Petition for Writ of Certiorari — Nazarian v. PPL Energyplus, LLC, 135 S. Ct. 1582 (2015) (No. 14-614)

Supreme Court brief2015

Ask Donna

What actually matters in this document.

Text

“ OL4 NOV 25 20%

No. OFFICE OF THE CLERK

In the

Supreme Court of the United States

DOUGLAS R.M. NAZARIAN, ET AL.,

Petitioners,

Vv.

PPL ENERGYPLUS, L.L.C., ET AL.,

Respondents.

On Petition for a Writ of Certiorari to the

United States Court of Appeals for the

Fourth Circuit

PETITION FOR A WRIT OF CERTIORARI

Scott H. STRAUSS*

*Counsel of Record

PETER J. HOPKINS

JEFFREY A. SCHWARZ

Spiegel & McDiarmid LLP

1875 Eye Street, NW, Suite 700

Washington, DC 20006

(202) 879-4000

scott.strauss@spiegelmcd.com

Counsel for Petitioners

November 2014

PRE I ge Ai A an ie tr IE Bie I

WILSON-EPES PRINTING CO., INC. — (202) 789-0096 - WASHINGTON, D C. 20002

QUESTIONS PRESENTED

The Federal Power Act (FPA) splits authority

among states, utilities, and the Federal Energy Regu-

latory Commission (FERC). States regulate generation

facilities and retail utility power purchases, but may

not set wholesale rates. Wholesale energy sellers set

their own rates. FERC has exclusive jurisdiction to re-

view them and determine their legality.

In much of the country, independent system opera-

tors run multi-state transmission systems and whole-

sale energy markets. PJM Interconnection LLC (PJM),

an operator whose region includes Maryland, procures

by auction the generation capacity it expects the region

to need for a one-year period beginning three years lat-

er. Looking beyond that horizon and concerned that

facility retirements could degrade reliability, Maryland

decided it needed new generation. It solicited offers,

and required retail utilities to accept the winning bid.

The resulting contracts obligate the bidder to build a

plant and make it available to PJM for twenty years,

while the retail utilities pay (or receive) the difference

between the contract and PJM auction prices. The

Fourth Circuit held Maryland’s actions field and con-

flict preempted—contrary to the FPA’s structure and

decisions of this Court, the D.C. Circuit, and FERC.

The questions presented are:

1. When a seller offers to build generation and sell

wholesale power on a fixed-rate contract basis,

does the FPA field-preempt a state order direct-

ing retail utilities to enter into the contract?

2. Does FERC’s acceptance of an annual regional

capacity auction preempt states from requiring

retail utilities to contract at fixed rates with

sellers who are willing to commit to sell into the

auction on a long-term basis?

PARTIES TO THE PROCEEDING

Petitioners (defendants in the district court and

appellants in the court of appeals) are Douglas R.M.

Nazarian, Harold Williams, Lawrence Brenner, Kelly

Speakes-Backman, and W. Kevin Hughes, who were

sued in their official capacities as the Chairman and

Commissioners of the Maryland Public Service

Commission. Rule 29.6 does not apply. Petitioner

Nazarian was Chairman when the relevant orders

were issued, but is no longer a member of the

Commission. Petitioner Hughes is now Chairman.

CPV Maryland, LLC is filing a separate petition for

a writ of certiorari. CPV was a defendant in the district

court and an appellant before the court of appeals.

Respondents (plaintiffs in the district court and ap-

pellees in the court of appeals) are: PPL EnergyP lus,

LLC; PPL Brunner Island, LLC; PPL Holtwood, LLC;

PPL Martins Creek, LLC; PPL Montour, LLC; PPL

Susquehanna, LLC; Lower Mount Bethel Energy, LLC;

PPL New Jersey Solar, LLC; PPL New Jersey Biogas,

LLC; PPL Renewable Energy, LLC; PSEG Power LLC;

and Essential Power, LLC.

TABLE OF CONTENTS

Page

QUESTIONS PRESENTED ................cccccccccocecccceeeeeees i

PARTIES TO THE PROCEEDING.....0000000000.en. ii

ia 1

I aa ltl 4

ERR ae ee Nm rem ea wee! 4

CONSTITUTIONAL AND STATUTORY

REESE EALERTS 4

IIT citeiesniiinssasinsieibincinianialtiapciinicleiidlaciataaliet lacs laa 4

REASONS FOR GRANTING THE PETITION ......... 9

I. The decision contorts the FPA’s rate machinery,

contrary to precedent, and thereby harms the

states, public utilities, and FERC. ..................... 10

A. The decision conflicts with decades of FPA

Ee 11

B. The decision conflicts with D.C. Circuit

precedent and FERC’s orders......................... 14

1. The decision elevates PJM’s tariff above

CPV’s rate-setting authority, contrary to

Se cescteasceansinninnicmienintiniatinnttunigesi 15

2. The decision conflicts with precedent on the

coexistence of contracts and markets. ....... 16

Il. The decision jeopardizes dozens of state laws and

billions in private investment. ........................... 18

III. The decision creates a generation-planning

vacuum, and will reduce investment in needed

EE Se aR ae Sete na Ce eee 26

A. The decision erects barriers to long-term

contracting needed to support investment. ...26

B. Neither wholesale markets nor FERC can

substitute for state-supervised generation

planning and contracting. .......................0.--++- 28

C.The decision guts the states’ authority at the

EEE SES See OO eee 30

OT ctrrnenncnctetnnsmiennessnnincsenstonipesenseemenegnane 31

TABLE OF CONTENTS TO APPENDIX

Page

Appendix A: Opinion, PPL EnergyPlus LLC

v. Nazarian, 753 F.3d 467 (4th Cir. 2014).......... la

Appendix B: Order No. 84815, In re Whether

New Generating Facilities Are Needed to

Meet Long-Term Demand for Standard

Offer Service, 297 P.U.R.4th 336 (Md.

I a 29a

Appendix C: Memorandum of Decision,

PPL EnergyPlus LLC v. Nazarian, 974 F

Supp. 2d 790 (D. Md. 2013)............................-+- 62a

Appendix D: Order Denying Rehearing,

PPL EnergyPlus LLC v. Nazarian, Nos.

13-2419, 13-2424 (4th Cir. June 30, 2014) ... 197a

Appendix E: Judgment, PPL EnergyPlus LLC

v. Nazarian, Nos. 13-2419, 13-2424 (4th

SEL ae eee 202a

Appendix F: U.S. Const., art. VI, cl. 2.............. 207a

Appendix G: Federal Power Act § 201,

a csienlicila 208a

Appendix H: Federal Power Act § 205,

EERE. de 21lla

Appendix I: Order Granting Extension of

Time to File Petition for a Writ of Certiorari,

Nazarian v. PPL Energy Plus, LLC,

No. 14A282 (U.S. Sept. 15, 2014). .................. 214a

TABLE OF AUTHORITIES

Page(s)

Federal Court Cases

Ark. Elec. Coop. Corp. v. Ark. Pub. Serv.

Comm'n, 461 U.S. 375 (1983)..............................-. 1

Atl. City Elec. Co. v. FERC, 295 F.3d 1 (D.C.

Cir. 2002) (Atlantic City), mandate enforced,

329 F.3d 856 (D.C. Cir. 2003).. 2, 12, 15, 16, 21, 29

Barnstable v. Berwick, No. 14-10148-RGS,

2014 U.S. Dist. LEXIS 61892 (D. Mass.

May 2, 2014), appeal pending, No. 14-1597

(1st Cir. filed June 2, 2014)............................0006. 21

City of Tacoma v. Taxpayers of Tacoma,

EE a 3

City of Winnfield, La. v. FERC, 744 F.2d

ETE eee 12

Conn. Dep't of Pub. Util. Control v. FERC,

569 F.3d 477 (D.C. Cir. 2009).......................c0000000. 5

Fed. Mar. Comm'n v. S.C. State Ports Auth.,

I i i cee 11

Fla. Mun. Power Agency v. Fla. Power & Light

Co., 64 F.3d 614, 616 (11th Cir. 1996) ................ 18

Grand Council of the Crees (of Quebec) v.

FERC, 198 F.3d 950, 957 (D.C. Cir. 2000).......... 29

Mississippi Power & Light Co. v. Mississippi

ex rel. Moore, 487 U.S. 354 (1988)....................... 18

Morgan Stanley Capital Grp. Inc. v. Pub.

Util. Dist. No. 1, 554 U.S. 527 (2008)

(Morgan Stanley) ........... 2, 5, 10, 11—12, 16, 26, 27

vii

New England Power Co. v. New Hampshire,

EE EEE AR nee eS ll

New England Power Generators Ass'n v.

FERC, 757 F.3d 283 (D.C. Cir. 2014).................. 19

N.J. Bd. of Pub. Utils. v. FERC,

744 F.3d 74 (Sd Cir. 2014) ...............000..........ecceeee 19

New York v. FERC, 535 U.S. 1 (2002) ................... 11

NRG Power Mkig., LLC v. Me. Pub. Utils.

Comm’n, 558 U.S. 165 (2010) (NRG) ........ 2, 12, 16

Permian Basin Area Rate Cases, 390 U.S.

EIRENE eee eee 12

PPL EnergyPlus, LLC v. Solomon, 766 F.3d

241 (3d Cir. 2014) (Solomon)..................... 3, 20, 30

United Gas Pipe Line Co. v. Memphis Light,

Gas & Water Div., 358 U.S. 103 (1958)............... 15

United Gas Pipe Line Co. v. Mobile Gas Serv.

Corp., 350 U.S. 332 (1956) (Mobile) .......... 2,11, 12

Federal Agency Cases

Cal. Pub. Utils. Comm’n, 132 FERC 4 61,047,

clarified, 133 FERC 4 61,059 (2010), reh’g

denied, 134 FERC ¥ 61,044 (2011)... 13

Cal. Pub. Utils. Comm’n, 134 FERC § 61,044

RCAC EEE ea ee, OE RT RS AY Fe 13

CPV Shore, L.L.C., 148 FERC § 61,096 (2014)....... 9

Midcontinent Indep. Sys. Operator, Inc., 148

clit 16

New England States Comm. on Elec. v.

ISO New England Inc., 142 FERC § 61,108

RECS SER ESE RR Eevee a 8 ore RO ere 17

PJM Interconnection, L.L.C., 115 FERC

SITE ESE Maactss 50S aA Le Oe 17

PJM Interconnection, L.L.C., 1385 FERC

61,022, on reh’g, 137 FERC § 61,145 (2011),

petition for review denied sub nom. N.J. Bd.

of Pub. Utils. v. FERC, 744 F.3d 74 (3d Cir.

PJM Interconnection, L.L.C., 137 FERC

{ 61,145 (2011), petition for review denied

sub nom. N.J. Bd. of Pub. Utils. v. FERC,

744 F.3d 74 (3d Cir. 2014)...............0..0...... 8, 18, 29

United Illuminating Co., 123 FERC

SEER a 9 Se 25

State Court Cases

Commonwealth Edison Co. v. Ill. Commerce

Comm'n, 16 N.E.3d 228, 233 (Ill. App. 2014) ..... 23

In re Calpine Corp., No. 24-C-12-002853

alt. Cty. ws A. Oct. 4, 2018), quertatte at

pdfs/mdbt2013-9.pdf, appeal pending but

stayed sub nom. Md. Office of People’s Counsel

v. Md. Pub. Serv. Comm'n, No. 1738, Sept.

Term 2013 (Md. Ct. Spec. App. docketed

a 7, 8,19

In re Review of Proposed Town of New Shoreham

Project, 25 A.3d 482 (R.1. 2011).......... ccc eee 23

State Agency Cases

DPUC Review of Peaking Generation Projects,

No. 08-01-01 (Conn. Dep’t. Pub. Util. Control

June 25, 2008), available at

ST eo ae ae a 23

In re Ga. Power Co.’s 2013 Integrated Resource Plan,

No. 36498 (Ga. Pub. Serv. Comm’n July 11, 2013),

available at http://goo.gl/trbZKA ..................00..0.. 24

In re Whether New Generating Facilities

Are Needed to Meet Long-Term Demand

for Standard Offer Service, Order No. 84815,

297 P.U.R.4th 336 (Md. Pub. Serv. Comm’n

naa i iniintatintiahseeeaiiiiiiiidsid 1, 5,6

Petition for Initiation of Proceeding to Examine

Proposal for Continued Operation of R.E.

Ginna Nuclear Power Plant, Order Directing

Negotiation of a Reliability Support Service

Agreement and Making Related Findings,

No. 14-E-0270 (N.Y. Pub. Serv. Comm'n Nov. 14,

2014), available at http://goo.gl/TNg213............. 22

Proceeding on Motion of the Comm’n to

Examine Repowering Alts. to Util. Transmission

Reinforcements, Order Addressing Repowering

Issues and Cost Allocation and Recovery,

No. 12-E-0577 (N.Y. Pub. Serv. Comm’n June 13,

2014) (Dunkirk Repowering Order), available

CO I I cevccccessccccessecscssesscesccsceceess 22

Re: Procurement Targets for Viable & Cost-

Effective Energy Storage Sys., Decision No.

13-10-040, 308 P.U.R.4th 213 (Cal. Pub. Utils.

I ae hibennetetienl 24

Federal Statutes

Le Cod | | | ace 4

OE, III orccececrenecssrensnensersionsnreevcevccnnsontsnonsnsten 9

EER Sn ae ere ae ne ey aa 9

Federal Power Act (FPA), 16 U.S.C.

S§ 791a—S25r ..............ccc00 1, 10, 11, 12, 13, 14, 30

§ 3(17)(A)(ii), 16 U.S.C. § 796(17)(A)(ii) 25

ES I inh nicatneencilanescceniiadied 4

§ 201(f), 16 U.S.C. § 824(f)....................... 14

§ 202(b), 16 U.S.C. § 824a(b) ssninaieinaianne 29

§ 205, 16 U.S.C. § 824d..................000. 4, 15-16

§ 207, 16 U.S.C. § 824f.........ececcccceseceseseeseeees 29

Public Utility Regulatory Policies Act of

1978 (PURPA), Pub. L. No. 95-617,

AREER Ls a an eee en 25

State Statutes

2013 Conn. Pub. Act No. 303, § 6 ..................... 21

2008 Mass. Legis. Serv. ch. 169......................... 20

2012 Mass. Legis. Serv. ch. 209......................42. 20

Me. Rev. Stat. tit. 35-A, §§ 3210-C(3)................ 24

Me. Rev. Stat. tit. 35-A, §§ 3210-C(6)................ 24

3 Rg Eee 23

i i SIN ios cccnensnectctantionauinaenions 23

Federal Administrative Regulations

a asieualienineteiel 13

enn 17

Promoting Wholesale Competition

Through Open Access Non-Discriminatory

Transmission Services by Public Utilities;

Recovery of Stranded Costs by Public

Utilities and Transmitting Utilities, Order

No. 888, 61 Fed. Reg. 21,539 (May 10, 1996),

FERC Stats. & Regs. § 31,036 (1996), clarified,

76 FERC 4 61,009 (1996), modified, Order No.

888-A, 62 Fed. Reg. 12,274 (Mar. 14, 1997),

FERC Stats. & Regs. 4 31,048 (1997), order

on reh’g, Order No. 888-B, 62 Fed. Reg.

64,688 (Dec. 9, 1997), 81 FERC 4 61,248

(1997), order on reh’g, Order No. 888-C,

82 FERC ¥ 61,046 (1998), affd in part and

remanded in part sub nom. Transmission

Access Policy Study Grp. v. FERC, 225 F.3d

667 (D.C. Cir. 2000), aff'd sub nom. New

York v. FERC, 535 U.S. 1 (2002).........................

U.S. Envtl. Protection Agency, Carbon

Pollution Emission Guidelines for Existing

Stationary Sources: Electric Utility Generating

Units, Proposed Rule, No. EPA-HQ-OAR-

2013-0602 (June 2, 2014), 79 Fed. Reg.

34,829 (June 18, 2014).....cccccccccccesecessesecseeeseeeeevees

State Administrative Regulations

Resolution E-4471 (Cal. Pub. Utils. Comm’n

Mar. 22, 2012), available at

TTT One e ETE

Other Authorities

An Act Relative to Clean Energy Resources,

H. 4187, 188th Gen. Court, Current Sess.

(Mass. 2014), available at https://malegislature.

gov/Bills/188/House/H4187 ...................02....000ee0e

xl]

Am. Elec. Power, Volatile Capacity Markets,

available at http://www.aepsustainability.

com/business/risk/volatile.aspx (last visited

I ae 27

Am. Pub. Power Ass’n, Power Plants Are

Not Built on Spec: 2014 Update, available at

http://appanet.files.cms-plus.com/PDFs/

94 2014 Power Plant Study.pdf.......................... 28

The Brattle Group, Second Performance

Assessment of P-JM’s Reliability Pricing

Model 11-15 (Aug. 26, 2011), available at

RTE SSRI eae ae 5, 27

The Brattle Grp., The Importance of Long-

Term Contracting for Facilitating Renewable

Energy Project Development (May 7, 2013)

(Brattle Report), available at http://goo.gl/

ESERIES REA AEES reece rel een nrneoe terete aaa 27, 28

Calpine Executes Contracts for Sutter

Energy Center With California Utilities,

Bus. Wire, May 7, 2012, available at

http:// ET ee 24

Corina Rivera Linares, P-JM’s Boston:

“World’s Largest and Fastest Fuel Change”

Taking Place Now, TransmissionHub (Oct. 22,

2014), available at http://goo.g/BWBxxM .......... 29

Dominion Va. Power, Request for Proposal

5-6 (Nov. 3, 2014), available at http://goo.

Elise Caplan, What Drives New Generation

Construction? An Analysis of the Financial

Arrangements behind New Electric

Generation Projects in 2011, Elec. J.,

I cons cracnsnepinieintenabinnesinoniamnien 28

Gwen Bredehoeft & Michelle Bowman,

State Renewable Energy Requirements

and Goals: Update through 2013, U.S.

Energy Information Admin., Annual Energy

Outlook 2014, Report No. DOE/EIA-

0383(2014), available at http://www.eia.gov/

forecasts/aeo/state_renewable.cfm (last

| EE eee 25

ISO New Eng!and, Finalized Auction

Results Confirm Slight Power System

Resource Shortfall in 2017-2018 (Feb. 28, 2014),

available at http://www.iso-ne.com/nwsiss/pr/

2014/fca8 final results final 02282014.pdf...... 27

Lance Duroni, JI. Court OKs Rate Hike to

Fund $2B FutureGen Coal Plant, Law360

(July 23, 2014), available at http://www.law360.

com/articles/560068/ill-court-oks-rate-hike-to-

-2b- - - EE Ae Ae ee SO Oe 23

Mathew J. Morey et al., Ensuring Adequate

Power Supplies for Tomorrow’s Electricity

Needs (June 16, 2014), available at http://goo.gl/

ESRI Eero a FoI Meee NnD 6 See SOMES 28

N.Y. Energy Highway Task Force, New York

Energy Highway Blueprint (2012), available at

http://www.nyenergyhighway.com/Blueprint.

