PPL Energyplus, LLC et al v. Nazarian et al

Filing 177

MEMORANDUM OF DECISION. Signed by Judge Marvin J. Garbis on 9/30/13. (mps, Deputy Clerk)

IN THE UNITED STATES DISTRICT COURT
FOR THE DISTRICT OF MARYLAND
PPL ENERGYPLUS, LLC, et al.
Plaintiffs

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vs.

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DOUGLAS R. M. NAZARIAN, in his
official capacity as Chairman
of the Maryland Public Service
Commission, et al.

CIVIL ACTION NO. MJG-12-1286

*
*
*

*

*

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Defendants
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MEMORANDUM OF DECISION
The Court has heard the evidence, reviewed the exhibits,
considered the materials submitted by the parties, and had the
benefit of the arguments of counsel.
The Court now issues this Memorandum of Decision as its
findings of fact and conclusions of law in compliance with Rule
52(a) of the Federal Rules of Civil Procedure.

The Court finds

the facts stated herein based upon its evaluation of the
evidence, including the credibility of witnesses, and the
inferences that the Court has found reasonable to draw from the
evidence.

I.

INTRODUCTION
Prior to 1999, Maryland utilized a vertically integrated

model of electric energy regulation.

A single electric utility

(such as BGE or Pepco) owned the facilities that produced and
delivered electricity to the users in its exclusive territory.
Maryland electric power users purchased electricity from the one
utility that served the territory in which they were located.
The Maryland Public Service Commission ("PSC") ultimately
determined whether additional generation resources were needed
in Maryland and provided for the financing of those resources
through the approval of rate increases.
In 1999, the Maryland General Assembly passed the Electric
Customer Choice and Competition Act (the "1999 Act"), which
restructured, or deregulated, Maryland's electric energy market.
The 1999 Act separated the Maryland "utilities' generating
assets from their distribution and transmission functions" by
transferring ownership of those generation assets to other
companies that owned and operated the power plants.

P.391

(2007 PSC Interim Report) at 10.
The PSC is empowered by the State of Maryland to assure
"safe, adequate, reasonable, and proper [electric] service."
Md. Code Ann., Pub. Util. § 5-101(a).

However, Maryland-based

utilities, which now no longer own generating facilities, must
purchase energy on federally regulated wholesale markets.

Thus,

the utilities and, correspondingly, Maryland ratepayers are
directly affected by the wholesale prices determined on the
federally regulated wholesale markets.
2

In mid-2000, the PSC and others began to voice concerns
over the operations of Maryland's electricity markets, the postrestructuring consumer electricity rates, and the existence of
adequate generation resources to serve the energy needs of
Maryland ratepayers.

In 2007, the PSC filed a report with the

General Assembly, stating that the federally regulated wholesale
markets had not responded to Maryland's needs and opining that
those markets were unlikely to respond in the immediate future
to the state’s "looming capacity shortage."
Interim Report) at 1.

P.391 (2007 PSC

The PSC concluded that it should require

the Maryland utilities to enter into long-term contracts to
induce the construction of new electric generation facilities in
Maryland.
Ultimately, on April 12, 2012, the PSC issued the
Generation Order at issue,1 directing Baltimore Gas and Electric
Company ("BGE"), Potomac Electric Power Company ("Pepco"), and
Delmarva Power & Light Company ("Delmarva") to enter into a
Contract for Differences ("CfD") with CPV Maryland, LLC ("CPV").
In essence, the CfD provided that regardless of the price set by
the federally regulated wholesale market, the Maryland utilities
would assure that CPV received a guaranteed price fixed by a
contractual formula.2

1
2

The result was that CPV had a secure

PSC Order No. 84815. See P.44.
Ultimately, the utilities' customers.
3

income stream available to finance construction of a generating
facility in a designated area within Maryland.3
Plaintiffs4 present claims in three Counts:
Count I

Violation of the Supremacy Clause, U.S.
Constitution, art. VI, cl.2;

Count II

Violation of the Commerce Clause, U.S.
Constitution, art. I, § 8, cl.3; and

Count III

Violation of 42 U.S.C. § 1983.

As discussed at length herein, the Court holds that
Plaintiffs have established their claim that the Generation
Order violates the Supremacy Clause of the United States
Constitution by virtue of field preemption5 but does not violate
the dormant Commerce Clause.6

3

As discussed herein, there was a theoretical possibility
(but a practical impossibility) that the facility could be
constructed in the District of Columbia.
4
The Plaintiffs are: 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; and Essential Power,
LLC.
The named Defendants are the Commissioners of the PSC, sued
in their official capacities, Douglas R. M. Nazarian, Harold
Williams, Lawrence Brenner, Kelly Speakes-Backman, and Kevin
Hughes. On January 8, 2013, after Plaintiffs filed the instant
suit, Douglas R. M. Nazarian was appointed to the Maryland Court
of Special Appeals.
5
The establishment of Plaintiffs' field preemption claim
renders moot the question of whether Plaintiffs also established
their Supremacy Clause conflict preemption claim.
6
The Court also holds that even if not formally abandoned,
Plaintiffs' 28 U.S.C. § 1983 claim is not viable.
4

II.

BACKGROUND
A.

Electric Power Grids In A Nutshell

As once said in reference to the Rule in Shelley's case, it
is one thing to put the subject of electric power grids in a
nutshell, but impossible to keep it there.7

Nevertheless, even

an oversimplified, incomplete, and imprecise introduction may be
useful to those totally unfamiliar with electric power grids.
To start, think of a power grid as analogous to a network
of pipes utilized to transport water from various pumping
stations, which take water from natural sources (lake, river,
etc.), to reservoirs.

The water in the reservoirs is then, as

demanded by a local utility, transported by pipes in the grid to
the local utility for distribution to the utility's customers.
However, for a closer analogy, think of the same grid
without any reservoirs.

When an amount of water is placed into

the grid by a pumping station, an equal amount must flow out of
the grid to a local utility.

Thus, the grid operator must

insure that, at all times, the supply (water put into the grid

7

Professor Barton W. Leach wrote that when "Lord Thurlow
undertook to put the Rule in Shelley's Case in a nutshell,"
Lord Macnaghten said, "'it is one thing to put a case like
Shelley's in a nutshell and another thing to keep it there.'"
W. Barton Leach, Perpetuities in a Nutshell, 51 Harv. L. Rev.
638, 638 n.a1 (1938)(quoting Van Grutten v. Foxwell, [1897] A.
C. 658, 671).
5

by the pumping stations) equals the demand (water sent out of
the grid to the local utilities).

This balance is maintained by

affecting the supply through adjustments of the price paid to
pumping station suppliers, payments to local utilities (or
customers) to reduce their usage, adjustments to the price paid
by the local utilities for the water they demand, etc.

B.

Federal Regulation of Electric Energy
1.

The Federal Power Act and FERC

In 1927, the United States Supreme Court held that the
dormant Commerce Clause prohibited states from regulating the
rates for wholesale power sales between utilities in different
states.

The Court reasoned that, unlike the regulation of the

rates charged to local consumers, regulation of interstate rates
places "a direct burden upon interstate commerce, from which the
state is restrained by the force of the commerce clause."

Pub.

Utils. Comm'n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S.
83, 89 (1927).8
In response to the Attleboro decision, Congress enacted the
Federal Power Act ("FPA") in 1935, which "closed the 'Attleboro
gap' by authorizing federal regulation of interstate, wholesale
sales of electricity — the precise subject matter beyond the
8

See Quill Corp. v. N.D. By & Through Heitkamp, 504 U.S. 298
(1992) (recognizing abrogation of Attleboro on other grounds).
6

jurisdiction of the States in Attleboro."9
535 U.S. 1, 20 (2002).

New York v. F.E.R.C.,

Specifically, the FPA gave the Federal

Power Commission, the predecessor agency to FERC, jurisdiction
over the regulation of interstate wholesale sales of electricity
and of interstate transmissions of electric energy.

See 16

U.S.C. § 824(a); New York, 535 U.S. at 20-21.
The FPA vested FERC with the responsibility for setting the
"rates and charges" of wholesale electric energy and for
ensuring that those rates are "just and reasonable."

Id. §

824d(a); Entergy La., Inc. v. La. Pub. Serv. Comm'n, 539 U.S.
39, 47-48 (2003).

In essence, FERC exercises this authority

through an intricate regulatory framework whereby transactions
for the wholesale sale of electricity are filed with FERC (on
either an individual basis or, more often, under a market-based
rate tariff). FERC determines on its own initiative, or in
response to a request by some party, whether such rates are
"just and reasonable" and not unduly preferential,
discriminatory, or disadvantageous to any party.10

See 16 U.S.C.

§ 824e; id. § 824d.

9

The "'sale of electric energy at wholesale' . . . means a
sale of electric energy to any person for resale." 16 U.S.C. §
824(d).
10
For example, FERC regulations require utilities with
market-based rate authority to file an Electronic Quarterly
Report ("EQR") every quarter summarizing the contractual terms
and conditions in agreements subject to the jurisdiction of
FERC, including agreements for the wholesale sales of capacity
7

As to the physical facilities that generate electric
energy, the FPA gave FERC jurisdiction "over all facilities for
[the] transmission or sale of electric energy" in interstate
commerce.

Id. § 824(b)(1).

But, "except as specifically

provided in this subchapter and subchapter III of this chapter,"
FERC has no jurisdiction "over facilities used for the
generation of electric energy or over facilities used in local
distribution or only for the transmission of electric energy in
intrastate commerce, or over facilities for the transmission of
electric energy consumed wholly by the transmitter."

Id.

The witnesses generally agreed that FERC has no authority
or power to order directly the siting, building, or construction
of a generation facility generally or in any particular location
within a state.

Tr. Mar. 5 (PM) at 82:4-21 (Nazarian); Tr. Mar.

6 (AM) at 44:1-21, 46:12-47:7 (Massey); Tr. Mar. 7 (AM) at
32:10-21 (Wodyka).

As discussed infra, that authority is

retained by the states under the FPA.
The FPA created an exclusive area of federal jurisdiction
in the electric energy realm regarding the regulation of
interstate wholesale energy sales and transmission, including
the entities that engage in such acts.

The FPA also retained a

sphere of state jurisdiction with respect to interstate retail
sales, distribution of electric energy, and the construction of
and energy.

See 18 C.F.R. § 35.10b.
8

local generation facilities.

See New York, 535 U.S. at 22-23

(explaining "the legislative history [of the FPA] is replete
with statements describing Congress' intent to preserve state
jurisdiction over local facilities").11

As summarized by the

U.S. Court of Appeals for the District of Columbia Circuit:
Jurisdiction
over
this
sale
and
delivery of electricity is split between the
federal government and the states on the
basis of the type of service being provided
and the nature of the energy sale . . . .
Thus transmission occurs pursuant to FERCapproved tariffs; local distribution occurs
under rates set by a state's public service
commission.
Niagara Mohawk Power Corp. v. F.E.R.C., 452 F.3d 822, 824 (D.C.
Cir. 2006).

2.

Development of Wholesale Energy Markets
a.

Traditional Vertically Integrated Utilities

"When Congress enacted the FPA, networks of high-voltage,
long-distance transmission lines which today crisscross the
United States" simply did not exist."

See Transmission Access

Policy Study Grp. v. F.E.R.C., 225 F.3d 667, 691 (D.C. Cir.

11

Also recognizing the role of the states, the Energy Policy
Act of 2005, which gave FERC jurisdiction over reliability
standards for the bulk-power system, states "[n]othing in this
section shall be construed to preempt any authority of any State
to take action to ensure the safety, adequacy, and reliability
of electric service within that State, as long as such action is
not inconsistent with any reliability standard." 16 U.S.C. §
824o(i)(3).
9

2000), aff'd sub nom. New York v. F.E.R.C., 535 U.S. 1 (2002).
The absence of this infrastructure likely was a factor in the
development of the vertically integrated structure of electric
utilities that generally predominated in the United States until
the 1990's.

The term "vertically integrated electric utilities"

refers to "generation, transmission, and distribution facilities
[which are] owned by a single entity and sold as part of a
bundled service (delivered electric energy) to wholesale and
retail customers."

Promoting Wholesale Competition Through Open

Access Non-discriminatory Transmission Services by Public
Utilities, Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities; Proposed Rulemaking and Supplemental
Notice of Proposed Rulemaking, 60 Fed. Reg. 17,662, 17,668 (Apr.
7, 1995) (hereinafter Open Access).

Under the vertically

integrated structure:
Most electric utilities built their own
power
plants
and
transmission
systems,
entered
into
interconnection
and
coordination arrangements with neighboring
utilities,
and
entered
into
long-term
contracts to make wholesale requirements
sales (bundled sales of generation and
transmission) to municipal, cooperative, and
other
investor-owned
utilities
(IOUs)
connected to each utility's transmission
system. Each system covered limited service
areas.
Id.

10

A utility operating in the vertically integrated structure
typically generates electricity with power plants it owns;
transmits the electricity from those power plants to its service
territory, usually defined by the state of location;12 and
distributes that electricity to end-use customers within its
service territory through local distribution networks, poles,
and wires that the utility owns and maintains.

See Tr. Mar. 4

(AM) at 121:14-122:21 (Alessandrini); Tr. Mar. 4 (PM) at 8:2310:20 (Carretta); Tr. Mar. 6 (AM) at 11:8-20 (Massey).
Where utilities operated in a vertical integration
structure, states often controlled the fiscal feasibility of a
utility's plans to expand its existing generation facilities or
to construct new power plants through a regulatory framework.
Thus, state regulators could decide whether to allow an increase
in the retail rate charged by the utility to end-use customers
sufficient to permit the utility to recover the cost of
financing the construction of new generation facilities or the
development of existing facilities.
121:14-122:25 (Alessandrini).

See Tr. Mar. 4 (AM) at

If the state approved an adequate

increase in retail rates, then the utility acquired a financial

12

Typically, a utility was granted a franchise by the state
government to provide electric service to all consumers located
within a defined territory or service territory. See Tr. Mar. 5
(AM) at 42:13-44:11 (Nazarian).
11

guarantee that assisted the utility in raising capital for its
generation projects.

See id.

When most electric utilities were vertically integrated
one-stop shops with monopolies over designated service
territories, the electric energy industry operated predominately
as a retail market subject to state regulation without
significant intervention from the federal government.
Mar. 4 (AM) at 121:14-122:26 (Alessandrini).

See Tr.

In this scenario,

the "wholesale market"13 regulated by FERC consisted primarily of
transactions between vertically integrated utilities whose
service territories were physically situated near each other.
Tr. Mar. 6 (AM) 13:3-16 (Massey).

b.

FERC's Fostering of Wholesale Energy Markets

In the 1970's and 1980's, significant "[t]echnological
improvements . . . made feasible the transmission of electric
power over long distances at high voltages."
Access, 225 F.3d at 681 (D.C. Cir. 2000).

See Transmission

In response to,

among other things, advancements in technology, the wholesale
electricity market began to blossom producing, inter alia,
independent and non-utility owned power plants capable of
providing competitively priced generation to the wholesale

13

Such as the market was in those days.
12

market.

See id.

With a burgeoning wholesale market came more

federal legislation and regulation.

For instance, in 1978

Congress passed the Public Utility Regulatory Policies Act
("PURPA"), which called for "a program to improve the wholesale
distribution of electric energy" and "the reliability of
electric service."

16 U.S.C. § 2601(2).

However, the

traditional vertically integrated utilities that owned
transmission lines were inhibiting the development of this
wholesale electricity market by "deny[ing] alternative producers
access to their transmission lines on competitive terms and
conditions."

Transmission Access, 225 F.3d at 682.

Congress and FERC took action during the 1990's to
facilitate the development of wholesale power markets by
"opening up transmission services" and reducing the ability of
vertically integrated public utilities to deny customers access
to competitively priced electric generation.
60 Fed. Reg. at 17,663-64.

See Open Access,

"[I]n 1992, Congress enacted the

Energy Policy Act, which amended sections 211 and 212 of the FPA
to authorize FERC to order utilities to 'wheel' power—i.e.,
transmit power for wholesale sellers of power over the
utilities' transmission lines—on a case-by-case basis."
Transmission Access, 225 F.3d at 682 (citing Energy Policy Act
of 1992, Pub. L. No. 102-486, §§ 721-22, 106 Stat. 2776
(codified at 16 U.S.C. §§ 824j-k) (giving non-utility generators
13

the right to have FERC order transmission-owning utilities to
interconnect and obtain access to the local utilities' delivery
systems)).14

In 1996, FERC issued Order No. 888, which "ordered

the national deregulation of electricity transmission services"
and required all public utilities that owned or controlled
transmission facilities to provide open access to their
transmission lines on the same basis on which they provide
access to themselves.

See Sacramento Mun. Util. Dist. v.

F.E.R.C., 616 F.3d 520, 523 (D.C. Cir. 2010) (internal quotation
marks omitted).
In a further effort to facilitate the development of
competitive wholesale power markets and to "increase the
efficiency of the electric transmission systems," FERC "strongly
encouraged the [electric power] industry to organize itself into
Regional Transmission Organizations" ("RTOs").

See generally

Delmarva Power & Light Co., 106 FERC ¶ 61,290, 62,080 (2004);
Tr. Mar. 6 (AM) at 48:7-11 (Massey).

