalized in June 2012; Duke Energy and18

Progress Energy, whose merger was finalized in June; and NStar and Northeast Utilities,19

whose merger was finalized in May 2012. I also eliminated CH Energy Group, whose20

purchase by Fortis was announced in February 2012.21

Next, I eliminated two utilities lacking sufficient dividend history: El Paso22

Electric, which only restarted its dividend in June of 2011 after many years of no23

dividends, and Empire District Electric, which suspended its dividend in the third quarter24

11 Value is for the year ended March 31, 2012, based on an average exchange rate for the year of $1.60per GBP. See National Grid plc, “Results for the year ended 31 March 2012,” p.18 and p. 42 (note12). (Attached as Exhibit NYP-5.)


Exhibit No. NYP-1

-15-

of 2011. All of the other electric utilities have paid constant or increasing dividends for1

at least the last two years.2

I then eliminated utilities with annual revenues in 2010 less than $1 billion.3

Finally, I eliminated utilities having corporate credit ratings more than one notch4

above or below NMPC, i.e., utilities with credit ratings of “A+” or above and utilities5

with credit ratings of BBB or below. This left a total of 16 utilities, as shown in Exhibit6

No. NYP-6, Schedule 1, and shown below in Table 2.7

Table 2: NMPC DCF Analysis – Proxy Group Utilities8

Alliant Energy Pepco Holdings

CenterPoint Energy SCANA Corp

Consol. Edison Sempra Energy

Dominion Resources Southern Co.

DTE Energy TECO Energy

Integrys Energy Vectren Corp.

NextEra Wisconsin Energy

OGE Energy Xcel Energy


Exhibit No. NYP-1

-16-

E. DCF Estimates1

Q. HOW DID YOU CALCULATE THE “BR + SV” OR “SUSTAINABLE”2EARNINGS GROWTH ESTIMATES?3

A. My “br + sv” calculations are set forth in Exhibit No. NYP-6, Schedule 2. I used4

Value Line data to estimate the average earnings per share, dividends per share, and book5

value per share values for each of the proxy companies to calculate the average internal6

growth (i.e., the “b ∙ r”) component. I then calculated the external growth (i.e., the “s ∙ 7

v”) component by taking the average market value of each company’s stock over the8

previous six months and dividing by the average book value. Finally, to calculate the9

external growth, I used the Value Line forecast of outstanding shares in the 2015/201710

time frame to determine the annual rate of share growth, as well as the forecast change in11

capital structure and total capitalization to reflect the growth adjustment factor referenced12

in Order No. 445.13

Q. PLEASE DESCRIBE THE I/B/E/S EARNINGS GROWTH FORECAST VALUES14YOU RELIED ON.15

A. Because the six-month period I used to determine dividend yields was February 1,16

2012 through July 31, 2012, I used the I/B/E/S earnings growth rates as forecast as of17

July 31, 2012, which are available on the website Yahoo!Finance for each proxy group18

utility.12 This is reasonable because, in preparing an ROE estimate, the most current19

earnings growth estimates within the six-month period incorporate the most current20

information about the future performance of a stock. The I/B/E/S forecast growth rates21

are shown in Exhibit No. NYP-6, Schedule 3.22

12 These long-term earnings growth rates can also be obtained directly from Thomson-ReutersDatastream.


Exhibit No. NYP-1

-17-

Q. HOW DID YOU ESTIMATE THE “LOW” AND “HIGH” STOCK PRICES FOR1EACH MONTH, AND THE CORRESPONDING “HIGH” AND “LOW”2DIVIDEND YIELDS?3

A. My calculations are set forth in Exhibit No. NYP-6, Schedule 4. I relied on the4

adjusted daily closing stock prices as published by Yahoo!Finance and the quarterly5

dividend payment data published by Value Line for each of the proxy companies.6

Q. WHAT IS AN ADJUSTED CLOSING PRICE?7

A. An adjusted closing price reflects a stock’s closing price on any given day of8

trading that has been adjusted to include any distributions and corporate actions, such as a9

stock split, that occurs at any time prior to the next day’s opening. For example, suppose10

ABC Corporation pays a dividend of $0.50 per share on a date certain and that the11

unadjusted closing price of the stock is $20.00 per share. Then the adjusted closing price12

would just be $19.50, $20.00 less the $0.50 dividend. If ABC Corporation announces a13

2-for-1 stock split (i.e., each shareholder will receive two “new” shares for one existing14

share), then the adjusted stock price would be $20 divided by 2, or $10 per share.15

Q. HOW DID YOU DETERMINE THE MINIMUM THRESHOLD DCF VALUE?16

A. In Southern California Edison I, the Commission set the minimum threshold17

value at 100 basis points above the corresponding long-term utility corporate bond rate.1318

The reason for having such a threshold is that bond holders have a senior claim over a19

firm’s assets than shareholders. Therefore, shareholders face higher financial risks than20

bondholders. This means that no shareholder will accept an expected return lower than21

the yield of the correspondingly rated long-term bond rates and, if fact, will expect a22

13 Southern Cal. Edison I at P 55.


Exhibit No. NYP-1

-18-

higher return. The Commission therefore established a threshold value equal to 100 bp1

above the corresponding utility bond rate.2

To calculate this threshold, I calculated the average of the monthly yields on3

BBB-rated, long-term utility bonds for the six-month period, February 1, 2012 through4

July 31, 2012, as reported by Moody’s. That average yield on “A” rated bonds over this5

six-month period was 4.28% and the average yield on “BBB” rated bonds value was6

5.01%, as shown in Table 3. Therefore, I established a minimum threshold DCF values7

100 basis points above these averages, or 5.28% for “A” and “A—” rated proxy group8

firms and 6.01% for “BBB+” rated proxy group firms.9

Table 3: Moody’s Average Long-Term Utility Bond Yields10

MonthA-rated

(Percent)

BBB-rated

(Percent)

Feb-12 4.36 5.02

Mar-12 4.34 5.03

Apr-12 4.40 5.11

May-12 4.20 4.97

Jun-12 4.08 4.91

Jul-12 3.93 4.85

Average 4.28 5.01

Source: Moody's Economy.com11

Q. WHAT ARE THE RESULTS OF YOUR DCF ANALYSIS?12

A. The results of my DCF analysis for the proxy group are shown in Exhibit No.13

NYP-6, Schedule 5 and Table 4 below.14


Exhibit No. NYP-1

-19-

Table 4: FERC DCF Methodology Analysis Results1

Company Symbol

6-Months

Dividend Yield

(Low)

6-Months

Dividend Yield

(High)

Earnings

Growth

(br+sv)

Earnings

Growth

(/I/B/ES)

Adjusted

Dividend

Yield (Low)

Adjusted

Dividend

Yield (High)

ROE (Low) ROE (High) Average ROE

[1] [2] [3] [4] [5] [6] [7] [8] [9]

1 Alliant Energy LNT 3.88% 4.06% 4.26% 6.30% 3.96% 4.19% 8.22% 10.49% 9.35%

2 CenterPoint Energy CNP 3.95% 4.13% 4.37% 4.90% 4.03% 4.23% 8.40% 9.13% 8.77%

3 Consol. Edison ED 3.96% 4.12% 3.36% 3.02% 4.02% 4.19% 7.04% 7.55% 7.30%

4 Dominion Resources D 3.84% 3.97% 5.87% 5.00% 3.93% 4.08% 8.93% 9.95% 9.44%

5 DTE Energy DTE 4.09% 4.28% 3.66% 4.59% 4.16% 4.38% 7.82% 8.97% 8.39%

6 Integrys Energy TEG 4.91% 5.16% 1.43% 5.00% 4.94% 5.29% 6.38% 10.29% 8.33%

7 NextEra NEE 3.49% 3.63% 6.83% 5.23% 3.58% 3.75% 8.81% 10.58% 9.70%

8 OGE Energy OGE 2.84% 2.98% 7.65% 5.00% 2.91% 3.10% 7.91% 10.75% 9.33%

9 Pepco Holdings POM 5.58% 5.78% 1.06% 4.75% 5.61% 5.92% 6.67% 10.67% 8.67%

10 SCANA Corp SCG 4.17% 4.32% 5.38% 6.13% 4.28% 4.45% 9.66% 10.58% 10.12%

11 Sempra Energy SRE 3.02% 3.17% 5.65% 7.00% 3.11% 3.28% 8.76% 10.28% 9.52%

12 Southern Co. SO 4.13% 4.27% 5.12% 5.38% 4.24% 4.38% 9.36% 9.76% 9.56%

13 TECO Energy TE 4.86% 5.07% 4.59% 2.66% 4.92% 5.19% 7.58% 9.78% 8.68%

14 Vectren Corp. VVC 4.72% 4.89% 3.59% 5.00% 4.81% 5.01% 8.40% 10.01% 9.21%

15 Wisconsin Energy WEC 2.93% 3.06% 5.19% 6.05% 3.01% 3.15% 8.20% 9.20% 8.70%

16 Xcel Energy XEL 3.75% 3.88% 4.54% 5.08% 3.84% 3.98% 8.37% 9.06% 8.72%

Minimum 6.38% Min of Avg 7.30%

Maximum 10.75% Max of Avg 10.12%

Median 9.01% ===>>>>> Median of Avg: 8.99%

Midpoint 8.56% Midpoint 8.71%

Moody's long-term BBB utility bond yield, 6-mos avg., ending July 2012 4.98%

Moody's long-term A utility bond yield, 6-mos avg., ending July 2012 4.22%

Exclude BBB-rated firms with values less than: 5.98%

Exclude A-rated firms with values less than: 5.22%

Number of Excluded Firms 0

Notes:

[1] Equals annual dividend divided by 6-months high stock price ending 7/31/2012

[2] Equals annual dividend divided by 6-months low stock price ending 7/31/2012

[3] Source: Value Line Investment Survey (Calculation is summarized in "Earnings Growth (br+sv)" Tab)

[4] Source: I/B/E/S Thomson Reuters, July 31, 2012 Forecasts

[5] Equals [2]*(1+0.5*MIN[3],[4]))

[6] Equals [2]*(1+0.5*MAX([3],[4]))

[7] Equals MIN([3],[4]) plus [5]

[8] Equals MAX([3],[4]) plus [6]

[8] Equals ( [8] + [9] ) / 2.2

All of the DCF estimates for the proxy group companies are above the threshold DCF3

value of 6.01% for “BBB” rated firms (and, hence, above the threshold DCF value for4

“A” rated firms). As shown, the resulting zone of reasonableness is between 6.38% and5

10.75%, and the median of the average of the “low” and “high” values of the proxy group6

companies in column [9] is 8.99%.7

Q. YOU ALSO SHOW A “MEDIAN” VALUE OF 9.01% ON THE LEFT-HAND8SIDE OF TABLE 4. CAN YOU EXPLAIN WHY THAT DIFFERS FROM THE98.99% MEDIAN OF THE AVERAGE VALUES?10


Exhibit No. NYP-1

-20-

A. Yes. My understanding is that, to establish a median ROE, the Commission1

prefers to first determine the average of each remaining proxy company’s “low” and2

“high” DCF values and then select the median of the resulting range. Thus, the 8.99%3

value is the median value of the values shown in column [9] of Table 4.4

The 9.01% value shown on the left-hand side of Table 4 and Exhibit No. NYP-6,5

Schedule 5, is the median of the larger sample of 32 values that includes the “low” and6

“high” values for each company. It is not surprising that the median of the larger sample7

is slightly different from the median of the average values.8

Q. DO YOU HAVE AN OPINION AS TO WHICH MEDIAN VALUE IS MORE9STATISTICALLY VALID?10

A. Yes. In my opinion, the median of the entire sample, before averaging the “low”11

and “high” values, has greater statistical validity. The larger sample reflects the same12

overall zone of reasonableness but provides twice the number of sample values from13

which the median is taken. Thus, even though the average values of both groups are14

necessarily the same, the standard deviation of the 20-value average is much smaller than15

the standard deviation of the 10-value average.14 However, the 2 bp difference in the16

values, 8.99% versus 9.01% is de minimus.17

Q. DOES YOUR RECOMMENDED ROE VALUE OF 9.49%, AS SHOWN18PREVIOUSLY IN TABLE 1, ALSO INCLUDE THE 50 BP ADDER FOR19MEMBERSHIP IN AN ISO OR RTO?20

14 The standard deviation of the average of a distribution equals the standard deviation of the entiresample divided by the square root of the number of observations. Thus, if the standard deviation of a

sample of N observations is , then the standard deviation of the average equals / N .