ERR TERE OU AA SA aE Re ae 21, 22

Nat'l Ass’n of Regulatory Util. Comm’rs,

Competitive Procurement of Retail Electricity

Supply: Recent Trends in State Policies and

Utility Practices (July 2008), available at

I il eaieinpmimenemnancnniiie 19

Paul J. Hibbard, Analysis Grp., Inc., The

Impacts of the Green Communities Act on

the Massachusetts Economy: A Review of the

X1V

First Six Years of the Act’s Implementation

(Mar. 4, 2014), available at http://goo.gl/

aan lle 20

U.S. Chamber of Commerce, Assessing the

Impact of Potential New Carbon Regulations

in the United States (Inst. for 21st Century

Energy 2014), available at http://www.

ener TTT 27-28

U.S. Energy Information Admin., Most States

Have Renewable Portfolio Standards, Today

in Energy (Feb. 3, 2012), available at

http://www.eia.gov/todayinenergy/detail.cfm

?id=4850 (last visited Nov. 21, 2014)............000... 25

U.S. Envtl. Protection Agency, Clean Power

Plan Toolbox for States, http://www2.epa.gov/

cleanpowerplantoolbox (last visited Nov. 21,

U.S. P’ship for Renewable Energy Fin.,

Ramping up Renewables: Leveraging State

RPS Programs amid Uncertain Federal

Support 18, 24-26 (June 2012), available at

a caasaseaneniniiinils 25

INTRODUCTION

Electricity is the “life blood of modern society,”

App. 29a, so regulating utilities to ensure that citizens

have electricity when and where they need it is among

a state’s most important police powers. See Ark. Elec.

Coop. Corp. v. Ark. Pub. Serv. Comm'n, 461 U.S. 375,

377 (1983). States must monitor and, if needed, modify

the generation-resource mix serving their citizens. An

adequate and diverse resource portfolio supplies power

across a wide range of conditions and reduces the risk

that an event that affects only some resources could

imperil reliability. States that fail to meet these re-

sponsibilities run unacceptable risks that the lights

will go out—along with medical equipment, traffic

lights, water purification plants, and virtually every-

thing necessary to a modern economy and the well-

being of a state’s citizens. The Federal Power Act

(FPA), 16 U.S.C. §§ 791a—825r, preserved the states’

ability to manage their power supplies, but the Fourth

Circuit’s opinion cripples that ability.

Maryland needed new natural-gas-fired generation,

solicited proposals, and ordered its retail utilities to

contract with the winner. CPV Maryland, LLC agreed

to build a power plant and make its capacity and out-

put available to the wholesale electricity market for

twenty years. In exchange, CPV would receive fixed

contract rates and stable revenues that it could not

obtain without a contract. The Fourth Circuit struck

down Maryland’s action and invalidated the contracts

on grounds that (1) the state “set” rates for CPV’s sales

and (2) the rates differed from those set through an

annual auction that procures year-by-year capacity to

fulfill needs forecast by PJM Interconnection LLC

(PJM).

Those holdings are contrary to a half century of this

Court’s teaching on FPA ratemaking, as well as D.C.

Circuit precedent and Federal Energy Regulatory

Commission (FERC) orders. The field-preemption hold-

ing—that states impermissibly “set[]” wholesale rates

by directing retail utilities to contract with the winners

of competitive power-supply solicitations, App. 19a—

fails to recognize that sellers like CPV set their own

rates and can do so by contract, subject to FERC re-

view. United Gas Pipe Line Co. v. Mobile Gas Serv.

Corp., 350 U.S. 332, 341 (1956) (Mobile); Morgan Stan-

ley Capital Grp. Inc. v. Pub. Util. Dist. No. 1, 554 U.S.

527, 531 (2008) (Morgan Stanley); NRG Power Mkig.,

LLC v. Me. Pub. Utils. Comm'n, 558 U.S. 165, 171

(2010) (NRG). The advent of independent system oper-

ators did not deprive sellers of rate-setting power. Atl.

City Elec. Co. v. FERC, 295 F.3d 1 (D.C. Cir. 2002) (At-

lantic City), mandate enforced, 329 F.3d 856 (D.C. Cir.

2003). CPV responded to Maryland’s procurement by

offering the rate at which it would contract to build a

new plant and sell its output to PJM on a long-term

basis. Maryland’s directive to accept the offer neither

set CPV’s rate nor intruded on FERC’s review authori-

ty.

The conflict-preemption holding likewise flouts this

Court’s precedent on the relationship between short-

term markets and long-term contracts, Morgan Stan-

ley, as well as FERC’s orders. When FERC accepted

PJM’s capacity-auction tariff, it held expressly that

states could support new generation through long-term

bilateral agreements. And later, with full knowledge of

Maryland’s procurement, FERC specifically disclaimed

any conflict between the state’s actions and the whole-

sale market. FERC held instead that resources like

CPV’s are needed and economic if—as the CPV re-

source was—they are selected in the auction after bid-

ding based on their costs excluding contract revenues.

Indeed, no state-federal conflict was possible here, as

FERC was gatekeeper of PJM’s auction and CPV could

bid only as FERC allowed. Thus, the decision’s finding

that Maryland’s actions could “distort” PJM auction

price signals is an improper collateral attack on

FERC’s orders. City of Tacoma v. Taxpayers of Tacoma,

357 U.S. 320, 336 (1958).

These matters are exceptionally important. The de-

cision below imperils dozens of state laws under which

private parties are investing billions in needed genera-

tion plants, from clean-coal facilities in Illinois to off-

shore wind in Massachusetts. The Third Circuit

already followed its sister Circuit’s lead in striking

down a law to support new gas-fired generation in New

Jersey, PPL EnergyPlus, LLC v. Solomon, 766 F.3d 241

(3d Cir. 2014) (Solomon),' and several other challenges

based on the Fourth Circuit’s decision are pending

elsewhere.

Going forward, the attacks leveled by this decision

and its progeny will sow uncertainty, stifle investment

in needed facilities, and open a dangerous generation-

planning vacuum. Volatile short-run electricity prices

rarely suffice to induce investment in expensive, long-

lived assets, and, even if they could do so, they would

not direct it to the right facilities. By design, the

wholesale markets focus only on preserving short-run

reliability at least cost, and are blind to long-run relia-

bility, fuel diversity, environmental concerns, and simi-

lar matters. Meanwhile, FERC lacks authority to

require utilities to build or buy what the market fails

| We understand that separate petitions for certiorari will seek

review of Solomon, which raises the same field-preemption ques-

tion as this case but did not reach the conflict-preemption ques-

tion.

to elicit. States must provide that backstop. But the

decision undercuts their ability to do so.

OPINIONS BELOW

The Fourth Circuit's opinion (App. la—28a) is re-

ported at 753 F.3d 467. The district court’s decision

(App. 62a—196a) is reported at 974 F.Supp. 2d 790.

JURISDICTION

The court of appeals entered judgment on June 2,

2014. Petitioners Nazarian et al. (acting collectively as

the Maryland Public Service Commission) filed a time-

ly petition for rehearing and rehearing en banc on

June 16, 2014. The court of appeals denied rehearing

on June 30, 2014. App. 197a—201la. On September 15,

2014, the Chief Justice extended until November 27,

2014 the time for filing petitions for a writ of certiorari

to review the Fourth Circuit’s judgment. App. 214a—

216a. This Petition is therefore timely. This Court has

jurisdiction under 28 U.S.C. § 1254(1).

CONSTITUTIONAL AND STATUTORY

PROVISIONS

Article VI, Clause 2, of the United States Constitu-

tion is reproduced at App. 207a. FPA section 201, 16

U.S.C. § 824, is reproduced in pertinent part at App.

208a—210a. FPA section 205, 16 U.S.C. § 824d, is re-

produced in pertinent part at App. 21la—213a.

STATEMENT

PJM is a “regional transmission organization” that

operates the electricity transmission system and ad-

ministers wholesale energy markets in a region that

spans the District of Columbia and parts of 13 states,

including Maryland.? PJM’s responsibilities include

ensuring short-term electric-system reliability, and to

that end it holds an annual auction to secure the quan-

tity of electric generation capacity that it expects the

region to need during a one-year period beginning

three years later. PJM’s auction procedures, estab-

lished in a FERC-filed tariff, see App. 8la, set the

amount of the capacity to be procured in each subre-

gion of PJM, select the least-cost resources, and pay a

uniform “clearing” price within each subregion for each

megawatt of selected capacity. App. 1la, 98a-102a. The

price is set by the most costly (or “marginal”) resource

needed to meet the subregional requirement. Jd.

Annual clearing prices fluctuate greatly. App. 98a.‘

And while new resources can lock in for three years the

price set by the first PJM auction in which they are

selected, App. 1la-12a, this system has not induced the

development of major new generation facilities in Mar-

yland or other eastern PJM states. App. 37a, 53a.

The absence of new generation concerned Mary-

land, and became critical as the fate of its existing

power supplies became less certain. PJM itself identi-

fied 2,320 megawatts of Maryland’s generation facili-

ties as being at “high risk” of retirement. App. 34a-35a.

2 App. 10a, 82a-83a; cf. Morgan Stanley, 554 U.S. at 536 (describ-

ing regional transmission organizations).

3 “Capacity” is “not electricity itself but the ability to produce it

when necessary.” Conn. Dep't of Pub. Util. Control v. FERC, 569

F.3d 477, 479 (D.C. Cir. 2009). “It amounts to a kind of call option

that electricity transmitters purchase from parties—generally,

generators—who can ... produce ... when required.” Jd.

4 See also The Brattle Group, Second Performance Assessment of

PJM’s Reliability Pricing Model 11-15 (Aug. 26, 2011), available

at http://goo. gl/OldwX.

The Maryland Public Service Commission investi-

gated the state’s need for new generation and, in paral-

lel, directed retail utilities to solicit offers from

developers willing to build facilities. App. 30a-34a. The

commission ultimately concluded that Maryland need-

ed 650-700 megawatts of new natural-gas-fired genera-

tion capacity by 2015,5 and selected CPV’s offer as

providing the best price for Maryland ratepayers. App.

56a-57a.

The commission directed the state’s retail utilities

to enter into contracts based on CPV’s offer. App. 60a.

The contracts required CPV to build the plant and bid

its output into the PJM capacity auction and energy

markets for twenty years.® In turn they obligated the

retail utilities (and, ultimately, their ratepayers) to pay

CPV a fixed price, offset by whatever CPV earned from

PJM. If the contract’s capacity price exceeded a given

year’s auction clearing price, ratepayers would pay

CPV the difference; alternatively, if the PJM auction

price rose above the contract price, ratepayers would

receive the excess. But Maryland was unwilling to pay

CPV for capacity if its resource failed to clear the auc-

5 Maryland’s conclusion reflected “major” concerns with the “al-

ways uncertain and now even more uncertain future of [the] exist-

ing coal-fired generation” in Maryland and neighboring states,

App. 49a-51a, and a finding that additions of wind and solar gen-

eration would require “other dispatchable generation with flexibil-

ity to start quickly, a characteristic that our existing coal and

nuclear fleet does not have.” App. 52a (footnote omitted). Neither

the district court nor the Fourth Circuit questioned Maryland’s

conclusions.

6 Although the contracts require CPV to offer both capacity and

energy, the ensuing litigation focused on CPV's capacity sales and

their relationship to PJM’s auction. This petition focuses on those

matters. Where a resource clears PJM’s capacity auction as CPV

did here, it must then offer energy into PJM’s energy markets.

tion. The reason is straightforward: if ratepayers had

to pay CPV for capacity that did not clear, then, under

the PJM tariff, ratepayers would pay twice for capacity

to meet the same reliability need—once to CPV under

the contract and again for replacement resources pro-

cured by PJM’s auction. To avoid potential double

charges, the contracts obligated the retail utilities to

pay the contract price only for CPV capacity that

cleared PJM’s auction.

The contracts, known in the industry as “contracts

for differences,” were otherwise identical in purpose

and effect to bilateral power purchases. If the retail

utilities had purchased the power from CPV bilateral-

ly, then they (instead of CPV) would have bid the ca-

pacity into the PJM auction—to get “credit” for the ca-

capacity and avoid paying twice—and would have

passed through to ratepayers the contract cost and any

auction revenues earned by the resource. Under that

arrangement, CPV still would have received the con-

tract price, and ratepayers still would have covered the

difference between the resource’s contract cost and

auction revenues. The contracts for differences accom-

plished in one step what otherwise would have taken

two, while allocating to CPV the risk of its resource not

clearing the auction.

The retail utilities appealed the commission’s di-

rective that they enter into the contract.? But a Mary-

land state court upheld the commission’s order, finding

that it was “directly related to ensuring reliable service

and protecting the public safety” and fit well within the

7 In re Calpine Corp., No. 24-C-12-002853 (Balt. Cty. Cir. Ct. Oct.

4, 2013), available at http://www.courts.state.md.us/businesstech/

pdfs/mdbt2013-9.pdf, appeal pending but stayed sub nom. Md.

Office of People’s Counsel v. Md. Pub. Serv. Comm'n, No. 1738,

Sept. Term 2013 (Md. Ct. Spec. App. docketed Nov. 6, 2013).

commission’s “broad supervisory and regulatory pow-

ers” to ensure that retail electric service is “safe, ade-

quate, just, reasonable, economical, and efficient.” Jn re

Calpine, slip op. at 16-17 (quotation omitted).

Reacting to both the Maryland contract and a larger

state-sponsored generation procurement in New Jer-

sey, some existing generators complained to FERC that

sellers with such contracts would bid their resources

into PJM’s capacity auction at artificially low (state-

subsidized) prices, thereby distorting the auction.

FERC responded by ensuring that could not happen. It

modified the PJM auction rules to require offers for

contract-backed resources to be set by PJM (subject to

FERC review) based on the projects’ actual costs—

excluding contract revenues.®

CPV’s resource was bid into and cleared the PJM

auction in accordance with these modified rules. PJM

reviewed CPV’s bid and replaced it with PJM’s own

assessment of the resource’s “competitive, cost-based”

net cost of entry, based “solely on revenues from PJM-

administered markets as required by [the] PJM Tariff.”

App. 125a (quotations omitted). The PJM-calculated

bid for CPV’s resource was more than forty percent less

than the auction clearing price. App. 125a-126a. FERC

held that such resources are “economic,” “competitive,”

and “[do] not artificially suppress market prices,”? and

concluded that its bidding rules “reconcile[d]” any “ten-

sion” between state generation-development programs

and the wholesale market’s needs. '°

8 PJM Interconnection, L.L.C., 1385 FERC % 61,022, P 122, on

reh’g, 137 FERC ¥ 61,145 (2011), petition for review denied sub

nom. N.J. Bd. of Pub. Utils. v. FERC, 744 F.3d 74 (3d Cir. 2014).

9135 FERC 4 61,022, PP 175, 177.

10137 FERC § 61,145, P 4.

Dissatisfied with FERC’s rulings, PPL EnergyPlus

and other incumbent generators (Respondents here)

sued in federal district court under 28 U.S.C. § 1331,

alleging that Maryland had violated the Supremacy

Clause and Commerce Clause. App. 65a. The district

court held Maryland’s orders field preempted, did not

rule on conflict preemption, and rejected the Commerce

Clause challenge. App. 14a-15a, 194a. Maryland ap-

pealed the preemption rulings, and the court of appeals

had jurisdiction under 28 U.S.C. § 1291.

The court of appeals affirmed the field-preemption

holding, reasoning that, by ordering the retail utilities

to accept CPV’s offer and sign the contracts, Maryland

impermissibly “set[{]” a wholesale rate. App. 19a. Un-

like the district court, the appellate court also held

Maryland’s actions conflict preempted, on grounds that

they “distort[ed]” the capacity auction (App. 25a) and

gave CPV a longer period of price stability than it could

otherwise obtain through the PJM auction (App. 25a-

26a). Requests for rehearing and rehearing en banc

were denied. App. 201a.

FERC did not participate in either the district court

or appellate litigation. FERC subsequently ruled that

the decisions rendered the contracts void ab initio, and

precluded FERC from passing on their justness and

reasonableness. CPV Shore, LLC, 148 FERC 4 61,096,

PP 30, 32 (2014).

REASONS FOR GRANTING THE PETITION

The matters at issue here are exceptionally im-

portant. Electricity is central to daily life. Providing it

reliably—and choosing the facilities that produce it—

are essential to protecting health and welfare.

The Court should grant certiorari because the deci-

sion below distorts the FPA’s rate-setting machinery,

and conflicts irreconcilably with multiple decisions of

this Court and the D.C. Circuit. The field-preemption

ruling conflates FERC’s ability to review wholesale

rates with a seller's ability to set them, constricting

both roles while simultaneously impeding the states’

ability to oversee power-supply planning and procure-

ment. And the decision’s reasoning—that states im-

permissibly set rates by directing retail utilities to

contract with willing power sellers—threatens dozens

of state laws and orders promoting needed electric gen-

eration facilities. The conflict-preemption ruling simi-

larly strikes at one of the FPA’s central premises—the

role of long-term contracts in supporting investment in

new facilities—and ignores this Court’s teaching that

“diminishment of [that] role” was “one of the seeds” of

the energy crisis that roiled the western states. Mor-

gan Stanley, 554 U.S. at 539.

The result is a decision that bulldozes state police

powers, imperils existing state laws promoting genera-

tion development, and chills further efforts to support

new resources. And by impeding the states, the deci-

sion creates a dangerous generation-planning vacuum

that neither FERC nor the wholesale markets can fill.

I. The decision contorts the FPA’s rate

machinery, contrary to precedent, and

thereby harms the states, public utilities,

and FERC.

The decision turns the FPA’s rate-setting frame-

work on its head, in conflict with precedent of this

Court and the D.C. Circuit. And it thereby harms not

only the states but, also, wholesale energy sellers and

FERC.

A. The decision conflicts with decades of FPA

rate-setting precedent.

“Dual sovereignty” is a “defining feature” not only of

our Nation’s “constitutional blueprint,” Fed. Mar.

Comm'n v. S.C. State Ports Auth., 535 U.S. 743, 751

(2002), but also the FPA. The statute gives FERC ex-

clusive authority to review and potentially to modify

rates for wholesale sales of electric energy in interstate

commerce. New England Power Co. v. New Hampshire,

455 U.S. 331, 340 (1982). But the statute simultane-

ously preserves state authority over local matters like

retail electric rates, generation facilities, “integrated

resource planning and utility buy-side” decisions and

“utility generation and resource portfolios,” New York

uv. FERC, 535 U.S. 1, 24 (2002) (quoting FERC Order

No. 888).!!

State and federal FPA responsibilities interact with

each other and with the rate-setting role of electric en-

ergy sellers. Under the FPA, neither states nor FERC

set wholesale rates in the first instance. Utilities that

sell electric energy at wholesale set their own rates

subject to FERC review, Mobile, 350 U.S. at 341, and

may do so by entering into contracts. Morgan Stanley,

1! Promoting Wholesale Competition Through Open Access Non-

Discriminatory Transmission Services by Public Utilities; Recov-

ery of Stranded Costs by Public Utilities and Transmitting Utili-

ties, Order No. 888, 61 Fed. Reg. 21,539 (May 10, 1996), FERC

Stats. & Regs. J 31,036 (1996), clarified, 76 FERC § 61,009 (1996),

modified, Order No. 888-A, 62 Fed. Reg. 12,274 (Mar. 14, 1997),

FERC Stats. & Regs. § 31,048 (1997), order on reh’g, Order No.

888-B, 62 Fed. Reg. 64,688 (Dec. 9, 1997), 81 FERC 4 61,248

(1997), order on reh’g, Order No. 888-C, 82 FERC 4 61,046 (1998),

aff'd in part and remanded in part sub nom. Transmission Access

Policy Study Grp. v. FERC, 225 F.3d 667 (D.C. Cir. 2000), affd

sub nom. New York v. FERC, 535 U.S. 1 (2002).