RTOs are voluntarily

formed independent entities that have "consolidate[ed] control
14

Additionally, in 2005 Congress passed the Energy Policy Act
of 2005, which made FERC responsible for system reliability
standards for the bulk-power system. See Energy Policy Act of
2005, Pub. L. No. 109-58, § 1211(a), 119 Stat. 594, 941
(codified at 16 U.S.C. § 824o); Mandatory Reliability Standards
for the Bulk-Power System, 72 Fed. Reg. 16,416 (Apr. 4, 2007).
Prior to enactment of the Energy Policy Act, "the nation's bulkpower system depended on participants' voluntary compliance with
industry standards." Alcoa Inc. v. F.E.R.C., 564 F.3d 1342,
1344 (D.C. Cir. 2009).
14

of all transmission services in a particular region" and that
provide a platform for regional wholesale power markets.

See

Braintree Elec. Light Dep't v. F.E.R.C., 550 F.3d 6, 8 (D.C.
Cir. 2008); Tr. Mar. 6 (AM) 14:20-15:8, 48:3-11 (Massey); Tr.
Mar. 6 (PM) at 5:6-6:1 (Wodyka).

FERC explained that such

consolidation of control in particular regions was needed
because "traditional management of the transmission grid" by
vertically integrated electric utilities was inadequate to
support the efficient and reliable operation that is needed for
the continued development of competitive electricity markets."
Regional Transmission Organizations, 65 Fed. Reg. 810, 811 (Jan.
6, 2000).

According to FERC, despite Order No. 888,

opportunities still existed "for transmission owners to unduly
discriminate in the operation of their transmission systems so
as to favor their own or their affiliates' power marketing
activities," which could in turn impede competitive electricity
markets.

Id. at 817.

In 2000, FERC issued Order No. 2000 requiring "utilities
that own, operate, or control interstate transmission facilities
either to file a proposal to participate in an RTO or to
describe their efforts toward joining one."

Me. Pub. Utils.

Comm'n v. F.E.R.C., 454 F.3d 278, 280 (D.C. Cir. 2006); 18
C.F.R. § 35.34(a).

FERC's stated purpose entailed "promoting

efficiency and reliability in the operation and planning of the
15

electric transmission grid and ensuring non-discrimination in
the provision of electric transmission services."
35.34(a).

18 C.F.R. §

FERC defined the required functions of any formed RTO

as including, inter alia: (1) "employ[ing] a transmission
pricing system that will promote efficient use and expansion of
transmission and generation facilities" and (2) "ensur[ing] the
development and operation of market mechanisms to manage
transmission congestion." Id. § 35.34(k)(1)-(2).

An RTO

"manage[s] all the accounting for the energy that's put in and
taken out" of the transmission system it oversees, "operate[s]
all the different pricing and biding mechanisms that fall under
those wholesale market structures," and operates and plans the
regional transmission system within its area.

Tr. Mar. 5 (AM)

at 126:20-127:18 (Nazarian).
To constitute an RTO, an entity has to satisfy certain
requirements and have its proposal approved by FERC.

A FERC-

approved RTO operates pursuant to tariffs filed with, and
approved by, FERC.
(Nazarian).

See Tr. Mar. 5 (AM) at 126:22-127:6

Presently, "[RTOs] exist in about two-thirds of the

country" and are thus responsible for "about two-thirds of the
load" or power consumption in the United States.
(AM) at 19:21-20:16 (Massey).

Tr. Mar. 6

As relevant hereto, all of

Maryland is part of an RTO formed in 2002, operated and

16

administered by PJM Interconnected, LLC15.

C.

PJM Interconnected, LLC ("PJM")

After issuance of Order No. 2000, PJM organized itself into
an RTO, receiving full RTO status from FERC in December 2002.
Although PJM operates as an RTO under the control of FERC, PJM
is a private entity with 750 members or stakeholders, including
"parties that own facilities, or buy or sell power in the PJM
region."

Tr. Mar. 6 (PM) at 11:16-12:3 (Wodyka); see also

P.606 (PSC Order No. 81423) at 42.

PJM's members include "power

generators, transmission owners, distributors, marketers, and
large consumers."

P.606 (PSC Order No. 81423) at 42.

are not members or stakeholders of PJM.

States

See id.

The PJM area encompasses the District of Columbia and all
or parts of 13 states (collectively the "PJM region").16

The PJM

region, i.e., PJM's geographic footprint, consists of about 18
interconnected transmission zones.
15

A transmission zone is the

PJM (Pennsylvania, Jersey, Maryland) traces its origins
back to 1927 when three traditional utilities in Pennsylvania,
New Jersey, and Maryland formed a power pool. See Tr. Mar. 6
(PM) at 10:9-23, 17:3-9 (Wodyka).
16
As part of organizing into an RTO, the transmission
resources in the PJM region were unified through the voluntary
agreement of the owner-utilities of those resources.
Logistically, the owner-utilities "transferred operational
control of their transmission lines to the PJM Interconnection,"
but still retained equity ownership. Tr. Mar. 6 (AM) at 14:2415:8 (Massey).
17

area or territory in which a particular utility, such as
Baltimore Gas & Electric ("BGE"), owns transmission lines or
resources.

A transmission zone generally mirrors the utility's

historical service territory, discussed supra.
16.

See Pls.' Dem.

The PJM region has an aggregate population of approximately

60 million people, covers 214,000 square miles, and includes
1,365 electric generators that are connected to PJM's regional
transmission system.

P.516 (PJM – At a Glance) at 3; Pls.' Dem.

16.
As an RTO:
PJM is responsible for the coordination and
operation of the electric power system
across the entire PJM footprint.
They also
then
design
and
administer
competitive
markets
to
support
the
operations
and
activities
within
the,
again,
PJM
RTO
region. And finally they do . . . resource
adequacy planning to ensure that appropriate
generation and transmission resources are
available to serve the load requirements
across the PJM region. And they do this in
a way that they try to ensure the safety and
reliability of all the activities that occur
in the PJM footprint.
Tr. Mar. 6 (PM) at 10:25-11:10 (Wodyka).
As a FERC-approved RTO, PJM carries out its
responsibilities under FERC's jurisdiction and pursuant to FERCapproved tariffs, including the Open Access Transmission Tariff
(the "PJM Tariff"), which governs broadly how PJM operates the
regional transmission system in the PJM region.

18

P.516 (PJM – At

a Glance) at 4.

Additionally, PJM executes its duties through

agreements with other parties that are filed with, and approved
by, FERC, including the Transmission Owners Agreement ("TOA"),
the Reliability Assurance Agreement ("RAA"), and the Operating
Agreement.17

Tr. Mar. 6 (PM) at 25:5-19 (Wodyka); P.516 (PJM –

At a Glance) at 4.

1.

PJM's Operation of the Bulk-Power System and
Transmission Planning

One aspect of PJM's duties as an RTO is the day-to-day
operation and maintenance of the bulk electric power system "to
ensure reliability of electricity delivery across the [PJM]
region."

Tr. Mar. 4 (AM) at 37:20-38:16 (Alessandrini).

Thus,

PJM operates and maintains a regional interconnected
transmission system and power grid that spans the PJM footprint,
enabling electric energy to be dispatched and delivered to
various points across the PJM region.

See PJM Interconnection,

LLC, 132 FERC ¶ 61,173, 61,869-70 (2010); see also Tr. Mar. 5
(AM) at 127:7-18 (Nazarian).

PJM can be thought of as analogous

17

The RAA, which is "signed by all the load-serving entities
['LSEs'] in the PJM region," contains provisions related to the
amount of capacity resources that must be procured by each LSE.
P.516 (PJM – At a Glance) at 4; see also Tr. Mar. 6 (PM) at
131:2-132:10 (Wodyka). "The Operating Agreement must be signed
by organizations to become members of PJM." P.516 (PJM – At a
Glance) at 4. It "establish[es] how PJM operates as a regional
transmission organization." Id.
19

to an "air traffic controller[] of the power grid" because it
"monitors and coordinates . . . electric generators, . . . highvoltage transmission lines, . . . substations," and the flow of
electric energy therein on a day-to-day basis.

P.516 (PJM – At

a Glance) at 1.
PJM is responsible for planning for the regional
transmission system it oversees to ensure resource adequacy and
future system reliability.

To that end, PJM evaluates whether,

and to what extent, new transmission resources or improvements
to existing transmission resources "are necessary to meet the
requirements of the load in the future."
38:12-16 (Alessandrini).

Tr. Mar. 4 (AM) at

For example, "PJM conducts a long-

range Regional Transmission Expansion Planning (RTEP) process
that identifies what changes and additional to the grid are
needed to ensure reliability and the successful operation of the
wholesale markets."18

P.516 (PJM – At a Glance) at 2; see also

Tr. Mar. 6 (AM) at 20:21-24 (Massey).

The RTEP includes long-

term planning studies that look "into the future as far as 15

18

PJM does not "own" the transmission resources within the
PJM region. Instead, it manages and operates those resources
through an interconnected bulk-power system. See Tr. Mar. 6
(AM) at 15:5-8 (Massey). As a result of the TOA, a FERC-filed
agreement, the transmission resource owners who wish to be part
of the PJM region are obligated to perform certain transmission
projects identified by PJM in its RTEP. All utilities that own
transmission resources within the PJM region and wish to be part
of the RTO must enter into the TOA. See P.516 (PJM – At a
Glance) at 4.
20

years . . . to evaluate the performance of the transmission as
well as the generation system that's going to be able to
reliably serve load in the long run."

Tr. Mar. 6 (PM) at 22:10-

21 (Wodyka).

2.

PJM-Administered Wholesale Electricity Markets

In addition to managing the physical flow of electric
energy across the interstate transmission system within the PJM
region and planning for improvements to ensure infrastructure
reliability, PJM administers three wholesale markets19 in which
electric energy products are sold by capacity resources to PJM
and then resold by PJM to Load Serving Entities ("LSEs"20)
according to prices set in each of the respective markets.

Only

two of these markets, the energy market and the capacity market,
are pertinent to the instant case.

19

The third wholesale market,

As explained supra, the FPA charges FERC with the
regulation of interstate wholesale sales of electricity. See 16
U.S.C. § 824(a). Pursuant to the FPA, FERC has the power to set
and regulate wholesale electric energy "rates and charges,"
subject to the requirement that "such rates or charges shall be
just and reasonable." Id. § 824d(a); Miss. Power & Light Co. v.
Miss. ex rel. Moore, 487 U.S. 354, 373 (1988). It is pursuant
to this power that FERC authorizes PJM to run the PJM wholesale
markets, setting the price for wholesale electricity sales
through market-based auctions.
20
"LSE" refers to an entity that serves an energy demand by
purchasing wholesale energy for purposes of resale to end-use
customers who are actually using and consuming that energy, such
as homes and businesses. Tr. Mar. 5 (AM) at 48:22-51:21
(Nazarian); Tr. Mar. 11 (AM) at 41:1-7 (Roach).
21

the ancillary services market,21 is not.

Therefore, the term

"PJM Markets" as used herein refers to the energy and capacity
markets collectively and excludes the ancillary services market.
The PJM Markets are run pursuant to FERC-approved tariffs
and are the mechanisms that PJM uses to set or determine the
price at which energy and capacity are to be bought and sold
within its territory.

Transactions on the PJM Markets are not

the only permissible FERC-regulated wholesale transactions.
Private parties can buy and sell wholesale energy, capacity, and
ancillary services outside the PJM Markets and thus outside the
prices set by PJM in such markets.
[Document 140] at 21.

See OPC's Post-Trial Br.

For instance, subject to FERC rules, a

capacity resource, such as a generation facility, may sell
energy and capacity directly to an LSE through a bilateral
contract at a price determined by the parties, not set by PJM
through its market-based mechanisms.

See Tr. Mar. 5 (AM) at

16:21-17:9 (Nazarian).
Irrespective of the transactional means used by an LSE to
procure energy for resale to end-use customers, the costs
incurred by the LSE for wholesale purchases are passed on to
end-use customers through the retail rate charged by the LSE.

21

"Ancillary Service Markets are markets for so-called
reliability services that are necessary in realtime [sic] to
keep the system perfectly in balance." Tr. Mar. 6 (AM) at
18:14-16 (Massey).
22

See Miss. Power & Light Co. v. Miss. ex rel. Moore, 487 U.S.
354, 372 (1988) ("States may not bar regulated utilities from
passing through to retail consumers FERC-mandated wholesale
rates.").

Thus, an increase in wholesale rates tends to result

in a corresponding increase in retail rates.

a.

PJM Wholesale Energy Market

The PJM wholesale energy market is a market in which
wholesale electric energy generated by power plants is bought
and sold to meet present load demand within the PJM region (the
"PJM Energy Market").

In the PJM Energy Market, generation

resources22 sell energy to PJM that is generated and delivered
into PJM's interconnected power grid by the generator.

LSEs

then purchase that energy from PJM to deliver and resell it to
end-use customers, thereby satisfying load or customer demand
for electricity at any point in time.
24, 37:20-38:6 (Alessandrini).

Tr. Mar. 4 (AM) at 23:16-

Because generators sell their

energy to PJM, and LSEs purchase that energy from PJM and
receive delivery through PJM's interstate grids and transmission
systems, there is no direct sale of energy from a generator to a
particular LSE.

Thus, the PJM Energy Market is composed of two

22

The term "generation resources" refers to resources or
facilities within PJM that generate electric energy such as
power plants.
23

separate sub-markets — day-ahead and real-time.

In the day-

ahead sub-market, generation facilities bid into an energy
market for energy delivery in the next twenty-four hours; in the
real-time sub-market, generation resources bid into a market for
delivery in the next hour.

See Tr. Mar. 6 (AM) at 18:4-19:12

(Massey).
With respect to setting the price of energy in the PJM
Energy Market, PJM uses a system called "Locational Marginal
Pricing [('LMP')], which is the economic dispatch and price
setting of energy."

Tr. Mar. 4 (AM) at 24:22-24 (Alessandrini).

The concept of LMP is that it "reflects the value of the energy
at the specific location and time it is delivered" and "takes
into account the effect of actual operating conditions on the
transmission system in determining the price of electricity at
different locations in the PJM territory."
Glance) at 11.

P.516 (PJM – At a

LMP may result in different prices for energy in

different zones or locations within the PJM region.

These

"[e]nergy prices vary across the PJM footprint according to a
number of factors that differentiate energy prices at different
points within the system."

P.391 (2007 PSC Interim Report) at

17; see also Tr. Mar. 4 (AM) at 114:11-25 (Alessandrini).

LMP

for energy is "volatile" because "it depends on the value of
that energy, where it's produced, at the time it's produced, and

24

what the weather and other conditions are."23

Tr. Mar. 5 (PM) at

65:21-66:6 (Nazarian).
Concerning the prices received by power plants for energy
sold into the PJM Energy Market, generation facilities across
the PJM region have the ability to bid electric energy into the
PJM Energy Market at a bid price.

PJM, as the operator of the

power grid, dispatches that energy to meet load demand by taking
generation bids in ascending order of cost (i.e., beginning with
the lowest cost generation and ending with the highest cost
generation) "until the electric load is satisfied."
PSC Interim Report) at 17.

P.391 (2007

The highest cost generation (that

is, the cost at the point at which the load demand is satisfied)
"set[s] the clearing price for all [generators] operating in the
zone," and the resulting price is the LMP received by those

23

FERC describes the LMP as:
a bid-based, security-constrained economic
dispatch
and
unit
commitment
model
to
determine real-time and next-day LMP for
electricity, which reflect the value of
energy at a specific location and time it is
delivered. If the lowest-priced electricity
can reach all locations, prices differ at
the approximately 8,000 pricing nodes on the
transmission system by marginal losses only.
When transmission congestion prevents the
free
flow
of
energy,
more
expensive
electricity is ordered to meet that demand,
and the LMP is higher in congested areas.

PJM Interconnection, LLC, 132 FERC ¶ 61173, 61,870 (2010).
25

generation resources.

Id.

One
factor
that
influences
LMPs
significantly is the extent, or lack, of
transmission capability into a state or
region [because w]hen transmission lines are
'congested' or 'constrained,' i.e., they
cannot carry the lower cost electricity to
meet
demand,
PJM
must
dispatch
more
expensive
generation
located
in
the
constrained zone, which increases LMPs.
Id.

That is, if lower cost generation cannot be dispatched to

serve load in a particular zone due to limitations in
transporting the energy, PJM "skips" it and dispatches higher
cost generation, which results in "congestion costs" and higher
LMPs paid by the purchasing LSE and corresponding increases in
the retail energy rates for the end-use customers served by the
LSE.

See id. at 17-18; see also Tr. Mar. 4 (AM) at 116:6-118:1

(Alessandrini); Tr. Mar. 8 (AM) at 93:20-94:19 (Willig).

Thus,

higher LMPs provide higher revenues to generation facilities.
According to PJM, the LMP pricing model:
give[s] price signals that encourage new
generation sources to locate in areas where
they will receive higher prices. It signals
large new users to locate where they can buy
lower-cost power.
It also encourages the
construction of new transmission facilities
in areas where congestion is common, in
order to reduce the financial impact of
congestion on electricity prices.
P.516 (PJM – At a Glance) at 11; see also Tr. Mar. 8 (AM) at
94:16-19 (Willig) ("If the LMPs are different at . . . two
points, it means there's . . . differential value to resources
26

located at those two points.").