Exhibit No. NYP-1

-21-

A Yes. I have taken the 8.99% median value shown in Table 4 and added 50 bp,1

resulting in my overall recommended ROE value of 9.49%, as prescribed by Commission2

policy in Order No. 679.153

F. Adjustment for Business and Financial Risk4

Q. DOES THE COMMISSION EVER DEVIATE FROM ESTABLISHING THE ROE5AT THE MEDIAN OF THE ZONE OF REASONABLESS?6

A. Yes. My understanding is that the Commission sets the ROE at the median of the7

zone of reasonableness unless there is specific evidence that the subject company has a8

business and financial risk profile that differs significantly from the “average” risk of the9

firms in the proxy group.1610

Q. WHAT IS MEANT BY THE TERMS “BUSINESS RISK” AND “FINANCIAL11RISK”?12

A. Business risk is typically defined as “the risk that a business will experience a13

period of poor earnings and, as a consequence, be unable to meet its financial obligations,14

such as the interest payments on its outstanding debt.”17 Financial risk reflects a firm’s15

ability to service its outstanding debt and maintain specific financial metrics associated16

with that debt, such as interest coverage ratios.17

Q. DO REGULATED UTILITIES FACE ANY OTHER TYPE OF RISK THAT CAN18AFFECT THE REQUIRED EQUITY RETURNS TO INVESTORS?19

15 Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ¶31,222, order on reh'g, Order No. 679-A, FERC Stats. & Regs. ¶ 31,236 (2006), order on reh'g, 119FERC ¶ 61,062 (2007).

16 See, e.g., Golden Spread Elec. Coop., Inc.. v. SWECI Pub. Serv. Co., 123 FERC ¶ 61,047 (2008),Opinion No. 501 at P 64.

17 PUCF, pp. 188-90 (attached hereto as Exhibit No. NYP-7).


Exhibit No. NYP-1

-22-

A. Yes. Regulatory risk is a third type of risk that affects investor expectations. As I1

state in Principles of Utility Corporate Finance (“PUCF”), “Regulated firms rely on2

consistency from regulators and assurance that existing regulations will be applied in a3

fair and reasonable way.”18 There is no evidence that NMPC faces any unusual4

regulatory risk, given that the National Grid plc report, “Results for the year ended 315

March 2012,” which was previously attached as Exhibit NYP-5, notes that, “Overall we6

have seen another year of measured progress developing our regulatory arrangements.7

Taken together with the benefit of our efficiency programmes, this progress underpins8

our confidence that we will be able to deliver improved returns from our US9

operations.”19 The report further states that, “The restructuring of our US business is now10

complete and is delivering operational and financial benefits to underpin our progress on11

further improving US returns.”20 Again, therefore, there is nothing noted about any12

unusual regulatory risk faced by NMPC.13

Q. DOES THE NATIONAL GRID PLC REPORT DISCUSS ANY14EXTRAORDINARY BUSINESS OR FINANCIAL RISKS RELATED TO RATE15REGULATION OF ITS U.S. SUBSIDIARIES?16

A. No. In that same report, National Grid plc states that it is improving the overall17

efficiency of its U.S. operations and projects higher returns. There is no discussion of18

any extraordinary business or financial risks that would merit setting the allowed ROE19

for NMPC other than at the median value of the proxy group.20

18 Id., p. 190.19 Exhibit NYP-4, Schedule 2, p. 5.20 Id., p. 9.


Exhibit No. NYP-1

-23-

IV. DETERMINATION ON CAPITAL STRUCTURE AND OVERALL WACC FOR1NMPC2

Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?3

A In this section of my testimony, I demonstrate the effect of using an ROE of4

9.49% on NMPC’s overall WACC and the required before-tax investment return. I relied5

on the tariff formula rate for calculating the cost of capital, as set forth on page 57 of6

Attachment H to the NYISO OATT on Schedule 8.21 A copy of Schedule 8, as filed on7

June 14, 2012, is attached as Exhibit No. NYP-8, Schedule 1. As shown on line 21, the8

formula-based WACC is 7.73%. As shown on line 64, the resulting value for the before-9

tax return (“investment return plus taxes”) is $136,652,963.10

Q. HOW DOES THE FORMULA RATE SPECIFY CAPITAL STRUCTURE?11

A. Schedule 8 uses a specific formula for capital structure that limits the percentage12

of common equity to no more than 50% of total capitalization. If the actual common13

equity capitalization is greater than 50%, then under the formula rate it is reduced to 50%14

and the percentage reduction is then added to the long-term debt capitalization15

percentage. For example, if the common equity percentage were 55% of total16

capitalization, for ratemaking purposes it would be reduced by 5% to 50% and the long-17

term debt percentage would be similarly increased by 5%. Because the actual amount of18

common equity shown on line 19 of Schedule 8 is $3,813,721,822, which is 61.33% of19

the total capitalization of $6,218,289,604 shown on line 21, the equity capitalization20

percentage is reduced by 11.33% to the 50% maximum and the long-term debt21

21 Informational Filing of Niagara Mohawk Power Corporation of the Annual Update to the FormulaTransmission Service Charge Under the NYISO Open Access Transmission Tariff, Docket No. ER08-552-000, June 14, 2012, Attachment 1, Schedule 8.


Exhibit No. NYP-1

-24-

percentage is increased 11.33% to 49.53%, as shown on line 17 of Schedule 8. (The1

preferred equity percentage is not adjusted from its actual value of 0.47% under the2

formula.) In calculating the revised WACC value for NMPC, I have used these3

capitalization percentages for common equity, long-term debt, and preferred equity.4

Q. WHAT IS THE RESULTING WACC FOR NMPC, USING YOUR 9.49% ROE5AND THE FORMULA-RATE CAPITALIZATION PERCENTAGES AND6RATES?7

A. As shown previously in Table 1, I derive an overall WACC of 6.73%.8

Q. HAVE YOU ESTIMATED THE IMPACT OF THE 6.73% WACC YOU9CALCULATE ON THE BEFORE-TAX INVESTMENT RETURN SHOWN ON10LINE 64 OF SCHEDULE 8 THAT WAS FILED ON JUNE 14, 2012?11

A Yes. The revised estimate is shown on line 64 of Exhibit No. NYP-8, Schedule 2.12

As can be seen, using the lower ROE results in a revised before-tax return of13

$117,572,426. This represents a reduction of $19,080,537 from the $136,652,963 before-14

tax return shown in the June 14, 2012 filing.15

Q. DOES THIS CONCLUDE YOUR TESTIMONY?16

A Yes.17


Exhibit No. NYP-1

UNITED STATES OF AMERICA

BEFORE THE


)

Niagara Mohawk Power Company (d/b/a) ) Docket No. ER12-___-000

National Grid USA )

)

VERIFICATION

I, Jonathan A. Lesser, declare under penalty of perjury that the foregoing testimony is

true and correct.

Executed this 11th day of SEPTEMBER, 2012.

__________________________

Jonathan A. Lesser


Docket No. EL12-___-000Exhibit No. NYP-2

Page 1 of 25

6 Real Place • Sandia Park, NM 87047 • main: 505.286.8833 • DC Office: 202.446.2062www.continentalecon.com

Jonathan A. Lesser, Ph.D.

President

SUMMARY OF EXPERIENCE

Dr. Jonathan Lesser is the President of Continental Economics, Inc., and has over 25

years of experience working for regulated utilities, governments, and as an economic

consultant. He has extensive experience in valuation and damages analysis, from

estimating the damages associated with breaking commercial leases to valuing nuclear

power plants. Dr. Lesser has performed due diligence studies for investment banks,

testified on generating plant stranded costs, assessed damages in commercial litigation

cases, and performed statistical analysis for class certification. He has also served as an

arbiter in commercial damages proceedings.

He has analyzed economic and regulatory issues affecting the energy industry, including

cost-benefit analysis of transmission, generation, and distribution investment, gas and

electric utility structure and operations, generating asset valuation under uncertainty,

mergers and acquisitions, cost allocation and rate design, resource investment decision

strategies, cost of capital, depreciation, risk management, incentive regulation,

economic impact studies of energy infrastructure development, and general regulatory

policy.

Dr. Lesser has prepared expert testimony and reports in cases before utility

commissions in numerous U.S. states; before the Federal Energy Regulatory

Commission (FERC); before international regulators in Latin America and the

Caribbean; in commercial litigation cases; and before legislative committees in

Connecticut, Maryland, New Jersey, Ohio, Texas, Vermont, and Washington State. He has

also served as an independent arbiter in disputes involving regulatory treatment of

utilities and valuation of energy generation assets.

Dr. Lesser is the author of numerous academic and trade press articles. He is also the

coauthor of Environmental Economics and Policy, published in 1997 by Addison Wesley

Longman, Fundamentals of Energy Regulation, published in 2007 by Public Utilities

Reports, Inc., and Principles of Utility Corporate Finance, published in 2011 by Public

Utilities Reports, Inc. Dr. Lesser is also a contributing columnist and Editorial Board

member for Natural Gas & Electricity.



Page 2 of 25


AREAS OF EXPERTISE

• State, federal, and international rate regulation – cost of capital, depreciation, cost of

service, cost allocation, rate design, incentive regulation, and regulatory framework

design

• Commercial damages estimation and litigation

• Cost-benefit analysis

• Regulatory policy and market design

• Economic impact analysis and input-output studies

• Environmental compliance and litigation

• Market power analysis

• Load forecasting and energy market modeling

• Energy asset valuation and due diligence

SELECTED EXPERT TESTIMONY AND REPORTS

Caribbean Utilities Company, Ltd.

Rebuttal report on

weighted average cost of capital methodology and recommendations for Caribbean

Utilities Company, Ltd.

Long Island Power Authority

Estimation of rate of

return for renegotiation of long-term power purchase agreement under FERC

regulation.

Utah Industrial Energy Users Coalition

Proceeding before the

Utah Public Service Commission (Case No. U-11035-200 )

Subject: Appropriate methodology for embedded cost allocation for Rocky

Mountain Power.

FirstEnergy Solutions Corp.


Michigan Public Service Commission (Case No. U-17032)



Page 3 of 25


Subject: Indiana & Michigan Power Co. proposed capacity charges for customers

taking retail electric service.


Ohio Public Utilities Commission (Case Nos. 11-346-EL-SSO and 11-348-EL-SSO)

Subject: Revised AEP Ohio energy security plan, benefits of retail market

competition.


Ohio Public Utilities Commission (Case No. 10-2929-EL-UNC)

Subject: Appropriate price for commercial retail electric suppliers to be charged by

AEP Ohio for installed capacity under the PJM Fixed Resource Requirement tariff

option.

Southwestern Electric Cooperative

FERC proceeding

regarding wholesale distribution rate application of Ameren Illinois (Re:

Midwestern ISO and Ameren Illinois, Docket No. ER11-2777-002, et al.)

Subject: Allowed rate of return and capital structure

Exelon Corporation


New Jersey Board of Public Utilities (Docket No. EO-11050309)

Subject: PJM Capacity Market, Capacity Procurement, and Transmission Planning

Industrial Energy Users of Ohio


Ohio Public Utilities Commission (Case No. 08-917-EL-SSO)

Subject: Determination of cost associated with “provider-of-last-resort” (POLR)

service and AEP Ohio’s use of option pricing models.

Southwest Gas Corporation

FERC proceeding regarding rate application of El Paso Natural Gas Company

(Docket No. RP10-1398-000)



Page 4 of 25


Subject: Development of risk-sharing methodology for unsubscribed and discount

capacity costs.

Portland Natural Gas Shippers

FERC rate proceeding

regarding the rate application by Northern Border Pipeline Company (Re: Portland

Natural Gas Transmission System, Docket No. RP10-729-000)

FERC rate proceeding

regarding the rate application by Northern Border Pipeline Company (Re: Portland

Natural Gas Transmission System, Docket No. RP08-306-000)

Subject: Natural gas supplies, economic lifetime, and depreciation rates.