554 U.S. at 531 (“[T]he FPA ... permits utilities to set

rates ... through bilateral contracts”). As this Court

explained, the FPA left electric energy sellers’ rate-

setting powers “unaffected,” Mobile, 350 U.S. at 343,

but required them to notify FERC so that the agency

could “examine]]” the rates and modify them if needed,

NRG, 558 U.S. at 171. The agency’s authority to pro-

tect the public interest is “paramount,” Mobile, 350

U.S. at 344, but its role remains “essentially passive

and reactive.” Atlantic City, 295 F.3d at 10 (quoting

City of Winnfield, La. v. FERC, 744 F.2d 871, 876 (D.C.

Cir. 1984) (Scalia, J.)).

And the FPA does not merely tolerate contracts. It

is “premised” on them. Permian Basin Area Rate Cases,

390 U.S. 747, 822 (1968). The “stability of supply ar-

rangements’ is a “dominant concern” under the Act,

NRG, 558 U.S. at 175 (quotation omitted), and con-

tracts play an “essential role” as a “key factor fostering

stability in the electricity market, to the long-run bene-

fit of consumers,” id. at 174 (citation omitted). That

remains true even if “rates for a subset of the public

might be high by historical standards” under a particu-

lar contract at a given point in time. Morgan Stanley,

554 U.S. at 551. The decision below, like the Ninth Cir-

cuit decision reversed in Morgan Stanley, “give[s] short

shrift to the important role of contracts in the FPA... ,

and ... threaten[s] to inject more volatility into the

electricity market by undermining a key source of sta-

bility.” Id.

The FPA establishes a system of interlocking au-

thority under which sellers decide the rates and terms

on which they are willing to sell, states may require

retail utilities to contract with willing sellers to devel-

op needed supplies, and FERC may review the result-

ing transactions. As FERC itself has held, states may

“dictate” the specific “generation resources from which

utilities may procure electric energy.” Cal. Pub. Utils.

Comm'n, 134 FERC 4 61,044, P 30 & n.62 (2011). And

though states may not impose prices on unwilling

sellers, they may choose among offers made by willing

sellers and require retail utilities to enter contracts,

subject to FERC review. Cal. Pub. Utils. Comm'n, 132

FERC 4 61,047, P 69, clarified, 133 FERC 4 61,059

(2010), reh’g denied, 134 FERC 4 61,044 (2011).

FERC’s rate-filing regulations expressly disclaim

any limitation on state authority to establish

“[c]lompetitive procedures for the acquisition of electric

energy, including demand-side management, pur-

chased at wholesale” and “(njon-discriminatory fees for

the distribution of such electric energy to retail con-

sumers for purposes established in accordance with

State law.” 18 C.F.R. § 35.27 That state-supervised

solicitations may result in wholesale sales contracts

raises no preemption concerns because a willing seller

must choose to sell and FERC may review and modify

the agreements. State decisions producing contracts

subject to FERC’s authority cannot be preempted by

that authority.

The decision below conflicts with all of this prece-

dent. It holds that Maryland usurped FERC’s whole-

sale rate-setting role—which the FPA assigns to

wholesale energy sellers, and not FERC. Maryland set

no rate: CPV set the rate here by bidding on Mary-

land’s solicitation and entering into the contracts based

on that bid. The decision likewise holds that Maryland

interfered with FERC’s regulation of wholesale mar-

kets—but FERC held otherwise. This Court and FERC

have both held that long-term contracts and short-term

markets can coexist. And, but for the decision below,

FERC could have reviewed the CPV contracts and if

necessary modified them to prevent any conflict.

The decision below, not Maryland’s procurement,

upsets the FPA’s orderly interlocking of authority.

Knowingly or not, the decision strips states of the pow-

er to control their generation portfolios. If directing

retail utilities to accept CPVs offer was field-

preempted because that action “set” a rate, then almost

any state order requiring retail utilities to contract

with the winner of a state-run power-supply solicita-

tion would be preempted. FERC’s field is not limited to

sales in PJM’s auction, but encompasses all wholesale

energy sales except narrow excluded categories. See,

e.g., FPA § 201(f), 16 U.S.C. § 824(f). And so, under the

decision, developers willing to build new facilities on

the basis of long-term contracts no longer can do so if

their counterparties act on state orders. This con-

strains wholesale power supplies and jeopardizes reli-

ability. And FERC loses the ability even to consider

contracts for needed supplies that the decision deters

or invalidates.

B. The decision conflicts with D.C. Circuit

precedent and FERC’s orders.

The decision treated PJM’s transmission tariff,

providing for annual capacity purchases and prices, as

a filed rate that CPV and Maryland could not vary and

that precluded them from entering into other ar-

rangements. This ignored (1) CPV’s rate-setting role as

a capacity seller, (2) the complementary roles of long-

term contracts and short-term power markets, and

(3) that annual sales pursuant to PJM’s tariff and

CPV’s contract commitment to offer capacity to PJM

each year for twenty years are different products.

1. The decision elevates PJM’s tariff

above CPV’s rate-setting authority,

contrary to Atlantic City.

PJM buys capacity annually under auction proce-

dures set forth in its tariff, but CPV—as the seller of

its plant’s capacity—has a statutory right to set rates

for those sales, subject to FERC review. CPV was will-

ing to commit to offer its plant’s capacity for twenty

years only on the basis of fixed contract rates. The

Fourth Circuit’s treatment of PJM’s tariff as supersed-

ing CPV’s right to set its own rates (subject to FERC

review) conflicts with D.C. Circuit precedent.

In Atlantic City, the D.C. Circuit held that utilities

cannot be forced to cede to PJM “the right to file rates

and terms for services rendered with [their] assets.”

295 F.3d at 9. There, transmission owners had given

PJM the right to operate their facilities, and signed a

contract under which they and PJM would share the

right to change the region’s transmission rate design,

subject to FERC review. FERC rejected the contract

and directed the transmission owners to cede their re-

maining rate-change authority to PJM, but the D.C.

Circuit reversed FERC’s decision. Jd. at 15.

The court emphasized that a public utility, “like the

seller of an unregulated commodity, has the right ... to

change its rates ... [at] will, unless it has undertaken

by contract not to do so.” Jd. at 10 (quoting United Gas

Pipe Line Co. v. Memphis Light, Gas & Water Div., 358

U.S. 103, 113-14 (1958)). Thus, FERC can neither

“force public utilities to file particular rates” under

FPA section 205 nor “prohibit public utilities from fil-

ing changes in the first instance,” because denying the

“ability to initiate rate design changes with respect to

services provided with their own assets ... eliminate[s]

the very thing that the statute was designed to pro-

tect.” Id.

So too here. Atlantic City’s reasoning compels the

conclusion that PJM’s tariff could not displace CPV’s

right to set its own rate for wholesale sales, subject to

FERC review. See Midcontinent Indep. Sys. Operator,

Inc., 148 FERC 4 61,057, P92 (2014) (modifying

transmission organization tariff that purported to give

the organization unilateral rights to set rates paid to

generators through that tariff). The D.C. Circuit and

Fourth Circuit decisions thus conflict on the question

whether regional transmission organization tariffs

trump the rate-setting rights of utilities that own the

facilities used to provide FERC-jurisdictional service.

The decision below—that PJM’s short-term capacity-

purchase tariff precludes CPV from establishing rates

for longer-term sales to PJM, subject to FERC review—

harms both sellers and states that want to develop

needed new generation facilities on the basis of long-

term contracts.

2. The decision conflicts with precedent

on the coexistence of contracts and

1 .arkets.

The Fourth Circuit held Maryland’s actions conflict

preempted because the contracts contained different

rates and provided more stability than the PJM auc-

tion offered. As this Court has explained, however,

long-term contracts play an “essential role ... fostering

stability” in those markets, NRG, 558 U.S. at 174, and

it would be a “perverse rule” that enforces such con-

tracts only if they mirror volatile year-to-year ar-

rangements. Morgan Stanley, 554 U.S. at 547. That the

contract and auction prices are different is no surprise,

as the obligations assumed by short- and long-term

sellers are different. Sellers in PJM’s auction under-

take single-year obligations and thereafter can seek to

retire or sell their capacity outside PJM; the Maryland

contracts, however, obligate CPV to offer its capacity to

PJM continually for twenty years.

FERC understands the complementary nature of

long-term contracts and short-term markets, and has

sought to facilitate contracting by requiring regional

transmission organizations to provide a platform on

their websites “for market participants to post offers to

buy or sell power on a long-term basis.” 18 C.F.R.

§ 35.28(g)(2). As the district court found, one of the

ways that retail utilities can satisfy their share of the

region’s capacity needs, in lieu of “[b]eing assigned ca-

pacity in the [auction],” is by “[e]ntering into a bilateral

contract with a capacity resource” at a price deter-

mined by the parties. App. 90a.

FERC specifically addressed the use of long-term bi-

lateral contracts to support new facilities when it ac-

cepted the settlement creating PJM’s capacity auction.

West Virginia challenged the auction as intruding on

state jurisdiction over generation, but FERC responded

that it would not curtail states’ options, which included

the ability to “create an incentive for the construction

of new capacity by entering into long-term bilateral

agreements.” PJM Interconnection, L.L.C., 115 FERC

§ 61,079, P 172 (2006).'2 In other words, FERC said

states could do exactly what Maryland did: support

new generation with a long-term bilateral agreement.

FERC then established terms on which resources

supported by state contracts could participate in PJM’s

12 See also New England States Comm. on Elec. v. ISO New Eng-

land Inc., 142 FERC § 61,108, at 61,490 (2013) (LaFleur, Comm’r,

concurring in part) (“[S]tates have the unquestioned right to make

policy choices through the subsidization of capacity”).

auction without distorting prices, and CPV’s resource

cleared the auction on that basis. App. 125a-126a.

FERC held that its bidding rules “reconcile[d]” any

“tension” between state generation-development pro-

grams and the wholesale market's needs, PJM Inter-

connection, LLC, 137 FERC 4 61,145, P 4, and that re-

resources clearing in accordance with them, like CPV’s,

are “economic,” “competitive,” and “[do] not artificially

suppress market prices.” PJM Interconnection, L.L.C.,

135 FERC 4 61,022, PP 175, 177.

The premises of the decision below—that FERC re-

lies exclusively on short-term auction prices to support

new generation and that long-term contracts at differ-

ent prices end-run a filed rate—are couirary to FERC’s

rulings, the reality of how PJM’s auction functions, and

decisions of this Court. The decision’s reliance on Mis-

sissippi Power & Light Co. v. Mississippi ex rel. Moore,

487 U.S. 354 (1988), App. 20a, is thus misplaced and

the resulting conflict-preemption conclusion unfound-

ed. Bilateral contracts and centralized auctions coexist,

and naturally produce different prices for short-term

and long-term sales. As the two products are not the

same, there can be no conflict as a matter of law. See

Fla. Mun. Power Agency v. Fla. Power & Light Co., 64

F.3d 614, 616 (11th Cir. 1996) (no filed-rate bar for sale

of a different service).

Il. The decision jeopardizes dozens of state

laws and billions in private investment.

Maryland is not the only state acting to secure its

energy future. States throughout the Nation require

retail utilities to procure supply from specific resources

or resource types or to support them with financial con-

tracts for differences.

The reasoning of the decision below threatens all of

these arrangements. It does not matter whether the

resource sells power to retail utilities directly or to a

regional transmission organization or whether a state

has provided for retail competition.!3 Even states with

vertically-integrated utilities sometimes require those

utilities to solicit offers to buy power instead of build-

ing facilities themselves.'* If mandating solicitations

and purchases “sets” a wholesale rate, then every state

order requiring the purchase of a FERC-jurisdictional

product or service from a competitively-selected seller

would be field preempted. And, under the decision be-

low, every state order directing retail utilities to con-

tract for long-term capacity in PJM (or any other

'3 The decision asserts (App. 13a) that, by “abandon|ing] the verti-

cal integration model,” Maryland “relinquish{ed] ... the regulatory

autonomy [it] had formerly enjoyed with respect to traditional

utility monopolies.” Other courts of appeals, however, have found

no such relinquishment. N..J. Bd. of Pub. Utils. v. FERC, 744 F.3d

at 98 (FERC “permit[s] states to develop whatever capacity re-

sources they wish, ... while ... prevent/ing] the state’s choices from

adversely affecting wholesale capacity rates.”); New England Pow-

er Generators Ass'n v. FERC, 757 F.3d 283, 291 (D.C. Cir. 2014)

(“[S]tates remain free to subsidize the construction of new genera-

tors[;]” FERC simply regulates how they are offered into whole-

sale capacity auctions). Similarly, in dismissing the appeal of

Maryland’s order, the state court recognized that giving retail

customers “choice as to their electricity supplier” did not divest

state regulators of authority to “supervise and regulate” retail

utilities to “promote adequate, economical, and efficient delivery of

utility services.” In re Calpine, supra note 6, slip op. at 18 (quota-

tion omitted).

14 See Nat'l Ase’n of Regulatory Util. Comm'rs, Competitive Pro-

curement of Retail Electricity Supply: Recent Trends in State Poli-

cies and Utility Practices 1, 4 (July 2008), available at

http://goo.gV/zPpshw; see also Dominion Va. Power, Request for

Proposal 5-6 (Nov. 3, 2014) (seeking bids for up to 1600 megawatts

of power under a 10-20 year purchase agreement), available at

http://goo.g/TW1A Ve.

region with a short-term auction) would also be conflict

preempted.

Several important state initiatives already have

been struck down or challenged based on the decision

below. New Jersey—responding to reliability risks sim-

ilar to Maryland’s—enacted a law requiring its retail

utilities to solicit offers to build 2,000 megawatts of

new natural-gas-fired generation. The state commis-

sion then conducted a competitive solicitation and in-

structed its regulated retail utilities to enter into

contracts (similar to those at issue here) with sellers

offering three new power plants, two of which later

cleared the PJM auction under FERC’s modified rules.

Solomon, 766 F.3d at 248-49. Citing the Fourth Cir-

cuit, the Third Circuit held New Jersey’s statute field

preempted as impermissible wholesale rate-setting. Id.

at 253.15

Massachusetts requires retail utilities to enter long-

term contracts with renewable energy developers, sub-

ject to state approval.'6 The law has spurred develop-

ment of more than 1,000 megawatts of wind-powered

generation across New England, including one of the

Nation’s first and largest offshore wind projects: the

468-megawatt Cape Wind Project.!7 Cape Wind’s oppo-

nents have relied on the decision below in their at-

tempt to invalidate a Massachusetts utility's contract

to purchase Cape Wind power. Joint Opening Brief of

‘8 Unlike the Fourth Circuit, the Third Circuit expressed no opin-

ion on conflict preemption. Solomon, 766 F.3d at 246.

16 2008 Mass. Legis. Serv. ch. 169, § 83 (S.B. 2768); 2012 Mass.

Legis. Serv. ch. 209 (S.B. 2395).

17 See Paul J. Hibbard, Analysis Grp., Inc., The Impacts of the

Green Communities Act on the Massachusetts Economy: A Review

of the First Six Years of the Act’s Implementation 11 (Mar. 4,

2014), available at http://goo.gi/mMEsii.

Appellants, Town of Barnstable v. Berwick, No. 14-

1597, at 4, 25, 46 (1st Cir. Aug. 25, 2014) (“[A]s the

Fourth Circuit recently held, a state may not use its

regulatory authority over utilities to compel the utility

to enter into a wholesale contract”). Although the dis-

trict court dismissed the plaintiffs’ suit on sovereign-

immunity grounds, it also explained that there could

be no Supremacy Clause violation because Cape Wind

had set its rate and FERC could review it.'*

Connecticut allows state regulators to solicit pro-

posals for renewable resources, select winners, and

compe! retail utilities to enter long-term agreements.!9

Under this authority, Connecticut required retail utili-

ties to enter long-term fixed-price contracts with a 250-

megawatt wind project in Maine and a twenty-

megawatt solar project in Connecticut.”° A disappoint-

ed bidder challenged Connecticut’s actions, citing the

decision below. Allco Fin. Ltd., Notice of Additional

Authority 3-5, June 16, 2014, Allco Fin. Ltd.

New York has adopted a comprehensive plan to

modernize the state’s energy infrastructure.?! The plan

contemplates state-directed contracting for thousands

of megawatts of new resources or the temporarily con-

tinued operation of facilities that have proposed to re-

18 Barnstable v. Berwick, No. 14-10148-RGS, 2014 U.S. Dist. LEX-

IS 61892, at *29 n.26 (D. Mass. May 2, 2014) (citing Atlantic City),

appeal pending, No. 14-1597 (1st Cir. filed June 2, 2014).

19 2013 Conn. Pub. Act No. 303, § 6.

% See First Amended Complaint for Declaratory and Injunctive

Relief for Violations of the Supremacy Clause of the United States

Constitution and the Federal Power Act J 53 & Ex. C, Alico Fin.

Ltd. v. Esty, No. 3:13-cv-01874-JBA (D. Conn. Feb. 26, 2014).

21 See N.Y. Energy Highway Task Force, New York Energy High-

way Blueprint (2012), available at http://www.nyenergyhighway.

com/Blueprint.html.

tire but remain needed for reliability.22 Some of the

contracts include power purchases, while others pro-

vide compensation solely to build new facilities or alter

existing ones. Yet competitors have challenged even

the latter kinds of contracts as field and conflict

preempted, citing the decision below.”3

Numerous other mandated purchases either pre-

ceded the decision below or have not yet been chal-

lenged on preemption grounds (to our knowledge), but

exemplify the kinds of important state actions that the

decision below puts in jeopardy:

1. Illinois mandates that twenty-five percent of the

state’s electricity be generated by “clean coal fa-

cilities,” so it required utilities to enter twenty-

year purchase agreements with a consortium

22 See New York Energy Highway Blueprint 16-17; Order Address-

ing Repowering Issues and Cost Allocation and Recovery at 2-6,

Proceeding on Motion of the Comm'n to Examine Repowering Alts.

to Util. Transmission Reinforcements, No. 12-E-0577 (N.Y. Pub.

Serv. Comm'n June 13, 2014) (Dunkirk Repowering Order), avail-

able at http://goo.g/HETtK3.

23 See Dunkirk Repowering Order 13, 37-40; Order Directing Ne-

gotiation of a Reliability Support Service Agreement and Making

Related Findings 25-27, Petition for Initiation of Proceeding to

Examine Proposal for Continued Operation of R.E. Ginna Nuclear

Power Plant, No. 14-E-0270 (N.Y. Pub. Serv. Comm'n Nov. 14,

2014), available at http;://goo.gl/TNg213; Letter from Doreen U.

Saia, Attorney for Entergy Entities, to Hon. Kathleen H. Burgess,

Secretary, N.Y. Pub. Serv. Comm'n at 6-7, Proceeding on Motion of

the Comm'n to Examine Repowering Alts. to Util. Transmission

Requirements, No. 12-E-0577 (May 27, 2014), available at

http://goo.gl/5gF Qu5; Letter from David B. Johnson, Attorney for

Indep. Power Producers of N.Y., Inc., to Hon. Kathleen H. Bur-

gess, Secretary, N.Y. Pub. Serv. Comm'n at 4 & n.11, Dynegy Dan-

skammer LLC, Petition For Waiver of the Generation Facility

Retirement Notice Period & Requesting Other Related Relief, No.