The Maryland Public Service

Commission ("PSC") has opined that LMPs do not work as intended,
in part because they "have not yielded adequate new generation
inside Maryland's transmission constraints."
Interim Report) at 18-19.

P.391 (2007 PSC

The PSC noted that as a "result[,]

Marylanders have paid and will continue to pay higher prices
than others in the PJM region due to our higher LMPs, but no new
material generation has been built in recent years."

b.

Id. at 19.

PJM Wholesale Capacity Market

PJM administers a wholesale capacity market (the "PJM
Capacity Market"), which is a forward market where a product
called "capacity" is sold by a capacity resource to PJM and then
resold by PJM to LSEs.

Capacity resources include generators

that will increase the energy supply and users that will reduce
the energy demand.

LSEs purchase capacity to meet their

capacity obligations under certain FERC-filed agreements with
PJM.

As in the PJM Energy Market, capacity resources sell

capacity to PJM; there is no direct sale of capacity from a
capacity resource to a particular LSE.
PJM sets the price for capacity bought and sold in the PJM
Capacity Market through application of the Reliability Pricing
Model ("RPM").

The RPM establishes an annual Base Residual

27

Auction ("BRA") through which PJM procures capacity from
capacity resources "for a particular 'power year'" three years
after the auction.

That is, capacity bid in the 2012 BRA will

be made available for the 2015/2016 power year.

The BRA

determines the market clearing price, which is the price that
PJM will pay for all capacity that clears the BRA. P.391 (2007
PSC Interim Report) at 19.

Generally speaking, increases in

capacity prices lead to increases in the retail rates paid by
end-use customers.

(i)

"Capacity"

"Capacity," as used herein to refer to a product,24 is a
standby commitment made by a capacity resource to either produce
electric energy or to consume less electric energy at a time in
the future when called upon by PJM to do so.

See Conn. Dep't of

Pub. Util. Control v. F.E.R.C., 569 F.3d 477, 479 (D.C. Cir.
2009).

"In a capacity market, in contrast to a wholesale energy

market, an electricity provider purchases from a generator an
option to buy a quantity of energy, rather than purchasing the
energy itself."

NRG Power Mktg., LLC v. Me. Pub. Utils. Comm'n,

24

Throughout the trial, witnesses referred to capacity as
both a product bought and sold in the PJM Capacity Market and,
more generally, as the mega-watt capability of existing
resources, i.e., how much electric energy an existing generation
facility (or facilities) is capable of producing at any point in
time. Herein, the Court refers to capacity as the product.
28

558 U.S. 165, 168 (2010).

Accordingly, the purchase of capacity

is the purchase of a capacity resource's availability either to
supply energy into PJM's interconnected transmission grid or to
reduce the demand for electric energy on the transmission system
at some defined future time.
(Willig).

Tr. Mar. 8 (AM) at 11:11-12:21

A purchase of capacity is not a purchase of actual

electric energy, but is instead a purchase of a resource capable
of producing, or reducing demand for, electric energy in the
transmission system when requested.25

Id.

Capacity resources take various forms.

The most typical

form is generation capacity, which is a generation resource's
commitment to generate actual electric energy into the
transmission system operated by PJM that can then be dispatched
to serve load at some future point, if and when called upon to
do so.

See id. at 11:11-18.

Any type of power plant (e.g.,

nuclear, natural gas, coal, wind farm, solar) is a generation
resource.

Capacity resources can also take the form of demand

reduction or energy efficient programs.

Unlike generation

resources that take place on the energy supply side of the
market, "demand response" programs occur on the energy demand
side of the market and represent a commitment by an LSE to

25

Therefore, a capacity resource that clears the BRA is paid
by PJM for that capacity irrespective of whether PJM actually
calls upon the resource in the future to generate actual energy
into the transmission system or to refrain from doing so.
29

reduce the demand for energy on the transmission system when
called upon to do so.

The ability of an LSE to reduce demand

generally involves an agreement by end-use customers to reduce
demand during peak periods at the request of the LSE in return
for compensation.

Under the RPM, generation and demand

reduction resources bid into the BRA as "capacity."
"Capacity is an important concept in the energy market due
to the substantial deviations between maximum energy demand and
minimum energy demand."

PPL Energyplus, LLC v. Solomon, No.

11-745, 2012 WL 4506528, at *1 (D.N.J. Sept. 28, 2012) (citing
U.S. Dep't of Energy, A Primer on Electric Utilities,
Deregulation, and Restructuring of U.S. Electricity Markets, at
A.4 (2002), http://www1.eere.energy.gov/femp/pdfs/primer.pdf)).
The purchase and sale of capacity ensures that at any given time
there are adequate resources capable of supplying energy to
serve forecasted load, as well as a reserve margin to meet
exigent circumstances, such as an unexpectedly high demand or
the failure of a generator.
(Willig).

See Tr. Mar. 8 (AM) at 11:4-12:7

As explained by Professor Willig:
If there is capacity in the market, and
there is need for the energy, then that
capacity is utilized, the physical cast is
turned on. However, sometimes capacity is
available, but it's not actually used. If
the capacity isn't there, then it can't be
used, but if it's there, then it could be
used if it's needed.

30

Id. at 12:8-14.
In addition to the general benefits of ensuring an adequate
amount of capacity to satisfy load demand, a capacity market
benefits capacity resources because capacity sales are a source
of revenue.

In particular, a generator that clears capacity in

the BRA run by PJM in a year (for example, 2012) will have a
fixed stream of revenue for one-year period three years in the
future (for example, from 2015 to 2016).

This fixed stream of

revenue is significant because it can enable the generator to
obtain current financing essential to its ability to deliver
capacity in the future.

(ii)

Capacity Obligations Within the PJM
Region

Pursuant to the RAA with PJM, each LSE must satisfy certain
"Capacity Obligations."26

See P.76 (PJM RAA Agt.) at 34.

The

RAA's stated purpose is "to ensure that adequate Capacity
Resources . . .

will be planned and made available to provide

reliable service to loads within the PJM Region."

Id. at 23.

To effect this purpose, the RAA sets forth a comprehensive
process pursuant to which PJM determines the total amount of
generating capacity needed within the PJM region and, based on
that calculation, creates capacity obligations for each LSE.
26

The RAA requires any LSE within the PJM region to become
and remain a party to the agreement.
31

See id. at 90-115.

To determine the total amount of capacity

needed in a future delivery year, PJM calculates the "amount of
capacity needed to meet the forecasted load" and adds to it
"reserves adequate to provide for the unavailability of
Generation Capacity Resources, load forecasting uncertainty, and
planned and maintenance outages."

See id. at 34.

The reserve

margin is computed as a percentage and applied to the load
forecasts to determine the total amount of capacity required to
serve reliably the forecasted load in the PJM region.

Tr. Mar.

6 (PM) at 33:7-34:17 (Wodyka).
Once PJM determines the total amount of capacity needed, it
divides responsibility for procuring that amount among the LSEs
within the PJM region.

Id. at 25:24-32:9.

Capacity obligations

can be satisfied by generation or demand resources, as discussed
infra.

An LSE can satisfy its capacity obligations by a

combination of the following actions:
1.

Designating its own generation or demand
resources;

2.

Entering into a bilateral contract with a
capacity resource with the parties to the
agreement determining the price for capacity;
and/or

3.

Being assigned capacity in the BRA, PJM's annual
capacity auction, which determines the price for
capacity through application of the RPM.

P.516 (PJM – At a Glance) at 9-10.
In lieu of the above actions, an LSE may elect the Fixed
32

Resource Requirement ("FRR") under the PJM Tariff.

Pursuant to

the FRR, the LSE, in essence, removes its load or energy demand
from PJM.

To use the FRR option, the LSE must demonstrate that

it can satisfy its share of the total capacity obligation
through individual bilateral agreements with capacity resources
or through the generation of electricity from its own
facilities.

Tr. Mar. 4 (AM) at 82:2-20, 124:22-125:15

(Alessandrini); Tr. Mar. 6 (PM) at 16:19-24 (Wodyka).

(iii)

PJM’s FERC-approved RPM

In 2006, FERC adopted and approved PJM's RPM for operating
a wholesale capacity market and implementing a competitive
capacity auction process.

The RPM sets forth the terms and

conditions governing the sale and delivery of capacity through
the annual BRA including the manner by which capacity is offered
into the auction, how the clearing price of capacity is
determined, how capacity resources are paid for cleared
capacity, and the penalties for failure to deliver capacity that
clears the auction.

Tr. Mar. 4 (AM) at 32:12-13, 37:23-38:2

(Alessandrini); Tr. Mar. 4 (PM) at 8:16-17 (Carretta); Tr. Mar.
4 (PM) at 104:25-106:16 (Cudwadie).

Ultimately, the RPM

encompasses the method by which PJM sets the price of capacity

33

that is offered into and clears the BRA.27

In each BRA, PJM

seeks to procure a target capacity reserve level for the RTO in
a least cost manner while also taking into account locational
constraints.
PJM is the buyer in the BRA, and the capacity resource is
the seller.

To sell successfully capacity to PJM in the BRA, a

capacity resource must bid or offer an amount of capacity at a
price, and the bid must be partially or fully selected in or
clear the BRA.

When a capacity bid clears the BRA, the seller

becomes obligated to sell the cleared amount of capacity to PJM
at the market clearing price.

The market clearing price is

determined in reference to all of the capacity bids (and the
corresponding bid prices) submitted in the BRA.
(AM) at 16:22-17:5 (Willig).

See Tr. Mar. 8

As discussed in more detail infra,

the market clearing price is the bid price at which demand, as
determined by PJM, is fully supplied.

All resources that offer

capacity in the BRA at or below the market clearing price
generally will clear the BRA and, as a result, receive the
market clearing price for the offered capacity.

See id. at

16:9-17:5.
27

As discussed supra, a capacity resource may sell its
capacity outside of the BRA, meaning at a price that is not set
pursuant to the RPM. Additionally, even if a generation
resource does not clear capacity in the BRA, that resource may
still sell its electric energy in the PJM Energy Market or in
some other FERC-approved manner. See Tr. Mar. 8 (AM) at 13:2114:2 (Willig).
34

(1)

Bidding in the BRA

To bid into the BRA, a capacity resource must submit an
offer consisting of: (1) an amount of capacity the bidder is
willing to sell for one year to be delivered beginning three
years after the BRA and (2) a bid price for the amount of
capacity offered.

Id. at 29:9-11.

Capacity is measured and

offered in megawatt-days ("MW-day"), and the bid price is a
dollar amount per MW-day ("$/MW-day").

See id. at 29:9-12.

For

instance, a power plant that bids 100 MW-days of capacity at $25
into the 2012 BRA, is offering its availability to deliver up to
100 MW of electric energy each day for one year beginning in
2015 (three years after the auction), at a minimum price of
$25/MW-day.
(Knight).

See generally Tr. Mar. 7 (AM) at 138:19-139:9

Hence, if the power plant's bid clears the BRA in its

entirety, the power plant will receive that year's clearing
price – which may be more than $25/MW-day - for 100 MW-days of
capacity during the delivery year beginning in 2015.
A capacity resource generally may select whatever price it
wishes in $/MW-day when bidding capacity into the BRA, subject
only to the Minimum Offer Price Rule ("MOPR") and a bid ceiling
or cap.

For example, if a generator is considering an uprate to

an existing generation resource that would increase the amount
of energy it can output into PJM's interconnected grid, thus
increasing its capacity, the generator may price its bid into
35

the BRA at an amount sufficient to recover the uprate costs not
gained back through anticipated energy sale revenue.
129:21-131:5.

See id. at

If the generator clears the BRA at that price, it

will go forward with the uprate, but if it does not clear, it
will not.

See id. at 129:9-130:7; see also Tr. Mar. 8 (AM) at

15:15-17:5 (Willig) (describing a "well-functioning" capacity
market as discouraging uneconomic development).

However,

bidding or bid prices are not necessarily connected directly to
an immediate development decision.

They may instead be chosen

by virtue of the view that getting anything for capacity is
better than nothing.

That is, an existing capacity resource

not subject to the MOPR can bid into the BRA at $0/MW-day.
is

referred to as "price taking."

19 (Knight).

This

See Tr. Mar. 7 (PM) at 68:3-

PJM has reported that in some BRAs, 80% of the

participants bid zero.

Id. at 68:19.

A bid of $0/MW-day

ensures that the offered capacity will clear the BRA and will
yield a payment more than zero, unless every bidder bids zero.
A price taker will accept whatever the market clearing price
happens to be in that BRA.28

See Mar. 7 (AM) at 140:23-41:23

(Knight).
28

Professor Willig explained that a capacity bid of zero by
an existing generation facility may well reflect its costs on
the capacity side for keeping the generation facility going
during the future delivery year because once the plant is built
and does not need new investment "the forward-looking
incremental cost of the capital is not high, it could be zero."
Tr. Mar. 8 (AM) at 21:9-18 (Willig).
36

New capacity resources bidding into the BRA are subject to
the MOPR, found in the PJM Tariff.

The MOPR has been in place

since establishment of the RPM in 2006, but its form has varied.
See id. at 91:20-22.

In essence, the MOPR subjects new

generation resources to a minimum bid amount "to ensure that . .
. new plant generating resources . . . bid[] their competitive
cost-based fixed nominal net cost of new entry if it was to rely
purely on PJM market revenues alone," and thereby precludes new
generators from acting as price takers.

(2)

Id. at 92:1-4.

Determining the Market Clearing
Price and Clearing Capacity in
the BRA

After all capacity offers are submitted into the BRA, PJM
must determine: (1) which offers will successfully sell into, or
clear, the BRA and (2)the single price that PJM will pay for the
cleared capacity (the "market clearing price").

Broadly

speaking, PJM makes these determinations by taking the capacity
bids, in ascending price order, until a pre-determined capacity
demand amount is fulfilled.

The price of the bid that fulfills

the demand amount sets the market clearing price for everyone.
Every bid at, or below, the market clearing price clears the
BRA, and every bid above the market clearing price does not.29

29

If there happens to be too much capacity bid at the market
37

Explanation of the RPM framework and establishment of a
market clearing price in any given BRA can be illustrated by the
simplified hypothetical provided by Plaintiffs' witnesses:
1.

In a BRA, PJM receives a number of capacity bids
at a variety of prices and amounts. The bids are
submitted in a sealed fashion so that initially,
only PJM knows what each capacity resource bid
into the BRA.

2.

Every capacity bid submitted is stacked in
ascending order of price, lowest priced bid at
the bottom and highest priced bid at the top.
Once the bids are stacked in price order, one can
tell the total MW-Days available at each bid
price by adding up the MW-day amount of each bid
preceding any particular price:

Generator

MW-Day
Bid

L
G
J
F
M

500
700
800
500
500

Price Bid

$0
$0
$0
$10
$25
Etc.

Total MW-Days
Available at Each
Price
500
1,200
2,000
2,500
3,000

3.

A graph can be created in which, in ascending
order, the x-axis is MW and the y-axis is Price
($MW-Day). PJM uses the bids stacked in price
order to create a "supply curve" and plots that
supply curve on the graph. With just the supply
curve plotted, one can see that at the price of
$25/MW-day on the y-axis, the BRA generated bids
totaling 3,000 MW, represented on the x-axis.
Stated differently, there are 3,000 MW of
capacity bid into the BRA willing to accept
$25/MW-day or less for the capacity.

4.

Next, PJM configures a Variable Resource

clearing price, a bid at that price may not entirely, or even at
all, clear the BRA.
38

Requirement curve ("VRR Curve" or "demand
curve"), representing the total amount of
capacity in MW that PJM has determined must be
procured through the BRA to adequately supply
forecasted load within the PJM region for the
one-year period three years following the BRA.
5.

The demand curve, generally a vertical line, is
plotted on the graph at the appropriate amount of
MW on the x-axis. The demand curve then
intersects with the supply curve of stacked bids
when the aggregate amount of capacity offered is
equal to the demand in MW established by PJM.
The point at which the supply curve intersects
with the demand curve is the market clearing
price and the market clearing amount of capacity.
This is illustrated by the demonstrative
submitted by Plaintiffs:

6.

As illustrated above, if the demand is determined
to be 8,000 MW, the market clearing price would
be $150/MW-day. This means that all capacity
offered at or below that price clears the BRA.
Every bidder whose capacity cleared the BRA will
be paid the clearing price of $150/MW-day. As a
result, even the generators that bid $0 for their
capacity will receive $150/MW-day.

Tr. Mar. 8 (AM) at 28:24-38:24 (Willig).
39

If a generation

resource successfully clears capacity in the BRA, PJM rules
require the generator to offer the electric energy generated in
the PJM Energy Market.
Since the market clearing price in any BRA is entirely
dependent on the bid prices received by PJM from capacity
resources (again, which for existing resources can be $0), the
price is volatile and difficult – if not impossible - to predict
with a reasonable degree of reliability.

See Tr. Mar. 8 (AM) at

76:19-22 (Willig); Tr. Mar. 11 (AM) at 32:8-12 (Roach); Tr. Mar.
11 (PM) at 101:20-102:1 (Kahal).