Independent Power Producers of New York

FERC proceeding (New

York Independent System Operator, Inc., Docket No. ER11-2224-000)

Subject: Reasonableness of the proposed installed capacity demand curves and cost

of new entry values proposed by the New York Independent System Operator.

Maryland Public Service Commission

Merger application of

FirstEnergy Corporation and Allegheny Energy, Inc. (I/M/O FirstEnergy Corp and

Allegheny Energy, Inc., Case No. 9233)

Subject: Proposed merger between FirstEnergy Corporation and Allegheny Energy.

Testimony described the structure and results of a cost-benefit analysis to

determine whether the proposed merger met the state’s positive benefits test, and

included analysis of market power and merger synergies.

Alliance to Protect Nantucket Sound

Proceeding before the Massachusetts Department of Public Utilities (Case No. D.P.U.

10-54)

Subject: Approval of Proposed Long-Term Contracts for Renewable Energy With

Cape Wind Associates, LLC.



Page 5 of 25


Brookfield Energy Marketing, LLC

FERC proceeding (New England Power Generators Association, et al. v. ISO New

England, Inc., Docket Nos. ER10-787-000, ER10-50-000, and EL10-57-000

(consolidated)).

Subject: Proposed forward capacity market payments for imported capacity into

ISO-NE.

Public Service Company of New Mexico

Proceeding before the New Mexico Public Regulation Commission (Case No. 10-

00086-UT)

Subject: Load forecast for future test year, residential price elasticity study.

M-S-R Public Power Agency

FERC proceeding (Southern California Edison Co., Docket No. ER09-187-000 and

ER10-160-000)

Subject: Allowed rate of return for construction work in progress (CWIP)

expenditures for certain transmission facilities.

FERC proceeding (Southern California Edison Co., Docket No. ER10-160-000)

Subject: Allowed rate of return for construction work in progress (CWIP)

expenditures for certain transmission facilities.

Financial Marketers

FERC proceeding (Black Oak Energy, LLC v PJM Interconnection, L.L.C., Docket No.

EL08-014-002)

Subject: Allocation of surplus transmission line losses under the PJM tariff.

Southwest Gas Corporation and Salt River Project

FERC proceeding regarding rate application of El Paso Natural Gas Company

(Docket No. RP08-426-000)



Page 6 of 25


Subject: Analysis of proposed capital structure and recommended capital structure

adjustments

New York Regional Interconnect, Inc.

Proceeding before the New York Public Service Commission (Case No. 06-T-0650)

Subject: Analysis of economic and public policy benefits of a proposed high-voltage

transmission line.

Occidental Chemical Corporation

FERC Proceeding (Westar Energy, Inc. ER07-1344-000)

Subject: Compliance of wholesale power sales agreement with FERC standards

EPIC Merchant Energy, LLC, et al.

FERC Proceeding (Ameren Services Company v. Midwest Independent System

Operator, Inc., Docket Nos. EL07-86-000, EL07-88-000, EL07-92-000 (Consolidated)

Subject: Allocation of revenue sufficiency guarantee costs.

Cottonwood Energy, LP

Proceeding before the Public Utility Commission of Texas (Application of Kelson

Transmission Company, LLC for a Certificate of Convenience and Necessity for the

Amended Proposed Canal to Deweyville 345 kV Transmission Line with Chambers,

Hardin, Jasper, Jefferson, Liberty, Newton, and Orange Counties, Docket No. 34611,

SOAH Docket No. 473-08-3341)

Subject: Benefits of transmission capacity investments.

Redbud Energy, LP

Proceeding before the Oklahoma Corporation Commission (Request of Public Service

Company of Oklahoma for the Oklahoma Corporation Commission to Retain an

Independent Evaluator, Cause No. PUD 200700418)

Subject: Reasonableness of PSO’s 2008 RFP design.

The NRG Companies



Page 7 of 25


FERC Proceeding (ISO New England Inc. and New England Power Pool, Docket No.

ER08-1209-000)

Subject: Compensation of Rejected De-list Bids Under ISO-NE’s Forward Capacity

Market Design

Dynegy Power Marketing, LLC

• FERC proceeding, KeySpan-Ravenswood, LLC v. New York Independent System

Operator, Inc., Docket No. EL05-17-000

Subject: Estimation of damages accruing to Dynegy arising from a failure by the

NYISO to accurately calculate locational installed capacity requirements in NYISO

during the summer of 2002.

Constellation Energy Group

FERC proceeding (Maryland Public Utility Commission, et al., v. PJM Interconnection,

LLC, Docket No. EL08-67-000)

Subject: “Just and reasonableness” of PJM’s Reliability Pricing Mechanism.

Government of Belize, Public Utility Commission

Proceeding before the Belize Public Utility Commission, In the Matter of the Public

Utilities Commission Initial Decision in the 2008 Annual Review Proceeding for Belize

Electricity Limited.

Subject: Arbitration and Independent Expert’s report, in dispute between the Belize

PUC and Belize Electricity Limited in an annual electric rate tariff review, as

required under Belize law.

Federal Energy Regulatory Commission

Technical hearings on wholesale electric capacity market design.

Subject: Analysis of proposal to revise RTO capacity market design developed by the

American Forest and Paper Association.

Dogwood Energy, LLC

Proceeding before the Missouri Public Service Commission, In the Matter of the

Application of Aquila, Inc., d/b/a Aquila Networks - MPS and Aquila Case No. EO-2008-

0046, Networks - L&P for Authority to Transfer Operational Control of Certain



Page 8 of 25


Transmission Assets to the Midwest Independent Transmission System Operator, Inc.,

Case No. EO-2008-0046.

Subject: Cost-benefit analysis to determine whether Aquila should join either the

Midwest Independent System Operator (MISO) or the Southwest Power Pool (SPP).

Independent Power Producers of New York

• FERC proceeding (Re: New York Independent System Operator, Inc., Docket No. ER08-

283-000)

Subject: Revisions to the installed capacity (ICAP) market demand curves in the New

York control area, which are designed to provide economic incentives for new

generation development.

Empresa Eléctrica de Guatemala

• Rate proceeding before the Comisión Nacional de Energía Eléctrica

Subject: Rate of return for an electric distribution company

Electric Power Supply Association

• FERC proceeding (Re: Midwest Independent Transmission System Operator, Inc.,

Docket No. ER07-1182-000)

Subject: Critique of cost-benefit analysis by MISO Independent Market Monitor

concluding that permanent establishment of Broad Constrained Area mitigation was

appropriate.

Constellation Energy Commodities Group, LLC

• FERC proceeding regarding rate application for ancillary services by Ameren Energy

(Re: Ameren Energy Marketing Company and Ameren Energy, Inc., Docket Nos. ER07-

169-000 and ER07-170-000)

• Subject: Analysis and testimony on appropriate “opportunity cost” rates for

ancillary services, including regulation service and spinning reserve service. Case

settled prior to testimony being filed.

Suiza Dairy Corporation

• Rate proceeding before the Office of Milk Industry Regulatory Administration of

Puerto Rico.

• Subject: Analysis and testimony on the appropriate rate of return for regulated milk

processors in the Commonwealth of Puerto Rico.



Page 9 of 25


DPL Inc.

• Proceeding before the Ohio Board of Tax Appeals (DPL, Inc. and its subsidiaries v.

William W. Wilkins, Tax Commissioner of Ohio, Case No. 2004-A-1437)

Subject: Economic impacts of generation investment and qualification of electric

utility investments as “manufacturing” investments for purposes of state investment

tax credits.

IGI Resources, LLC and BP Canada Energy Marketing Corp.

• FERC proceeding regarding the rate application by Gas Transmission Northwest

Corporation (Re: Gas Transmission Northwest, Docket No. RP06-407-000)


Baltimore Gas and Electric Co.

• Maryland Public Service Commission (Case No. 9099)

Subject: Standard Offer Service pricing. Testimony focused on factors driving

electric price increases since 1999, and estimates of rates under continued

regulation


Subject: Stranded costs of generation. Testimony focused on analysis of benefits of

competitive wholesale power industry.


Subject: Optimal structure of Maryland’s electric industry. Testimony focused on

the benefits of competitive wholesale electric markets. Presented independent

estimates of benefits of restructuring since 1999.

Pemex-Gas y Petroquímica Básica

• Expert report in a rate proceeding. Presented analysis before the Comisión

Reguladora de Energía on the appropriate rate of return for the natural gas pipeline

industry.

BP Canada Marketing Corp.

• FERC proceeding regarding the rate application by Northern Border Pipeline

Company (Re: Northern Border Pipeline, Docket No. RP06-072-000)




Page 10 of 25


Transmission Agency of Northern California

• FERC rate proceeding (Re: Pacific Gas & Electric Company, Docket No. ER09-1521-

000)

Subject: Analysis of appropriate return on equity, capital structure, and overall cost

of capital. Case settled prior to filing expert testimony.


000)




000)




000)




000)



• FERC rate proceeding (Re: Pacific Gas & Electric Company, Docket Nos. ER03-409-

000, ER03-666-000)

Subject: Analysis and development of recommendation for the appropriate return

on equity, capital structure, and overall cost of capital.

State of New Jersey Board of Public Utilities

• Merger application of Public Service Enterprise Group and Exelon Corporation

(I/M/O The Joint Petition Of Public Service Electric And Gas Company And Exelon

Corporation For Approval Of A Change In Control Of Public Service Electric And Gas

Company And Related Authorizations, BPU Docket No. EM05020106, OAL Docket No.

PUC-1874-050)



Page 11 of 25


Subject: Proposed merger between Exelon Corporation and PSEG Corporation.

Testimony described the structure and results of a cost-benefit analysis to

determine whether the proposed merger met the state’s positive benefits test, and

included analysis of market power, value of changes in nuclear plant operations, and

merger synergies.

Sierra Pacific Power Corp.

• FERC proceeding regarding the rate application by Paiute Pipeline Company (Re

Paiute Pipeline Company Docket No. RP05-163-000)

Subject: Depreciation analysis, negative salvage, and natural gas supplies. Case

settled prior to filing expert testimony.

Matanuska Electric

• Regulatory Commission of Alaska rate proceeding (In the Matter of the Revision to

Current Depreciation Rates Filed by Chugach Electric Association, Inc., Docket No. U-

04-102)

Subject: Analysis of the reasonableness of Chugach electric’s depreciation study.

Duke Energy North America, LLC

• FERC proceeding (Re: Devon Power, LLC, et al., Docket No. ER03-563-030)

Subject: Appropriate market design for locational installed generating capacity in

the New England market to ensure system reliability.

Keyspan-Ravenswood, LLC

• FERC proceeding, KeySpan-Ravenswood, LLC v. New York Independent System

Operator, Inc., Docket No. EL05-17-000

Subject: Estimation of damages arising from a failure by the NYISO to accurately

calculate locational installed capacity requirements in New York City during the

summer of 2002.

Electric Power Supply Association

• FERC proceeding (Re: PJM Interconnection, LLC, Docket No. EL03-236-002)

Subject: Analysis and critique of proposed pivotal supplier tests for market power in

PJM identified load pockets.



Page 12 of 25


Vermont Department of Public Service

• Vermont Public Service Board Rate Proceedings

o Concurrent proceedings: Re: Green Mountain Power Corp., Dockets No.

7175 and 7176. Subject: Cost of capital and allowed return on equity

under cost of service regulation, as well as under a proposed alternative

regulation proposal.

o Re: Shoreham Telephone Company, Docket No. 6914. Subject: Analysis

and development of recommendations for the appropriate return on

equity, capital structure, and overall cost of capital.

o Re: Vermont Electric Power Company, Docket No. 6860. Subject:

Development of a least-cost transmission system investment strategy to

analyze the prudence of a major high-voltage transmission system

upgrade proposed by the Vermont Electric Power Company.

o Re: Central Vermont Public Service Company, Docket No. 6867. Subject:

Analysis and development of recommendations for the appropriate

return on equity, capital structure, and overall cost of capital.

o Re: Green Mountain Power Corporation, Docket No. 6866. Subject:

Analysis and development of recommendations for the appropriate

return on equity, capital structure, and overall cost of capital.