13-E-0012 (Jan. 15, 2014), available at http://goo.g//G3etMi.

building the “world’s first coal-fueled, near-zero

emissions electric power plant,” a multi-billion-

dollar project.”4

2. Nevada has required electric utilities serving

densely-populated counties to retire at least 800

megawatts of coal-fired generation and to con-

struct, acquire, or contract for replacement ca-

pacity, including at least 350 megawatts of

renewable-energy facilities.25

3. Connecticut required its retail utilities to enter

long-term contracts for differences with develop-

ers of 678 megawatts of new “peaking” genera-

tion.76

4. Rhode Island required a retail utility to solicit

proposals for long-term contracts from renewa-

ble generators,?? and then approved the result-

ing power purchase agreements.”8

5. California required investor-owned retail utili-

ties to contract with the owner of a roughly 570-

24 See Commonwealth Edison Co. v. Ill. Commerce Comm'n, 16

N.E.3d 228, 233 (Ill. App. 2014) (quotation omitted); Lance Du-

roni, [1l. Court OKs Rate Hike to Fund $2B FutureGen Coal Plant,

cane (uly 23, 2014), re at oe nein een

25 Nev. Rev. Stat. § 704.7316.

26 Decision, DPUC Review of Peaking Generation Projects, No. 08-

01-01, slip op. at 51 (Conn. Dep’t. Pub. Util. Control June 25,

2008), available at http://goo.g/UOf8vv.

27 RI. Gen. Laws § 39-26.1-1 et seq.

% In re Review of Proposed Town of New Shoreham Project, 25

A.3d 482, 485-86 (R.I. 2011).

megawatt gas-fired generator to keep the plant

operating when it otherwise would retire.?9

6. In a groundbreaking step, California also re-

quired those utilities to procure 1,325 mega-

watts of electric energy “storage” facilities—such

as grid-scale batteries—with the procurements

to be overseen by the state commission.*®

7 Regulators required Georgia Power to procure

525 megawatts of new solar generation by com-

petitive solicitation, using an independent bid

evaluator per Commission rules.*!

8. Maine allows its state commission to direct re-

tail utilities to enter into long-term contracts for

electric capacity and energy selected through

competitive procurements.®*?

9. Massachusetts is considering a bill to require re-

tail utilities to solicit up to 18,900 gigawatt-

hours of clean energy per year, in addition to the

state’s renewable portfolio standard require-

ments, via fifteen- to twenty-five-year con-

tracts.*4

29 Resolution E-4471 (Cal. Pub. Utils. Comm’n Mar. 22, 2012),

available at http://goo.g/u8M7q7; Calpine Executes Contracts for

Sutter Energy Center With California Utilities, Bus. Wire, May 7,

2012, available at http://goo.gl/ssgJrp.

30 See Re: Procurement Targets for Viable & Cost-Effective Energy

Storage Sys., Decision No. 13-10-040, 308 P.U.R.4th 213 (Cal. Pub.

Utils. Comm'n 2013).

31 Final Order, In re Ga. Power Co.’s 2013 Integrated Resource

Plan, No. 36498, slip op. at 18 (Ga. Pub. Serv. Comm'n July 11,

2013), available at http://goo.gi/trbZkA.

32 Me. Rev. Stat. tit. 35-A, §§ 3210-C(3), (6).

33 An Act Relative to Clean Energy Resources, H. 4187, 188th Gen.

Court, Current Sess. (Mass. 2014), available at https://

malegi . Oo 7.

10. More generally, twenty-nine states and the Dis-

trict of Columbia have enacted enforceable re-

newable portfolio standards (RPS) or similar

laws,*4 which “set[] a minimum requirement for

the share of electricity to be supplied from des-

ignated renewable energy resources,” often tai-

loring the requirement “to best fit the State’s

particular resource base or local preferences.”*5

Some can be satisfied by purchasing non-FERC-

jurisdictional “Renewable Energy Credits,” but

others require the purchase of capacity or ener-

gy from those resources.*€

The decision below casts a deep shadow over these

and other mandated-purchase programs. The sheer

number of state laws and procurements endangered by

the decision underscores the need for immediate re-

view. Deferring review now on the supposition that the

% See Gwen Bredehoeft & Michelle Bowman, State Renewable

Energy Requirements and Goals: Update through 2013, U.S. En-

ergy Information Admin., Annual Energy Outlook 2014, a

No. DOE/EIA-0383(2014), available at http://www.eia.gov/

forecasts/aeo/state_renewable.cfm (last visited Nov. 21, 2014).

35 See U.S. Energy Information Admin., Most States Have Renew-

able Furtte Standards, ae in ws a 3, =m, availa-

visited Nov. 21, 2014).

% See U.S. P’ship for Renewable Energy Fin., Ramping up Renew-

ables: Leveraging State RPS Programs amid Uncertain Federal

Support 18, 24-26 (June 2012), available at http://goo.g/f6KxQw.

While some RPS-driven purchases will fall under the Public Utili-

ty Regulatory Policies Act of 1978 (PURPA), Pub. L. No. 95-617,

92 Stat. 3117, many will fall outside it because the resources ex-

ceed PURPA’s size thresholds, see 16 U.S.C. § 796(17)(A)(ii), or

because FERC has terminated PURPA purchase requirements in

certain markets, e.g., United Illuminating Co., 123 FERC

§ 61,269, P 1 (2008).

issues can be considered later runs the risk that tre-

mendous damage will be done in the meantime. Much

of the nation’s existing generation was built decades

ago and is out of step with current needs. The fleet re-

quires an overhaul, and the states are the regulators

with authority to oversee it. But the Third and Fourth

Circuit decisions threaten existing state actions and

will chill new ones, to the country’s great and lasting

harm. For every day that new generation facilities are

delayed, the reliability, economic, and environmental

benefits they would have provided are lost forever.

Ill. The decision creates a generation-

planning vacuum, and will reduce

investment in needed facilities.

The decision below struck down Maryland’s order

as conflicting with what the court perceived to be fed-

eral reliance on short-term wholesale price signals to

develop new generation. App. 25a. That reasoning ele-

vates PJM’s auction and FERC’s capacity-sales regula-

tion to power-supply planning and development roles

they were never intended to have and cannot fulfill,

while gutting the states’ ability to perform those jobs.

The decision creates a regulatory vacuum for genera-

tion planning and development—at the worst possible

time.

A. The decision erects barriers to long-term

contracting needed to support investment.

As Morgan Stanley explained, “[mJarkets are not

perfect, and one of the reasons that parties enter into

wholesale-power contracts is precisely to hedge against

the volatility that market imperfections produce.” 554

U.S. at 547. That is especially true here where the

state is seeking to induce, in a highly volatile market, a

several-hundred-million dollar investment in a new

power plant with a useful life measured in decades. In

five of the first seven auctions, capacity prices in the

part of PJM where CPV’s plant will be located varied

more than 20 percent from year to year.3’ Other PJM

sub-regions are even more volatile, with one generator

noting that during the 2013 auction capacity prices

dropped more than fifty-six percent from the previous

year, sending “shockwaves through the investment

community and creat[ing] a great deal of uncertainty

in the market.”38 Prices elsewhere may be more volatile

still. The annual capacity price in New England’s most

recent auction more than doubled from the previous

year, increasing annual consumer costs by nearly two

billion dollars.%9

This Court has explained that “uncertainties re-

garding rate stability and contract sanctity can have a

chilling effect on investments ... and this, in turn, can

harm customers in the long run.” Morgan Stanley, 554

U.S. at 551 (citation omitted). Indeed, the “vast majori-

ty” of new power plants, especially renewable-energy

facilities, are built either by vertically integrated utili-

ties or “with the support of long-term contracts.”4° The

U.S. Chamber of Commerce agrees: “The amount of

37 See Second Performance Assessment of PJM’s Reliability Pricing

Model, supra note 4, at 11-15.

38 Am. mise. Power, stnanypnand ee ae available at http://

eDE ’ sinesa/ri olatile.aspx (last visit-

ed Nov. 21, 2014).

88 TSO New England, Finalized Auction Results Confirm Slight

Power System Resource o_o in 2017- 2018 oe. 28, =

available at e.com 36 l R

Facilitating Renewable Energy Project Development 1 (May 7,

2013) (Brattle Report), available at http://goo.g/2SA15x.

incremental wind or solar that gets deployed in com-

petitive power markets, for instance, will depend on

the ability of developers to enter into long-term con-

tracts to sell the electricity from their projects.”4!

By one estimate, just two percent of all new genera-

tion in 2011 was built by an independent power pro-

ducer based solely on wholesale market revenues.‘? An

update for 2013 reached almost identical findings. Just

2.4 percent of new capacity built in 2013 was based

solely on market revenues.‘3 The decision below con-

signs states to exclusive reliance on markets that have

neither supported construction of major new genera-

tion facilities nor will be able to do so because they cov-

er periods “far too short” to provide “the long-term as-

assurance of revenues ... needed to adequately support

generation investments.”*4

B. Neither wholesale markets nor FERC can

substitute for state-supervised generation

planning and contracting.

Congress left the states in charge of regulating gen-

eration facilities and retail utility power supply portfo-

41 U.S. Chamber of Commerce, Assessing the Impact of Potential

New Carbon Regulations in the United States 29 (Inst. for 21st

Century Energy 2014), available at http://www.energyxxi.org/epa-

regs-report.

42 Brattle Report, supra note 39, at 10 (citing Elise Caplan, What

Drives New Generation Construction? An Analysis of the Financial

Arrangements behind New Electric Generation Projects in 2011,

Elec. J., July 2012, at 48).

43 Am. Pub. Power Ass’n, Power Plants Are Not Built on Spec:

2014 Update 2, available at http://appanet.files.cms-plus.com/

PDFs/94 2014 Power Plant Study.pdf.

44 Mathew J. Morey et al., Ensuring Adequate Power Supplies for

Tomorrow's Electricity Needs 60 (June 16, 2014), available at

lios because those decisions have important local con-

sequences. Facilities have different effects on local air

and water quality, noise levels, local economies, and a

state’s ability to comply with federal environmental

mandates.

Neither FERC nor the organized wholesale power

markets are able, legally or practically, to perform the

states’ traditional power-supply planning role. FERC

acknowledges that the organized wholesale markets

choose resources based on price, location, and near-

term reliability needs, and are blind to other important

considerations. PJM Interconnection, LLC, 137 FERC

{ 61,145, P 90 (PJM’s capacity auction does not “recog-

nize ... environmental or technological goals, nor does

it contemplate reliability concerns beyond a three-year

forecast.”). The wholesale markets do not attempt to

promote fuel diversity.45 and FERC deems itself power-

less to incorporate environmental impacts into its

ratemaking decisions. Grand Council of the Crees (of

Quebec) v. FERC, 198 F.3d 950, 957 (D.C. Cir. 2000).

Regulators must be able to require utilities to pro-

cure needed generation that the market does not elicit,

and Congress reserved that authority to the states, not

FERC. Congress expressly denied FERC the authority

to “compel the enlargement of generating facilities,”

even as a means of remedying insufficient service, FPA

§§ 207, 202(b), 16 U.S.C. §§ 824f, 824a(b), and FERC

cannot order a public utility to file a rate for service it

has not chosen to provide, Atlantic City, 295 F.3d at 10.

Corina Rivera Linares, PJM’s Boston: “World’s Largest and

Fastest Fuel Change” Taking Place Now, TransmissionHub

(Oct. 22, 2014), available at http://goo.gl/BWBxxM (quoting FERC

Chairman LaFleur’s statement that fuel diversity “was never part

of the design”).

Under the FPA, only the states can order utilities to

build new facilities or support them by contracting

with generation developers. But the decision below

tramples that authority.

C. The decision guts the states’ authority at

the worst time.

The decision below wrongly implies that losing the

authority at issue here is a small thing because states

may be able to support investment with non-contract

incentives. See App. 23a (asserting the “limited scope”

of its holding); see also Solomon, 766 F.3d at 253 & n.4.

That is cold comfort. Just as volatile short-term market

prices are ill-suited to inducing needed investment, the

same is true of tax incentives and similar non-contract

measures that can be repealed at a legislature’s whim.

Durable, capital-intensive utility assets are rarely built

on such shifting sands. Long-term contracts—enduring

and enforceable—are required.

And the need for states to be able to direct retail

contracting to support new generation is about to be-

come even more acute. On the same Jay the decision

below was issued, the U.S. Environmental Protection

Agency proposed a rule requiring each state to reduce

power plant carbon dioxide emission rates by a specific

amount.*® Achieving mandated cuts while preserving

reliability will require the states to manage actively a

major shift in their power supplies, reducing reliance

on coal- and oil-fired resources and increasir~ the use

of natural-gas-fired generators, renewable resources,

* U.S. Envtl. Protection Agency, Carbon Pollution Emission

Guidelines for Existing Stationary Sources: Electric Utility Gen-

erating Units, Proposed Rule, No. EPA-HQ-OAR-2013-0602

(June 2, 2014), 79 Fed. Reg. 34,829 (June 18, 2014).

and nuclear facilities.47 To accomplish this transfor-

mation while maintaining reliability, many states will

need to direct utilities to enter long-term contracts for

cleaner new resources and shorter-term contracts to

retain existing supplies temporarily. The decision be-

low ties the states’ hands at the wo st possible time.

CONCLUSION

The petition for a writ of certiorari should be grant-

ed.

Respectfully submitted,

Scott H. Strauss*

Peter J. Hopkins

Jeffrey A. Schwarz

*Counsel of Record

Spiegel & McDiarmid LLP

1875 Eye Street, NW, Suite 700

Washington, DC 20006

(202) 879-4000

scott.strauss@spiegelmcd.com

47 See U.S. Envtl. Protection Agency, Clean Power Plan Toolbox

for States, http://www2.epa.gov/cleanpowerplantoolbox (last visit-

ed Nov. 21, 2014).

APPENDIX

TABLE OF CONTENTS

Appendix A: Opinion, PPL EnergyPlus LLC

uv. Nazarian, 753 F.3d 467 (4th Cir. 2014).......... la

Appendix B: Order No. 84815, In re Whether

New Generating Facilities Are Needed to

Meet Long-Term Demand for Standard

Offer Service, 297 P.U.R.4th 336 (Md.

Pub. Serv. Comm’n 2012).....................0.000c0000000 29a

Appendix C: Memorandum of Decision,

PPL EnergyPlus LLC v. Nazarian, 974 F.

Supp. 2d 780 (D. Md. 2019)............................... 62a

Appendix D: Order Denying Rehearing,

PPL EnergyPlus LLC v. Nazarian, Nos.

13-2419, 13-2424 (4th Cir. June 30, 2014) ... 197a

Appendix E: Judgment, PPL EnergyPlus LLC

v. Nazarian, Nos. 13-2419, 13-2424 (4th

eras 202a

Appendix F: U.S. Const., art. VI, cl. 2.............. 207a

Appendix G: Federal Power Act § 201,

EERIE SS RES or ee 208a

Appendix H: Federal Power Act § 205,

16 U.S.C. § 824d o...cccceccccecessesesseseseesesecsceeeneens 21la

Appendix I: Order Granting Extension of

Time to File Petition for a Writ of Certiorari,

Nazarian v. PPL Energy Plus, LLC,

No. 14A282 (U.S. Sept. 15, 2014). ............0..... 214a

APPENDIX A

PUBLISHED

UNITED STATES COURT OF APPEALS FOR THE

FOURTH CIRCUIT

No. 13-2419

PPL ENERGYPLUS, LLC; PPL BRUNNER

ISLAND, LLC; PPL HOLTWOOD, LLC; PPL

MARTINS CREEK, LLC; PPL MONTOUR, LLC;

PPL SUSQUEHANNA, LLC; LOWER MOUNT

BETHEL ENERGY, LLC; PPL NEW JERSEY

SOLAR, LLC; PPL NEW JERSEY BIOGAS, LLC;

PPL RENEWABLE ENERGY, LLC; PSEG

POWER LLC; ESSENTIAL POWER, LLC,

Plaintiffs Appellees,

DOUGLAS R.M. NAZARIAN; HAROLD WILLIAMS;

LAWRENCE BRENNER; KELLY SPEAKES-

BACKMAN; KEVIN HUGHES,

Defendants — Appellants,

and

CPV MARYLAND, LLC,

Defendant.

AMERICAN PUBLIC POWER ASSOCIATION;

NATIONAL RURAL ELECTRIC COOPERATIVE

ASSOCIATION; NRG ENERGY INC., MARYLAND

OFFICE OF PEOPLE'S COUNSEL; CONNECTICUT

PUBLIC UTILITIES REGULATORY AUTHORITY;

CONNECTICUT DEPARTMENT OF ENERGY

AND ENVIRONMENTAL PROTECTION;

GEORGE JEPSEN, Attorney General for the State

of Connecticut; CONNECTICUT OFFICE OF

CONSUMER COUNSEL; NEW # ENGLAND

CONFERENCE OF PUBLIC UTILITIES

COMMISSIONERS, INC.; MAINE PUBLIC

UTILITIES COMMISSION; RHODE ISLAND

PUBLIC UTILITIES COMMISSION; VERMONT

PUBLIC SERVICE BOARD; VERMONT

DEPARTMENT OF PUBLIC SERVICE;

CALIFORNIA PUBLIC UTILITIES COMMISSION;

PUBLIC SERVICE COMMISSION OF THE STATE

OF NEW YORK (NYPSC); PUBLIC SERVICE

COMMISSION OF THE DISTRICT OF COLUMBIA;

DELAWARE PUBLIC SERVICE COMMISSION;

NEW JERSEY BOARD OF PUBLIC UTILITIES;

NEW JERSEY DIVISION OF RATE COUNSEL;

MARYLAND ENERGY ADMINISTRATION;

AMERICAN WIND ENERGY ASSOCIATION; THE

MID- ATLANTIC RENEWABLE ENERGY

COALITION,

Amici Supporting Appellants,

PJM POWER PROVIDERS GROUP;

ELECTRIC POWER SUPPLY ASSOCIATION;

EDISON ELECTRIC INSTITUTE,

Amici Supporting Appellees.

No. 13-2424

PPL ENERGYPLUS, LLC; PPL BRUNNER

ISLAND, LLC; PPL HOLTWOOD, LLC; PPL

MARTINS CREEK, LLC; PPL MONTOUR, LLC;

PPL SUSQUEHANNA, LLC; LOWER MOUNT

BETHEL ENERGY, LLC; PPL NEW JERSEY

SOLAR, LLC; PPL NEW JERSEY BIOGAS, LLC;

PPL RENEWABLE ENERGY, LLC; PSEG

POWER LLC; ESSENTIAL POWER, LLC,

Plaintiffs - Appellees,

CPV MARYLAND, LLC,

Defendant — Appellant,

and

DOUGLAS R.M. NAZARIAN; HAROLD

WILLIAMS; LAWRENCE BRENNER; KELLY

SPEAKES-BACKMAN; KEVIN HUGHES,

Defendants.