The following reflects six

years of BRA clearing prices:

Delivery Year

2007/2008
2008/2009
2009/2010
2010/2011
2011/2012
2012/2013

PJM
(charted as
"RTO")
$40.80
$111.92
$102.04
$174.29
$110.00
$16.46

Market Clearing Price
SWMAAC
MAAC
Southwest MidMid-Atlantic
Atlantic Area
Area Council
Council
$188.54
$40.80
$210.11
$111.92
$237.33
$191.32
$174.29
$174.29
$110.00
$110.00
$133.37
$133.37

See D.34 (2015/2016 RPM BRA Results).

(3)

Locational Deliverability Areas
("LDAs") and Price Separation in
the BRA

In theory, the BRA could establish one uniform market
clearing price based on one model supply and demand curve for

40

the entire PJM region.

However, in practice the process is

significantly more complicated.

When procuring capacity through

the BRA, PJM recognizes that not all locations are equally
situated.

Transmission constraints exist that make importing

energy and capacity into certain areas within the PJM region
more difficult than importing into other areas.

A "transmission

constraint" is a limitation on the ability of the transmission
system or infrastructure effectively and reliably to transport
electric energy from one point to another point within the PJM
region.

See Tr. Mar. 8 (AM) at 94:6-95:8 (Willig).

PJM employs

several indicators and standards to alert whether and where
transmission constraints exist and the consequences, affects,
and severity of any such constraints.
In the context of the PJM Capacity Market, to take
locational transmission constraints into account, PJM models
certain areas as Locational Deliverability Areas ("LDAs") for
purposes of the BRA.30

An area or zone is modeled as an LDA if

"the amount of transmission import capability into [that] area"
from the rest of the RTO (the Capacity Emergency Transport Limit
("CETL")) falls below a target ratio with the level of capacity
needed to import power to meet reliability requirements under

30

There can be transmission constraints between any two
points within the PJM region for a variety of reasons not just
with respect to energy being dispatched into an LDA.
41

the Capacity Emergency Transfer Objective ("CETO").31
Boston Pacific Evaluation of Draft RFP) at 16.

P.42 (2011

"The lower the

ratio, the 'tighter' supply line into the area. If the CETL/CETO
ratio is less than 1.15, then the area must be modeled as a
separate zone in RPM."

Id.

Being modeled as an LDA neither

precludes generators outside the LDA from supplying electric
energy into the LDA, nor necessarily affects the ability of
generators outside the LDA to enter into bilateral agreements
for energy and/or capacity with LSEs within an LDA.

See Tr.

Mar. 4 (PM) at 115:16-117:6 (Cudwadie).
Once an area or zone is modeled as an LDA, it functions as
a separate capacity market with a separate supply and demand
curve and a separate market clearing price from the balance of
the PJM footprint.

That is, there are "separate supply stacks

and separate reliability needs . . . considered by the PJM" in
the BRA process for an LDA.
(Willig).

See Tr. Mar. 8 (AM) at 93:15-19

Since LDAs function as a separate capacity market for

purposes of the BRA, the market clearing price for an LDA may be
different from the price for the rest of the RTO.

When the

market clearing price for an LDA is different from the balance
of the PJM footprint the phenomenon is referred to as "price
separation."

See Tr. Mar. 4 (PM) at 113:23-114:1 (Cudwadie).

31

The CETO is an import capability required by an area to
comply with a Transmission Risk of Loss of Load Event of 1 in 25
years.
42

Price separation occurs because each LDA has a separate
target capacity reserve level and a maximum limit on the amount
of capacity that it can import from resources located outside of
the LDA.

See id. at 114:1-115:15, 119:2-122:23.

As a result of

the import limitation, a lower-priced capacity resource located
outside the LDA may be "skipped" or excluded from the stack of
bids used by PJM to create the supply curve.

This occurs

because the LDA has reached its import limit so that even though
the outside resource is the next bid in price order PJM will not
select it to meet the capacity needs within the LDA.
Mar. 8 (AM) at 94:2-22 (Willig).

See Tr.

Where lower-cost capacity

resources outside of the LDA are excluded due to the import
limitation, PJM must then select more expensive capacity
resources located within the LDA to fulfill the LDA's capacity
target level.

See Tr. Mar. 4 (PM) at 113:23-115:15, 119:8-

122:15 (Cudwadie).

When an LDA reaches its import limitation

before the LDA's capacity needs are met and PJM is forced to
select more expensive capacity bids from within the LDA, the
LDA's market clearing price will separate from the rest of PJM
because the last capacity bid selected – a more expensive
resource within the LDA - sets the LDA price at a level higher
than the RTO clearing price.

See id.

Within the PJM region, the Mid-Atlantic Area Council
("MAAC") is modeled as an LDA.

The Southwest Mid-Atlantic Area
43

Council ("SWMAAC") is a sub-LDA within MAAC.
(PM) at 27:6-10 (Carretta).

See Tr. Mar. 4

SWMAAC includes part of Maryland

and the District of Columbia; about 98% of SWMAAC is within
Maryland.

Tr. Mar. 6 (AM) at 37:15-18 (Massey).

SWMAAC

includes the transmission systems of BGE and Pepco.

The

portions of Maryland not in SWMAAC are in the Eastern MidAtlantic Area Council ("EMAAC"), a sub-LDA that includes parts
of Delaware, Pennsylvania, and New Jersey.
(AM) at 106:15-18 (Nazarian).

Tr. Mar. 5, 2013

In the BRA conducted for the

2015/2016 delivery year, the market clearing price in all of
MAAC (including EMAAC and SWMAAC) was $167.46/MW-day, and the
market clearing price in the rest of PJM was $136.00/MW-day.
D.34 (2015/2016 RPM BRA Results).

For the 2010/2011, 2011/2012,

2012/2013, and 2015/2016 delivery years, the market clearing
price for SWMAAC did not separate from the rest of MAAC, even in
years when MAAC separated from the balance of the PJM footprint.
Id.

(iv)

Price Signals

FERC has described the PJM Capacity Market as "provid[ing]
long-term price signals to attract needed investment in the PJM
region through a competitive auction process three years in
advance."

PJM Interconnection, LLC, 132 FERC ¶ 61,173, 61,870

44

(2010).

PJM identifies the RPM system as a means of providing

"incentives that are designed to stimulate investment both in
maintaining existing generation and in encouraging the
development of new sources of capacity – not just generating
plants, but demand response and energy efficiency programs as
well."

P.516 (PJM – At a Glance) at 8.

Plaintiffs submitted

expert testimony to explain in an economic sense how the
capacity prices set in the PJM Capacity Market through the RPM
send price signals to market participants capable of inducing
investment in generation development.

Plaintiff's expert,

Professor Willig, opined that higher capacity prices in an LDA
encourage projects to be developed in that area because the RPM32
"reflect[s] the locational impact on need and on cost" of
electric energy.

Tr. Mar. 8 (AM) at 95:9-24, 99:5-20 (Willig).

According to Professor Willig, because the RPM is configured to
create a positive correlation between transmission constraint
and price, higher prices indicate greater difficulties in
importing energy into an LDA, which signals to the market a need
for capacity development and/or signals to PJM a need for
transmission planning.

Id. at 98:6-99:20.

This is because

constraint on the transmission system can be eased by additional
32

According to Professor Willig, the same principles apply to
the LMP in the PJM Energy Market because the LMP increases to
the extent there is "congestion" or some other constraint as to
the transmission system in dispatching electric energy to a
particular location.
45

capacity resources in the right location and/or new or expanded
transmission lines to that location.

Id.

As Professor Willig

concluded, a decrease in constraint, either by additional
capacity or by a transmission-related solution, "will tend to
bring pricing closer, because when prices are closer, it's
because there's less constraints between their areas."

Id. at

99:5-9.
The PSC has stated that the RPM "ha[s] failed to attract
new generation in [Maryland] to mitigate these longer-term
reliability concerns," and that "RPM's signal remains unable to
anchor the financing new generation development requires."

P.2

(2011 RFP) at 3.

D.

Maryland’s Regulation of Electric Energy

Maryland has, as have various other states, abandoned the
vertical integration model of electric energy regulation.
1.

Pre-Restructuring Vertical Integration

Before the restructuring of 1999, Maryland's electric
utilities (such as BGE and Pepco) were vertically integrated and
predominately regulated by the Maryland PSC, except insofar as
the utilities engaged in wholesale transactions, which were
regulated by FERC.

Tr. Mar. 5 (AM) at 40:23-41:18 (Nazarian).

Even then, however, Maryland's utilities imported approximately
46

30% of the electric energy resold to end-use customers from
generation resources outside the state in wholesale
transactions.

Id. at 50:6-51:24.

Under the vertically integrated structure, the PSC
generally retained authority to "regulate[] the distribution,
transmission and generation rates" that Maryland utilities
charged to rate payers.

P.606 (PSC Order No. 81423) at 33.

The

rates charged by Maryland utilities to end-use customers were
determined by the PSC through cost-of-service principles.

That

is, the PSC set rates that "w[ould] result in an operating
income to the [utility] that yields, after reasonable deduction
for . . . expenses and reserves, a reasonable return on the fair
value of the [utility]'s property used and useful in providing
service to the public."
Report) at 10.

Id. at 33-34; P.391 (2007 PSC Interim

Because the Maryland utilities primarily sold

electric energy generated by their own power plants to users in
retail transactions, the PSC effectively determined - through
its rate making authority - whether new or additional generation
resources would be built in Maryland.

Generation development by

a Maryland utility would be financed through rate increases,
which required approval by the PSC.
Presentation) at slide 10.

See P.162 (2009 Nazarian

Additionally, in pre-restructured

Maryland, ratepayers had no choice as to their electric utility
supplier; they purchased electricity from whichever utility's
47

service territory in which they were located.

See Tr. Mar. 5

(AM) at 43:12-23, 44:21-24 (Nazarian).

2.

1999 Maryland Restructures

In 1999, the Maryland General Assembly passed the Electric
Customer Choice and Competition Act (the "1999 Act"), which
restructured, or deregulated, Maryland's electric energy market.
See Md. Code Ann., Pub. Util. § 7-504, et seq.

"The premise of

the 1999 Act was that electric consumers would benefit more from
a competitive market for their electricity rather than being
captive to a single utility that had a monopoly on their
electricity service."

P.606 (PSC Order No. 81423) at 36.

The

1999 Act put this premise into effect by removing generating
assets from the control and ownership of the Maryland utilities
and requiring the utilities to provide Standard Offer Service,
discussed in more detail infra, to their customers.
Post-restructuring, the PSC remains an agency empowered by
the State of Maryland to assure "safe, adequate, reasonable, and
proper [electric] service."
101(a).

Md. Code Ann., Pub. Util. § 5-

In addition to regulating the procurement of electric

energy by the Maryland Electric Distribution Companies (the
"EDCs" or "Maryland EDCs") for Maryland residents, the PSC
administers a streamlined "process by which transmission and
generating facilities are sited and . . . approve[d]" for
48

construction in Maryland.

P.606 (PSC Order No. 81423) at 42.

However, the PSC does not evaluate the need for new generation
stations in Maryland.
marketplace.

Rather, that need is determined by the

Tr. Mar. 5 (AM) at 58:18-59:5 (Nazarian) (noting

the "residual authority [of the PSC] to order new generation in
anticipation of a long-term demand in the state").

a.

Separation of Generation Assets

The 1999 Act separated the Maryland "utilities' [Marylandlocated] generating assets from their distribution and
transmission functions" by transferring ownership of those
generation assets to other companies that owned and operated the
power plants.

P.391 (2007 PSC Interim Report) at 10; see also

Md. Code Ann., Pub. Util. § 7-504(3); Tr. Mar. 5 (AM) at 42:1318 (Nazarian).

This separation effectively forced Maryland

utilities, now referred to as EDCs, to purchase electric energy
at wholesale, thereby engaging in federally regulated energy
transactions.

Since the EDCs no longer owned generation assets

or power plants,33 "electricity previously subject to traditional
rate-of-return regulation (in which the PSC set the utility's
profit through a state regulatory proceeding) would now be
33

Post-restructuring, Maryland's EDCs still own their
transmission and distribution systems. See Tr. Mar. 5 (AM) at
42:13-43:15 (Nazarian).
49

purchased by local [EDCs] in the federally regulated wholesale
electricity market" for purposes of re-selling that electricity
to end-use customers.

P.391 (2007 PSC Interim Report) at 10.

Consequently, Maryland EDCs now rely on the wholesale energy
market regulated by FERC to purchase the electric energy that
they ultimately sell to end-use customers.
No. 81423) at 37.

See P.606 (PSC Order

By virtue of having to purchase energy at

wholesale, the Maryland EDCs (and correspondingly Maryland
ratepayers) are financially affected by wholesale prices set by
the PJM Markets.

b.

Standard Offer Service

Maryland's restructuring not only required local utilities
to divest themselves of ownership of power-generating
facilities, but also allowed Maryland electricity consumers to
choose their electric energy supplier.

Electricity customers in

Maryland have a choice to buy electric service from the default
local utility or from an alternative supplier.
at 45:3-47:19 (Nazarian).

Tr. Mar. 5 (AM)

The sale of electricity supplied by

the default local utility is called Standard Offer Service
("SOS").

The PSC regulates the SOS procurement process, which

is conducted by the Maryland EDCs, and the rate the EDCs may
charge customers for SOS.

See id. at 44:2-45:23.

50

If a Maryland

customer chooses an alternative supplier, that transaction is a
matter of contract and is not regulated by the PSC.
46:16-24, 48:10-18.

See id. at

Since Maryland's energy market is

deregulated, the EDCs purchase the electric energy for SOS from
the wholesale market.

This procurement of electric energy takes

place through contractual agreements as well as through the use
of "PJM spot energy markets."34
140] at 15-16.

OPC's Post Trial Br. [Document

According to the Maryland Office of People's

Counsel, only 15% of all wholesale electricity sales in the PJM
region occur through "PJM spot energy markets."

E.

Id. at 15.

The Path to the PSC Order

In mid-2000, the Maryland General Assembly and the PSC
began to voice concerns over the operations of Maryland's
electricity markets, the post-restructuring consumer electricity
rates, and the existence of adequate generation resources to
serve the energy needs of Maryland ratepayers.

For instance, in

"the summer of 2006, the General Assembly convened a special
session to pass legislation that would mitigate a proposed 72%
rate increase on residential ratepayers [in the] BGE" territory,
the largest utility territory in Maryland.
34

P.391 (2007 PSC

"[I]f [the EDCs’] customers use more energy in a particular
hour than they have bought ahead of time for that hour, then
they buy the residual through the PJM spot energy market."
OPC's Post Trial Br. [Document 140] at 15.
51

Interim Report) at 5.
These concerns, which took the form of several legislative
and regulatory actions, eventually culminated in the issuance of
the Generation Order at issue.

1.

Maryland General Assembly Orders the PSC to Study
Re-Regulatory Options for Maryland

In May 2007, the Maryland General Assembly signed into law
Senate Bill 400, calling for the PSC to study re-regulatory
options and the availability of adequate generation and
transmission assets in the state and to also provide the General
Assembly with interim and final reports35 containing the results
of the PSC's evaluations.

See P.391 (2007 PSC Interim Report)

at 1; see also EmPOWER Maryland Energy Efficiency Act of 2008,
Md. Code Ann., Pub. Util. § 7-211.
In December 2007, the PSC filed its interim report with the
General Assembly that "offer[ed its] recommendations and
analysis regarding options for 're-regulating' Maryland's
electricity markets and for obtaining new generation and
transmission resources" in Maryland.
Report) at 1.

P.391 (2007 PSC Interim

In the interim report, the PSC explained that

35

The reports provided to the Maryland General Assembly
consisted of reports authored by the PSC and by two groups of
consultants, the law firm Kaye Scholer LLP and the economic
consulting firm Levitan & Associates, Inc.
52

"Maryland faces a critical shortage of electricity capacity . .
. because Maryland sits in a highly congested portion of the
regional electric transmission system (which makes it difficult
to bring more power in) and because we use more electricity than
is generated here."

Id.

To respond to this problem, the PSC

advised that Maryland could "add more capacity, either through
new generation or transmission, or . . . reduce the amount of
electricity [it] use[s]."

Id.

Describing the wholesale and retail markets as "structured
ostensibly to create price incentives for new generation or
transmission," the PSC noted that the wholesale markets had not
responded to Maryland's needs and opined that those markets were
unlikely to respond in the immediate future to the state’s
"looming capacity shortage."

Id.

According to the PSC,

"capacity shortages and transmission constraints" in Maryland
caused consumers to "pay much higher than average prices for
wholesale (and thus retail) electricity."

Id.

The PSC reasoned

that this situation provided no incentive for existing
generators to build more capacity and increase the supply, since
such actions would decrease the price received by the generators
for energy and capacity on the wholesale market.

See id.

Ultimately, after reviewing reports presented by two groups
of consultants, the PSC concluded that "[t]he analyses by [the
consultants] combine to create a compelling case for directing
53

utilities in the state to enter into long-term contracts to
induce the supply of new electricity in Maryland.

This is a

're-regulation' option that we believe should be pursued and
that we intend to pursue."

Id. at 41.

The PSC believed this

option would maintain the reliability of the transmission grid
and obtain the best possible prices for Maryland ratepayers.
Tr. Mar. 5 (AM) at 64:5-11 (Nazarian).

2.