Pipeline shippers

• FERC proceeding regarding the rate application of Northern Natural Gas Company

(Re: Northern Natural Gas Company, Docket No. RP03-398-000)

Subject: Gas supply analysis to determine pipeline depreciation rates as part of an

overall rate proceeding.

Arkansas Oklahoma Gas Corp.

• Oklahoma Corporation Commission rate proceeding (Re: Arkansas Oklahoma Gas

Corporation, Docket No. 03-088)

Subject: Analysis and development of recommendations for the appropriate return


• Arkansas Public Service Commission rate proceedings

o In the Matter of the Application of Arkansas Oklahoma Gas Corporation for a

General Change in Rates and Tariffs, Docket No. 05-006-U. Subject: Analysis and



Page 13 of 25


development of recommendations for the appropriate return on equity, capital

structure, and overall cost of capital.

o In the Matter of the Application of Arkansas Oklahoma Gas Corporation for a

General Change in Rates and Tariffs, Docket No. 02-24-U. Subject: Analysis and

development of recommendations for the appropriate return on equity, capital

structure, and overall cost of capital.

Entergy Nuclear Vermont Yankee, LLC

• Vermont Public Service Board proceeding (Re: Petition of Entergy Nuclear Vermont

Yankee for a Certificate of Public Good, Docket No. 6812)

Subject: Analysis of the economic benefits of nuclear plant generating capacity

expansion as required for an application for a Certificate of Public Good.

Central Illinois Lighting Company

• Illinois Commerce Commission rate proceeding (Re: Central Illinois Lighting

Company, Docket No. 02-0837)

Subject: Analysis and development of recommendations for the appropriate return


Citizens Utilities Corp.

• Vermont Public Service Board rate proceeding (Tariff Filing of Citizens

Communications Company requesting a rate increase in the amount of 40.02% to take

effect December 15, 2001, Docket No. 6596)

Subject: Analysis of the prudence and economic used-and-usefulness of Citizens’

long-term purchase of generation from Hydro Quebec, including the estimated

environmental costs and benefits of the purchase.

Dynegy LNG Production, LP

• FERC proceeding (Re: Dynegy LNG Production Terminal, LP, Docket No. CP01-423-

000). September 2001

Subject: Analysis of market power impacts of proposed LNG facility development.

Missouri Gas Energy Corp.

• FERC rate proceeding (Re: Kansas Pipeline Corporation, Docket No. RP99-485-000)



Page 14 of 25


Subject: Gas supply analysis to determine pipeline depreciation rates as part of an

overall rate proceeding.

Green Mountain Power Corp.

• Vermont Public Service Board rate proceedings

o In the Matter of Green Mountain Power Corporation requesting a 12.93% Rate

Increase to take effect January 22, 1999, Docket No. 6107. Subject: Analysis of the

appropriate discount rate, treatment of environmental costs, and the treatment

of risk and uncertainty as part of a major power-purchase agreement with

Hydro-Quebec.

o Investigation into the Department of Public Service’s Proposed Energy Efficiency

Utility, Docket No. 5980. Subject: Analysis of distributed utility planning

methodologies and environmental costs.

o Tariff Filing of Green Mountain Power Corporation requesting a 16.7% Rate

Increase to take effect 7/31/97, Docket No. 5983. Subject: Analysis of distributed

utility planning methodologies and avoided electricity costs.

o Tariff Filing of Green Mountain Power Corporation requesting a 16.7% Rate

Increase to take effect 7/31/97, Docket No. 5983. Subject: Valuation of a long-

term power purchase contract with Hydro-Quebec in the context of a

determination of prudence and economic used-and-usefulness.

United Illuminating Company

• Connecticut Dept. of Public Utility Control proceeding (Application of the United

Illuminating Company for Recovery of Stranded Costs, Docket No. 99-03-04)

Subject: Development and application of dynamic programming models to estimate

nuclear plant stranded costs.

COMMERCIAL LITIGATION EXPERIENCE

• Vacqueria Tres Monjitas

and Suiza Dairy, Inc. v. Jose O. Laboy, in his Official capacity, as the Secretary of the

Department of Agriculture for the Commonwealth of Puerto Rico, and Juan R. Pedro-

Gordian, in his official capacity, as Administrator of the Office of the Milk Industry

Regulatory Administration for the Commonwealth of Puerto Rico. U.S. District Court,

District of Puerto Rico, Civil Case No. 04-1840. Determined the appropriate



Page 15 of 25


“country risk” premium for the fresh milk dairy industry in the Commonwealth of

Puerto Rico.

• Lorali, Ltd., et al. v. Sempra Energy Solutions, LLC, et al. Damages associated with

abrogation of retail electric supply contract.

• IMO Industries v. Transamerica. Estimated the appropriate discount rate to use for

estimating damages over time associated with a failure of the insurance companies

to reimburse asbestos-related damage claims and the resulting losses to the firm’s

value.

• John C. Lincoln Hospital v. Maricopa County. Performed statistical analysis to

determine the value of a class of unpaid hospital insurance claims.

• Catamount/Brownell, LLC. v. Randy Rowland. Prepared an expert report on the

damages associated with breach of commercial lease.

• Lyubner v. Sizzling Platters, Inc.. Performed an econometric analysis of damage

claims based on sales impacts associated with advertising.

• Pietro v. Pietro. Estimated pension benefits arising from a divorce case.

• Nat’l. Association of Electric Manufacturers v. Sorrell. U.S. District Court for theDistrict of Vermont. Expert report and testimony on the costs of labelingfluorescent lamps and the impacts of labeling laws on the demand for electricity.

ARBITRATION CASES

TransCanada Hydro Northeast, Inc. v. Town of Littleton, New Hampshire, (CPR File

No. G-09-24).

Subject: dispute regarding valuation for property tax purposes of a hydroelectric

facility located on the Connecticut River.

Served as neutral on a three-person arbitration panel.

Belize Electricity Limited v. Belize Public Utilities Commission (Claim No. 512 of

2008).

Subject: Proceeding before the Supreme Court of Belize alleging that the Final

Decision by the Belize Public Utilities Commission setting electric rates and tariffs

for the 2008-2009 period were unreasonable and non-compensatory.



Page 16 of 25


Prepared independent report on behalf of the Belize Supreme Court for arbitration

of the dispute.

SELECTED BUSINESS CONSULTING EXPERIENCE

• For the Manhattan Institute, prepared a comprehensive report on the economic

impacts of early shutdown of the Indian Point Nuclear Facility.

• For Energy Choice Now, prepared a report on economic benefits of electric

competition in Michigan.

• For the COMPETE Coalition, prepared a report on how electric competition creates

economic growth.

• For an industry group, developed econometric models of the impacts of shale gas

production on U.S. natural gas and electric prices.

• For an environmental advocacy group, critically evaluated the financial implications

of operating restrictions for an off-shore wind generating facility stemming from

requirements under the U.S. Endangered Species Act.

• For a major investor-owned utility in the US, prepared a new system of short-term

peak and energy forecasting models.

• For a major wholesale electric generation company, prepared comprehensive

economic impact studies for use in FERC hydroelectric relicensing proceedings.

• For a major investor-owned utility in the Southwest US, prepared a detailed

econometric model and wrote a comprehensive report on residential price elasticity

that was required by regulators.

• For a major investor-owned utility in the Southwest US, developed a methodology to

value nuclear plant leases that incorporated future uncertainty regarding

greenhouse gas regulations.

• Faculty member, PURC/World Bank International Training Program on Utility

Regulation and Strategy, University of Florida, Public Utility Research Center,

Gainesville, FL, 2008 – 2009. Courses taught:

o Sector Issues: Basic Techniques–Energy

o Sector Issues in Rate Design: Energy

o Sector Issues in Rate Design: Energy–Case Studies

o Transmission Pricing Issues



Page 17 of 25


• For a major solar energy firm, evaluated costs and benefits of alternative solar

technologies; assisted with siting and transmission access issues.

• For industrial customers in the State of Vermont, prepared a position paper on the

impacts of demand side management funding on electric rates and competitiveness.

• For a major New York brokerage firm, performed a fairness opinion valuation of a

gas-fired electric generating facility.

• For electric utilities undergoing restructuring, developed comprehensive economic

models to value buyer offers associated with nuclear power plant divestitures.

• For a large municipal electric utility in Florida, analyzed real option values of

alternative proposed purchased generation contracts whose strike prices were tied

to future natural gas and oil prices, and developed contract recommendations.

• For a municipal electric utility in Florida, developed an analytical model to

determine risk-return tradeoffs of alternative generation portfolios, identify an

efficient frontier of generation asset portfolios, and recommended asset purchase

and sale strategies.

• For Central Vermont Public Service Corp. and Green Mountain Power Corp.,

developed analyses of distribution capacity investments accounting for uncertainty

over future peak load growth.

• For a major electric utility in Latin America, developed risk management strategies

for hedging natural gas supplies with minimal up-front investment; prepared

training materials for utility staff; and wrote the utility’s risk management Policies

and Procedures Manual.

• For a major nuclear plant owner and operator in the U.S., prepared reports of the

economic benefits of nuclear plant operation and development.

• For the Electric Power Supply Association, prepared numerous policy papers

addressing wholesale electric market design and competition.

• For the California Energy Commission, developed a new policy approach to

renewables feed-in tariffs and developed portfolio analysis models to develop an

“efficient frontier” of generation portfolios for the state.

• For a major nuclear plant owner and operator, assessed the likelihood of relicensing

a specific nuclear plant in New England, given state regulatory concerns over on-site

spent fuel storage.

• For a large investor-owned utility in the Southeast, analyzed alternative

environmental compliance strategies that directly incorporated uncertainty over



Page 18 of 25


future emissions costs, environmental regulations, and alternative pollution control

technology effectiveness.

• For a Special Legislative Committee of the Province of New Brunswick, served as an

expert advisor on the development of a deregulated electric power market.

• For the Bonneville Power Administration, developed models to assess the economic

impacts of local generation resource development in Washington State and Oregon.

• For an electric utility in the Pacific Northwest, assisted in negotiations surrounding

relicensing of a large hydroelectric generating facility.

• Served as an expert advisor for the Northwest Power Planning Council regarding

future power supplies, load growth, and economic growth.

EDUCATION

• PhD, Economics, University of Washington

• MA, Economics, University of Washington

• BSc, Mathematics and Economics (with honors), University of New Mexico

EMPLOYMENT HISTORY

2009–Present: Continental Economics, Inc., President.

2004–2009: Bates White, LLC, Partner, Energy Practice.

2003–2004: Vermont Dept. of Public Service, Director of Planning.

1998–2003: Navigant Consulting, Senior Managing Economist.

1996–1998: Adjunct Lecturer, School of Business, University of Vermont.

1993–1998: Green Mountain Power Corporation, Manager, Economic Analysis.

1990–1993: Adjunct Lecturer, Dept. of Business and Economics, Saint Martin’sCollege.

1986–1993: Washington State Energy Office, Energy Policy Specialist.

1984–1986: Pacific Northwest Utilities Conference Committee, Energy Economist.

1983–1984: Idaho Power Corporation, Load Forecasting Analyst.

PROFESSIONAL ACTIVITIES



Page 19 of 25


• Reviewer, Energy

• Reviewer, The Energy Journal

• Reviewer, Energy Policy

• Reviewer, Journal of Regulatory Economics

PROFESSIONAL ASSOCIATIONS

• Energy Bar Association

• International Association for Energy Economics

• Society for Benefit-Cost Analysis

PUBLICATIONS

Peer-reviewed journal articles

• Lesser, J., “Gresham’s Law of Green Energy,” Regulation, Winter 2010-2011, pp. 12-

18.

• Lesser, J., and E. Nicholson, “Abandon all Hope? FERC’s Evolving Standards for

Identifying Comparable Firms and Estimating the Rate of Return,” Energy Law

Journal 30 (April 2009): 105-132.

• Lesser, J. and X. Su. “Design of an Economically Efficient Feed-in Tariff Structure for

Renewable Energy Development.” Energy Policy 36 (March 2008) 981–990.

• Lesser, J. “The Economic Used-and-Useful Test: Its Origins and Implications for a

Restructured Electric Industry.” Energy Law Journal 23 (November 2002): 349–82.