AMERICAN PUBLIC POWER ASSOCIATION;

NATIONAL RURAL ELECTRIC COOPERATIVE

ASSOCIATION; NRG ENERGY INC.; MARYLAND

OFFICE OF PEOPLE'S COUNSEL; CONNECTICUT

PUBLIC UTILITIES REGULATORY AUTHORITY;

CONNECTICUT DEPARTMENT OF ENERGY AND

ENVIRONMENTAL PROTECTION; GEORGE

JEPSEN, Attorney General for the State of

Connecticut; CONNECTICUT #£=OFFICE OF

CONSUMER COUNSEL; NEW ENGLAND

CONFERENCE OF PUBLIC UTILITIES

COMMISSIONERS, INC.; MAINE PUBLIC

UTILITIES COMMISSION; RHODE ISLAND

PUBLIC UTILITIES COMMISSION; VERMONT

PUBLIC SERVICE BOARD; VERMONT

DEPARTMENT OF PUBLIC SERVICE;

CALIFORNIA PUBLIC UTILITIES COMMISSION;

PUBLIC SERVICE COMMISSION OF THE STATE

OF NEW YORK (NYPSC); PUBLIC SERVICE

COMMISSION OF THE DISTRICT OF COLUMBIA;

DELAWARE PUBLIC SERVICE COMMISSION;

NEW JERSEY BOARD OF PUBLIC UTILITIES;

NEW JERSEY DIVISION OF RATE COUNSEL;

MARYLAND ENERGY ADMINISTRATION;

AMERICAN WIND ENERGY ASSOCIATION; THE

MID-ATLANTIC RENEWABLE ENERGY

COALITION,

Amici Supporting Appellant,

PJM POWER PROVIDERS GROUP;

ELECTRIC POWER SUPPLY ASSOCIATION;

EDISON ELECTRIC INSTITUTE,

Amici Supporting Appellees.

Appeals from the United States District Court for

the District of Maryland, at Baltimore. Marvin J.

Garbis, Senior District Judge. (1:12-cv-01286-MJG)

Argued: May 13, 2014 Decided: June 2, 2014

Before WILKINSON, KEENAN, and DIAZ, Circuit

Judges.

Affirmed by published opinion. Judge Wilkinson

wrote the opinion, in which Judge Keenan and Judge

Diaz joined.

ARGUED: Scott H. Strauss, SPIEGEL &

MCDIARMID, LLP, Washington, D.C.; Clifton Scott

Elgarten, CROWELL & MORING LLP, Washington,

D.C., for Appellants. Paul D. Clement, BANCROFT,

PLLC, Washington, D.C., for Appellees. ON BRIEF:

H. Robert Erwin, Ransom E. Davis, Baltimore,

Maryland; Peter J. Hopkins, Jeffrey A. Schwarz,

SPIEGEL & MCDIARMID LLP, Washington, D.C., for

Appellants Douglas R.M. Nazarian, Harold Williams,

Lawrence Brenner, Kelly Speakes-Backman, and

Kevin Hughes. Larry F Eisenstat, Richard Lehfeldt,

Jennifer N. Waters, CROWELL & MORING LLP,

Washington, D.C., for Appellant CPV Maryland, LLC.

Erin E. Murphy, Candice Chiu, BANCROFT PLLC,

Washington, D.C., for Amici. Jesse A. Dillon, PPL

SERVICES CORP., Allentown, Pennsylvania; David L.

Meyer, MORRISON & FOERSTER LLP, Washington,

D.C., for Appellees PPL EnergyPlus, LLC, PPL

Brunner Island, LLC, PPL Holtwood, LLC, PPL

Martins Creek, LLC, PPL Montour, LLC, PPL

Susquehanna, LLC, Lower Mount Bethel Energy,

LLC, PPL New Jersey Solar, LLC, PPL New Jersey

Biogas, LLC, and PPL Renewable Energy, LLC.

Tamara Linde, Vice President-Regulatory, Vaughn L.

McKoy, General State Regulatory Counsel, PSEG

SERVICES CORP., Newark, New Jersey; Shannen W.

Coffin, STEPTOE & JOHNSON LLP, Washington,

D.C., for Appellee PSEG Power, LLC. David

Musselman, ESSENTIAL POWER, LLC, Princeton,

New Jersey, for Appellee Essential Power, LLC. Susan

N. Kelly, Senior Vice President of Policy Analysis and

General Counsel, Delia D. Patterson, Assistant

General Counsel, AMERICAN PUBLIC POWER

ASSOCIATION, Washington, D.C.; Jay A. Morrison,

Vice President, Regulatory Issues, Pamela M.

Silberstein, Associate Director, Power Supply Issues,

NATIONAL RURAL ELECTRIC COOPERATIVE

ASSOCIATION, Arlington, Virginia, for Amici

American Public Power Association and National

Rural Electric Cooperative Association. Abraham

Silverman, Cortney Madea, NRG ENERGY, INC.,

Princeton, New Jersey; Jeffrey A. Lamken, Martin V.

Totaro, Washington, D.C., Kaitlin R. O'Donnell,

MOLOLAMKEN LLP, New York, New York, for

Amicus NRG Energy Inc. Paula M. Carmody, William

F. Fields, MARYLAND OFFICE OF PEOPLE'S

COUNSEL, Baltimore, Maryland, for Amicus

Maryland Office of People's Counsel. Randall L. Speck,

Jeffrey A. Fuisz, Kimberly B. Frank, Susanna Y. Chu,

KAYE SCHOLER LLP, Washington, D.C., for Amici.

Clare E. Kindall, Assistant Attorney General, OFFICE

OF THE ATTORNEY GENERAL, New Britain,

Connecticut, for Amicus Connecticut Public Utilities

Regulatory Authority. Robert D. Snook, Assistant

Attorney General, OFFICE OF THE ATTORNEY

GENERAL, New Britain, Connecticut, for Amicus

Connecticut Department of Energy and Environmental

Protection. John S. Wright, Assistant Attorney

General, Michael C. Wertheimer, Assistant Attorney

General, OFFICE OF THE ATTORNEY GENERAL,

New Britain, Connecticut, for Amicus George Jepsen,

Attorney General for the State of Connecticut. Elin

Swanson Katz, Joseph A. Rosenthal, CONNECTICUT

OFFICE OF CONSUMER COUNSEL, New Britain,

Connecticut, for Amicus Connecticut Office of

Consumer Counsel. Sarah Hofmann, Executive

Director, NEW ENGLAND CONFERENCE OF

PUBLIC UTILITIES COMMISSIONERS, _INC.,

Montpelier, Vermont, for Amicus New England

Conference of Public Utilities Commissioners, Inc. Lisa

Fink, STATE OF MAINE PUBLIC UTILITIES

COMMISSION, Augusta, Maine, for Amicus Maine

Public Utilities Commission. Amy K. D'Alessandro,

RHODE ISLAND PUBLIC UTILITIES

COMMISSION, Warwick, Rhode Island, for Amicus

Rhode Island Public Utilities Commission. June

Tierney, General Counsel, VERMONT PUBLIC

SERVICE BOARD, Montpelier, Vermont, for Amicus

Vermont Public Service Board. Edward McNamara,

Regional Policy Director, VERMONT DEPARTMENT

OF PUBLIC SERVICE, Montpelier, Vermont, for

Amicus Vermont Department of Public Service. Frank

Lindh, Candace Morey, CALIFORNIA PUBLIC

UTILITIES COMMISSION, San Francisco, California,

for Amicus California Public Utilities Commission.

Kimberly A. Harriman, Acting General Counsel,

Jonathan D. Feinberg, Solicitor, Alan Michaels,

Assistant Counsel, PUBLIC SERVICE COMMISSION

OF THE STATE OF NEW YORK, Albany, New York,

for Amicus Public Service Commission of the State of

New York. Richard A. Beverly, Richard S. Herskovitz,

PUBLIC SERVICE COMMISSION OF THE

DISTRICT OF COLUMBIA, Washington, D.C., for

Amicus Public Service Commission of the District of

Columbia. Kathleen Makowski, Deputy Attorney

General, DELAWARE PUBLIC SERVICE

COMMISSION, Dover, Delaware, for Amicus

Delaware Public Service Commission. John Jay

Hoffman, Acting Attorney General, Richard F. Engel,

Deputy Attorney General, Lisa J. Morelli, Deputy

Attorney General, Alex Moreau, Deputy Attorney

General, Jennifer S. Hsia, Deputy Attorney General,

NEW JERSEY DEPARTMENT OF LAW AND

PUBLIC SAFETY, Trenton, New Jersey, for Amicus

New Jersey Board of Public Utilities. Stefanie A.

Brand, Director, NEW JERSEY DIVISION OF RATE

COUNSEL, Trenton, New Jersey, for Amicus New

Jersey Division of Rate Counsel. Douglas F. Gansler,

Attorney General, Brent A. Bolea, Assistant Attorney

General, Steven M. Talson, Assistant Attorney

General, MARYLAND ENERGY ADMINISTRATION,

Annapolis, Maryland, for Amicus Maryland Energy

Administration. Gene Grace, AMERICAN WIND

ENERGY ASSOCIATION, Washington, D.C., for

Amici American Wind Energy Association and The

Mid-Atlantic Renewable Energy Coalition. Glen

Thomas, PJM POWER PROVIDERS GROUP, King of

Prussia, Pennsylvania; John Lee Shepherd, Jr., Karis

Anne Gong, SKADDEN, ARPS, SLATE, MEAGHER &

FLOM LLP, Washington, D.C., for Amicus PJM Power

Providers Group. David G. Tewksbury, Stephanie S.

Lim, Ashley C. Parrish, KING & SPALDING LLP,

Washington, D.C., for Amicus The Electric Power

Supply Association. Edward H. Comer, Vice President,

General Counsel and Corporate Secretary, Henri D.

Bartholomot, Associate General Counsel, Regulatory

and Litigation, EDISON ELECTRIC INSTITUTE,

Washington, D.C., for Amicus Edison Electric

Institute.

WILKINSON, Circuit Judge:

At issue is a Maryland program to subsidize the

participation of a new power plant in the federal

wholesale energy market. Appellees are energy firms

that compete with this new plant in interstate

commerce. They contend that the Maryland scheme is

preempted under the Federal Power Act's authorizing

provisions, which grant exclusive authority over

interstate rates to the Federal Energy Regulatory

Commission. The district court agreed. For the reasons

that follow, we affirm.

For much of the 20th century, the energy

market was dominated by vertically integrated firms

that produced, transmitted, and delivered power to

end-use customers. New York v. FERC, 535 U.S. 1, 5,

122 S. Ct. 1012, 152 L. Ed. 2d 47 (2002); PPL

EnergyPlus, LLC v. Nazarian, 974 F. Supp. 2d 790,

798 (D. Md. 2013) (opinion below). These firms were

10a

subject to extensive local regulation, though state

power in this respect was limited by the strictures of

the dormant Commerce Clause. See Pub. Utils.

Comm'n v. Attleboro Steam & Elec. Co., 273 U.S. 83,

89, 47 S. Ct. 294, 71 L. Ed. 549 (1927).

The Federal Power Act (FPA), passed in 1935,

was designed in part to fill the regulatory gap created

by the dormant Commerce Clause and cover the then-

nascent field of interstate electricity sales. It vests the

Federal Energy Regulatory Commission (FERC) with

authority over the "transmission of electric energy in

interstate commerce" and the "sale of electric energy at

wholesale in interstate commerce." 16 U.S.C. §

824(b)(1). Federal regulation has become increasingly

prominent as the energy market has shifted away from

local monopolies to a system of interstate competition.

See New York, 535 U.S. at 7.

Rather than ensuring the reasonableness of

interstate transactions by directly setting rates, FERC

has chosen instead to achieve its regulatory aims

indirectly by protecting "the integrity of the interstate

energy markets." N.J. Bd. of Pub. Utils. v. FERC, 744

F.3d 74, 81 (3d Cir. 2014). To this end, FERC has

authorized the creation of "regional transmission

organizations" to oversee certain multistate markets.

PJM Interconnection, LLC (PJM), superintended by

FERC, administers a large regional market that (as

relevant here) includes Maryland and the District of

Columbia.

PJM operates both energy and capacity

markets. The energy market is essentially a real-time

market that enables PJM to buy and sell electricity to

lla

distributors for delivery within the next hour or 24

hours.

The capacity market is a forward-looking

market, which gives buyers the option to purchase

electricity in the future.

In the capacity market, PJM sets a quota based

on how much capacity it predicts will be needed three

years hence and then relies on a Reliability Pricing

Model (RPM) to determine the appropriate price per

unit. Auction participants bid to sell capacity for a

single year, three years in the future. PJM stacks the

bids from lowest to highest and, starting at the bottom,

accepts bids until it has acquired sufficient capacity to

satisfy its quota.

The highest-priced bid that PJM must accept to

meet this quota establishes the market-clearing price.

Every generator who bids at or below this level "clears"

the market and is paid the clearing price, regardless of

the price at which it actually bid. Existing generators

are permitted to bid at zero as "price-takers," meaning

they agree to sell at whatever the clearing price turns

out to be.

Both the capacity and energy markets are

designed to efficiently allocate supply and demand, a

function which has the collateral benefit of

incentivizing the construction of new power plants

when necessary. Clearing prices occasionally differ

based on geographical subdivisions designed by FERC

to stimulate new construction by signaling that certain

regions are prone to supply shortages. Such price

signals are not the sole mechanism for incentivizing

generation, however. PJM's new _ entry price

12a

adjustment (NEPA) guarantees certain new producers

a fixed price for three years to "support . the new

entrant until sufficient load growth [ie., increased

demand] would be expected to” do so. PJM

Interconnection, LLC, 128 FERC 4 61,157, at 4 101

(2009).

In 2006, FERC instituted a requirement (the

minimum offer price rule, or MOPR) that new

generators in certain circumstances bid at or above a

specified price, fixed according to the agency's

estimation of a generic energy project's cost. This rule

was designed to prevent the manipulation of clearing

prices through the exercise of buyer market power. The

MOPR originally exempted certain state-supported

generators, however, and permitted them to bid at

Zero.

Following a complaint lodged by several

competitors, FERC eliminated the exemption for state-

sanctioned plants. The new rule required such plants

to bid initially at the agency-specified minimum price

unless they could demonstrate that their actual costs

were lower than this default price. FERC held that this

adjustment was necessary to protect the integrity of its

markets against below-cost bids by subsidized plants

that might artificially suppress clearing prices. See

PJM Interconnection, LLC, 137 FERC 4 61,145, at 7 96

(2011).

As these features suggest, the federal markets

are the product of a finely-wrought scheme that

attempts to achieve a variety of different aims. FERC

rules encourage the construction of new plants and

sustain existing ones. They seek to preclude state

distortion of wholesale prices while preserving general

13a

state authority over generation sources. They satisfy

short-term demand and ensure sufficient long-term

supply. In short, the federal scheme is carefully

calibrated to protect a host of competing interests. It

represents a comprehensive program of regulation that

is quite sensitive to external tampering.

In 1999, Maryland decided to abandon the

vertical integration model and throw in its lot with the

federal interstate markets. Deregulation was

accomplished by the Electric Customer Choice and

Competition Act, Md. Code Ann., Pub. Utils. § 7-501, et

seq., which divested utilities of their generation

resources, effectively compelling Maryland energy

firms to participate in the federal wholesale markets.

See PPL EnergyPlus, LLC, 974 F. Supp. 2d at 815. The

state believed that these markets would ultimately

produce more efficient and cost-effective service than

traditional monopolies, thus providing state residents

the benefit of lower prices. See In the Matter of

Baltimore Gas and Electric Company's Proposal, Order

No. 81423, at 36 (Md. Pub. Serv. Comm'n, May 2007).

Maryland's decision to participate in the federal

scheme and enjoy its benefits was necessarily

accompanied by a relinquishment of the regulatory

autonomy the state had formerly enjoyed with respect

to traditional utility monopolies.

Maryland soon became concerned, though, that

the RPM was failing to adequately incentivize new

generation. PPL EnergyPlus, LLC, 974 F. Supp. 2d at

795. To solve this perceived problem, the Maryland

Public Service Commission (MPSC) solicited proposals

for the construction of a new power plant. The plant

14a

was to be located in the "SWMAAC zone," an area

comprising part of Maryland and all of D.C., which the

state believed was at heightened risk for reliability

problems. In order to attract offers, the MPSC offered

the successful bidder a fixed, twenty-year revenue

stream secured by contracts for differences (CfDs) that

the state would compel one or more of its local electric

distribution companies (EDCs) to enter. Maryland's

plan was ultimately formalized in the Generation

Order, issued by MPSC in 2012.

Intervenor-appellant Commercial Power

Ventures Maryland, LLC (CPV) submitted the winning

bid and was awarded the promised CfDs. The CfDs

required CPV to build a plant and sell its energy and

capacity on the federal interstate wholesale markets. If

CPV successfully cleared the market, it would be

eligible for payments from the EDCs amounting to the

difference between CPV's revenue requirements per

unit of energy and capacity sold (set forth in its

winning bid) and its actual sales receipts. These costs

would in turn be passed on to the EDCs' retail

ratepayers. If CPV's receipts exceeded its approved

revenue requirements, it would be obligated to pay the

difference to the EDCs. The CfDs did not require CPV

to actually sell any energy or capacity to the EDCs.

Plaintiffs-appellees are existing power plants in

competition with CPV who allege that the Generation

Order is unconstitutional and has resulted in the

suppression of PJM prices, a reduction in their revenue

from the PJM market, and a distortion of the price

signals that market participants rely on in

determining whether to construct new capacity. After a

six-day bench trial, the district court found the

15a

Generation Order field preempted. It reasoned that the

CfD payments had the effect of setting the ultimate

price that CPV receives for its sales in the PJM

auction, thus intruding on FERC's exclusive authority

to set interstate wholesale rates. It did not reach

appellees’ conflict preemption claim and rejected their

dormant Commerce Clause claim. This appeal followed.

Il.

Plaintiffs argue that the Generation Order and

the resulting CfDs are preempted by federal law under

the Supremacy Clause. U.S. Const. art. VI, cl. 2. They

ground this contention in two alternative theories: field

preemption and conflict preemption. We address each

in turn.!

Preemption of all varieties is ultimately a

question of congressional intent. Nw. Cent. Pipeline

Corp. v. State Corp. Comm'n, 489 U.S. 493, 509, 109 S.

Ct. 1262, 103 L. Ed. 2d 509 (1989). Here, the district

court found the Generation Order invalid under the

doctrine of field preemption, which applies when

"Congress has legislated comprehensivelv to occupy an

entire field of regulation, leaving no room for the

States to supplement federal law." Jd. Actual conflict

! As a threshold matter, appellants assert that we lack jurisdiction

under the filed rate doctrine. See Appellants’ Br. at 9. This claim is

meritless, however, given that a judgment in plaintiffs’ favor

would require this court neither “to invalidate a filed rate nor to

assume a rate would be charged other than the rate adopted by

the federal agency in question.” Pub. Util. Dist. No. 1 v. IDACORP

Inc., 379 F.3d 641, 650 (9th Cir. 2004) (internal quotation marks

omitted).

16a

between a challenged state enactment and relevant

federal law is unnecessary to a finding of field

preemption; instead, it is the mere fact of intrusion

that offends the Supremacy Clause. See N. Natural

Gas Co. v. State Corp. Comm'n, 372 U.S. 84, 97-98, 83

S. Ct. 646, 9 L. Ed. 2d 601 (1963). "If Congress

evidences an intent to occupy a given field, any state

law falling within that field is pre-empted." Silkwood v.

Kerr-McGee Corp., 464 U.S. 238, 248, 104 S. Ct. 615, 78

L. Ed. 2d 443 (1984).

Statutory text and structure provide the most

reliable guideposts in this inquiry. See Medtronic, Inc.

vu. Lohr, 518 U.S. 470, 486, 116 S. Ct. 2240, 135 L. Ed.

2d 700 (1996) ("Congress’ intent, of course, primarily is

discerned from the language of the pre-emption statute

and the statutory framework surrounding it.")