PSC Initiates the "Gap RFP Proceeding"

In the summer of 2007, PJM began warning the PSC about a
potential capacity shortfall in Maryland for the following year.
In November 2008, the PSC issued an order in Case No. 9149,
referred to as the "Gap RFP Proceeding," to address "a
['potential'] gap between the anticipated need [for electricity]
in the summers going forward based on load forecasts and the
known resources available to serve that need" in response to
PJM's representation of a "potential delay in a transmission
line project" known as the TrAIL Line.
74:10-76:19 (Nazarian).

Tr. Mar. 5 (AM) at

Seeking new demand response resources

that would bid as capacity resources into the BRA, the PSC
ordered the four Maryland EDCs to issue Requests for Proposals
("Gap RFPs").

P.345 (PSC Order in Case No. 9149) at 7.

In

exchange for the demand response resources bidding into the BRA,

54

the PSC offered the EDCs contracts for differences that
apparently guaranteed the suppliers a fixed revenue stream for
the demand response, irrespective of the market clearing price
in the BRA.

The Gap RFPs yielded 600 MW of demand response.36

3.

PSC Provides Final Report to General Assembly

On December 10, 2008, the PSC provided its final report to
the Maryland General Assembly.
Final Report).

See generally P.582 (2008 PSC

In the report, the PSC stated that in addition

to reliability measures already underway, the PSC would
"undertake a new investigation in 2009 to determine whether[,]
and on what terms[,] to direct or solicit the construction of
one or more new power plants in Maryland."

Id. at 2.

Former

PSC Chairman Nazarian testified that although the PSC had
intended to open a proceeding for the particular purpose of
addressing that issue, it never opened such a case.
Mar. 5, 2013 (AM) at 78:22-81:-23 (Nazarian).

Trial Tr.

Instead, the PSC

commenced a proceeding related to inducing new generation in
Maryland — Case No. 9214.

It is this proceeding that led to the

PSC's issuing the Generation Order.

36

Demand response capacity in the amount of 600 MW means a
commitment to decrease the demand for electric energy up to 600
MW if and when called upon by PJM to do so.
55

4.

CPV Requests a Long-Term Contract from the PSC in
an Unrelated Matter

In PSC Case No. 9117, a case unrelated to the Generation
Order, CPV filed a motion to intervene and "strongly urge[d] the
[PSC] to encourage policies that promote and direct long-term
(10 to 15 years) PPAs [Purchase Power Agreements] from in-state
generation to serve Maryland's load."
Intervene) at 3.

P.31 (CPV Motion to

In July 2009, CPV made a specific request that

the PSC "order one or more [Maryland EDCs] to enter into 20-year
long-term contract(s)" providing a fixed revenue stream to CPV
for purposes of financing CPV's development of new generation in
Charles County, Maryland.37

P.14 (2009 CPV Motion) at 1; Tr.

Mar. 5, 2013 (AM) at 86:21-87:16 (Nazarian).
In its filings in Case No. 9117, CPV asserted its belief
in the necessity of having state-sponsored long-term financing
to move forward with its Charles County project because
"traditional commercial banks no longer are willing to finance
the types of risks they might once have undertaken; nor will
they be willing to rely on third party consultant reports
estimating a project's potential revenue stream in a particular
wholesale market."

P.14 (2009 CPV Motion) at 22.

CPV explained

that "RPM's conditional three-year commitment period is simply
37

Former PSC Chairman Nazarian reflected that in 2008-2009,
CPV advocated heavily and strongly for the PSC to order the
long-term contract, but the PSC never gave CPV the contract.
Tr. Mar. 5 (AM) at 85:13-86:3 (Nazarian).
56

insufficient to allow new baseload [sic] generation to be
financed [because] the RPM is too short-term, too volatile, and
too fraught with continued regulatory uncertainty to provide
lenders with anything close to the certainty of a fixed revenue
stream required for financing."

Id. at 24.

CPV went on to note

that "given RPM's purpose to provide an accurate price signal to
new generation, the FERC rejected" proposed changes to RPM that
would extend the commitment period.

See id. at 24-25.

Instead of granting CPV's request for a state-sponsored
financing contract specifically for CPV's Charles County
project, in September 2009 the PSC opened a separate proceeding,
Case No. 9214, which implemented the competitive bid process
that eventually resulted in the Generation Order, and eventually
awarded the contract for differences to CPV for its Charles
County project.

5.

Tr. Mar. 5 (AM) at 85:13-86:20 (Nazarian).

PSC Opens Case No. 9214 for "New Maryland-Located
Electric Generating Facilities"

On September 29, 2009, the PSC initiated Case No. 9214 and
directed "[t]hat any proposals for new Maryland-located electric
generating facilities . . . be filed by December 11, 2009."
P.35 (PSC Order No.82936) at 3-4.

57

a.

The Draft RFP and Engagement of Boston
Pacific

On December 29, 2010, the PSC issued for comment a draft
Request for Proposals for Generation Capacity Resources Under
Long-Term Contract (the "Draft RFP").
Draft RFP).

See generally P.13 (2010

The Draft RFP solicited up to 1,800 MW of capacity,

energy, and ancillary services from generation resources.

The

PSC invited all interested parties to review the Draft RFP and
provide comments.
The Draft RFP differed in several respects from the RFP
ultimately issued by the PSC.

For example, the Draft RFP

solicited proposals from all types of generation resources and
permitted bids from existing facilities that would uprate, or
expand, their existing generation capacity.

With respect to

locational requirements, the Draft RFP required "[t]he proposed
Generation Capacity Resource [to] be interconnected to the
System such that the [resource's] output may be infed to a node
east of the Western Interface and deliverable to Maryland east
of the Western Interface avoiding likely transmission
congestion."

Id. at 15.

Using this locational definition, it

was possible for a generation facility in Pennsylvania to submit
a proposal to the PSC in response to the Draft RFP.

See Tr.

Mar. 5 (AM) at 99:6-100:6 (Nazarian).
In the summer of 2011, the PSC engaged Boston Pacific

58

Company, Inc. ("Boston Pacific") to perform consultation work in
connection with the Draft RFP.
(Nazarian).

Tr. Mar. 5 (AM) at 100:20-102:1

On August 12, 2011,38 Boston Pacific provided the

PSC with its (1) "review [of] the factual basis for the
reliability concern that motivated the [PSC] to issue the Draft
RFP," (2) view of possible paths forward for the PSC, and (3)
"suggested edits to the Draft RFP."

P.42 (Boston Pacific

Evaluation of Draft RFP) at 1.
Regarding the reliability concern in Maryland, Boston
Pacific observed that conditions had improved since 2008 when
the PSC provided its final report to the Maryland General
Assembly illustrating scenarios in which there could be a
generation shortfall in Maryland.

For example, many of the

scenarios posited to the General Assembly in 2008 related to a
failure on the part of PJM to secure the construction of the
Trans-Allegheny Interstate Line ("TrAIL Line"). Id. at 1-2, 15.
But, as Boston Pacific pointed out, PJM had come through and the
TrAIL Line had gone into service in May 2011 "providing more
transmission support for the [Maryland] region."

Id.

Boston Pacific also explained that load growth in Maryland
had declined, reducing pressure on the transmission system, and
that demand response resources had materially increased, due in

38

Boston Pacific filed its report in Case No. 9214 on January
23, 2012.
59

part to the Gap RFPs.

Id.

However, Boston Pacific identified

"several key risk factors that could rapidly change Maryland's
future [energy] supply needs."

Id. at 2.

Specifically, Boston

could

higher

Pacific noted:
(1)

"[L]oad growth
expected;"

be

than

(2)

"[R]etirements of existing generation
facilities
could
be
greater
than
expected [where] coal-fired generation
makes up about 60% of all electricity
produced in [Maryland, and] sources
anticipate new EPA regulations will
force shutdowns and increase costs as
coal-fired
generators
modify
their
plants," which would leave Maryland
more reliant on importing power; and

(3)

Certain PJM transmission projects, such
as the MAPP line, may not be completed
on time, which is of concern since
"Maryland imports roughly 30% of its
power" and relies on transmission to
bring power into the state.

Id. at 2, 17-27.
Boston Pacific identified two alternatives for the PSC to
respond to reliability concerns: (1) take more time to evaluate
the risks identified by Boston Pacific or (2) issue a request
for proposals "targeted to address and mitigate the key risks"
identified by the company.

Id. at 3, 27.

Boston Pacific

advised the second option if the PSC "believes . . . that the
current risks to reliability are great enough to justify
immediate action, and that RPM will not bring new generation to

60

the State."

Id. at 3.

If the PSC decided on the second option

to issue a request for proposals, Boston Pacific suggested
several modifications to the Draft RFP "[t]o effectively
mitigate the [reliability] risks" faced by Maryland.
3-5.

See id. at

Boston Pacific advised:
[T]he RFP should specifically solicit only
new, in-State, natural gas-fired combinedcycle
generation
located
in
SWMAAC
or
Eastern MAAC (EMAAC) . . . because [those]
zones, due to their constrained nature, have
seen the highest RPM prices, the least
development of generation and are most at
risk for reliability problems caused by load
swings,
generator
retirements,
and
transmission issues.

Id. at 4; see id. at 30-31.

b.

The PSC Issues the RFP Seeking Proposals to
Construct and Operate a New Generation
Resource in SWMAAC in Exchange for the
Contract for Differences

On December 8, 2011, the PSC issued the Amended Request for
Proposals for New Generation to be Issued by Maryland Electric
Distribution Companies (the "RFP"), which ordered each Maryland
EDC to issue an attached request for proposals.39

See generally

P.2 (2011 RFP).

39

The PSC issued the first RFP on September 29, 2011, but
after holding a pre-bid conference concerning the RFP, it issued
the amended RFP on December 8, 2011. Among other things, the
amended RFP extended the proposal due date to January 20, 2012.
See P.2 (2011 RFP) at 12.
61

According to the PSC, the RFP's purpose was "to ensure the
continued, long-term reliability of the electricity supply to
Maryland customers by mitigating key risks faced by the State."
Id. at 1.

Such risks, as listed in the RFP, included the risks

identified by Boston Pacific, as well as "the risk that RPM will
not attract enough new capacity to address these risks
effectively, whatever the level of need turns out to be."
id. at 2-3.

See

According to the PSC, "RPM has failed to attract

new generation in the State to mitigate these longer-term
reliability concerns, and RPM's signal remains unable to anchor
the financing new generation development requires."

Id. at 3.

Consequently, the PSC concluded that, "[a]lthough [it]
appreciates PJM's role in planning regional transmission
solutions, . . . [b]ecause market forces have not produced new
generation in our region," the PSC may need to order the
construction of new generation to "satisfy the long-term
anticipated demand in Maryland" for electric supply.

Id. at 3-

4.
The PSC set a deadline of January 20, 2012 for proposals
from interested parties for the construction and operation of
new generation resource(s) to be submitted pursuant to the
requirements detailed in the RFP.

In exchange for building and

operating the generation resource, the PSC offered the selected
supplier a long-term contract for differences with three
62

Maryland EDCs, which would provide the supplier with a
guaranteed revenue stream based upon the supplier's wholesale
energy and capacity sales into the PJM Markets.

The PSC stated

that it would select "the bid(s) that produces the lowest-cost
solution for ratepayers when accounting for risk."

Id. at 16.

The PSC explicitly reserved the right to reject all proposals
submitted in response to the RFP.

(i)

Requested Generation Resource(s)
Requirements

In the RFP, the PSC sought proposals to build and operate a
particular type of generation resource in a particular location.
Specifically, the PSC only solicited proposals for:


"[N]ew, natural gas-fired" generation capacity
resources;



Physically located inside the SWMAAC zone of the
PJM region;



Capable of producing energy and capacity products
"not to exceed, a total installed capacity of
1,500 MW;"



"[F]or an initial term of up to twenty years
beginning no earlier than June 1, 2015 and no
later than June 1, 2017."

Id. at 4-5.

Hence, an existing generation resource or a

resource physically located outside of SWMAAC was ineligible to
submit a proposal to the PSC and to compete for the long-term
financial benefits to be awarded to any selected submission.
63

Pursuant to the structure employed by the RFP,40 the
selected supplier would construct, operate, and own the new
generation resource.

As to the physical delivery of energy and

capacity, the supplier would be obligated to offer the
generator's output to PJM in the PJM Markets.

See id. at 5.

The PSC described the selected supplier's relationship with the
Maryland EDCs as a "financial arrangement . . . in which the
physical delivery to the EDC of Capacity, Energy and Ancillary
Services is not required. . . . Hence, the delivery of Capacity
and Energy will be settled financially rather than physically,
thereby providing compensation to Supplier for Capacity and
Energy."

Id.

(ii)

The Contract for Differences

As outlined in the RFP, the compensation structure for any
supplier chosen by the PSC to construct and operate a new
generation resource in SWMAAC would be governed by a long-term
contract for differences ("CfD").

The RFP provided that, after

selecting a supplier, the PSC would direct or order one or more
40

The PSC attached to the RFP a draft contract for
differences "to be executed as a result of th[e] RFP." Id. at
6. The PSC explained that the contract for differences "is
meant to memorialize the terms and conditions described in this
RFP; to the extent there is any conflict, this RFP controls and
the final Agreement will be revised to comply with it. The
Agreement contains the parties' rights and obligations for
providing and receiving Capacity and Energy." Id.
64

of the Maryland EDCs to enter into the CfD with the supplier.
The CfD contained compensation provisions that enabled the
selected supplier to receive its proposed "contract price" for
each unit of energy and capacity sold to PJM in the PJM Markets
up to a ceiling amount.

See generally id.; id., Attachment 1

(CfD Settlement Example); id., Attachment 8 (Sample CfD).
The terms of the RFP required each submitted proposal to
contain "the total pricing provisions for the Capacity and
Energy produced by the Generation Capacity Resource over the
contract term."

See P.2 (2011 RFP) at 10-11.

The RFP and its

attachments contained detailed explanations of the parameters
for submission of the contract price.
At trial, CPV explained its "method" for reaching the
proposed contract price.

CPV assessed the costs of all of its

obligations surrounding its proposed project, including:
construction of its facility; fixed operating costs going
forward, such as labor, property taxes, and maintenance; raising
capital to finance the construction; and a reasonable rate of
return to CPV.

CPV then applied those assessments to a

financial model to determine the annual revenue requirements
necessary to construct and operate its proposed generation
resource.

Tr. Mar. 7 (AM) at 122:15-123:19 (Knight).

That

annual revenue requirement served as the basis for CPV's
requested contract price presented in $/MW-day of unforced
65

capacity and $/MWh.
As discussed in detail infra, under the CfD the actual
revenue received by the supplier for its sale of energy and
capacity in the PJM Markets is compared to what the supplier
would have received for those sales had the contract prices been
controlling, and any difference is settled between the supplier
and the EDC(s).

If the contract prices are higher than the

market prices, the EDC(s) pays the difference to the supplier.
If the market prices are higher than the contract prices, the
supplier pays the difference to the EDC(s).

In the event the

EDC(s) have to make payments to the supplier, the EDCs would
able to recoup their losses through increases in the rates paid
by Maryland SOS customers.

Correspondingly, the EDC(s) would be

required to pass on any gains to the SOS ratepayers.

c.

The Generation Order and Selection of CPV's
Charles County Proposal

In response to the RFP, the PSC received seven bids,
including a proposal from CPV for the construction and operation
of a power plant in Charles County, Maryland.

On April 12,

2012, after evaluation of the bids, the PSC issued the
Generation Order directing BGE, Pepco and Delmarva (the
"Maryland EDCs") "to enter into a Contract for Differences with
CPV . . . under which CPV will construct a 661 megawatt (MW)
66

natural gas-fired combined-cycle generation plant in Waldorf in
Charles County, Maryland, with a commercial operation date of
June 1, 2015.

P.44 (Generation Order) at 7.

The PSC determined that CPV's bid provided "the best price
for [Maryland] 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."

Id. at 26.

The PSC also ordered that the Maryland EDCs required to enter
into the CfD with CPV should recover their costs from all
Maryland SOS ratepayers, not just those ratepayers in the SWMAAC
zone.

Id. at 26-27.
In the Generation Order, the PSC provided a summary of the

comments it received from various interested parties with
respect to moving forward with the RFP.

Specifically, the

Maryland EDCs opposed proceeding with the RFP on the grounds
"that customers would be 'burdened' with additional costs for
unneeded and uneconomic generation."

See id. at 10-12.

With

respect to the Plaintiffs, PPL opposed the RFP on the grounds
that "it is not necessary because the competitive market is
working to create reserve margins above 20% through 2015, and
trends indicate demand is declining."

Id. at 13-14.

Similarly,

PSEG "assert[ed] that proceeding with the RFP will interfere
with the proper functioning of the wholesale competitive
market."

Id. at 14.

The PSC rejected these concerns along with
67

the contention that demand needs could be satisfied by the RPM
and the BRA, stating:
[O]f critical importance, we cannot rely on
PJM's Reliability Pricing Model to deliver
new generation to Maryland. . . . 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 PJM. . . .
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 . . . . 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.
Id. at 22-23.

F.

Commercial Power Ventures Maryland

Commercial Power Ventures Maryland ("CPV") and its
affiliates develop natural gas-fired and renewable energy
generation facilities and manage generation assets on behalf of
other owners, usually financial institutions that have taken
control of the asset as collateral.