• Lesser, J., and C. Feinstein. “Electric Utility Restructuring, Regulation of Distribution

Utilities, and the Fallacy of ‘Avoided Cost’ Rules.” Journal of Regulatory Economics 15

(January 1999): 93–110.

• Lesser, J., and C. Feinstein. “Defining Distributed Utility Planning.” The Energy

Journal, Special Issue, Distributed Resources: Toward a New Paradigm (1998): 41–

62.

• Lesser, J., and R. Zerbe. “What Can Economic Analysis Contribute to the

Sustainability Debate?” Contemporary Policy Issues 13 (July 1995): 88–100.



Page 20 of 25


• Lesser, J., and R. Zerbe. “The Discount Rate for Environmental Projects.” Journal of

Policy Analysis and Management 13 (Winter 1994): 140–56.

• Lesser, J., and D. Dodds. “Can Utility Commissions Improve on Environmental

Regulations?” Land Economics 70 (February 1994): 63–76.

• Lesser, J. “Estimating the Economic Impacts of Geothermal Resource Development.”

Geothermics 24 (Winter 1994): 52–69.

• Lesser, J. “Application of Stochastic Dominance Tests to Utility Resource Planning

Under Uncertainty.” Energy 15 (December 1990): 949–61.

• Lesser, J. “Resale of the Columbia River Treaty Downstream Power Benefits: One

Road From Here to There.” Natural Resources Journal 30 (July 1990): 609–28.

• Lesser, J., and J. Weber. “The 65 M.P.H. Speed Limit and the Demand for Gasoline: A

Case Study for the State of Washington.” Energy Systems and Policy 13 (July 1989):

191–203.

• Lesser, J. “The Economics of Preference Power.” Research in Law and Economics 12

(1989): 131–51.

Books and contributed chapters

• Lesser, J., and L.R. Giacchino, Principles of Utility Corporate Finance, Vienna, VA:

Public Utilities Reports, 2011.

• Lesser, J., and L.R. Giacchino. Fundamentals of Energy Regulation, Vienna, VA: Public

Utilities Reports, 2007.

• Lesser, J., and R. Zerbe. “A Practitioner’s Guide to Benefit-Cost Analysis.” In

Handbook of Public Finance, edited by F. Thompson, 221–68. New York: Rowan and

Allenheld, 1998.

• Lesser, J., D. Dodds, and R. Zerbe. Environmental Economics and Policy, Reading: MA:

Addison Wesley Longman, 1997.

Trade press publications

• Lesser, J., “Wind Power in the Windy City, Not There When Needed,” Energy Tribune,

July 25, 2012.

• Lesser, J. “How Will EPA’s Newest Regulations Affect Electric Markets?” Natural Gas

and Electricity (June 2012): 30-32.

• Lesser, J. “Pipeline Petulance,” Natural Gas and Electricity (March 2012): 27-29.



Page 21 of 25


• Lesser, J. “Global Warming, Climate Change, er Climate Volatility: 2012 and Beyond,”

Natural Gas and Electricity (January 2012): 22-24.

• Lesser, J., “Sunburnt: Solyndra, Subsidies, and the Green Jobs Debacle,” Natural Gas

& Electricity (November 2011):30-32..

• Lesser, J., “Illinois an Example of when the Wind Doesn’t Blow,” Natural Gas &

Electricity (September 2011):27-29.

• Lesser, J., “Salmon and Wind Dueling for Subsidies in the Pacific Northwest,” Natural

Gas & Electricity (July 2011):18-20.

• Lesser, J., “Nuclear Fallout,” Natural Gas & Electricity (May 2011):31-33.

• Lesser, J., “Texas Two-Step: EPA’s Greenhouse Gas Permitting Takeover,” Natural

Gas & Electricity (March 2011):21-23.

• Lesser, J., “Looking Forward: Energy and the Environment through 2012,” Natural

Gas & Electricity (January 2011):30-32.

• Lesser, J., “First-Mover Disadvantage: Offshore Wind’s False Economic Promises,”

Natural Gas & Electricity (November 2010): 26-28.

• Lesser, J., “Will the BP Disaster Affect Natural Gas and Electricity Markets?,” Natural

Gas & Electricity (August 2010): 23-24.

• Lesser, J., “Renewable Energy and the Fallacy of ‘Green’ Jobs,” The Electricity Journal

(August 2010):45-53.

• Lesser, J., “Let the Tough Choices Begin: Affordable or Green?,” Natural Gas &

Electricity (June 2010): 27-29.

• Lesser, J., “Will Shale Gas Production be Damaged by Too Many Fraccing

Complaints?,” Natural Gas & Electricity (April 2010): 31-32.

• Lesser, J., “As the Climate Turns: The Saga Continues,” Natural Gas & Electricity

(February 2010): 29-32.

• Lesser, J. and N. Puga, “Public Policy and Private Interests: Why Transmission

Planning and Cost-Allocation Methods Continue to Stifle Renewable Energy Policy

Goals,” The Electricity Journal (December 2009): 7-19.



Page 22 of 25


• Lesser, J, “Short Circuit: Will Electric Cars Provide Energy and Environmental

Salvation?” Natural Gas & Electricity (November 2009): 27-28.

• Lesser, J., “Green is the New Red: The High Cost of Green Jobs,” Natural Gas &

Electricity (August 2009): 31-32.

• Lesser, J., “Regulating Greenhouse Gas Emissions: EPA Gets Down,” Natural Gas &

Electricity (June 2009): 31-32.

• Lesser, J., “Being Reasonable While Regulating Greenhouse Gas Emissions under the

Clean Air Act,” Natural Gas & Electricity (April 2009): 30-32.

• Lesser, J., “Renewables, Becoming Cheaper, Are Suddenly Passé,” Natural Gas &

Electricity (February 2009): 30-32.

• Lesser, J., “Measuring the Costs and the Benefits of Energy Development,” Natural

Gas & Electricity (December 2008): 30-32.

• Lesser, J., “Comparing the Benefits and the Costs of Energy Development,” Natural

Gas & Electricity (October 2008): 31-32.

• Lesser, J., “New Source Review Is Still Anything but Routine,” Natural Gas &

Electricity (August 2008): 31-32.

• Lesser, J., and N. Puga, “PV versus Solar Thermal,” Public Utilities Fortnightly 146

(July 2008), pp. 16-20, 27.

• Lesser, J., “Kansas Secretary Unilaterally Bans Coal Plants,” Natural Gas & Electricity

(June 2008): 30-32.

• Lesser, J., “Seeing Through a Glass, Darkly, Banks Approach Coal-Fired Power

Financing,” Natural Gas & Electricity (April 2008): 29-31.

• Lesser, J., “The Energy Independence and Security Act of 2007: No Subsidy Left

Behind,” Natural Gas & Electricity (February 2008): 29-31.

• Lesser, J., “Control of Greenhouse Gases: Difficult with Either Cap-and-Trade or Tax-

and-Spend.” Natural Gas & Electricity (December 2007): 28-31.

• Lesser, J., “Déjà vu All Over Again: The Grass was not Greener Under Utility

Regulation.” The Electricity Journal 20 (December 2007): 35–39.



Page 23 of 25


• Lesser, J., “Blowin’ in the Wind: Renewable Energy Mandates, Electric Rates, and

Environmental Quality.” Natural Gas & Electricity (October 2007): 26-28.

• Lesser, J., “No Leg to Stand On.” Natural Gas & Electricity (August 2007): 28–31.

• Lesser, J., “Goldilocks Chills Out.” Natural Gas & Electricity (July 2007): 26–28.

• Lesser, J., “Goldilocks and the Three Climates.” Natural Gas & Electricity (April

2007): 22–24.

• Lesser, J., “Command-and-Control Still Lurks in Every Legislature.” Natural Gas &

Electricity (February 2007): 8–12.

• Lesser, J., and G. Israilevich, “The Capacity Market Enigma.” Public Utilities

Fortnightly 143 (December 2005): 38-42.

• Lesser, J., “Regulation by Litigation.” Public Utilities Fortnightly 142 (October 2004):

24–29.

• Lesser, J., “ROE: The Gorilla is Still at the Door.” Public Utilities Fortnightly 144 (July

2004): 19–23.

• Lesser, J., and S. Chapel, “Keys to Transmission and Distribution Reliability.” Public

Utilities Fortnightly 142 (April 2004): 58–62.

• Lesser, J. ,“DCF Utility Valuation: Still the Gold Standard?” Public Utilities Fortnightly

141 (February 15, 2003): 14–21.

• Lesser, J., “Welcome to the New Era of Resource Planning: Why Restructuring May

Lead to More Complex Regulation, Not Less.” The Electricity Journal 15 (July 2002):

20–28.

• Lesser, J., and C. Feinstein, “Identifying Applications for Distributed Generation:

Hype vs. Hope.” Public Utilities Fortnightly 140 (June 1, 2002): 20–28.

• Lesser, J., et al., “Utility Resource Planning: The Need for a New Approach.” Public

Utilities Fortnightly 140 (January 15, 2002): 24–27.

• Lesser, J., “Distribution Utilities: Forgotten Orphans of Electric Restructuring?”

Public Utilities Fortnightly 137 (March 1, 1999): 50–55.

• Lesser, J., “Regulating Distribution Utilities in a Restructured World.” The Electricity

Journal 12 (January/February 1999): 40–48.



Page 24 of 25


• Lesser, J., “Is it How Much or Who Pays? A Response to Rothkopf.” The Electricity

Journal 10 (December 1997): 17–22.

• Lesser, J., and M. Ainspan, “Using Markets to Value Stranded Costs.” The Electricity

Journal (October 1996): 66–74.

• Lesser, J., “Economic Analysis of Distributed Resources: An Introduction.”

Proceedings, First Annual Conference on Distributed Resources, Electric Power

Research Institute, Kansas City, MO, July 1995.

• Lesser, J., “Distributed Resources as a Competitive Opportunity: The Small Utility

Perspective.” Proceedings, First Annual Conference on Distributed Resources,

Electric Power Research Institute, Kansas City, MO, July 1995.

• Lesser, J., and M. Ainspan, “Retail Wheeling: Deja vu All Over Again?” The Electricity

Journal 7 (April 1994): 33–49.

• Lesser, J., “An Economically Rational Approach to Least-Cost Planning: Comment.”

The Electricity Journal 4 (October 1991).

• Lesser, J., “Long-Term Utility Planning Under Uncertainty: A New Approach.” Paper

presented for the Electric Power Research Institute: Innovations in Pricing and

Planning, May 1990.

• Lesser, J., “Centralized vs. Decentralized Resource Acquisition: Implications for

Bidding Strategies.” Public Utilities Fortnightly (June 1990).

• Lesser, J., “Most Value—The Right Measure for the Wrong Market?” The Electricity

Journal 2 (December 1989): 47–51.

Other Publications

• Lesser, J., and R. Bryce, “The High Cost of Closing Indian Point,” New York Post,

August 8, 2012.

• Lesser, J., “Cap-and-Trade for Gasoline?” Wall Street Journal, June 14, 2008, A14.

• Lesser, J., “Overblown Promises: The Hidden Costs of Symbolic Environmentalism.”

Livin’ Vermont (January/February 2005): 7, 27.

Selected speaking engagements

• “EPA Regulation of Generator Emissions – Key Market Issues,” Energy Bar

Association, Annual Meeting, April 28, 2012.



Page 25 of 25


• “Competitive Energy Markets: How are they Working?” Constellation Executive

Energy Forum, November 2, 2011.

• “The Failures of Transmission Planning and Policy,” Harvard Electric Policy Group,

February 25, 2010.

• “Financing the Smart Grid,” Energy Bar Association Seminar, Washington, DC,

December 4, 2009.

• “Renewable Power: At the Crossroads of Economics and Policy,” Presentation to the

Utilities State Government Organization, Newport, Rhode Island, July 13, 2009.

• “The Stimulus Act and Laws they Didn’t Teach You in Law School,” presentation to

the 27th National Regulatory Conference, Williamsburg, VA, May 19, 2009.

• “Rate Recovery for Capital Intensive Generation: Rate Base and Construction Work

in Progress,” Law Seminars International, Las Vegas, NV, February 5, 2009.