(internal quotation marks omitted). The FPA's

"declaration of policy" states:

It is declared that the business of transmitting

and selling electric energy for ultimate

distribution to the public is affected with a

public interest, and that Federal regulation of

matters relating to generation to the extent

provided in this subchapter and subchapter ITI

of this chapter and of that part of such

business which consists of the transmission of

electric energy in interstate commerce and the

sale of such energy at wholesale in interstate

commerce is necessary in the public interest,

such Federal regulation, however, to extend

only to those matters which are not subject to

regulation by the States.

16 U.S.C. § 824(a); see also id. at § 824(b).

17a

The breadth of this grant of authority is

confirmed by the FPA's similarly capacious substantive

and remedial provisions. For example, 16 U.S.C. §

824d(a) states that:

All rates and charges made, demanded, or

received by any public utility for or in

connection with the transmission or sale of

electric energy subject to the jurisdiction of the

Commission, and all rules and regulations

affecting or pertaining to such rates or charges

shall be just and reasonable, and any such

rate or charge that is not just and reasonable

is hereby declared to be unlawful.

A wealth of case law confirms FERC's exclusive

power to regulate wholesale sales of energy in

interstate commerce, including the justness and

reasonableness of the rates charged. "The [FPA] long

has been recognized as a comprehensive scheme of

federal regulation of all wholesales of [energy] in

interstate commerce," Schneidewind v. ANR Pipeline

Co., 485 U.S. 293, 300, 108 S. Ct. 1145, 99 L. Ed. 2d

316 (1988) (internal quotation marks omitted), and

"FERC's jurisdiction over interstate wholesale rates is

exclusive," Appalachian Power Co. v. Pub. Serv.

Comm'n, 812 F.2d 898, 902 (4th Cir. 1987); see also

New England Power Co. v. New Hampshire, 455 U.S.

331, 340, 102 S. Ct. 1096, 71 L. Ed. 2d 188 (1982).2 In

2 Schneidewind dealt with the Natural Gas Act rather than the

FPA. However, because "the relevant provisions of the two

statutes are in all material respects substantially identical,” the

Supreme Court has adopted an “established practice of citing

interchangeably decisions interpreting the pertinent sections of

the two statutes.” Ark. La. Gas Co. v. Hall, 453 U.S. 571, 578 n.7,

18a

this area, "if FERC has jurisdiction over a subject, the

States cannot have jurisdiction over the same subject."

Miss. Power & Light Co. v. Mississippi ex rel. Moore,

487 U.S. 354, 377, 108 S. Ct. 2428, 101 L. Ed. 2d 322

(1988) (Scalia, J., concurring in the judgment).

Indeed, the Supreme Court has expressly

rejected the proposition that the "scope of [FERC's]

jurisdiction is to be determined by a case-by-case

analysis of the impact of state regulation upon the

national interest." Nantahala Power & Light Co. v.

Thornburg, 476 U.S. 953, 966, 106 S. Ct. 2349, 90 L.

Ed. 2d 943 (1986) (quoting FPC v. S. Cal. Edison Co.,

376 U.S. 205, 215, 84 S. Ct. 644, 11 L. Ed. 2d 638

(1964)) (internal quotation marks omitted). Instead,

"Congress meant to draw a bright line easily

ascertained, between state and federal jurisdiction ... .

This was done in the [FPA] by making [FERC]

jurisdiction plenary and extending it to all wholesale

sales in interstate commerce except those which

Congress has made explicitly subject to regulation by

the States." Id. (quoting S. Cal. Edison Co., 376 U.S. at

215-16) (internal quotation marks omitted).

The federal scheme thus "leaves no room either

for direct state regulation of the prices of interstate

wholesales of [energy], or for state regulations which

would indirectly achieve the same result." N. Natural

Gas Co., 372 U.S. at 91 (citation omitted). "Even where

state regulation operates within its own field, it may

not intrude indirectly on areas of exclusive federal

authority." Pub. Utils. Comm'n v. FERC, 900 F.2d 269,

274 n.2, 283 U.S. App. D.C. 285 (D.C. Cir. 1990)

101 S. Ct. 2925, 69 L. Ed. 2d 856 (1981) (internal quotation marks

omitted).

19a

(internal quotation marks omitted). As a result, states

are barred from relying on mere formal distinctions in

"an attempt" to evade preemption and "regulate

matters within FERC's exclusive jurisdiction."

Schneidewind, 485 U.S. at 308.

Applying these principles, we conclude that the

Generation Order is field preempted because it

functionally sets the rate that CPV receives for its

sales in the PJM auction.

The CfD payments, which are conditioned on

CPV clearing the federal market, plainly qualify as

compensation for interstate sales at wholesale, not

simply for CPV's construction of a plant. Furthermore,

the Order ensures -- through a system of rebates and

subsidies calculated on the basis of the PJM market

rate -- that CPV receives a fixed sum for every unit of

capacity and energy that it clears (up to a certain

ceiling). The scheme thus effectively supplants the rate

generated by the auction with an alternative rate

preferred by the state. See Appalachian Power Co., 812

F.2d at 904 (holding that the agreement at issue did

not "set a rate per se," but that it nevertheless

"sufficiently resemble[d] a filed rate to come within the

realm of exclusive federal jurisdiction"). The Order

thus compromises the integrity of the federal scheme

and intrudes on FERC's jurisdiction.

Maryland and CPV argue that the Generation

Order does not actually set a rate because it does not

directly affect the terms of any transaction in the

federal market. Relevantly, appellants contend, the

Order does not fix the rate that PJM pays to CPV for

20a

its sales in the auction; instead, it merely fixes the rate

that CPV receives for such sales. On the basis of this

asymmetry, appellants contend that the CfD payments

represent a separate supply-side subsidy implemented

entirely outside the federal market.

We cannot accept this argument. The case of

Mississippi Power & Light Co. v. Mississippi ex rel.

Moore, 487 U.S. 354, 108 S. Ct. 2428, 101 L. Ed. 2d 322

(1988), is illustrative. There, FERC ordered a utility to

purchase a specified percentage of a particular

generator's output. Jd. at 363. The utility petitioned

Mississippi to approve an increase in its retail rates to

cover the costs imposed by the order, but the state

insisted that it retained the authority to determine

whether the purchases were prudent before acceding to

the request. Id. at 365-67. The Supreme Court rejected

this argument, ruling that the state was required to

treat the utility's FERC-mandated payments as

"reasonably incurred operating expenses for the

purpose of setting” the utility's retail rates. Jd. at 370;

see also Nantahala Power & Light Co., 476 U.S. 953,

106 S. Ct. 2349, 90 L. Ed. 2d 943 (rejecting a similar

state effort to bar a utility from passing FERC-

mandated wholesale rates through to consumers).

Mississippi's prudence review was preempted because

it denied full effect to the rates set by FERC, even

though it did not seek to tamper with the actual terms

of an interstate transaction.

As the district court recognized, see PPL

EnergyPlus, LLC, 974 F. Supp. 2d at 831, the

principles articulated in Mississippi Power & Light Co.

apply with equal force to this dispute. If states are

required to give full effect to FERC-mandated

2la

wholesale rates on the demand side of the equation, it

stands to reason that they are also required to do so on

the supply side. Here, the contract price guaranteed by

the Generation Order supersedes the PJM rates that

CPV would otherwise earn -- rates established through

a FERC-approved market mechanism. The Order

ensures that CPV receives a fixed price for every unit

of energy and capacity it sells in the PJM auction,

regardless of the market price. The fact that it does not

formally upset the terms of a federal transaction is no

defense, since the functional results are precisely the

same. As in the above-mentioned cases, Maryland has

"eroded the effect of the FERC determination and

undermined FERC's exclusive jurisdiction."

Appalachian Power Co., 812 F.2d at 904.

Our conclusion that the Generation Order

"seeks to regulate a field that the [FPA] has occupied

also is supported by the imminent possibility of

collision between" the state and federal regimes.

Schneidewind, 485 U.S. at 310. While the potential for

collision between the two schemes is discussed in detail

in Part D, a high probability of conflict tends to suggest

that Congress intended federal authority in a

particular field to be uniform and exclusive. See id.

Even if "collision between the state and federal

regulation" in this case is not "an inevitable

consequence," it is sufficiently likely to warrant

invalidating the Maryland program "in order to assure

the effectuation of the comprehensive federal

regulation ordained by Congress." N. Natural Gas Co.,

372 U.S. at 92.

22a

Appellants argue that this court should apply a

robust version of the presumption against preemption

to save the Maryland scheme. See, e.g., Intervenor-

Appellant's Br. at 14. As its name suggests, this

presumption militates against findings of federal

preemption, especially in areas of traditional state

authority. See Rice v. Santa Fe Elevator Corp., 331

U.S. 218, 230, 67 S. Ct. 1146, 91 L. Ed. 1447 (1947).

However, the presumption "is not triggered when the

State regulates in an area where there has been a

history of significant federal presence." United States v.

Locke, 529 U.S. 89, 108, 120 S. Ct. 1135, 146 L. Ed. 2d

69 (2000). The presumption "is almost certainly not

applicable here because the federal government has

long regulated wholesale electricity rates." IDACORP

Inc., 379 F.3d at 648 n.7. Nevertheless, even were we

to apply the presumption, we would find it overcome by

the text and structure of the FPA, which

unambiguously apportions control over wholesale rates

to FERC.

Appellants emphasize the FPA's decree that

FERC "shall not have jurisdiction, except as

specifically provided in this subchapter and subchapter

III of this chapter, over facilities used for the

generation of electric energy." 16 U.S.C. § 824(b)(1).

They contend that the Generation Order falls on the

state side of the jurisdictional line, since it is designed

to ensure that Maryland enjoys an adequate supply of

generation capacity.

Although states plainly retain substantial

latitude in directly regulating generation facilities,

they may not exercise this authority in a way that

impinges on FERC's exclusive power to specify

23a

wholesale rates. As the Supreme Court noted in a

similar context:

[T]he problem of this case is not as to the

existence or even the scope of a State's power

to [regulate generation facilities]; the problem

is only whether the Constitution sanctions the

particular means chosen by [the state] to

exercise the conceded power if those means

threaten effectuation of the federal regulatory

scheme.

N. Natural Gas Co., 372 U.S. at 93. Here, Maryland

has chosen to incentivize generation by setting

interstate wholesale rates. This particular choice of

means is impermissible. Wholesale energy prices

"fixed by FERC must be given binding effect by state

authorities" even "in areas subject to state

jurisdiction." California ex rel. Lockyer v. Dynegy,

Inc., 375 F.3d 831, 851 (9th Cir. 2004) (internal

quotation marks omitted).

Nonetheless, it is important to note the limited

scope of our holding, which is addressed to the specific

program at issue. We need not express an opinion on

other state efforts to encourage new generation, such

as direct subsidies or tax rebates, that may or may not

differ in important ways from the Maryland initiative.

It goes without saying that not "every state statute

that has some indirect effect" on wholesale rates is

preempted, Schneidewind, 485 U.S. at 308, for "there

can be little if any regulation of production that might

not have at least an incremental effect on the costs of

purchasers in some market," Nw. Cent. Pipeline Corp.,

489 U.S. at 514. In this case, however, the effect of the

24a

Generation Order on matters within FERC's exclusive

jurisdiction is neither indirect nor incidental.

Rather, the Order strikes at the heart of the

agency's statutory power to establish rates for the sale

of electric energy in interstate commerce, see 16 U.S.C.

§ 824e(a), by adopting terms and prices set by

Maryland, not those sanctioned by FERC.

Appellants’ position is further complicated by

the fact that the principles of field and conflict

preemption in this case are mutually reinforcing. As

relevant here, conflict preemption applies “where

under the circumstances of a particular case, the

challenged state law stands as an obstacle to the

accomplishment and execution of the full purposes and

objectives of Congress." Crosby v. Nat'l Foreign Trade

Council, 530 U.S. 363, 373, 120 S. Ct. 2288, 147 L. Ed.

2d 352 (2000) (internal quotation marks and

alterations omitted). "What is a sufficient obstacle is a

matter of judgment, to be informed by examining the

federal statute as a whole and identifying its purpose

and intended effects." Id. "A state law may pose an

obstacle to federal purposes by interfering with the

accomplishment of Congress's actual objectives, or by

interfering with the methods that Congress selected for

meeting those legislative goals." College Loan Corp. v.

SLM Corp, 396 F.3d 588, 596 (4th Cir. 2005).

(emphasis omitted).

In a system of “interlocking” jurisdiction, such

as that created by the FPA, "[ijt is inevitable that

jurisdictional tensions will arise” -- even if each

sovereign formally remains within the confines of its

25a

“assigned sphere." Nw. Cent. Pipeline Corp., 489 U.S.

at 506, 515 & n.12 (internal quotation marks and

alteration omitted). "Thus, conflict-pre-emption

analysis must be applied sensitively in this area, so as

to prevent the diminution of the role Congress reserved

to the States while at the same time preserving the

federal role." Jd. at 515. Here, "the impact of state

regulation of production on matters within federal

control is so extensive and disruptive of" the PJM

markets that preemption is appropriate. Id. at 517-18.

As an initial matter, the Generation Order has

the potential to seriously distort the PJM auction's

price signals, thus "interfer[ing] with the method by

which the federal statute was designed to reach its

goals." IDACORP Inc., 379 F.3d at 650. PJM's price

signals are intended to promote a variety of objectives,

including incentivizing new generation sources. See

PJM Interconnection, LLC, 132 FERC 4 61,173, at

61,870 (2010); see also PPL EnergyPlus, LLC, 974 F.

Supp. 2d at 813. Market participants necessarily rely

on these signals in determining whether to construct

new capacity or expand existing resources. The signals

appear to be serving their purpose; according to FERC,

the evidence "suggests that RPM has in fact succeeded

in securing sufficient capacity to meet reliability

requirements for the PJM _ region." PJM

Interconnection, LLC, 137 FERC 4 61,145, at 4 3

(2011).

Maryland's initiative disrupts this scheme by

substituting the state's preferred incentive structure

for that approved by FERC. See PPL EnergyPlus, LLC

v. Hanna, No. 11-745, 977 F. Supp. 2d 372, 2013 U.S.

Dist. LEXIS 147273, 2013 WL 5603896, at *36 (D.N.J.

26a

Oct. 11, 2013) (describing the distorting impact of a

similar New Jersey program on the business decisions

of private participants in the PJM auctior). Two

features of the Order render its likely effect on federal

markets particularly problematic. First, as noted, the

CfDs are structured to actually set the price received at

wholesale. They therefore directly conflict with the

auction rates approved by FERC. Second, the duration

of the subsidy -- twenty years -- is substantial.

The Order is preempted for the further reason

that it conflicts with NEPA, which represents an

exception to PJM's otherwise steadfast commitment to

a uniform market clearing price. In order to stimulate

plant construction, NEPA carves out a three-year

period during which certain new generators are

eligible to receive a fixed price for the capacity they sell

in the PJM markets. See PJM Interconnection, LLC,

128 FERC 4 61,157, at 9 92 (2009). CPV petitioned

FERC to extend the NEPA period to ten years on the

grounds that the three-year period was insufficient to

achieve its objective. Jd. at § 93. FERC rejected CPV's

request, stating that "[bjoth new entry and retention of

existing efficient capacity are necessary to ensure

reliability and both should receive the same price so

that the price signals are not skewed in favor of new

entry." Id. at § 102.

The Generation Order represents an effort by

the state to directly override this explicit policy choice.

As a functional matter, the CfDs extend the NEPA

period for CPV to twenty years, a duration vastly

exceeding the current NEPA term and double the term

that CPV unsuccessfully requested FERC to institute.

Maryland has sought to achieve through the backdoor

27a

of its own regulatory process what it could not achieve

through the front door of FERC proceedings.

Circumventing and displacing federal rules in this

fashion is not permissible.

Appellants assert that no conflict is present

because FERC explicitly accommodated -- via the

MOPR -- the participation of subsidized plants in its

auction. See, e.g., Intervenor-Appellant's Reply Br. at

23. The fact that FERC was forced to mitigate the

Generation Order's distorting effects using the MOPR,

however, tends to confirm rather than refute the

existence of a conflict. Furthermore, FERC's own

comments on the subject belie appellants’ claim that

the agency has affirmatively approved the Generation

Order. See PJM Interconnection, LLC, 137 FERC at 4

3 ("Our intent is not to pass judgment on state and

local policies and objectives with regard to the

development of new capacity resources... .").

As was the case with our field preemption

holding, our conflict preemption ruling is narrow and

focused upon the program before us. Obviously, not

every state regulation that incidentally affects federal

markets is preempted. Such an outcome "would

thoroughly undermine precisely the division of the

regulatory field that Congress went to so much trouble

to establish .. . , and would render Congress’ specific

grant of power to the States to regulate production

virtually meaningless." Nw. Cent. Pipeline Corp., 489

U.S. at 515. The Generation Order, however, is simply

a bridge too far. It presents a direct and transparent

28a

impediment to the functioning of the PJM markets,

and is therefore preempted.’

Ill.

For the foregoing reasons, we hold the

Generation Order preempted under federal law and

affirm the judgment of the district court.

AFFIRMED

3 Our conclusion that the Generation Order is preempted renders

it unnecessary for us to reach plaintiffs’ dormant Commerce

Clause arguments, which were rejected by the district court. See

Schneidewind, 485 U.S. at 311 ("Because we have concluded that

Act 144 is pre-empted by the NGA, we need not decide whether,

absent federal occupation of the field, Act 144 violates the

Commerce Clause.").

29a

APPENDIX B

ORDER NO. 84815

IN THE MATTER OF BEFORE THE

WHETHER NEW PUBLIC SERVICE

GENERATING COMMISSION

FACILITIES ARE OF MARYLAND

NEEDED TO MEET

LONG- TERM CASE NO. 9214

DEMAND FOR

STANDARD OFFER

SERVICE

Issue Date: April 12, 2012

Among our most important responsibilities as

regulators is to ensure that electricity is available to

all Maryland ratepayers, whenever and wherever

they need it. Electric service is no longer a luxury

reserved for the wealthy few -- it is the life blood of

modern society. Our primary statutory mandate is to

assure "safe, adequate, reasonable and proper service

for any class of public service company. ._,”!

including Maryland's electric companies. Put another

way, the public expects us to keep the lights on (and

water treatment plants, and heat pumps, and air

conditioners, and medical equipment, and everything

else on which we depend) in Maryland. The General

Assembly has given us tools to fulfill that obligation,

and in doing so has expressed the distinct

1 Maryland Code Annotated, Public Utilities Article ("PUA"), §

5-101(a) (emphasis added).

30a

expectation that we will use those tools when

appropriate rather than relying blindly on the

operation of market forces.

Our concern about the adequacy of electric

generation in Maryland began with the Public

Service Commission's ("Commission") Summer 2007

Electricity Planning Conference,? and while it has

been postponed by subsequent exogenous events, it

has not disappeared. Consequently, for the reasons

set forth below, in this Order we direct Baltimore

Gas and Electric Company ("BGE"), Potomac Electric

Power Company ("Pepco"), and Delmarva Power &

Light Company ("Delmarva") to enter into a Contract

for Differences with CPV Maryland, LLC ("CPV"),

under which CPV will construct a 661 megawatt

(MW) natural gas-fired combined-cycle generation

plant in Waldorf in Charles County, Maryland, with

a commercial operation date of June 1, 2015.

Procedural Background

We initiated this case on September 29, 2009,

by Order No. 82936, "to investigate whether [the

Commission] should exercise its authority to order

electric utilities to enter into long-term contracts to

anchor new generation or to construct, acquire, or

lease, and operate, new electric generating facilities

in Maryland.”3 We initially directed parties

interested in making proposals for new generating

2 In the Matter of the Commission's Maryland Electricity

Planning Conference, Public Conference No. PC 9.