68

Tr. Mar. 7 (AM) at 87:7-25.

(Knight).

CPV is located in Charles County, Maryland, which is

part of the SWMAAC LDA.
In 2006, CPV began planning the project to build its
Charles County Facility (the "Facility").
87:3-10 (Egan).

Tr. Mar. 7 (PM) at

As discussed supra, CPV was of the opinion that

it needed a long-term price contract, or its equivalent, to
finance the construction and development of the Facility.
at 89:6-18.

Id.

In about 2008, after exploring options in the open

market to no avail, CPV began pursuing the procurement of a
long-term contract from the State of Maryland, and in 2009 it
formally requested such a contract from the PSC.
15.

Id. at 88:9-

As discussed herein, on April 12, 2012, the PSC issued the

Generation Order selecting CPV's generation proposal and
awarding CPV the CfD.

As of the time of bench trial, CPV has

stated that it would not move forward with construction of the
Facility without the CfD.

Id. at 89:15-18, 93:21-94:1.

In the spring of 2012, CPV bid 661 MW-days of capacity from
its yet-to-be-built Facility into the BRA.
104:19-107:22 (Knight).

Tr. Mar. 7 (AM) at

Because it involved a new generation

resource, CPV's bid was subject to the MOPR, which FERC had
recently modified in 2011.

The MOPR, as it existed in 2012,

placed a floor on CPV's bid into the BRA that precluded CPV from
bidding zero and acting as a price taker.

69

Pursuant to the MOPR,

CPV could not bid less than 90% of Net CONE (Cost of New Entry)41
or its unit specific cost once it received a unit-specific MOPR
exception from PJM.

As described by FERC, the MOPR:

is the mechanism that seeks to prevent the
exercise of buyer market power in the
forward capacity market by ensuring that all
new
resources
are
offered
into
PJM's
Reliability
Pricing
Model
(RPM)
on
a
competitive
basis.
The
MOPR
imposes
a
minimum offer screen to determine whether an
offer from a new resource is competitive. We
continue to conclude that the MOPR serves a
critical function to ensure that wholesale
prices are just and reasonable and should
elicit new entry when new capacity is
needed. The long-term viability of the PJM
market demands an assurance of competitive
offers from new entrants.
PJM Interconnection, L.L.C., 137 FERC ¶ 61,145, at *4 (2011).
On March 7, 2012, CPV filed a unit-specific MOPR exception
proposing a bid floor of $13.95/MW-day.
(CPV MOPR Exception Request).

See generally D.173

Pursuant to PJM's tariff, PJM

must review a submitted unit-specific exception "to determine if
it's consistent with competitive cost-based fixed nominal
levelized [CONE]."

Tr. Mar. 7 (AM) at 96:12-97:23 (Knight).

PJM's independent market monitor made the initial determination
that CPV's unit-specific costs precluded it from bidding below

41

CONE is a PJM-determined analysis as to the generic cost of
a new power plant to enter the market. The Net CONE is the
amount of annual revenue requirements from the capacity market
that a new generic generator would need, assuming the plant will
earn money from energy and ancillary service markets. See Tr.
Mar. 7 (AM) at 92:9-93:23 (Knight).
70

$136.87/MW-day.

See id. at 98:15-103:23.

On April 10, 2012,

CPV requested a separate determination from PJM.

One month

later, on April 20, 2012, PJM approved a bid floor of $96.13/MWday for CPV because the offer was "'consistent with the
competitive, cost-based, fixed, net cost of new entry were the
resource to rely on solely on revenues from PJM-administered
markets' as required by [the] PJM Tariff."

D.265 (PJM

Decision).
In accordance with PJM's unit-specific determination, CPV
submitted a bid into the 2012 BRA of $96.13/MW-day for the
amount of 661 MW for the delivery year 2015/2016.

In SWMAAC and

MAAC, the market clearing price for the 2012 BRA was $167.46/MWday.

Hence, CPV cleared the BRA.

After the 2012 BRA results

were released, PJM performed a sensitivity analysis.
Mar. 4 (PM) at 22:23-24, 24:23-24 (Carretta).

See Tr.

In the

sensitivity analysis, PJM calculated that if the offered supply
of capacity had been decreased in SWMAAC by 750 MW from the
bottom of the supply stack or curve, the resulting clearing
price for capacity in SWMAAC would have been $195.00/MW-day
instead of $167.46/MW-day.

See id. at 24:23-25:6; Tr. Mar. 5

(PM) at 135:13-140:6 (Cudwadie).

71

III. DISCUSSION
A.

Supremacy Clause (Count I)
1.

Legal Principles

The Supremacy Clause of the United States Constitution
renders federal law "the supreme Law of the Land."
art. VI, cl. 2.

U.S. Const.

"The Supremacy Clause is grounded in the

allocation of power between federal and state governments . . .
."

Md. Pest Control Ass'n v. Montgomery Cnty., Md., 884 F.2d

160, 162 (4th Cir. 1989) (per curiam).

Rooted in the Supremacy

Clause and its recognition of a hierarchy of federal and state
power is the doctrine of preemption.

See Gade v. Nat'l Solid

Wastes Mgmt. Ass'n, 505 U.S. 88, 108 (1992).

Pursuant to the

doctrine of preemption, "[i]t is a familiar and well-established
principle that the Supremacy Clause invalidates state laws that
'interfere with, or are contrary to,' federal law."
Hillsborough Cnty., Fla. v. Automated Med. Labs., Inc., 471 U.S.
707, 712-13 (1985) (internal citation omitted) (quoting Gibbons
v. Ogden, 22 U.S. 1, 211 (1824)).

Accordingly, the doctrine of

preemption is a limitation on state power stemming from the
recognition in the U.S. Constitution of a dual system of
government where the national government reigns supreme.

See

Anderson v. Sara Lee Corp., 508 F.3d 181, 191 (4th Cir. 2007)
(explaining that "'federal statutes and regulations properly
enacted and promulgated can nullify conflicting state or local
72

actions'") (citation omitted).
Preemption of state action through federal law can occur as
the result of: (1) "the Constitution itself," (2) "a valid act
of Congress," and/or (3) "regulations duly promulgated by a
federal agency."

City of Charleston, S.C. v. A Fisherman's

Best, Inc., 310 F.3d 155, 168-69 (4th Cir. 2002).

"Yet

'[c]onsideration under the Supremacy Clause starts with the
basic assumption that Congress did not intend to displace state
law.'"

S. Blasting Servs., Inc. v. Wilkes Cnty., N.C., 288 F.3d

584, 589-90 (4th Cir. 2002) (quoting Maryland v. Louisiana, 451
U.S. 725, 746 (1981)).

This presumption (of a lack of

congressional intent to displace state law) is strongest when
"Congress has 'legislate[d] . . . in a field which the States
have traditionally occupied.'"

Medtronic, Inc. v. Lohr, 518

U.S. 470, 485 (1996) (alteration in original) (citation
omitted).

"[A]n 'assumption' of nonpre-emption is not triggered

when [a] State regulates in an area where there has been a
history of significant federal presence." United States v.
Locke, 529 U.S. 89, 108 (2000).
However, even in a traditionally state-occupied realm, the
Supremacy Clause empowers Congress to preempt or supersede state
or local law, either expressly through explicit statutory
language or impliedly through field or conflict preemption.

See

Hillsborough Cnty., 471 U.S. at 713; Shaw v. Delta Air Lines,
73

Inc., 463 U.S. 85, 95 (1983) ("'Pre-emption may be either
express or implied, and 'is compelled whether Congress' command
is explicitly stated in the statute's language or implicitly
contained in its structure and purpose. '") (citation omitted);
Anderson, 508 F.3d at 191-92.

"Accordingly, '[t]he purpose of

Congress is the ultimate touchstone' of pre-emption analysis."
Cipollone v. Liggett Grp., Inc., 505 U.S. 504, 516 (1992)
(alteration in original) (citations omitted).

2.

Field Preemption

Plaintiffs contend that the Generation Order impermissibly
invades a field occupied exclusively by FERC — the regulation of
wholesale energy and capacity sales, including the price at
which such sales are made — because the Generation Order sets
the wholesale price received by CPV for its capacity and energy
sales into the PJM Markets.

Defendants assert that the

Generation Order falls within the area of electric energy
regulation not only traditionally occupied by the states, but
also explicitly reserved to the states in the Federal Power Act
("FPA").
As discussed supra, preemption of state law may be express,
i.e., explicitly provided for by the federal statue in question,
or implied.

See Morales v. Trans World Airlines, Inc., 504 U.S.

74

374, 383 (1992).
preemption.

One type of implied preemption is field

Field preemption occurs "where Congress has

legislated comprehensively, thus occupying an entire field of
regulation."
(1986).

La. Pub. Serv. Comm'n v. F.C.C., 476 U.S. 355, 368

Thus, "state law is [field] pre-empted where it

regulates conduct in a field that Congress intended the Federal
Government to occupy exclusively."

English v. Gen. Elec. Co.,

496 U.S. 72, 79 (1990).
The congressional intent essential for a field preemption
claim can be found in
[A] "scheme of federal regulation . . . so
pervasive as to make reasonable the
inference that Congress left no room for the
States to supplement it," or where an Act of
Congress "touch[es] a field in which the
federal interest is so dominant that the
federal system will be assumed to preclude
enforcement of state laws on the same
subject."
English, 496 U.S. at 79 (alterations in original) (quoting Rice
v. Santa Fe Elevator Corp., 331 U.S. 218, 230, 67 (1947)).
Generally speaking, "if Congress evidences an intent to occupy a
given field, any state law falling within that field is
preempted."

Silkwood v. Kerr-McGee Corp., 464 U.S. 238, 248

(1984); Pac. Gas & Elec. Co. v. State Energy Res. Conservation &
Dev. Comm'n, 461 U.S. 190, 212 (1983).
Accordingly, assessment of Plaintiffs' field preemption
claim requires a determination of whether Congress intended the
75

federal government to regulate exclusively the field of
wholesale energy and capacity sales and, if so, whether the
Generation Order can be said to have regulated in that field.
Plaintiffs assert that through the FPA, "Congress has made
plain its intention" for FERC to occupy exclusively "the field
of wholesale sales of electric power, including the prices at
which those sales occur."
at 12-13.

Pls.' Post-Trial Br. [Document 144]

Though not necessarily disputing that Congress

intended FERC to regulate exclusively some of the field of
wholesale energy and capacity sales, Defendants maintain that
the Maryland PSC acted within the jurisdiction reserved to the
states by Congress under the FPA, and that therefore, the PSC
could not have invaded any field occupied by FERC.
By enacting the FPA and other related laws, Congress
created a division between federal and state authority within
the broad field of electric energy regulation.

As discussed

supra, this division was somewhat necessitated by the Supreme
Court's holding in Pub. Utils. Comm'n of R.I. v. Attleboro Steam
& Elec. Co., 273 U.S. 83 (1927)42 that the dormant Commerce
Clause prohibited states from regulating the rates for wholesale
power sales between utilities in different states. Cf. First
Iowa Hydro-Elec. Co-op. v. Fed. Power Comm'n, 328 U.S. 152, 167-

42

See Quill Corp. v. N.D. By & Through Heitkamp, 504 U.S. 298
(1992) (recognizing abrogation of Attleboro on other grounds).
76

68, 171 (1946) (interpreting the FPA as mandating divided powers
and "a dual system involving the close integration of these
powers rather than a dual system of futile duplication of two
authorities over the same subject matter").
In the FPA, Congress declared:
Federal regulation of matters relating to
generation to the extent provided in this
subchapter
and
subchapter
III
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).
In line with this dual federal/state regulatory regime,
pursuant to the FPA, FERC has jurisdiction over "the
transmission of electric energy in interstate commerce and . . .
the sale of electric energy at wholesale in interstate
commerce,"43 but not over "any other sale of electric energy."
Id. § 824(b)(1).

Additionally, the FPA grants FERC jurisdiction

over all facilities for the transmission and wholesale sales of
electric energy in interstate commerce, but not "over facilities
used for the generation of electric energy."

43

Id. § 824(b)(1).

The "'sale of electric energy at wholesale' . . . means a
sale of electric energy to any person for resale." 16 U.S.C. §
824(d).
77

Though it creates a federal role, the FPA explicitly
"preserve[d] state jurisdiction" over certain areas of the
electric energy regulation field, including, but not limited to,
regulation concerning the siting and construction of physical
facilities used for the generation of electric energy.44
York v. F.E.R.C., 535 U.S. 1, 22-24 (2002).

See New

Where Congress has

explicitly recognized a role for the states, there can be no
serious assertion that the structure and framework of the FPA
expresses a clear and manifest intent on the part of Congress to
displace completely state authority vis-à-vis physical
generation facilities (distinct from those facilities' wholesale
energy sales and transmissions) and the construction thereof.
Of course, given the dual federal/state regulatory regime, the
division of power regulation labor may not always be clear,
because, for example, FERC's regulatory actions relating to
wholesale energy sales are surely capable of seeping into issues
that surround the emergence of generation facilities.

See,

e.g., Miss. Power & Light Co. v. Miss. ex rel. Moore, 487 U.S.
354, 355-56 (1988) (finding that FERC's order requiring a power
company to purchase 33% of the output of a newly constructed
power plant at a rate determined by FERC to be just and
reasonable preempted the state PSC from "examining the prudence"
44

However, FERC obviously has jurisdiction over a facility's
market actions to the extent the facility engages in wholesale
energy and capacity transmission and sales.
78

of the construction of the power plant in calculating rates
chargeable to a retail customer by the power company to recover
the cost of its purchases from the new power plant).

In any

event, Plaintiffs do not contend that an act of the Maryland
General Assembly or PSC related to the siting or building of a
physical generation facility, the direct financing of the
construction of a power plant, or the encouragement of or
limitations on certain types of power plants within its borders
(such as environmental-related regulation) would be field
preempted by the FPA.45

Rather, Plaintiffs take the more narrow

position that the field of wholesale electric energy sales and
price setting is exclusive to FERC and that the regulatory means
by which the PSC sought to bring about the construction of a new
power plant in Maryland invaded this field.
The preservation of state authority in a carved-out area
within a broader federal regulatory field does not eliminate the
exclusive federal jurisdiction over the balance of the field.
See generally Pac. Gas & Elec. Co. v. State Energy Res.
Conservation & Dev. Comm'n, 461 U.S. 190, 212 (1983) (explaining
that "the federal government has occupied the entire field of
nuclear safety concerns, except the limited powers expressly
ceded to the states").

Indeed, structuring a statutory scheme

45

Of course, Plaintiffs would likely argue that there could
be circumstances in which such action would be conflict
preempted and/or violate the dormant Commerce Clause.
79

so as to divide state and federal authority within one
regulatory realm could be viewed as indicating that Congress
intended the "federal side" of the field to be regulated
exclusively by the federal government.
In regard to electric energy regulation, through the FPA
Congress vested FERC with authority over wholesale electric
energy prices.

The FPA provides 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.
16 U.S.C. § 824d(a).

A "public utility" is defined as "any

person who owns or operates facilities subject to the
jurisdiction of the Commission."

Id.

§ 824(e).

A power plant

that engages in wholesale electric energy sales and interstate
transmission would fall within the definition of a public
utility.
To ensure the just and reasonableness of wholesale electric
energy rates, the FPA implements a regulatory framework that
vests FERC with authority to determine the lawfulness of
wholesale energy rates or prices.

See NRG Power Mktg., LLC v.

Me. Pub. Utils. Comm'n, 558 U.S. 165, 172 (2010).

80

Under the

present regulatory scheme, wholesale energy prices are generally
established in the first instance by public utilities, either
unilaterally through tariffs or through contracts between
wholesale sellers and buyers.

Id.

Such rates or prices must be

filed with FERC and are lawful only if "'just and reasonable.'"
Morgan Stanley Capital Grp. Inc. v. Pub. Util. Dist. No. 1 of
Snohomish Cnty., Wash., 554 U.S. 527, 531 (2008).

"Rates may be

examined by [FERC], upon complaint or on its own initiative,
when a new or altered tariff or contract is filed or after a
rate goes into effect." NRG Power Mktg., 558 U.S. at 171 (citing
§§ 824d(e), 824e(a)).

"Following a hearing, [FERC] may set

aside any rate found 'unjust, unreasonable, unduly
discriminatory or preferential,' and replace it with a just and
reasonable rate."

NRG Power Mktg., 558 U.S. at 171 (quoting §

824e(a)).
Wholesale electric energy rates include energy prices as
well as capacity prices, which "are a large component of
wholesale rates."