• “Financial Risks Faced by Regulated Utilities: Implications for the Cost of Capital and

Ratemaking Policies,” Law Seminars International, Las Vegas, NV, February 7, 2008.

• “Alternative Regulatory Structures and Tariff Mechanisms: Practical approaches to

providing low-cost, environmentally responsible energy and how to avoid some

dangerous pitfalls.” Western Energy Institute, October 1, 2007.

• “Economics and Energy Regulation.” Law Seminars International, Washington, DC,

March 15-16, 2007.

• “Energy in the Northeast: Resource Adequacy & Reliability.” Law Seminars

International, Boston, MA, October 16–17, 2006.

• “Energy in the Southwest: New Directions in Energy Markets and Regulations.” Law

Seminars International, Santa Fe, NM, July 14, 2006.

• “Energy and the Environment.” Vermont Journal of Environmental Law, South

Royalton, VT, March 10, 2006.

• “Electricity and Natural Gas Regulation: An Introduction.” Law Seminars

International, Washington, DC, March 17–18, 2005.



Page 1 of 2


JONATHAN A. LESSER, PHD

LIST OF FERC TESTIMONY AND PROCEEDINGS

Docket No. ER11-2777-002, et al. Southwestern Electric Cooperative, MidwesternIndependent System Operator, Inc. and Ameren Illinois Company.

Docket No. RP10-1398, Southwest Gas Corporation, El Paso Natural Gas Company.

Docket No. RP10-729-000, Shippers’ Group, Portland Natural Gas Transmission System.

Docket No. ER11-2224-000, Independent Power Producers of New York, New YorkIndependent System Operator, Inc.

Docket No. ER10-2026-000, Transmission Agency of Northern California. Re: Pacific Gas& Electric Company.

Docket No. ER10-160-000, M-S-R Public Power Agency, Southern California Edison Co.

Docket Nos. ER09-187-000 and ER10-160-000, M-S-R Public Power Agency, SouthernCalifornia Edison Co.

Docket No. EL08-014-002. Black Oak Energy, et al. Black Oak Energy, LLC v. PJMInterconnection, L.L.C.

Docket No. RP08-426-000. Southwest Gas Corporation and Salt River Project. El PasoNatural Gas Company.

Docket No. ER08-306-000. Shippers’ Group. Portland Natural Gas Transmission System.

Docket No. ER07-1344-000. Occidental Chemical Corp. Westar Energy, Inc.

Docket No. EL07-86-000, EL07-88-000, EL07-92-000 (Consolidated). EPIC MerchantEnergy, LLC, et al. Ameren Services Company v. Midwest Independent System Operator,Inc.

Docket No. ER08-1209-000. The NRG Companies. ISO New England Inc. and New EnglandPower Pool.

Docket No. EL08-67-000. Constellation Energy Group. Maryland Public UtilityCommission, et al., v. PJM Interconnection, LLC.


Docket No. EL12-___000.Exhibit No. NYP-3

Page 2 of 2

Docket No. ER08-283-000. Independent Power Producers of New York. New YorkIndependent System Operator, Inc.

Docket No. ER07-1182-000. Electric Power Supply Association. Midwest IndependentTransmission System Operator, Inc.

Docket No. RP06-407-000. BP Canada Energy Marketing Corp. Re: Gas TransmissionNorthwest.

Docket No. RP06-072-000. BP Canada Energy Marketing Corp. Re: Northern BorderPipeline.

Docket No. ER05-1284-000. Transmission Agency of Northern California. Re: Pacific Gas& Electric Company.

Docket Nos. ER03-409-000, ER03-666-000. Transmission Agency of Northern California.Re: Pacific Gas & Electric Company.

Docket No. RP05-163-000. Sierra Pacific Power Corp. Re: Paiute Pipeline Company.

Docket No. ER03-563-030. Duke Energy North America, LLC. Re: Devon Power, LLC, etal.

Docket No. EL05-17-000. Dynegy Power Marketing, LLC. KeySpan-Ravenswood, LLC v.New York Independent System Operator, Inc.

Docket No. EL05-17-000. KeySpan-Ravenswood, LLC. KeySpan-Ravenswood, LLC v. NewYork Independent System Operator, Inc.

Docket No. EL03-236-002. Electric Power Supply Association. Re: PJM Interconnection,Inc.

Docket No. RP03-398-000. Pipeline Shippers. Re: Northern Natural Gas Company.

Docket No. CP01-423-000., Dynegy. Re: Dynegy LNG Production Terminal, LP.

Docket No. RP99-485-000. Missouri Gas Energy Co., Re: Kansas Pipeline Corporation.

Technical hearings on wholesale electric capacity market design (2008).


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02

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03

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04

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Selection of Proxy Group Utilities Docket No. ER12-___-000Exhibit No. NYP-6

Schedule 1Page 1 of 2

Line

NoCompany name Ticker VL Report Date

Pays Constant or

Increasing

Dividend?

S&P Corporate

Credit rating

2011 Revenues

> $1 billion

Credit Rating Within

1 Notch of NiMo?

Total 2011 revenues

(millions)

Merger/Spin-off

Activity?

Include in Comparables

Group?

1 Allete ALE 6/22/2012 YES BBB+ YES $928

2 Alliant Energy LNT 6/22/2012 YES BBB+ YES YES $3,665 YES

3 Amer.Elec. Power AEP 6/22/2012 YES BBB YES $15,116

4 Ameren Corp. AEE 6/22/2012 YES BBB- YES $7,531

5 Avista Corp. AVA 8/3/2012 YES BBB YES $1,620

6 Black Hills BKH 8/3/2012 YES BBB- YES $1,272

7 CenterPoint Energy CNP 6/22/2012 YES BBB+ YES YES $8,450 YES

8 CH Energy Group CHG 5/25/2012 YES A YES $985 YES

9 Cleco Corp. CNL 6/22/2012 YES BBB YES $1,117

10 CMS Energy Corp. CMS 6/22/2012 YES BBB- YES $6,503

11 Consol. Edison ED 5/25/2012 YES A- YES YES $12,938 YES

12 Dominion Resources D 5/25/2012 YES A- YES YES $14,379 YES

13 DTE Energy DTE 6/22/2012 YES BBB+ YES YES $8,897 YES

14 Duke Energy DUK 5/25/2012 YES A- YES YES $14,529 YES

15 Edison International/SCE EIX 8/3/2012 YES BBB- YES $12,760

16 El Paso Electric EE 8/3/2012 NO BBB $918

17 Empire Dist. Elec. EDE 6/22/2012 NO BBB- $577

18 Entergy Corp ETR 6/22/2012 YES BBB YES $11,229 YES

19 Exelon Corp. EXC 5/25/2012 YES BBB YES $18,924 YES

20 FirstEnergy Corp. FE 5/25/2012 YES BBB- YES $16,258

21 Great Plains Energy GXP 6/22/2012 YES BBB YES $2,318

22 Hawaiian Elec. HE 8/3/2012 YES BBB- YES $3,242

23 IDACORP, Inc. IDA 8/3/2012 YES BBB YES $1,027

24 Integrys Energy TEG 6/22/2012 YES A- YES YES $4,709 YES

25 ITC Holdings ITC 6/22/2012 YES BBB+ YES $757 YES

26 MGE Energy MGEE 6/22/2012 YES AA- $546

27 NextEra NEE 5/25/2012 YES A- YES YES $15,341 YES

28 Northeast Utilities NU 5/25/2012 YES A- YES YES $4,466 YES

29 Northwestern Corp. NEW 8/3/2012 YES BBB YES $1,117

30 NV Energy NVE 8/3/2012 YES BB+ YES $2,943

31 OGE Energy OGE 6/22/2012 YES BBB+ YES YES $3,916 YES

32 Otter Tail Corp. OTTR 6/22/2012 YES BBB- YES $1,078

33 Pepco Holdings POM 5/25/2012 YES BBB+ YES YES $5,920 YES

34 PG&E Corp. PCG 8/3/2012 YES BBB YES $14,956

Docket No. EL12-____-000


Selection of Proxy Group Utilities Docket No. ER12-___-000Exhibit No. NYP-6


Line

NoCompany name Ticker VL Report Date

Pays Constant or

Increasing

Dividend?

S&P Corporate

Credit rating

2011 Revenues

> $1 billion

Credit Rating Within

1 Notch of NiMo?

Total 2011 revenues

(millions)

Merger/Spin-off

Activity?

Include in Comparables

Group?

35 Pinnacle West Capital PNW 8/3/2012 YES BBB YES $3,241

36 PNM Resources PNM 8/3/2012 YES BBB- YES $1,701

37 Portland General POR 8/3/2012 YES BBB YES $1,813

38 PPL Corp. PPL 5/25/2012 YES BBB YES $12,737

39 Public Serv. Enterprise PEG 5/25/2012 YES BBB YES $11,343

40 SCANA Corp SCG 5/25/2012 YES BBB+ YES YES $4,409 YES

41 Sempra Energy SRE 8/3/2012 YES BBB+ YES YES $10,036 YES

42 Southern Co. SO 5/25/2012 YES A YES YES $17,657 YES

43 TECO Energy TE 5/25/2012 YES BBB+ YES YES $3,343 YES

44 UIL Holdings UIL 5/25/2012 YES BBB YES $1,570

45 UNS Energy UNS 8/3/2012 YES BB+ YES $1,510

46 Vectren Corp. VVC 6/22/2012 YES A- YES YES $2,325 YES

47 Westar Energy WR 6/22/2012 YES BBB YES $2,171

48 Wisconsin Energy WEC 6/22/2012 YES A- YES YES $4,486 YES

49 Xcel Energy XEL 8/3/2012 YES A- YES YES $10,655 YES

Number of Firms 16



"Sustainable" or "br+sv" Growth Rate Calculation Docket No. ER12-___-000Exhibit No. NYP-6


Line

No.Company Symbol

Earnings Per

Share (EPS)

Dividend Per

Share (DPS)

Book Value

Per Share

(BV)

Internal

Growth (br)

Average

Market Price

Per Share

(MV)

MV/BV

2011

Common

Shares

Outstanding

2015-17

Common

Shares

Outstanding

AARG

2011-2015/17

External

Growth (sv)br+sv

[2] [3] [4] [6] [7] [8]

1 Alliant Energy LNT 3.02$ 1.90$ 29.65$ 3.84% 43.62$ 1.47 111.02 116.00 0.88% 0.42% 4.26%

2 CenterPoint Energy CNP 1.27$ 0.83$ 10.74$ 4.17% 19.71$ 1.84 426.00 431.00 0.23% 0.20% 4.37%

3 Consol. Edison ED 3.84$ 2.44$ 42.13$ 3.36% 59.65$ 1.42 292.90 293.00 0.01% 0.00% 3.36%

4 Dominion Resources D 3.30$ 2.23$ 22.93$ 4.79% 51.52$ 2.25 570.00 595.00 0.86% 1.08% 5.87%

5 DTE Energy DTE 3.94$ 2.49$ 44.55$ 3.31% 55.87$ 1.25 169.25 181.00 1.35% 0.34% 3.66%

6 Integrys Energy TEG 3.39$ 2.75$ 40.07$ 1.43% 54.16$ 1.35 77.91 77.90 0.00% 0.00% 1.43%

7 NextEra NEE 5.16$ 2.60$ 41.22$ 6.47% 63.68$ 1.54 416.00 430.00 0.66% 0.36% 6.83%

8 OGE Energy OGE 3.77$ 1.67$ 30.39$ 7.23% 52.29$ 1.72 98.10 101.00 0.58% 0.42% 7.65%

9 Pepco Holdings POM 1.36$ 1.11$ 19.98$ 1.17% 19.02$ 0.95 227.50 255.00 2.31% -0.11% 1.06%

10 SCANA Corp SCG 3.27$ 2.02$ 33.71$ 3.86% 45.80$ 1.36 130.00 160.00 4.24% 1.52% 5.38%

11 Sempra Energy SRE 4.79$ 2.37$ 45.05$ 5.45% 62.87$ 1.40 239.93 246.00 0.50% 0.20% 5.65%

12 Southern Co. SO 2.78$ 2.02$ 22.57$ 3.46% 45.04$ 2.00 865.10 940.00 1.67% 1.67% 5.12%

13 TECO Energy TE 1.44$ 0.94$ 11.55$ 4.35% 17.41$ 1.51 215.80 221.00 0.48% 0.24% 4.59%

14 Vectren Corp. VVC 2.03$ 1.47$ 19.18$ 2.84% 29.05$ 1.51 81.90 88.00 1.45% 0.74% 3.59%

15 Wisconsin Energy WEC 2.39$ 1.35$ 18.47$ 5.83% 36.38$ 1.97 230.50 223.00 -0.66% -0.64% 5.19%

16 Xcel Energy XEL 1.91$ 1.15$ 19.11$ 4.06% 27.15$ 1.42 486.49 515.00 1.15% 0.48% 4.54%

Notes:

[1] Source: Value Line Investment Survey (Arithmetic Average of 2011, 2012, and 2015/17 Forecast Values)

[2] Equals (EPS-DPS)/BV

[3] Equals arithmetic average of 6-month monthly high and low stock prices ending July 31, 2012

[4] Equals MV/BV

[5] Source: Value Line Investment Survey (Common Shares Outstanding in Millions Adjusted for Split)

[6] Equals annual growth of common shares outstanding in [5]

[7] Equals ([4]-1)*[6]

[8] Equals [2]+[7]

[1] [5]



I/B/E/S Earnings Growth Forecasts

July 31, 2012Docket No. ER12-____-000

Exhibit No. NYP-6Schedule 3Page 1 of 1

"%&$ #'! Company Name Ticker

I/B/E/S Consensus long-term

earnings forecast, as of July

31, 2012

1 Alliant Energy LNT 6.30%

2 CenterPoint Energy CNP 4.90%

3 Consol. Edison ED 3.02%

4 Dominion Resources D 5.00%

5 DTE Energy DTE 4.59%

6 Integrys Energy TEG 5.00%

7 NextEra NEE 5.23%

8 OGE Energy OGE 5.00%

9 Pepco Holdings POM 4.75%

10 SCANA Corp SCG 6.13%

11 Sempra Energy SRE 7.00%

12 Southern Co. SO 5.38%

13 TECO Energy TE 2.66%

14 Vectren Corp. VVC 5.00%

15 Wisconsin Energy WEC 6.05%

16 Xcel Energy XEL 5.08%

-69702* ./366! ,45/502" +0028821 %)$&($'%&'#



Average Monthly Closing Stock Prices and Dividend Yields: Proxy Companies Docket No. ER12-___-000Exhibit NYP-6


FERC Monthly Average Stock Prices, Low, High Dividend Yields

Company Stock Price Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Avg.

Alliant Energy High $42.58 $42.83 $44.81 $44.90 $45.37 $47.25

Low $41.81 $41.47 $41.49 $43.02 $42.99 $44.97

(High+Low)/2 $42.20 $42.15 $43.15 $43.96 $44.18 $46.11 $43.62

Annual Dividend $1.7000 $1.7250 $1.7250 $1.7250 $1.7500 $1.7500

Dividend Yield (Low) 3.99% 4.03% 3.85% 3.84% 3.86% 3.70% 3.88%

Dividend Yield (High) 4.07% 4.16% 4.16% 4.01% 4.07% 3.89% 4.06%

Dividend Yield (Average) 4.03% 4.09% 4.00% 3.92% 3.96% 3.80% 3.97%

CenterPoint Energy High $19.29 $19.52 $20.01 $20.24 $20.71 $21.19

Low $18.20 $18.75 $18.87 $19.52 $19.78 $20.46

(High+Low)/2 $18.75 $19.14 $19.44 $19.88 $20.25 $20.83 $19.71

Annual Dividend $0.7900 $0.7900 $0.7950 $0.7950 $0.8000 $0.8000




Consol. Edison High $58.27 $58.80 $58.85 $60.36 $63.48 $64.94

Low $57.07 $56.55 $56.56 $58.54 $60.29 $62.09

(High+Low)/2 $57.67 $57.68 $57.71 $59.45 $61.89 $63.52 $59.65

Annual Dividend $2.4000 $2.4050 $2.4050 $2.4050 $2.4100 $2.4100




Dominion Resources High $50.37 $50.84 $51.67 $52.06 $54.38 $54.97

Low $48.85 $49.75 $49.67 $51.15 $51.47 $53.01

(High+Low)/2 $49.61 $50.30 $50.67 $51.61 $52.93 $53.99 $51.52

Annual Dividend $1.9700 $2.0050 $2.0050 $2.0050 $2.0300 $2.0300










DTE Energy High $53.74 $55.31 $55.98 $56.28 $59.94 $61.66

Low $52.09 $52.78 $53.30 $54.52 $55.81 $58.97

(High+Low)/2 $52.92 $54.05 $54.64 $55.40 $57.88 $60.32 $55.87

Annual Dividend $2.3000 $2.3275 $2.3275 $2.3275 $2.3550 $2.3550




Integrys Energy High $53.23 $53.46 $53.96 $54.27 $57.31 $61.11

Low $51.16 $51.42 $50.58 $52.55 $53.65 $57.23

(High+Low)/2 $52.20 $52.44 $52.27 $53.41 $55.48 $59.17 $54.16

Annual Dividend $2.7200 $2.7200 $2.7200 $2.7200 $2.7200 $2.7200




NextEra High $59.66 $60.52 $63.95 $65.34 $68.81 $71.42

Low $58.81 $58.98 $61.26 $62.98 $64.59 $67.86

(High+Low)/2 $59.24 $59.75 $62.61 $64.16 $66.70 $69.64 $63.68

Annual Dividend $2.2000 $2.2500 $2.2500 $2.2500 $2.3000 $2.3000










OGE Energy High $52.95 $52.70 $53.55 $54.51 $53.90 $53.98

Low $51.27 $50.89 $50.54 $52.33 $50.02 $50.88

(High+Low)/2 $52.11 $51.80 $52.05 $53.42 $51.96 $52.43 $52.29

Annual Dividend $1.5000 $1.5175 $1.5175 $1.5175 $1.5350 $1.5350




Pepco Holdings High $19.59 $19.39 $18.66 $18.82 $19.57 $20.16

Low $18.91 $18.59 $18.06 $18.29 $18.96 $19.29

(High+Low)/2 $19.25 $18.99 $18.36 $18.56 $19.27 $19.73 $19.02

Annual Dividend $1.0800 $1.0800 $1.0800 $1.0800 $1.0800 $1.0800




SCANA Corp High $44.75 $45.17 $45.64 $46.46 $48.04 $49.65

Low $43.65 $43.63 $43.54 $45.11 $46.21 $47.73

(High+Low)/2 $44.20 $44.40 $44.59 $45.79 $47.13 $48.69 $45.80

Annual Dividend $1.9300 $1.9400 $1.9400 $1.9400 $1.9500 $1.9500










Sempra Energy High $58.11 $59.42 $64.22 $64.48 $68.88 $70.86

Low $56.36 $57.08 $60.59 $62.85 $63.50 $68.07

(High+Low)/2 $57.24 $58.25 $62.41 $63.67 $66.19 $69.47 $62.87

Annual Dividend $1.8300 $1.9100 $1.9100 $1.9100 $2.0400 $2.0400




Southern Co. High $43.97 $44.47 $45.03 $45.44 $47.80 $47.92

Low $43.14 $43.05 $43.44 $44.73 $45.48 $45.97

(High+Low)/2 $43.56 $43.76 $44.24 $45.09 $46.64 $46.95 $45.04

Annual Dividend $1.8700 $1.8875 $1.8875 $1.8875 $1.9050 $1.9050




TECO Energy High $17.67 $17.56 $17.58 $17.59 $18.07 $18.23

Low $17.20 $17.06 $16.52 $17.02 $16.99 $17.45

(High+Low)/2 $17.44 $17.31 $17.05 $17.31 $17.53 $17.84 $17.41

Annual Dividend $0.8500 $0.8650 $0.8650 $0.8650 $0.8700 $0.8700










Vectren Corp. High $29.36 $29.36 $29.10 $29.32 $29.93 $30.27

Low $28.12 $28.38 $27.72 $28.61 $29.06 $29.41

(High+Low)/2 $28.74 $28.87 $28.41 $28.97 $29.50 $29.84 $29.05

Annual Dividend $1.3900 $1.3950 $1.3950 $1.3950 $1.4000 $1.4000




Wisconsin Energy High $34.08 $34.72 $36.26 $37.55 $39.28 $40.97

Low $33.37 $33.56 $34.05 $35.68 $37.50 $39.58

(High+Low)/2 $33.73 $34.14 $35.16 $36.62 $38.39 $40.28 $36.38

Annual Dividend $1.0400 $1.0800 $1.0800 $1.0800 $1.1200 $1.1200




Xcel Energy High $26.09 $26.61 $26.82 $27.76 $28.75 $29.58

Low $25.72 $25.73 $25.76 $26.66 $27.70 $28.59

(High+Low)/2 $25.91 $26.17 $26.29 $27.21 $28.23 $29.09 $27.15

Annual Dividend $1.0250 $1.0325 $1.0325 $1.0325 $1.0400 $1.0400






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Niagara Mohawk Power Corporation Attachment 1Annual Revenue Requirements of Transmission Facilities Schedule 8Cost of Capital Rate

Shading denotes an input 2011

LineNo1 The Cost of Capital Rate shall equal the proposed Weighted Costs of Capital plus Federal Income Taxes and State Income Taxes.2 The Weighted Costs of Capital will be calculated for the Transmission Investment Base using NMPC’s actual capital structure and will equal the sum of (i), (ii), and (iii) below:

34 (i) the long-term debt component, which equals the product of the actual weighted average embedded cost to maturity of NMPC’s long-term debt outstanding during the year and the sum of (a) the ratio of actual long-term debt to total capital at year-en5 (b) the extent, if any, by which the ratio of NMPC's actual common equity to total capital at year end exceeds fifty percent (50%). Long term debt shall be defined as the average of the beginning of the year and end

6 of the year balances of the following: long term debt less the unamortized Discounts on Long-Term Debt less the unamortized

7 Loss on Reacquired Debt plus Unamortized Gain on Reacquired Debt. Cost to maturity of NMPC's long-term debt shall be defined as the cost of long term debt included in the debt discount expense and any loss or gain on reacquired debt.89 (ii) the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of NMPC’s preferred stock then outstanding and the ratio of actual preferred stock to total capital at year-end;

1011 (iii) the return on equity component shall be the product of the allowed return on equity o f 11.5% and the ratio of NMPC’s actual common equity to total capital at year-end, provided that such ratio

12 shall not exceed fifty percent (50%).13 WEIGHTED14 CAPITALIZATION COST OF COST OF EQUITY15 CAPITALIZATION Source: RATIOS CAPITAL CAPITAL PORTION1617 (i) LONG-TERM DEBT $2,375,583,081 Workpaper 6, Line 16b 49.53% 3.96%Workpaper 6, Line 17c 1.96%18 (ii) PREFERRED STOCK $28,984,701 FF1 112.3c 0.47% 3.66%Workpaper 6, Line 24d 0.02% 0.02%19 (iii) COMMON EQUITY $3,813,721,822 112.16c - FF1 112.3,12,15c 50.00% 11.50% Per Tariff 5.75% 5.75%2021 TOTAL INVESTMENT RETURN $6,218,289,604 100.00% 7.73% 5.77%

2223242526 9.2.2.(b) Federal Income Tax shall eq= ( A. + [ B / C] X Federal Income Tax Rate )27 ( 1 - Federal Income Tax Rate )2829 where A is the sum of the preferred stock component and the return on equity component, each as determined in Sections (a)(ii) and for the ROE set forth in (a)(iii) above, B is the Equity AFUDC component of Depreciation Expense for30 Transmission Plant in Service as defined at Section 14.1.9.1.16 (FF1 117.38c), and C is the Transmission Investment Base as shown at Schedule 6, Page 1 of 2, Line 28.3132 = ( 0.0577 +( $6,061,115 ) / $1,152,171,571 X 35% ) JLL33 ( 1 - 0.35 )3435 = 0.0339019