3 In the Matter of Whether New Generating Facilities are Needed

to Meet Long-Term Demand for Standard Offer Service, Case

No. 9214, Order No. 82936, pp. 2-3.

3la

facilities to file such proposals by December 1, 2009,

but we subsequently tolled the filing date.‘ After

reviewing comments filed in the case, on December

29, 2010, the Commission prepared a draft Request

for Proposals for New Generation ("RFP") and

invited comments on the draft.5

Nearly thirty parties filed comments

addressing the draft RFP. As a result of those

comments, the Commission made changes in the

RFP and on September 29, 2011 directed BGE,

Pepco, Delmarva, and The Potomac Edison Company

("PE") to issue the modified RFP *® In the Notice to

Issue the RFP, the Commission noted that it would

hold a hearing on January 31, 2012 on the need for

new generation and, if required, the amount needed,

and invited any written comments to be filed by

January 13, 2012. As a result of some of the early

comments and questions concerning the RFP and its

schedule for bids, the Commission issued an

Amended RFP on December 8, 2011, which extended

the due dates for bids to January 20, 2012, and

encouraged each bidder to submit two proposals, one

for a fixed gas price offering and another for a

variable gas price offering. Twenty parties availed

themselves of the opportunity to file comments

4 Id., Notice of Tolling Submission Date of Proposals, Nov. 10,

2009.

5 Id., Notice of Comment Period on Request for Proposals for

New Generating Facilities, Dec. 29, 2010.

8 Id. Notice of Approval of Request for Proposals for New

Generation to be Issued by Maryland Electric Distribution

Companies, Sep. 29, 2010. The comments received and the

changes to the draft RFP are summarized in the Notice and will

not be repeated here.

32a

concerning the need for new generation.’ Fourteen

of those parties testified at the January 31, 2012

hearing and answered the Commission's questions.®

Finally, several parties have filed Motions in

the case. On October 21, 2011, Northland Power Inc.

and Eastaico Aluminum Company each filed a

Request to Modify the RFP On October 31, 2011,

Pepco and Delmarva filed an Application for

Rehearing. On January 25, 2012, NRG Energy, Inc.

filed a Motion to Postpone Procurement of New

Generation. Each of these Motions will be addressed

in this Order.

’ Written comments were filed by: GE Energy; PJM Power

Providers Group (P3); BGE; Genon Mid-Atlantic, LLC; Exelon

Corporation; Calpine Corporation; Office of People's Counsel

C‘OPC"); CPV Maryland, LLC ("CPV"); Commission's technical

staff ("Staff’ ); PJM Interconnection, LLC ("PJM"); PSEG

Energy Resources & Trade LLC ("PSEG"); Pepco & Delmarva

(Joint Comments); PE; The Electric Power Supply Association

("EPSA"); Retail Energy Supply Association ("“RESA"); Sierra

Club & Chesapeake Climate Action Network (Joint Comments);

Maryland Energy Administration ("MEA"); PPL Energy Plus,

LLC ("PPL"); and the Independent Market Monitor for PJM

("IMM"). In response to a Commission request, PJM filed

Supplemental Comments on Jan. 31, 2012. CPV filed additional

comments following the hearing, on February 6, 2012. In

addition, Boston Pacific filed its Evaluation Report dated

August 12, 2011 and the Governor filed a letter concerning the

RFP on Oct. 20, 2011. Finally, on March 29, 2012 the four

Maryland Electric Distribution Companies ("EDCs") -- BGE,

Pepco, Delmarva, and PE -- filed a letter expressing technical

concerns with the Contract for Differences.

8 The following parties testified at the hearing: Boston Pacific;

PJM; the IMM; MEA; OPC; Staff; Sierra Club & Chesapeake

Climate Action Network; Pepco & Delmarva; CPV; NRG

Energy, Inc.; EPSA; PPL; P3; and GE Energy.

33a

The RFP

In the Amended RFP, dated December 2, 2011,

the EDCs seek bids for new, natural gas-fired

Generation Capacity Resources (as defined by PJM)

to be located inside the Southwest MAAC Locational

Deliverability Area. The RFP seeks proposals in

any quantity not to exceed 1,500 MW on an installed

capacity basis, to be operational no earlier than June

1, 2015 and no later than June 1, 2017 '° The RFP

requires the Supplier to offer and deliver the

generation output into the PJM capacity, energy and

ancillary services markets, and the EDCs do not take

physical delivery of the generation.'! The Supplier

must bid the capacity into the PJM Base Residual

Auction ("BRA") "in accordance with BRA rules and

regulations as they exist throughout the term of the

Contract. The Supplier will not be paid for any year

in which the Supplier's Generation Capacity

Resource does not clear the BRA."!2 Thus, the risk of

not clearing in the BRA is left on the Supplier, not

ratepayers. Anyone is eligible to bid, provided they

meet the PJM membership requirements and are

willing to meet the RFP contractual requirements. !3

The RFP specifies that the Supplier and the

EDC will enter into a financial arrangement under a

Contract for Differences.'4 Under the Contract for

Differences, the difference between the Supplier's

® RFP, § 2.1.

10 Id., §§ 2.2, 2.3.

1 Id., § 3.

12 Id., § 3.1(b).

13 Id., § 5.1.

4 Id., § 3.

34a

actual revenue from the PJM capacity and energy

sales and the fixed contract price for capacity results

in a payment or credit.'5 If the actual revenues are

below the fixed contract capacity price, the EDC is

obligated to pay the supplier the difference. If,

however, the actual revenue from the PJM market

exceeds the fixed contract capacity price, the

Supplier pays the EDC the excess. Settlement

between the Supplier and the EDC is to take place

monthly. !¢

Positions of the Parties

PJM .

In its written comments, PJM "does not take a

position of whether the Commission should

determine there is a reliability need to pursue the

construction of new generation in Maryland."'7 PJM

notes that in its load forecast, economic activity as

measured by gross metropolitan product (GMP) is

the primary driver for peak load growth and growth

in total energy consumption, and that in its 2012

forecast, projected GMP growth remains below the

2011 forecast GMP growth through 2016.'8 The

Economic Index Variabi. used by PJM shows even

slower growth rates.'? PJM also notes that peak load

growth in the BGE, Pepco, Delmarva, and PE zones

is below the PJM average growth rate of 1.4% per

year.20 PJM does note that coal-fired generation

18 Td., § 3.2.

16 Jd., § 3.2.

17 Comments of PJM Interconnection, LLC, pp. 1-2.

18 Id., p. 4.

19 Td.

2 Id., p.8.

35a

more than 40 years old and less than 400 MW is

considered at "high risk" for retirement, of which

there are 2,320 MW in Maryland.?! PJM adds that

due to such retirements, "there may be localized

reliability concerns that will need to be addressed."2?

In its Supplemental Comments requested by the

Commission to look at the effects of possible

retirement of coal generation at the C. P Crane and

H. A. Wagner plants, PJM found that retirement of

either or both would result in potential reliability

violations.23 PJM also found that such retirements

would "increase existing constraints but not cause

new constraints. .. . In their absence the lowest cost

replacements are generally west of constrained

interfaces into the APS system which increases both

the incremental cost of energy and congestion for

large portions of PJM load. "24

In his testimony at the hearing, PJM Senior

Vice President of Operations and Long-Term

Planning Michael Kormos stated that prior to 2008,

due to a very strong economy and very strong load

growth, they were seeing problems from inadequate

capacity beginning in 2012 to 2015. However, due to

the downturn in the economy and very slow recovery,

they now see a possible need for new generation in

2020, and no earlier than 2017 in their worst case

scenario.25 Mr. Kormos also noted that the biggest

constraint in Maryland comes from bringing in

energy from the west across the Allegheny

21 Id., pp.11-12.

22 Id., p. 13.

23 Supplemental Comments of PJM Interconnection, LLC., p. 4.

%4 Id., p. 5.

%5 Transcript, pp. 48-50.

36a

Mountains,” and that coal plant retirements could

cause “significant congestion increases."2” He stated

that PJM believes such coal retirement problems can

be addressed by transmission upgrades.”8

The IMM

The IMM does not support going forward with

the RFP, at least in its present form. Dr. Bowring

takes the position that "[iJf you're going to rely on

markets, you have to be fully committed to

markets,"2° and he disagrees with the premise that

PJM's Reliability Pricing Model ("RPM") fails to

adequately incent new generation.*° He testified

that the Commission's RFP "will have long lasting,

negative consequences for PJM markets” because it

will suppress prices.3! He believes that the RFP will

result in a situation where only "subsidized" units

would be built under such long-term contracts.32 He

does state that with significant changes to the RFP

to include participation by existing suppliers and any

fuel type, the RFP would be "consistent with the

competitive wholesale market design."

MEA

The Maryland Energy Administration

supports going forward with the RFP. It notes that

26 Id., p. 63.

27 Id., p. 57.

28 Id., p. 56.

29 Id., p. 67.

30 Jd., p. 66.

31 Id., p. 67.

32 Comments of the Independent Market Monitor for PJM, p.2.

33 Jd., pp. 2-4.

37a

"while current generation resources meet today's

reliability needs," studies looking into the future

reveal there is a need for new generation in

Maryland.4 MEA cites the finding in the Long Term

Electricity Report for Maryland ("LTER") that shows

electricity usage increasing by 18% by 2030, and in

the High Demand scenario by over 30%.55 MEA

notes that 90% of Maryland's generation is coal or

nuclear, and much of it is very old, reflecting a lack

of fuel diversity.°6 MEA also notes that Maryland

has not had any major new generation come on-line

since 2003, and that RPM has not led to the

construction of any significant power plants in

Maryland since its inception in 2007, despite high

prices for capacity.27 MEA's witness, Mr. Lucas,

testified at the hearing that 30% of Maryland's

electricity is imported and that figure is projected to

grow.*85 He said that the LTER ran a combined

events scenario in which coal _ retirements,

transmission delays, and reductions in demand

response resulted in Maryland requiring new

generation by 2015.39 He also commented on the

substantial variability in the year-to-year forecasts of

the utilities, sometimes "swinging by more

megawatts than a large gas plant."4°

OPC

% Comments of the Maryland Energy Administration, p. 1.

3 Id., p. 2.

37 Id., p. 3.

% Transcript, p. 80.

3 Id., p. 83.

Id., p. 84.

38a

OPC supports going forward with the RFP.

While noting that there is presently significant

excess reserve capacity beyond the 15.5% minimum

planning reserve requirements in PJM, OPC states

that "[T]here is reason to believe that a combination

of new environmental regulations, low gas prices,

and the inability of developers to arrange financing

for new generation development in the current

market could result in a deficiency of generation

resources for Maryland consumers as early as 2015

or 2016."41 OPC points specifically to the Mercury

and Air Toxic Standards ("MATS") issued by the

Environmental Protection Agency ("EPA") on

December 16, 2011, and the Cross-State Air

Pollution Rule ("CSAPR") issued on July 6, 2011, as

likely to lead to the retirement of between 11,000

MW to 25,000 MW of coal-fired capacity in PJM.4?

This is exacerbated by low gas prices, which lead to

coal plants being dispatched for fewer hours and

receiving less revenue when they are dispatched,

which in turn leads to more retirements.*3 OPC also

notes that the LTER simulation of early retirement

of 14,000 MW of at-risk coal capacity advances the

Maryland need date to 2016, and early retirement of

25,000 MW of at-risk coal advances the Maryland

need date to 2015.44 In the latter instance, the LTER

model would add 2,100 MW of new capacity in the

Southwestern Mid-Atlantic Area Council

("“SWMAAC") between 2015 and 2018.45 OPC does

not believe that the Contract for Differences

41 Comments of the Office of People’s Counsel, p. 8.

42 Jd., pp. 9, 11.

43 Td., p. 14.

“4 Id., pp. 18-19, Transcript, P. 87.

45 Id., p. 19.

39a

stemming from the RFP would undermine the

capacity market or have a widespread negative

effect.46

Staff

Although Staff makes no _ explicit

recommendation, it does note that the utilities

forecast for projected peak demand would require

some new generation in 2016.4’ Staff also states that

the "more conservative scenarios" incorporated in the

LTER indicate a need for new generation in both

PJM and Maryland by 2015.** Staff points out that

the PJM peak load forecast is lower than the

utilities’ forecast for 2015 by more than 7%.‘ Staff

performed an analysis of the bill impacts to

residential customers for 600 MW of a combined

cycle project and found, if it cleared every auction

and received RPM capacity payments every year, the

monthly bill impact would range from a credit of $

0.23 to a cost of $ 0.36 for the high market value and

low market value case respectively. Staff also

cautions that demand response in Maryland is very

high, and that Commercial and Industrial demand

response may be in a state of maturity and any

additional demand response will have to come from

the residential sector.5! Staff recommends that if the

Commission does decide to proceed with the RFP, it

* Transcript, p. 89.

47 Comments of the Staff or the Public Service Commission of

Maryland, p. 17.

Id., p. 18.

Id., p. 4, Table A.2.

8 Id., p. 23.

51 Id., p. 13.

40a

should do so in increments rather than by ordering

all 1,500 MW now.®2

BGE comments that there is an excess of

generation capacity throughout PJM already, that

new transmission projects have been identified to

meet Maryland's needs, that PJM's peak load

forecasts are decreasing, that demand response

continues to grow, and that customers would be

“burdened” with additional costs for unneeded and

uneconomic generation by proceeding with the RFP.

According to BGE, the RFP is “unnecessary."™

Potomac Edison states there is no need for new long-

term generation, because for the foreseeable future

adequate resources are available to meet electric

supply demand in Maryland. PE cites the LTER

that, "For most scenarios, no new generation

capacity is needed in PJM to meet reliability

requirements until about 2018."55 PE notes that it

receives ample bids of supply in the Standard Offer

Service ("SOS") auctions and that retail choice

remains strong in Maryland. PE argues that

supply is increasing due to addition of renewable

generation while demand is moderating, indicating

no need to proceed with the RFP’ In their joint

comments, Pepco and Delmarva vigorously oppose

going forward with the RFP at this juncture. They

52 Transcript, p. 93.

53 Comments of Baltimore Gas and Electric Company, p. 1.

54 Comments of Potomac Edison, p. 1.

55 Id., p. 2.

56 Id., p. 3.

57 Id., p. 4.

4la

urge the Commission to pause and hold evidentiary

hearings which include pre-filed sworn testimony,

discovery, and cross-examination.*® They note that

PJM's peak load forecast for SWMAAC has declined

virtually every year since 2007, and that from a load

perspective, there is less of a need for new generation

than there was in 2009.59 They argue that the

current SOS procurement process has produced

adequate supplies, that PJM projects adequate

transmission for the Pepco and Delmarva zones

through at least 2019.1 that demand response

resources have reduced the need for new

generation,®2 and they also point to the LTER as

evidence that no new generation is needed until at

least 2020.68 The PHI companies vigorously advocate

that distribution companies such as themselves

should be allowed to bid and build the new

generation if the RFP proceeds.“ Finally, they ask

the Commission to include an appropriate cost

recovery mechanism for them to recover any

payments made under the Contract for Differences if

the RFP proceeds.®

The Suppliers

CPV and GE Energy both advocate that the

RFP should proceed. CPV includes an extensive

58 Comments of Potomac Electric Power Company and Delmarva

Power & Light Company, pp. 8, 35-36.

59 Id., pp. 13-14.

8! Id., pp. 17-21.

82 Jd., pp. 21-22.

63 Id., p. 21.

4 Id., pp. 26-28.

8 Jd., pp. 30-35.

42a

discussion of the PJM data and the LTER analysis

that concludes that there will be a need for 675 MW

reaches this conclusion by finding that four

"adjustments" need to be made to the assumptions

underlying the LTER: first, that the effect of the Mt.

Storm -- Doubs transmission upgrade is overstated;®

that it overstates the amount of available demand

response capacity;® that it overestimates demand

response because it does not account for non-

performance and fatigue;®? and that the LTER fails

to account for the effect of recent environmental

regulations in estimating retirements of coal

facilities.7? Mr. Egan of CPV testified at the hearing

that SWMAAC is relying on demand response and

energy efficiency for 2,400 MW, or slightly more than

20% of its total capacity needs in 2014/2015.”' CPV

also notes it requires a total of 5 to 6 years for

planning and construction of new generation, and

that the building phase alone requires 2 1/2 to 3

years.”2 GE Energy points out that the reserve

margin in SWMAAC has been negative for several

years, rather than the 15% usually deemed

necessary, and that it is projected to exceed -20%

during 2012.73 GE also notes that 90% of the total

energy supplied in SWMAAC since 2008 is from coal

and nuclear resources, which require a long time to

% Comments of CPV Maryland , LLC, Exhibit A, Transcript, P

151.

87 Id., p. 8.

68 Id., pp. 9-10.

88 Id., pp. 10-13.

70 Id., pp. 13-16.

71 Transcript, p. 156.

72 Id., p. 155.

73 Comments of GE Energy, p. 1.

43a

start-up.”4 Particularly as additional renewable

resources are added to the generation mix by 2022,

there will be a need for greater flexibility in

generation resources, a requirement satisfied by

natural gas combined cycle generation.”®

Other suppliers are equally adamant that the

Commission should not proceed with the RFP

Exelon Corporation states that new generation is not

needed citing the LTER and notes it projects the

utilities will reduce demand by almost 3000 MW by

2015." Calpine Corporation likewise asserts new

generation is not needed, that proceeding would

"destroy" the competitive market, and that new

merchant generation is being built elsewhere.”

Calpine also contends the RFP violates the U. S.

Constitution's Supremacy and Commerce Clauses.”®

PPL claims that going forward with the RFP is not

necessary because the competitive market is working

to create reserve margins above 20% through 2015,

and trends indicate demand is declining.”9 It asserts

that building new generation now will only lead to

higher, not lower, electricity prices for Maryland

consumers, and notes that similar proposals in New

Jersey have led to constitutional challenges. PSEG

joins the others in asserting that proceeding with the

RFP will interfere with the proper functioning of the

4 Id., p. 2, Transcript, p. 228.

7% Jd., p. 2, Transcript, p. 229.

78 Comments of Exelon Corporation Regarding the Commission's

Request for and Review ef Proposals, pp. 2-3.

77 Comments of Calpine Corporation, pp. 1-3.

78 Id., p. 4.

7 Comments of PPL Energy Plus, LLC Regarding the

Commission's Request for and Review of Proposals, p. 1.

8 Id., pp. 2-3.

44a

wholesale competitive market, and cites the Brattle

Group's finding that "RPM is performing well."®!

PSEG advocates that instead of proceeding with the

RFP, the Commission should work with PJM to

improve RPM.®2 If the Commission were to proceed,

PSEG urges it to open the RFP to existing

generation, any fuel type and any location in PJM.®

Tr siations

The trade association representatives also

oppose going forward with the RFP P3, which

represents existing generation owners in PJM,

suggests that resources have already been procured

through 2015 to meet Maryland's needs with a

"robust" reserve margin, demonstrating there is no

need for new generation.** P3 notes that demand is

not growing at the rate previously expected, and

PJM has been regularly reducing its projected future

needs for Maryland.® It points to the experience last

summer when peak demand was extremely high, but

PJM met that peak demand with present

generation.* P3 emphasizes that coal generation in

Maryland has already been upgraded with

environmental controls, so that the impact of new

federal rules will not be as severe in Maryland as in

other States.8’ Like some of the suppliers, P3 asserts

81 PSEG Energy Resources & Trade LLC Comments, pp. 2-3,

and fn. 2.