See Miss. Indus. v. F.E.R.C., 808 F.2d 1525,

1541 (D.C. Cir. 1987), vacated in part on other grounds, 822
F.2d 1104 (D.C. Cir. 1987); see also Entergy La., Inc. v. La.
Pub. Serv. Comm'n, 539 U.S. 39, 43, n.1 (2003) ("Where, as here
public utilities share capacity, the allocation of costs of
maintaining capacity and generating power constitutes 'the sale

81

of electric energy at wholesale in interstate commerce.'"
(quoting § 824(b)(1))).
As stated by the Supreme Court:
FERC has exclusive authority to determine
the reasonableness of wholesale rates.
It
is now settled that "'the right to a
reasonable rate is the right to the rate
which the Commission files or fixes, and, .
. . . except for review of the Commission's
orders, [a] court can assume no right to a
different one on the ground that, in its
opinion, it is the only or the more
reasonable one.'"
. . . .
Congress
has
drawn
a
bright
line
between state and federal authority in the
setting of wholesale rates and in the
regulation
of
agreements
that
affect
wholesale rates. States may not regulate in
areas where FERC has properly exercised its
jurisdiction
to
determine
just
and
reasonable wholesale rates or to insure that
agreements affecting wholesale rates are
reasonable.
Miss. Power & Light, 487 U.S. at 371, 374 (alteration in
original) (quoting Nantahala Power & Light Co. v. Thornburg, 476
U.S. 953, 960, 957 (1986) (noting that FERC "has exclusive
jurisdiction over wholesale power rates")); Ark. La. Gas Co. v.
Hall, 453 U.S. 571, 580-82 (1981) (finding that state breach-ofcontract claim was preempted by FERC's exclusive jurisdiction on
the grounds that the state court's interpretation of terms could
interfere with FERC rates); see also Pub. Util. Dist. No. 1 of
Snohomish Cnty. v. Dynegy Power Mktg., Inc., 384 F.3d 756, 758
82

(9th Cir. 2004) (acknowledging FERC's "exclusive jurisdiction
over interstate sales of wholesale electricity"); Appalachian
Power Co. v. Pub. Serv. Comm'n of W. Va., 812 F.2d 898, 902 (4th
Cir. 1987) ("FERC's jurisdiction over interstate wholesale rates
is exclusive.").
Accordingly, it appears well accepted that Congress
intended to use the FPA to give FERC exclusive jurisdiction over
setting wholesale electric energy and capacity rates or prices
and thus intended this field to be occupied exclusively by
federal regulation.

Thus, state action that regulates within

this field is void under the doctrine of field preemption.46

a.

The Generation Order

Plaintiffs contend that the PSC has impermissibly regulated
in the field of wholesale electric energy price setting because
the Generation Order effectively sets the price received by CPV
for its wholesale energy and capacity sales to PJM in the PJM
Markets.

Defendants contend the Generation Order does not "set

46

The preemptive effect of the FPA on the Generation
Order does not depend on whether FERC intended to preempt the
actions of the PSC in this case. See generally N. Natural Gas
Co. v. Iowa Utils. Bd., 377 F.3d 817, 824 (8th Cir. 2004) ("The
preemptive effect of the [Natural Gas Act] does not depend on
whether the FERC intends to preempt state authority.").
However, FERC has acted pursuant to its exclusive authority by
determining that the rates set by the PJM Markets and ultimately
received by generation facilities that participate in such
markets are just and reasonable.
83

wholesale prices" because it is a purely financial arrangement
that secured the construction and development of a new
generation facility in Maryland.

(i)

Purpose of the Generation Order

Defendants take the position that the Court cannot, or at
least should not, construe the PSC's regulatory action in
connection with the Generation Order as invading the exclusive
field of FERC because the Order sought to secure the
construction of a generation facility, an act within the
jurisdiction reserved to the states under the FPA.
The Court agrees with Defendants' position that the FPA
preserved states' jurisdiction over certain direct regulation of
physical generation facilities.

For instance, it appears that

the states hold the authority to do the following: (1) take
regulatory action to require existing generation facilities to
retire; (2) limit the type or amount of generation facilities
constructed in the state; (3) promote certain environmentally
desired types of generation facilities; and (4) determine the
siting or location of a new generation facility within the
state.

See 16 U.S.C. § 824(b)(1); Conn. Dep't of Pub. Util.

Control v. F.E.R.C., 569 F.3d 477, 481 (D.C. Cir. 2009).

The

Court can accept Defendants' position that FERC and/or PJM

84

cannot directly order the construction of a new generation
facility, let alone require or direct a state to permit such
construction to occur within its borders.

See Tr. Mar. 5 (PM)

at 21:1-14, 82:4-21 (Nazarian); Tr. Mar. 6 (AM) at 44:1-21,
46:12-47:7 (Massey); Tr. Mar. 7 (AM) at 32:10-21 (Wodyka).

The

Court also can accept the position that the State of Maryland
has a legitimate interest and federally permissible role in
securing an adequate supply of electric energy for Maryland
residents in the present and in the future.

See 16 U.S.C. §

824o(i); Md. Code Ann., Pub. Util. § 5-101(a).
Yet after a generator physically comes into existence and
operation and participates in the wholesale electric energy
market, the prices or rates received by that generator in
exchange for wholesale energy and capacity sales are within the
sole purview of the federal government.

While Maryland may

retain traditional state authority to regulate the development,
location, and type of power plants within its borders, the scope
of Maryland's power is necessarily limited by FERC's exclusive
authority to set wholesale energy and capacity prices under,
inter alia, the Supremacy Clause and the field preemption
doctrine.

Based on this principle, Maryland cannot secure the

development of a new power plant by regulating in such a manner
as to intrude into the federal field of wholesale electric
energy and capacity price-setting.
85

Furthermore, Maryland's

stated purpose to use the Generation Order to secure the
existence of sufficient and reliable electric energy for
Maryland residents does not permit invasion into a federally
occupied field.

Where a state action falls within a field

Congress intended the federal government alone to occupy, the
good intentions and importance of the state's objective are
immaterial to the field preemption analysis.

Field preemption

requires the state to "yield to the force of federal law . . .,
notwithstanding that [the state’s action] is constructed upon
values familiar to many and cherished by most, and
notwithstanding that it may fit neatly within or alongside the
federal scheme."

See French v. Pan Am Exp., Inc., 869 F.2d 1, 6

(1st Cir. 1989).
Defendants maintain that the Generation Order cannot be
field preempted because states may take a variety of actions to
incentivize the development of generation facilities that affect
wholesale energy and capacity prices without infringing on
FERC's jurisdiction.

The Court does not doubt that state action

that promotes the development of power plants contemplated to
participate in the wholesale energy market would not be field
preempted merely because the action — by increasing the supply
of available energy and capacity — affects wholesale energy and
capacity prices in the PJM Markets.

Indeed, Plaintiffs do not

contend that the Generation Order is field preempted solely
86

because it will have an effect on wholesale prices.

Rather,

Plaintiffs assert that the Generation Order is field preempted
because it seeks to secure new generation by setting or
establishing the prices to be received by CPV for its wholesale
energy and capacity sales in the PJM Markets for the next twenty
(20) years.
Therefore, the Court rejects Defendants' position that
because the Generation Order sought to accomplish an objective
within the purview of state jurisdiction contemplated by the
FPA, the Order cannot be held to be field preempted.

It is the

means by which the PSC sought to secure a new generation
facility that Plaintiffs challenge as field preempted, not the
securing of the facility itself or the purpose for taking action
to do so.

Consequently, the fact that the Generation Order

secured the construction of a generation facility capable of
serving the electric energy needs of Maryland is not
determinative of the field preemption issue.

The Court must

assess whether the compensation mechanism, the CfD,
impermissibly set wholesale prices for CPV's energy and capacity
sales into the PJM Markets.

87

(ii)

The Contract for Differences

The price or rate received by CPV or by any generation
resource within the PJM region for energy and capacity sales to
PJM in the PJM Markets is regulated exclusively by FERC under
the FPA.

PJM sets the prices received by generators for sales

into the PJM Markets through market-based auction processes that
are filed with, and approved by, FERC.

The heart of the

parties' dispute relates to whether the PSC has effectively "set
the wholesale prices" that CPV will receive for its energy and
capacity sales into the PJM Markets by issuing the Generation
Order, which requires the Maryland EDCs to enter into the CfD
with CPV.

In essence, the CfD permits CPV ultimately to recover

its proposed "contract price" — accepted and approved by the PSC
in the Generation Order — for energy and capacity sales into the
PJM Markets.
Allegedly impermissible wholesale rate setting by a state
usually occurs with respect to the demand side of the energy
market.

That is, a state takes direct or indirect action that

effectively alters the rate paid by an LSE for wholesale energy
and capacity purchases by exercising jurisdiction over retail
sales to preclude such a regulated utility from passing FERCmandated wholesale rates through to retail consumers.

See,

e.g., Miss. Power & Light, 487 U.S. at 371-72 (recognizing the
"filed rate doctrine," a subset of field preemption, which
88

ensures that regulated utilities can recover the costs incurred
by payment of just and reasonable FERC-determined rates from
retail customers).

However, the instant case relates to an

action that affects the wholesale supply side of the energy
market because the CfD deals with a rate for wholesale energy
sales received by CPV, a generator.

The Court does not

perceive, for purposes of field preemption, any meaningful
difference between state actions directed to the demand side and
those directed to the supply side of the wholesale energy
market.

The foundation that FERC has exclusive authority to

determine the reasonableness of wholesale rates and that,
therefore, state regulation of such matters is void under the
Supremacy Clause, holds firm whether the rate or price in
question is that received by a generation facility for wholesale
sales or is that paid by an LSE for wholesale purchases.
Pursuant to the CfD, CPV agreed to, inter alia:


"[C]onstruct, own, operate, and maintain" a
generation facility "physically located entirely
within the Southwest MAAC;"



"[W]arrant[] that the Facility . . . will
participate in and offer [its output and
products] into all PJM Markets . . . including
but not limited to the BRA, the Day-Ahead Energy
Market, Real-Time Energy Market and the Ancillary
Services Market consistent with PJM Rules;"



Not enter into any "bilateral contract or other
arrangement to sell any of its output, products
or services, . . . with another third party, PJM,
89

or any Government Agency during the Term of the
Agreement, unless approved by the [PSC];"


Beginning on the Commercial Operation Date, have
the generation facility offer and participate in
the PJM Wholesale Energy Market and Capacity
Market and submit only cost-based offers; and



Engage in a monthly compensation scheme with the
Maryland EDCs based upon a comparison of the
revenue received by CPV for its actual sales of
energy and capacity into the PJM Markets and the
"contract price" for energy and capacity provided
for in the CfD.

P.2 (2011 RFP), Attachment 8 (Sample CfD) at 18, 19, 32, 33.
Under the compensation scheme outlined in the CfD, CPV is
guaranteed to receive the "contract price" for each unit of
energy and capacity it sells to PJM in the PJM Markets up to a
ceiling quantity of 661 MW.

The contract price is a dollar

figure assigned to a unit of energy and capacity.47

CPV

configured and proposed the contract price to the PSC as part of
its proposal, and the PSC adopted and accepted CPV's contract
price in the Generation Order.48

The compensation scheme

47

The contract price for energy is different and separate
from the contract price for capacity.
48
The Court finds unpersuasive Defendants' contention that
the contract price is a competitive market price because CPV
initially proposed that price as part of the RFP. In the RFP,
CPV bid the contract price it was willing to receive for its
energy and capacity sales into the PJM Markets in exchange for
developing and operating a generation facility in SWMAAC and
selling the facility's output (up to 661 MW) in the PJM Markets.
The contract price became operative only after reviewed,
evaluated, and accepted by the PSC in an agency order.
Testifying based upon his involvement in the selection process,
former PSC Chairman Nazarian testified that the contract price
90

operates through a monthly netting mechanism that calculates the
volume of units sold by CPV into the PJM Markets and then
compares the market price actually received by CPV for the units
it sold to PJM with the contract price for the same amount of
units.

See id. at 38, 88-94.

If the aggregate market price

received by CPV for its actual energy and capacity wholesale
sales is less than the contract price, then the Maryland EDCs
must pay CPV the difference.

If the aggregate market price

received by CPV for its energy and capacity wholesale sales is
more than the contract price, then CPV must pay the EDCs the
difference.

Id. at 38.

Any loss or gain to the Maryland EDCs

is passed onto Maryland SOS ratepayers in the form of a rate
increase or rate credit.
The following chart, using completely hypothetical numbers,
illustrates the compensation mechanism employed by the CfD:

accepted by the PSC in the Generation Order represented a
unilateral decision by the PSC, and that under the RFP
guidelines, the PSC had reserved the right to select none of the
proposed contract prices. Tr. Mar. 5 (AM) at 122:3-123:6
(Nazarian). Accordingly, although it was proposed by CPV, the
contract price in the CfD is a price "set" or "determined" by
the PSC.
91

Energy
Total Units Sold
to PJM in PJM
Markets in One
Month by CPV
Contract Price
per Unit
Market Price
per Unit
CPV Market
Revenue (Units
Sold * Market
Price)
Contract
Payment Stream
(Units Sold *
Contract Price)
Payment from
EDC to CPV:
Payment from
CPV to EDC:

Capacity

Total ($)

200049

300050

10051

120

5052

7553

$100,000.00

$225,000.00

$325,000.00

$200,000.00

$360,000.00

$560,000.00

$100,000.00

$135,000.00

$235,000.00

$0

$0

$0

Pursuant to the terms of the CfD, assuming that CPV clears
the BRA, for each unit of capacity and energy CPV actually sells

49

This represents the total amount of energy dispatched by
CPV into the PJM Energy Market during a one-month period.
50
Capacity that clears the RPM is sold or offered in MW-days.
The total amount of capacity sold during any one month would be
the capacity offered (100 MW-days) multiplied by the number of
days in the month (30).
51
The contract price per unit is comprised of the Indexed
Variable O&M (VOMe), $/MWh, Heat rate, MMBtu/MWh, and the Gas
Index Price, $/MMBtu (the average of the daily Gas Price Index).
The contract per unit energy price or the "strike price" is the
indexed VOM + [Heat rate * Gas Index Price]. As explained by
Plaintiff's witness, the heat rate multiplied by the gas index
price converts the gas price from dollars per BTU into dollars
per MWh. Then, the variable O&M expenses are added to that
number. Tr. Mar. 4 (PM) at 82:7-20 (Cudwadie).
52
This price would be the average energy price, or the sum of
hourly market energy revenue divided by total energy dispatched.
53
The market price for capacity would be the capacity price
set in the RPM auction.
92

to PJM in the PJM Markets (up to a ceiling amount), CPV will
ultimately realize or be compensated according to the "contract
price" set by the PSC in the Generation Order and not according
to the market-based rates set in the FERC-approved PJM Markets.
Thus, the Generation Order fixes the monetary value of the
energy and capacity generated by CPV's facility and actually
sold by CPV into the PJM Markets.

The monetary value of CPV's

wholesale energy and capacity sales dictated by the PSC in the
Generation Order is determined outside of the auction mechanisms
approved by FERC and utilized by PJM.
Accordingly, the Court finds that the Generation Order,
through the CfD, establishes the price ultimately received by
CPV for its actual physical energy and capacity sales to PJM in
the PJM Markets.

However, under field preemption principles,

the PSC is impotent to take regulatory action to establish the
price for wholesale energy and capacity sales.

FERC has

exclusive domain in that field and has fixed the price for
wholesale energy and capacity sales in the PJM Markets as the
market-based rate produced by the auction processes approved by
FERC and utilized by PJM.

(iii)

Alleged Mere Financing Arrangement

Defendants assert that despite the fact that the CfD's

93

compensation mechanism provides CPV with the contract price for
its actual capacity and energy sales to PJM in the PJM Markets,
the Court cannot consider the Generation Order field preempted
because the Order is a mere financing arrangement outside the
jurisdiction of FERC.

According to Defendants, the contract

price represents CPV's "revenue requirements . . . to construct
a power plant," and therefore, any payments between the EDCs and
CPV are in return for CPV's construction of a generation
facility and not for the sale of energy and capacity.

Defs.'

Post-Trial Br. [Document 146] at 19-20, 22.
The evidence established that CPV formulated the contract
price it submitted in response to the RFP based upon, inter
alia, the cost of constructing the proposed Charles County
Facility.

But, the financial considerations taken into account

by CPV when computing the contract price go beyond recouping the
costs for physically constructing a generation facility.

Mr.

Knight, a representative of CPV, testified that CPV formulated
the contract price submitted to the PSC based upon its
calculation of the annual revenue requirement necessary for CPV
to construct the facility, operate the facility going forward,
and receive a reasonable return on the project.
at 122:15-123:19 (Knight).

Tr. Mar. 7 (AM)

Indeed, evidence was presented that

the same types of financial concerns or factors are taken into
account by an existing generation resource when formulating the
94

price at which it is willing to bid into the BRA.
129:5-130:7.

See id. at

As Mr. Knight explained, the CfD exchanged the

"unknown or variable energy prices" received in the PJM Markets
for the fixed contract price, and, from CPV's perspective, all
CPV needed to know was that the contract price plus the minor
profit it estimated from ancillary services "covers our total
costs on a forward going basis."

Id. at 124:16-21.

The

evidence establishes that the contract price represents a fixed
revenue stream for actual energy and capacity sales into the PJM
Markets that replaces the non-fixed wholesale market revenue
that CPV would otherwise depend upon to finance and operate a
power plant, i.e., to pay for the costs of construction,
operating, capital, etc.
Based on the foregoing, the Court finds that the market
revenue for wholesale energy and capacity sales into the PJM
Markets and the contract price under the CfD serve basically the
same goal: incoming revenue that enables CPV's facility to
exist, operate, and dispatch electric energy into the PJM
region.

Consequently, the variables used by CPV to configure

the contract price submitted to and accepted by the PSC in the
Generation Order do not support Defendants' position that the
CfD is limited to a financing arrangement outside the reach of
FERC and is therefore incapable being field preempted.
The CfD is not a purely financial contract, financial
95

hedging agreement, or swap agreement,54 as those terms are
commonly understood in the energy or financial industry.