363738 9.2.2.(c) State Income Tax shall equa= ( A. + [ B / C] + Federal Income Tax ) X State Income Tax Rate39 ( 1 - State Income Tax Rate )4041 where A is the sum of the preferred stock component and the return on equity component as determined in (a)(ii) and (a)(iii) above , B is the Equity AFUDC component of Depreciation Expense for Transmission Plant in42 Service as defined at Section 14.1.9.1.16 above, and C is the Transmission Investment Base as shown at Schedule 6, Page 1 of 2, Line 28.43444546 = ( 0.0577 +( $6,061,115 ) / $1,152,171,571 + 0.0339019 ) X 7.10%47 ( 1 - 7.10% )4849 = 0.0074028

50515253 (a)+(b)+(c) Cost of Capital Rate = 11.86%

545556 9.2(a) A. Return and Associated Income Taxes shall equal the product of the Transmission Investment Base and the Cost of Capital Rate57585960 Transmission Investment Base $1,152,171,571 Schedule 6, page 1 of 2, Line 286162 Cost of Capital Rate 0.1186047 Line 536364 = Investment Return and Income Taxes $136,652,963 Line 60 * Line 62


Niagara Mohawk Power Corporation Attachment 1Annual Revenue Requirements of Transmission Facilities Schedule 8Cost of Capital Rate

Shading denotes an input 2011

LineNo1 The Cost of Capital Rate shall equal the proposed Weighted Costs of Capital plus Federal Income Taxes and State Income Taxes.2 The Weighted Costs of Capital will be calculated for the Transmission Investment Base using NMPC’s actual capital structure and will equal the sum of (i), (ii), and (iii) below:

34 (i) the long-term debt component, which equals the product of the actual weighted average embedded cost to maturity of NMPC’s long-term debt outstanding during the year and the sum of (a) the ratio of actual long-term debt to total capital at year-end; and5 (b) the extent, if any, by which the ratio of NMPC's actual common equity to total capital at year end exceeds fifty percent (50%). Long term debt shall be defined as the average of the beginning of the year and end

6 of the year balances of the following: long term debt less the unamortized Discounts on Long-Term Debt less the unamortized

7 Loss on Reacquired Debt plus Unamortized Gain on Reacquired Debt. Cost to maturity of NMPC's long-term debt shall be defined as the cost of long term debt included in the debt discount expense and any loss or gain on reacquired debt.89 (ii) the preferred stock component, which equals the product of the actual weighted average embedded cost to maturity of NMPC’s preferred stock then outstanding and the ratio of actual preferred stock to total capital at year-end;

1011 (iii) the return on equity component shall be the product of the allowed return on equity o f 11.5% and the ratio of NMPC’s actual common equity to total capital at year-end, provided that such ratio

12 shall not exceed fifty percent (50%).13 WEIGHTED14 CAPITALIZATION COST OF COST OF EQUITY15 CAPITALIZATION Source: RATIOS CAPITAL CAPITAL PORTION1617 (i) LONG-TERM DEBT $2,375,583,081 Workpaper 6, Line 16b 49.53% 3.96% Workpaper 6, Line 17c 1.96%18 (ii) PREFERRED STOCK $28,984,701 FF1 112.3c 0.47% 3.66% Workpaper 6, Line 24d 0.02% 0.02%19 (iii) COMMON EQUITY $3,813,721,822 112.16c - FF1 112.3,12,15c 50.00% 9.49% Per Tariff 4.75% 4.75%2021 TOTAL INVESTMENT RETURN $6,218,289,604 100.00% 6.730% 4.77%

2223242526 9.2.2.(b) Federal Income Tax shall eq= ( A. + [ B / C] X Federal Income Tax Rate )27 ( 1 - Federal Income Tax Rate )2829 where A is the sum of the preferred stock component and the return on equity component, each as determined in Sections (a)(ii) and for the ROE set forth in (a)(iii) above, B is the Equity AFUDC component of Depreciation Expense for30 Transmission Plant in Service as defined at Section 14.1.9.1.16 (FF1 117.38c), and C is the Transmission Investment Base as shown at Schedule 6, Page 1 of 2, Line 28.3132 = ( 0.0477 +( $6,061,115 ) / $1,152,171,571 X 35% ) JLL33 ( 1 - 0.35 )3435 = 0.0285172

363738 9.2.2.(c) State Income Tax shall equa= ( A. + [ B / C] + Federal Income Tax ) X State Income Tax Rate39 ( 1 - State Income Tax Rate )4041 where A is the sum of the preferred stock component and the return on equity component as determined in (a)(ii) and (a)(iii) above , B is the Equity AFUDC component of Depreciation Expense for Transmission Plant in42 Service as defined at Section 14.1.9.1.16 above, and C is the Transmission Investment Base as shown at Schedule 6, Page 1 of 2, Line 28.43444546 = ( 0.0477 +( $6,061,115 ) / $1,152,171,571 + 0.0285172 ) X 7.10%47 ( 1 - 7.10% )4849 = 0.0062270

50515253 (a)+(b)+(c) Cost of Capital Rate = 10.20%

545556 9.2(a) A. Return and Associated Income Taxes shall equal the product of the Transmission Investment Base and the Cost of Capital Rate57585960 Transmission Investment Base $1,152,171,571 Schedule 6, page 1 of 2, Line 286162 Cost of Capital Rate 0.1020442 Line 536364 = Investment Return and Income Taxes $117,572,426 Line 60 * Line 62



Page 1 of 2

Service List For NYAPP Complaint

Village of Akron [email protected] of Andover [email protected] of Andover [email protected] of Arcade [email protected] of Bergen [email protected] Commission of Boonville [email protected] of Brocton [email protected] of Churchville [email protected] of Churchville [email protected] of Frankfort [email protected] of Holley [email protected] of Ilion [email protected] of Little Valley [email protected] of Mayville [email protected] of Mohawk [email protected] of Philadelphia [email protected] of Salamanca [email protected] of Skaneateles [email protected] of Solvay [email protected] of Springville [email protected] of Theresa [email protected] of Wellsville [email protected] of Wellsville [email protected] of Westfield [email protected] of Fairport [email protected] York Municipal Power Agency/MEUA [email protected] Placid [email protected] Placid [email protected] Madison [email protected] Lake [email protected] Lake [email protected] [email protected] [email protected] Island [email protected] [email protected] Power & Light [email protected] White, LLP [email protected] White, LLP [email protected] Denton [email protected] Denton [email protected] Denton [email protected] [email protected] Public Power [email protected] Ohio [email protected] Municipal Electric Energy [email protected]

Cooperative, Inc.CCS Energy [email protected]



Page 2 of 2State of Vermont [email protected] NY State [email protected] NY State [email protected] [email protected] & Williams LLP [email protected] Ness Feldman Law Firm [email protected] Utilities Dept., RI [email protected] & Allen, Counselors at Law [email protected] Municipal Wholesale Elec. Co. [email protected] [email protected] Edison [email protected] Edison [email protected] [email protected] Coburn LLP [email protected] Regis Mohawk Tribe [email protected] Morrison Hecker LLP [email protected] Maine Power Co. [email protected]

[email protected] Gas & Electric [email protected] Hudson [email protected] Electric Utilities Assoc. of NY State [email protected] White, LLP [email protected] Ness Feldman Law Firm [email protected] Ness Feldman Law Firm [email protected], Weinberg, Genzer & Pembroke, P.C. [email protected] & Strawn LLP [email protected] & Strawn LLP [email protected] [email protected] [email protected] [email protected]


Exhibit No. NYP-10

UNITED STATES OF AMERICAFEDERAL ENERGY REGULATORY COMMISSION

New York Association of Public Power )Complainant, )

)v. )

) Docket No. EL12-___-000)

Niagara Mohawk Power Corporation )d/b/a National Grid, )

Respondent. )

NOTICE OF COMPLAINT

(March 6, 2009)

Take notice that on September 11, 2012, the New York Association of PublicPower (Complainant) filed a complaint against Niagara Mohawk Power Corporationd/b/a National Grid (Respondent) pursuant to Section 206 of the Federal Power Act, seekingan order to reduce the 11.5 percent return on equity (“ROE”) used in calculating rates fortransmission service under the New York Independent System Operator, Inc.’s(“NYISO”) Open Access Transmission Tariff (“OATT”) to a just and reasonable level at9.49 percent, inclusive of a 50 basis point adder for participation in the NYISO, with acorresponding overall weighted cost of capital of 6.73 percent.

Complainants certify that copies of the complaint were served on the contacts forNiagara Mohawk Power Corporation as listed on the Commission’s list of CorporateOfficials.

Any person desiring to intervene or to protest this filing must file in accordancewith Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR385.211, 385.214). Protests will be considered by the Commission in determining theappropriate action to be taken, but will not serve to make protestants parties to theproceeding. Any person wishing to become a party must file a notice of intervention ormotion to intervene, as appropriate. The Respondent’s answer and all interventions, orprotests must be filed on or before the comment date. The Respondent’s answer, motionsto intervene, and protests must be served on the Complainants.

The Commission encourages electronic submission of protests and interventions inlieu of paper using the “eFiling” link at http://www.ferc.gov. Persons unable to file


http://www.ferc.gov/

Docket No. EL12-___-000 -2- Exhibit No. NYP-10

electronically should submit an original and 14 copies of the protest or intervention to theFederal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426.

This filing is accessible on-line at http://www.ferc.gov, using the “eLibrary” linkand is available for review in the Commission’s Public Reference Room in Washington,D.C. There is an “eSubscription” link on the web site that enables subscribers to receiveemail notification when a document is added to a subscribed docket(s). For assistancewith any FERC Online service, please email [email protected], or call(866) 208-3676 (toll free). For TTY, call (202) 502-8659.

Comment Date: 5:00 pm Eastern Time on (insert date).

Kimberly D. Bose,Secretary


http://www.ferc.gov/

mailto:[email protected]

Exhibit No. NYP-10

UNITED STATES OF AMERICAFEDERAL ENERGY REGULATORY COMMISSION

New York Association of Public Power )Complainant, )

)v. )

) Docket No. EL12-___-000)

Niagara Mohawk Power Corporation ) d/b/a National Grid, )

Respondent. )

NOTICE OF COMPLAINT

(March 6, 2009)

Take notice that on September 11, 2012, the New York Association of Public Power (Complainant) filed a complaint against Niagara Mohawk Power Corporationd/b/a National Grid (Respondent) pursuant to Section 206 of the Federal Power Act, seeking an order to reduce the 11.5 percent return on equity (“ROE”) used in calculating rates for transmission service under the New York Independent System Operator, Inc.’s(“NYISO”) Open Access Transmission Tariff (“OATT”) to a just and reasonable level at 9.49 percent, inclusive of a 50 basis point adder for participation in the NYISO, with a corresponding overall weighted cost of capital of 6.73 percent.

Complainants certify that copies of the complaint were served on the contacts for Niagara Mohawk Power Corporation as listed on the Commission’s list of Corporate Officials.

Any person desiring to intervene or to protest this filing must file in accordance with Rules 211 and 214 of the Commission’s Rules of Practice and Procedure (18 CFR 385.211, 385.214). Protests will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make protestants parties to the proceeding. Any person wishing to become a party must file a notice of intervention or motion to intervene, as appropriate. The Respondent’s answer and all interventions, or protests must be filed on or before the comment date. The Respondent’s answer, motions to intervene, and protests must be served on the Complainants.

The Commission encourages electronic submission of protests and interventions in lieu of paper using the “eFiling” link at http://www.ferc.gov. Persons unable to file


Docket No. EL12-___-000 -2- Exhibit No. NYP-10

electronically should submit an original and 14 copies of the protest or intervention to the Federal Energy Regulatory Commission, 888 First Street, NE, Washington, DC 20426.

This filing is accessible on-line at http://www.ferc.gov, using the “eLibrary” link and is available for review in the Commission’s Public Reference Room in Washington, D.C. There is an “eSubscription” link on the web site that enables subscribers to receive email notification when a document is added to a subscribed docket(s). For assistance with any FERC Online service, please email [email protected], or call (866) 208-3676 (toll free). For TTY, call (202) 502-8659.

Comment Date: 5:00 pm Eastern Time on (insert date).

Kimberly D. Bose,Secretary


Document Content(s)

NYAPP Complaint Against NMPC.PDF......................................1-139

NYAPP Notice of Complaint (D0137594).DOC..............................140-141