82 Id., p. 4.

83 Id., p. 5.

8 Comments of the PJM Power Providers Group, p. 2,

Transcript, p. 209.

86 Id., p.2.

8 Transcript, p. 213.

87 Comments of the PJM Power Providers Group., p. 3.

45a

the RFP, like a New Jersey statute, will be found to

be unconstitutional because it intrudes on FERC's

exclusive authority to establish wholesale market

prices and it violates the Commerce Clause by

discriminating against out-of-state generation.®* P3

complains about a lack of transparency, and states

the Commission should make all bids public and

open for comment.8® EPSA, a national trade

association of competitive power suppliers including

generators and marketers, also believes that new

generation is not needed, and the Commission should

rely on the competitive markets to provide the least-

cost, long-term solutions.™ In _ reaching its

conclusion, EPSA relies on the LTER that new

generation is not needed until 2019 or 2020, and

notes the EmPOWER programs effectiveness in

reducing peak demand.?! EPSA asserts that PJM is

maintaining reliability with a cleared reserve margin

of over 20%.92 It points to PJM peak load forecasts

for 2015 and 2020 that are 3% smaller than expected

just a year ago as further indication that additional

generation is not needed. It cites LS Power

Development's recent ability to obtain financing for

construction of a new generating plant in New Jersey

as evidence that the market works to provide new

generation without the need for ratepayer

subsidies.*4 Mr. Shelk of EPSA testified at the

hearing that even a small amount of generation, if

88 Id., pp. 3-4, Transcript, pp. 210-211.

89 Jd., pp. 5-6, Transcript, p. 212.

% Comments of the Electric Power Supply Association, p. 3.

91 Jd., p. 7.

8 Id., p. 9.

93 Id.

% Id., p. 12, Transcript, p. 189.

46a

uneconomic and not needed, has a major impact on

the market.% RESA, an association of competitive

marketers, also recommends an _ "extensive

evidentiary hearing."6 RESA seems _ mostly

concerned with the cost recovery mechanism for the

utilities, and encourages the Commission to place it

in a charge on SOS customers, rather than on all

customers (which would include customers of third-

party suppliers).°%”

Sierra Club

The Sierra Club takes the position that "there

is no demonstrated need for capacity in the

foreseeable future" as current projections show

excess capacity.% It included in its written

Comments a report by Synapse Energy Economics

Inc. which emphasizes the emergence of new supply-

side resources in reducing projected need.® It argues

the current RFP is unduly restrictive and should be

opened up to renewable generation, and energy

efficiency and demand response resources that are

more environmentally friendly. At the hearing,

Mr. Hausman testified on behalf of the Sierra Club

that renewable generation primarily supplies energy

% Transcript, p. 189.

% Comments of the Retail Energy Supply Association, p. 2.

97 Id., pp. 4-7.

98 Comments of the Sierra Club and Chesapeake Climate Action

Network Regarding the Need for New Generating Facilities to

Meet Long-Term Demand for Standard Offer Service in

Maryland, pp. 2, 5-6, Transcript, p 98.

% Jd., Maximizing Benefits: Recommendations for Meeting

Long-Term Demand for Standard Offer Service in Maryland.

100 Jd., pp. 2-3, 7-17, Transcript, p. 101.

47a

and doesn't help with regard to capacity resources. !°!

He urged the Commission to rely on PJM to ensure

reliability throughout the region. }°2

Boston Pacific

Boston Pacific, the Commission's consultants

in this proceeding, acknowledges that the situation

regarding reliability in Maryland has improved since

2007 due to a slowing of load growth, activation of

additional transmission, and a substantial addition

of demand response.'!°3 However, Boston Pacific

identified four key risks to future reliability: (1) load

growth could speed up as the economy recovers; (2)

retirement of generating units, especially coal units,

could be greater than expected; (3) since Maryland

imports 30% of its power, it is very dependent on

transmission projects, which could be delayed; and

(4) increased penetration of renewable generation

could accelerate transmission problems.'% Boston

Pacific notes that the PJM capacity market has

failed to bring new generation to Maryland, in spite

of the fact that clearing prices in SWMAAC capacity

auctions average almost double that of the non-

constrained portions of PJM.'!% They recommended

the Commission seek new, natural gas-fired,

combined cycle generation because it is operationally

flexible, clean relative to our current generation mix,

and comparatively inexpensive to operate.!% They

10! Transcript, p. 104.

102 Transcript, pp. 107-108.

103 Evaluation of a Draft Request for Proposals for Generating

Capacity Resources Under Long-Term Contract, pp. 1-2.

104 Td., pp. 2-3, 17-26.

105 Jd., pp. 7-10 Transcript, p. 43.

106 [d., p. 30, Transcript, p. 32.

48a

suggested the new generation should be limited to

SWMAAC because that is the constrained zone that

has seen the highest prices, the least generation

development, and is at most risk for reliability

problems.'® At the hearing, Dr. Roach testified that

30% of Maryland's energy is imported, and is thereby

at risk for transmission difficulties, !% and 90% of the

in-state generation is coal or nuclear.’ Mr.

Mossberg of Boston Pacific stated that 9,000 MW out

of 12,500 MW, or 72%, of Maryland generation is

over 30 years old.'!° They emphasized the need to

look long-term since it requires 3 years to build a

combined cycle generating plant.!!!

Commission Decision

The Nee New Generation

Among the things that go bump in the night,

the thought that the lights might go out in Maryland

as a result of our actions, or inactions, during our

term as Commissioners is one that keeps us awake.

On November 6, 2008, we wrote that "From the time

the potential shortfall first was revealed, this

Commission has stated publicly, forcefully and

unequivocally that a policy of conscious inaction was

not acceptable."!!2 That statement remains true

107 Jd., p. 31, Transcript, p. 18.

108 Transcript, p. 22.

109 Transcript, p. 26.

110 Transcript, p. 35.

‘1! Transcript, p. 39.

112 In the Matter of the Investigation of the Process and Criteria

for Use in Development of Request for Proposal by the Maryland

Investor-Owned Utilities for New Generation to Alleviate

49a

three-and-one-half years later. Much has changed in

the interim, most of it for the good. PJM's peak load

forecasts have been reduced and, where prior to 2008

they were seeing a need for new generation in 2012,

it has now moved that date back to 2017 - 2020.''5 As

was noted by numerous parties, the LTER model's

most likely scenario also does not project a need for

new generation until 2020. Certainly the evidence in

this case indicates the need for new generation is

less imminent than it was in 2008.

However, load forecasting is not a science and

the forecasts are extremely variable. For example,

Staff's analysis notes, "the significant difference for

the BGE and the Maryland portion of the DPL

transmission zone is approximately 324 MW in 2012,

increasing to 767 MW in 2015 as presented in Table

A.5, and may represent more than half of the 1,500

MW being considered in this proceeding."!'4 Such

variability demonstrates the risk of reliance on such

projections for when new generation will be needed.

A major source of the variability, and a major

source of concern for us, is the always uncertain and

now even more uncertain future of our existing coal-

fired generation and the coal-fired generation in

neighboring states that export electricity into

Maryland. PJM categorizes coal generation more

than 40 years old and less than 400 MW as at "high-

risk" of retirement.!!5 Several parties emphasized

Potential Short-Term Reliability Problems in the Sate of

Maryland, Case No. 9149, Order dated November 6, 2008, p. 2.

113 Transcript, pp. 48-50.

114 Staff Comments, p. 6.

115 PJM Comments, pp. 11-12.

50a

that 90% of Maryland generation is either coal or

nuclear.'!46 Of the nearly 5,000 MW of coal

generating capacity in Maryland, 70% is more than

40 years old, and thus at "high-risk."!!7 Recent EPA

Mercury and Air Toxic Standards and the Cross-

State Pollution Rule applied to coal-fired plants are

likely to lead to the retirement of between 11,000

MW and 25,000 MW of coal-fired capacity in PJM.!!8

Although it is likely Maryland's coal-fired generation

will see less retirements since most of it has had

some environmental controls installed to comply

with the Maryland Healthy Air Act,'!® there is

nonetheless considerable uncertainty about how

these new rules will impact Maryland coal-fired

generation and the plants in adjoining states that

have not taken the same environmental initiative.

Two such coal-fired plants falling in the "high-

risk" category are C. P Crane and H. A. Wagner, two

plants Constellation agreed to sell in order to

mitigate market power concerns from its merger

with Exelon.12° PJM has acknowledged that

retirement of either or both of these plants would

likely result in potential reliability violations.!?! PJM

also acknowledged that their retirement would

exacerbate the existing transmission constraint in

116 MEA Comments, p. 2; GE Energy Comments, p. 2;

Transcript, p. 26 (Boston Pacific).

117 MEA Comments, p. 2.

118 OPC Comments, pp. 9, 11.

19 P3 Comments, pl 3.

120 In the Matter of the Merger of Exelon Corporation and

Constellation Energy Group, Inc., Case No. 9271, Order No.

84698, p. 104.

121 PJM Supplemental Comments, p. 4.

5la

SWMAAC.!22 There is simply restricted ability to

bring electricity to Maryland from the west over the

Allegheny Mountains. !23

In addition, the retirements of coal plants in

the PJM region outside of Maryland poses yet

another reliability risk, as the lack of in-state electric

generation forces Maryland to rely more and more on

out-of-state generation and transmission resources.

As noted by Boston Pacific, Maryland imported

around 30% of its electricity needs during the 2005-

2009 period and that amount grew to 35% in 2009

alone.!24 We agree there are great uncertainties and

risks associated with transmission planning and that

Maryland is "very susceptible to the risks of

transmission planning and approval = and

transmission outages."!25

We are also concerned about the extent of

Maryland's reliance on demand response to keep

peak load demand in check. The evidence indicates

that SWMAAC will rely on demand response and

energy efficiency for 2,400 MW, or slightly more than

20%, of its total capacity needs in 2014/2015.'26 Staff

pointed out that Commercial and Industrial demand

response may be close to saturation, and any

additional relief by way of demand response is likely

to have to come from the residential sector.!27 We

note that we are already seeing problems in

123 Td., p. 5.

183 Transcript, p. 63.

124 Boston Pacific Report, p.24.

125 Jd.

1% Transcript, p. 156 (CPV).

127 Staff Comments, p. 13.

52a

Maryland with our Curtailment Service Providers

being able to meet their contractual commitments for

demand response.!28 While we remain strong

advocates for demand response as a low cost-effective

way to address peak load growth, we are reluctant to

rely on it to the exclusion of considering new

generation.

We also share Boston Pacific's concern that

significant additions of renewable generation will

require more diversification of our generation mix.

Because it is dependent on sun or wind, renewable

generation is intermittent, and cannot help address

reliability issues.'29 Maryland has an aggressive RPS

that calls for 20% of our generation to come from

renewable sources by 2022.!3° This will require other

dispatchable generation with flexibility to start

quickly, a characteristic that our existing coal and

nuclear fleet does not have.'3! Nuclear power plants

especially do not run in a load-following up-and-

down mode. Therefore, successful integration of

renewable generation to meet our RPS goal will

require additional flexible generation.

128 See In the Matter of the Investigation of the Process and

Criteria for use in Development of Request for Proposal by the

Maryland Investor-Owned Utilities for New Generation to

Alleviate Potential Short-Term Reliability Problems in the State

of Maryland, Case No. 9149, Motion of EnerNOC to Amend

Agreement for Capacity Resources dated June 28, 2011;

Transcript 192-193 (EPSA).

129 Transcript, p. 25 (Boston Pacific); p. 86 (MEA); p. 104 (Sierra

Club).

130 GE Energy Comments, p. 2.

131 Jd.; Transcript, p. 228 (GE Energy)

53a

Furthermore, and of critical importance, we

cannot rely on PJM's Reliability Pricing Model to

deliver new generation to Maryland.'32 Maryland has

not seen any significant new generation constructed

here since 2003.'33 Since its inception in 2007, RPM

has brought no new generation to Maryland, in spite

of the fact that clearing prices for capacity in

SWMAAC have averaged almost double those of the

non-constrained portions of P.JM.'54 As an example,

the RPM clearing prices in SWMAAC rose from $

110/MW-day in the 2011/2012 delivery year, to $ 133

in 2012/2013, and to $ 226 in 2013/2014 (more than

eight times the capacity prices paid by ratepayers

living in Western Maryland). Despite these

exorbitant capacity charges, which have increased

energy costs to Maryland ratepayers by hundreds of

millions of dollars, no new base load generation was

bid into the BRA during the 2012-2014 delivery

period. Zero. The simple fact is that the one year

signal, three years into the future has not provided

sufficient certainty for prospective generation

suppliers to secure financing in the current economic

climate. And we do not find it reasonable to require

us, as P3 and the IMM and other generators would,

to entrust the reliability of our State's electricity

supply entirely to the operation of a capacity market

that, by design, seeks to incent long-term assets

solely through short-term price signals. The Federal

Power Act does not relegate us or our ratepayers to

that binary choice, and we would flout the intent of

the General Assembly if we ignored our authority

182 Commissioner Brenner does not join the Commission's

discussion in this paragraph.

183 MEA Comments, p. 3.

14 MEA Comments, p. 3; Boston Pacific Comments, pp. 7-10.

54a

under State law in order to see whether the capacity

market construct someday might work. Even the

market-approach proponents acknowledge that RPM

requires changes.'!35

Our statute requires us to anticipate and meet

“long-term, anticipated demand in the State for

standard offer service and other electricity supply."

PUA, § 7-510(c)(6). The most salient risk factors we

have examined, taken individually and cumulatively,

point to the potential need for new generation in the

2015-2017 time period. Numerous parties pointed us

to the LTER conservative scenario that indicates a

need for new generation in Maryland by 2015.'°* We

accept these more conservative forecasts and find

there is a need for new generation in Maryland by

2015. The evidence is that it requires three years to

construct a new gas-fired combined cycle generating

plant and have it operational.!3’ Therefore, much as

Branch Rickey advised "[t]rade a player a year too

early rather than a year too late,"'3* we find it

reasonable and prudent to act conservatively and

before a serious reliability crisis occurs. We find,

therefore, that we must move forward with the RFP

at this time in order to meet Maryland's anticipated

long-term electricity demands. !%9

Having found there is a need for new

generation by 2015, we must still determine how

‘38 Transcript, p. 67 (IMM); Calpine Comments, p. 5; PSEG

Comments, p. 4; EPSA Comments, p. 12.

1% Transcript, p. 83 (MEA); OPC Comments, pp. 18-19; Staff

comments, p. 18;

137 Transcript, p. 155 oe p. 39 (Boston Pacific).

138 http://www . u br.shtml

55a

much additional generation is necessary to meet

long-term demand in the transmission-constrained

portions of the State. The evidence on this question

is less well developed. CPV's analysis of the LTER

data concludes there is a need for 675 MW in

SWMAAC by 2015.'4° Other parties also noted there

may be a need for less than the full 1,500 MW called

for in the RFP '4! We also recognize that our Order

in the recent merger of Exelon and Constellation

requires Exelon to cause construction of 120 MW of

gas-fired combustion turbine generation in Maryland

by the end of 2015.'42 These incremental megawatts

will address peak load, and may not necessarily be

built in SWMAAC. The merger Order also calls for

Exelon to cause construction of up to another 165

MW of renewable generation to be operational

sometime between 2015 and 2022.'43 This renewable

generation will not address our reliability need, but

may contribute to strains on the transmission system

due to their intermittent and locational attributes.

When we consider all the evidence in this case, we

find there is a need for approximately one new power

plant -- new generation in the range of 650 to 700

MW in SWMAAC -- beginning in 2015.

The Bids

Three bidders met the minimum threshold

requirements set forth in the RFP, two of which

contained multiple pricing options. Invenergy

proposed a 549 MW combined cycle facility located in

140 CPV Comments, Exhibit A.

41 Transcript, p. 93 (Staff) ; Boston Pacific Report, p. 31.

142 Case No. 9271, Order No. 84698, p. 105.

43 Jd., pp. 105-109.

56a

Prince George's County that would be operational on

June 1, 2017. Mattawoman proposed a 731 MW

combined cycle facility, also to be located in Prince

Georges County, that would be operational on June

1, 2016. CPV proposed a 661 combined cycle facility

in Charles County and offered a choice of in-service

dates of June 1, 2015 or June 1, 2016.'*4

The RFP specified the method by which the

bids were evaluated for the final short list

evaluation. The bids were modeled in a production

cost model to determine their cost to ratepayers

throughout the term of the Contract for

Differences.'*5 Boston Pacific and Siemens Power

Technologies International used the PROMOD IV

market simulation model for this analysis, using

"base case" inputs and four different sensitivities: a

high gas price case; a low gas price case; a PJM Net

Revenue Case;!4* and a coal retirement case.'4? The

modeling ultimately projected average bill impacts

for residential SOS customers (based on 1,000

kilowatt hours/month) and assumed a $ 150/MW-day

RPM price.'*® The CPV bid for an in-service date of

44 Boston Pacific Bid Memorandum dated April 3, 2012.

146 RFP, § 6.5.5, p. 16.

146 In the PJM Net Revenue Case, it is assumed the bids would

earn the same net revenues (i.e. market revenues less variable

costs) that PJM estimates in calculating its Minimum Offer

Price Rule (MOPR) screen. Boston Pacific Bid Memorandum

dated April 3, 2012, p. 3.

147 Boston Pacific Bid Memorandum dated April 3, 2012, pp. 2-

148 Modeling assumes rate impact applies only to SOS

customers in the BGE, Pepco and Delmarva service territories,

and that 22.5% of residential load is served by non-SOS third

party suppliers (based on 2011 data).

57a

June 1, 2015 was found to be the best price for SOS

ratepayers, with the average impact to residential

SOS ratepayers projected to be a credit of $

0.49/month over the entire life of the contract.'49

Under the model, average residential SOS

ratepayers would see a rate payment in the initial

years ranging from $ 2.03/month in 2015 to $

1.05/month in 2019, which is projected to change to a

rate credit for the remaining 15 years of the contract,

ranging from $ 0.32 in 2020 to a high of $ 2.98/month

in 2024. The analysis showed a credit to residential

SOS ratepayers over the life of the contract for all

cases except the PJM Net Revenue Case, and

remained so even if customer migration to third-

party suppliers were to increase to 30% in 2015.!5°

Based on this analysis, and our finding concerning

the amount of need in 2015, we accept only the CPV

bid for a 661 MW combined cycle facility located in

Charles County to be operational on June 1, 2015.

Cost Recovery

We have given careful attention to the parties'

concern that we address the issue of the utilities’ cost

recovery for their payments (if any) under the

Contract for Differences.'5! Considering that our

statutory mandate is to meet the long-term demand

for SOS service for residential and small commercial

customers, we find that the utilities we direct to

enter into these Contracts for Differences should

recover the costs through their respective SOS

149 Jd., pp. 7-8.

150 Id., p. 9.

151 Pepco/Delmarva Comments, pp. 30-35; RESA Comments, pp.

4-7.

58a

surcharges. We direct that this cost "recovery" is to

go both ways: the SOS surcharge will be increased as

appropriate to reflect those months in which the

utilities have payments due to the Supplier under

the Contract for Differences, but likewise the SOS

surcharge is to be credited for those months in which

the Supplier pays the utility. Because the Boston

Pacific modeling indicated the likelihood of a net

credit over th

This text is long and has been trimmed here. Open the source document for the complete record.

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.