The

Court finds credible and reliable the expert testimony of Mr.
Cudwadie.

Mr. Cudwadie explained that participants in the

financial market enter into contracts that in essence bet on
what the market price of energy or capacity (or any other
article of commerce) will be at some defined point(s) in the
future in reference to some market pricing index.
4 (PM) at 76:11-77:13 (Cudwadie).

See Tr. Mar.

Using an example provided by

Mr. Cudwadie, a hypothetical (and oversimplified) swap agreement
for energy prices works as follows:


A and B enter into a swap agreement for 50 MW of
electric energy for 10 hours for tomorrow ("Day
X") at a price of $40 using the settlement index
of PJM West. The amount of MW that would be
subject to the swap would be 500 (10 hours * 50
MW).



The fixed price under the swap is $40. The
floating price is based upon the market or actual
energy sales on Day X (i.e., PJM West pricing
index that shows prices for actual real time
energy sales), and thus will not be known until
delivery on Day X. The floating price is used to
create a settlement price.



Under the swap, A is the "seller" and is betting
that prices are going to be lower than $40, and B
is the "buyer" and is betting prices will be

54

A swap agreement is a specific type of purely financial
contract or financial hedging agreement. See Tr. Mar. 4 (PM) at
63:11-13 (Cudwadie). Industry participants may also label a
swap agreement as a contract for differences. See id. at 63:310. To avoid confusion with the "CfD", the Court shall simply
refer to such financial arrangements as swap agreements.
96

higher than $40. Stated differently, A is
hypothetically selling 500 MW of power at the
floating price to B and B is simultaneously
hypothetically selling 500 MW of power at the
fixed price to A. Therefore, if the fixed price
is higher than the floating price, A will
hypothetically be entitled to receive a payment
upon settlement.


On Day X, PJM posts the 10 hours of real time
prices for energy on its PJM West index, which
shows a market price of $38. Thus, the
settlement price is $38.



Because the settlement price is below the fixed
price, B owes $1,000 to A ([$40-$38] * 500).55

See id. at 63:14-65:25.
Though swap agreements refer to "buying" and "selling,"
those terms are used in relation to how the agreement settles —
who "wins," and how much, based upon the agreed fixed price and
the actual floating price.

Id. at 65:22-25.

Thus, A (seller)

and B (buyer) agree to use a fixed price of $40 at the
conclusion of the contract period for a hypothetical sale of 500
units.

If the actual (floating) price is $38, A (seller) "wins"

and is entitled to receive $1,000 from B (buyer).

There is no

actual delivery or receipt of energy as between A and B.
id. at 66:1-20.

See

Furthermore, there is no contractual

requirement between A and B that either party actually sell or
deliver energy to a third party in order to receive payment
55

The same result would be reached if the amount was computed
by calculating the selling price for A ($19,000) and the selling
price for B ($20,000). Because B will be paying more to A, A
makes $1,000 in the transaction after a setoff.
97

under the swap.

Id. at 66:6-69:16.

Because the swap is a

purely financial arrangement, the parties to the agreement could
be participants in the financial market that have no ownership
interest in, or economic relation to, any facility that buys or
sells electric energy in the wholesale market.

See id. at

66:24-67:1.
Participants in the energy industry may enter into swap
agreements as a financial hedge for actual energy transactions
conducted independently with third parties in the market.
at 67:6-9, 68:24-69:16.

Id.

Thus, a party intending to purchase

energy can guarantee that it will cost $40 per unit by entering
into a swap transaction.

If the actual market price is $42, the

party pays $42 for the energy but receives $2 from the hedge
transaction, making its net cost $40 per unit.

If the actual

market price is $38, the party will pay $38 for the energy but
an additional $2 to the other side of the hedge transaction,
also making its net cost $40 per unit.

Payment under the swap

agreement is not conditioned upon actual physical sales or
deliveries into the energy market.

Id. at 69:22-70:13.

As a

result, the swap agreement on its own has no contractual effect
or relation to the swap parties' behavior in the market upon
which the deal is based because the swap agreement is not a real
sale of a tangible product.
The Court agrees with Mr. Cudwadie that the CfD is
98

critically distinguishable from a swap or similar agreement and
cannot be categorized as a "purely financial arrangement" as
that term is commonly understood in the energy industry.

Unlike

the swap agreement described above, the CfD: (1) obligates CPV
to construct and operate the generation Facility; (2) requires
CPV to participate and offer that Facility's output into the PJM
Markets; (3) dictates the manner in which CPV participates in
the PJM Markets, (4) mandates a financial settlement only if CPV
clears the BRA in any given year; and (5) determines the amount
of settlement based on CPV's physical energy and capacity sales
into the PJM Markets.

See id. at 94:12-98:14.

Indeed, because

the CfD requires CPV to bid and clear the BRA at a price
different from the amount that CPV will actually receive, the
CfD directly affects the market price.

Accordingly, the Court

finds that the CfD does not constitute a pure financial contract
of the type used by participants in the energy market for
hedging purposes.

Consequently, the Court rejects Defendants'

position that the CfD is not field preempted because it amounts
to a non-FERC jurisdictional financial swap agreement.56

56

Defendants seek to utilize the contract between PPL and
Longview Power LLC (the "PPL Longview Contract") to assert that
the CfD is not field preempted. The PPL Longview Contract is
not before this Court for review. Thus whether or not one of
the Plaintiffs entered into a state-mandated contract that
shares similar components with the CfD is not controlling as to
whether the CfD is field preempted. In addition, Defendants
have not presented any sort of estoppel position.
99

Defendants' contend that the compensation mechanism
implemented by the CfD does not regulate in an exclusively
federal field because any payments to CPV are in return for
CPV's construction of the Facility and not for energy and
capacity sales into the PJM Markets.

That is, because the

payment mechanism to CPV is for the construction of the Facility
and not for CPV's wholesale energy and capacity sales, the
payment scheme does not impinge on FERC's exclusive jurisdiction
to set wholesale energy and capacity prices.

An obvious aspect

and objective of the CfD is, of course, the construction of the
Facility by CPV.

As all parties agree, and as is plain from the

terms of the CfD, there could be no payment to CPV under the CfD
if the Facility was never built or was never operational.
Nevertheless, the Court finds that the payment scheme to CPV
under the CfD is in return, at least in part, for CPV's
wholesale sales of capacity and energy in the PJM Markets.
First, the compensation scheme orchestrated by the PSC in
the CfD renders payment directly contingent upon CPV's clearing
capacity in the BRA.

If CPV does not clear any capacity in the

annual BRA, then it gets nothing under the CfD.

Specifically,

"[n]o Monthly Payment shall be provided during any period in
which [CPV] has not been selected to provide capacity in PJM's
BRA."

P.2 (2011 RFP), Attachment 8 (Sample CfD) at 37.

Even if

CPV constructs and operates the Charles County Facility, CPV
100

will receive no payment under the compensation scheme if it does
not clear capacity in the BRA.

Yet, a power plant that does not

clear the BRA may still sell its electric energy to PJM in the
PJM Wholesale Energy Market.
(Willig).

See Tr. Mar. 8 (AM) at 13:19-14:2

The clearing pre-condition in the CfD rewards CPV for

clearing the BRA because CPV only obtains the contract price for
wholesale energy and capacity sales into the PJM Markets if the
CPV bid clears.

Thus, the Court finds that the CfD's payment

scheme compensates CPV, in part, for making wholesale capacity
sales to PJM in the PJM Wholesale Capacity Market.
A second illustration of how the contract price compensates
CPV for its wholesale energy and capacity sales into the PJM
Markets is provided by the way in which monthly settlements are
calculated under the CfD.

If CPV clears the BRA, the pricing

terms in the CfD are linked directly to the quantity of energy
and capacity sold from the CPV Facility into the PJM Markets.
Mar. 7 (PM) at 11:11-13:3, 16:20-17:7 (Knight).

As discussed

supra, CPV is compensated based upon how much capacity and
energy it actually sells to PJM in the PJM Markets up to a
ceiling figure.

As Mr. Cudwadie testified, "to get paid [CPV]

ha[s] to clear the auction.

That same type of principle applies

to the energy market as well.

If they're going to get payment

under the contract, they must clear megawatts in the energy
market."

Tr. Mar. 4 (PM) at 98:4-8 (Cudwadie).
101

The Generation Order, the 2011 Amended RFP, and the CfD
contain other representations that rebut the notion that the CfD
does not compensate CPV for wholesale energy and capacity sales.
For instance, the CfD provides that the Maryland EDCs "shall not
pay for Capacity and Energy that PJM deems was not made
available up to the performance standards required by PJM
Agreements and PJM Tariff."
(Sample CfD) at 38.

See P.2 (2011 RFP), Attachment 8

The CfD obligates CPV to bid its 661 MW of

the Facility only into the PJM Markets.

See id. at 32.

However, wholesale energy and capacity sales may occur through
bilateral contracts or other arrangements outside the PJM
Markets.

The RFP explains that the structure of the CfD is such

that "the delivery of Capacity and Energy will be settled
financially rather than physically, thereby providing
compensation to Supplier for Capacity and Energy."

Id. at 5.

The Court finds that the CfD compensates CPV for more than
developing a new power plant.

Under the CfD, the PSC has

provided payment to CPV for its wholesale energy and capacity
sales to PJM in the PJM Markets at a price different from that
generated by the FERC-approved market auction processes
implemented by PJM.
Defendants assert that the Generation Order is outside the
purview of the FERC-regulated field because the CfD is not an
agreement for the physical delivery or sale of energy and
102

capacity between CPV and the Maryland EDCs.57

The Court does not

find that the lack of physical delivery of energy between the
parties to the CfD (CPV and the Maryland EDCs) insulates the
Generation Order from a field preemption attack.

If the PSC had

ordered CPV to sell, at wholesale, and deliver energy to the
EDCs for the contract price, then the unconstitutionality of the
Generation Order would certainly be obvious.

Here, the CfD

provides payment in the form of the contract price to CPV based
upon CPV's physical sales and delivery of energy and capacity to
PJM in the PJM Markets.

That is, if CPV makes no physical

delivery of energy and capacity in the PJM Markets, then CPV
gets no payment under the CfD.

As former PSC Chairman Nazarian

testified, CPV's physical delivery of energy and capacity into
the PJM Markets "was a central component" of the Generation
Order and the regulatory actions leading thereto.
5 (AM) at 17:15-22 (Nazarian).

See Tr. Mar.

By making CPV's compensation

57

The CfD does contain a provision that would enable the EDCs
to take title to output generated, delivered, or sold by CPV's
facility:
[The Maryland EDCs] shall not take title to
or risk loss to any products or services
generated,
delivered,
or
sold
by
the
Facility unless ordered to do so by the
MDPSC upon the recommendation of the Buyer
or Supplier.
Either Party can initiate an
amendment to the Agreement to require that
the Buyer receive title to the Supplier's
output.
P.2 (2011 RFP), Attachment 8 (Sample CfD) at 35.
103

contingent upon the number of megawatts sold in the PJM Markets
up to the contract cap of 661 MW-days and by also including
other provisions related to CPV's delivery of energy to PJM, the
PSC sought, through the CfD, to have CPV make physical
deliveries of energy to PJM and to compensate CPV with the
contract price for those deliveries from CPV's facility.
Accordingly, the Generation Order involves, and compensates for,
CPV's delivery of energy and capacity to PJM in the PJM Markets,
which provides further evidence that the CfD is not a purely
financial contract generally considered to be outside FERC's
jurisdiction.

See generally Puget Sound Energy, Inc., 96 FERC ¶

63,044, 65,381 n.318 (2001) ("Commission precedent on this issue
is clear - the Commission has asserted jurisdiction only over
those transactions that result in the physical delivery of
electricity.

The Commission has jurisdiction under Sections 205

and 206 of the Federal Power Act only where three conditions are
present: where '[(i)] the electricity futures contract goes to
delivery, [(ii)] the electric energy sold under the contract
will be resold in interstate commerce, [(iii)] and the seller is
a public utility.'") (alteration in original) (quoting N.Y.
Mercantile Exch., 74 FERC ¶ 61,311, 61,987 (1996)).

104

b.

CPV's Market-Based Rate Tariff Argument

Defendants contend that Plaintiffs' field preemption claim
is moot because a finding of field preemption subjects
adjudication of the instant matter to the jurisdiction of FERC.
CPV filed an application with FERC pursuant to Section 205
of the FPA on November 8, 2012 (and amended the application on
December 4, 2012) seeking, inter alia, "authorization to make
market-based wholesale sales of energy, capacity, and ancillary
services pursuant to [an attached] market-based rate tariff."
P.611 (CPV FERC Application for Market-Based Rate Authorization)
at 1.

On February 1, 2013, FERC approved CPV's market-based

rate tariff (the "MBR Tariff").

Defendants assert that if "the

CfD were a contract within FERC's jurisdiction, that contract is
now authorized by FERC and controlled by the MBR Tariff [and]
any complaint by Plaintiffs regarding the CfD . . . would have
to be directed to FERC, and not this Court."58

Defs.' Post-Trial

Br. [Document 146], at 27.
"[Market-based rate t]ariffs, instead of setting forth rate
schedules or rate-fixing contracts, simply state that the seller
58

Prior to trial, CPV filed the Motion to Dismiss Preemption
Claims as Moot [Document 103] asserting that even if Plaintiffs
were correct that the CfD is subject to FERC's jurisdiction,
Plaintiffs would not be entitled to relief on their preemption
claims because FERC granted CPV authority under the FPA to sell
wholesale electricity pursuant to the MBR Tariff. The Court
denied the motion without prejudice to the right of CPV, or of
any other party, to present the mootness contention after trial
[Document 110].
105

will enter into freely negotiated contracts with purchasers."
Morgan Stanley, 554 U.S. at 537.

Contracts entered into under

market-based rate tariffs need not be filed immediately with
FERC.

Instead, the wholesale seller must file quarterly reports

summarizing the contracts into which it has entered.

Id.

A

market-based rate tariff authorizes a seller to enter into
bilateral transactions "for resale of electric energy, capacity,
or ancillary services at market-based rates."

See 18 C.F.R. §

35.36(b); Tr. Mar. 4 (AM) at 40:2-9 (Alessandrini) (explaining
that market-based rate authority gives a seller "the ability to
buy and sell electricity with two willing counter-parties at
arm's length and at market-based rates").

However, "FERC will

grant approval of a market-based tariff only if a utility
demonstrates that it lacks or has adequately mitigated market
power, lacks the capacity to erect other barriers to entry, and
has avoided giving preferences to its affiliates."

Morgan

Stanley, 554 U.S. at 537.
As a result of its MBR Tariff, CPV has FERC approval to
sell electric energy, capacity, or ancillary services at
wholesale through freely negotiated contracts with purchasers,
including wholesale sales made to PJM in the PJM Markets.

See

Tr. Mar. 7 (PM) at 5:4-8 (Knight) (explaining that CPV would be
required to obtain market-based rate authority from FERC prior
to making the sales required under the CfD to PJM).
106

Of course,

the MBR Tariff would affect only those transactions that are
subject to FERC's jurisdiction.
In CPV's application for market-based rate authorization,
it provided in a footnote that:
CPV Maryland has included as Exhibit E the
most current public draft of the CFD that is
under view before the MPSC solely for
informational purposes.
The Commission has
determined that financial contracts that do
not provide for sales of capacity or energy
are not subject to the filing and reporting
requirements
under
Section
205
of
the
Federal Power Act. However, CPV Maryland is
not requesting that Commission to address or
discuss its jurisdiction over the contract
for differences in its decision on this
request for market based rates.

P.611 (CPV FERC Application for Market-Based Rate Authorization)
at 4 n.7 (internal citations omitted).

In its order authorizing

CPV's MBR Tariff, FERC referenced CPV's above-quoted
representation, but did not address the CfD as part of the
proceeding for market-based rate authority, limiting its
discussion to whether CPV had horizontal or vertical market
power.

CPV Shore, LLC, 142 FERC ¶ 61,081, at *7-10 (2013).

FERC has not passed judgment, one way or another, on the
reasonableness or fairness of the terms of CfD, whether the CfD
is a "FERC-jurisdictional" contract, or any other potential
issue within its regulatory jurisdiction.
Defendants contend that a finding in favor of Plaintiffs on

107

the field preemption claim means that FERC would have
jurisdiction over the CfD and, since CPV has been granted its
MBR Tariff, the only forum to debate the enforceability of the
CfD is FERC.

The Court does not agree.

Even if the MBR Tariff granted by FERC authorized CPV, in
the first instance, to enter into the CfD with the Maryland
EDCs, thereby rendering any dispute over the CfD within the
primary jurisdiction of FERC, such an authorization would not by
extension preclude this Court from granting relief to Plaintiffs
on a field preemption claim against the Maryland PSC.
Plaintiffs' Complaint seeks relief enjoining the PSC from
enforcing the Generation Order, which includes the requirement
that the Maryland EDCs enter into the CfD with CPV.

In this

action, Plaintiffs have not directly challenged the CfD (i.e.,
the ability of the Maryland EDCs and CPV to enter into the CfD
absent state directive).

Plaintiffs do not seek relief against

CPV and do not assert that CPV has engaged in an unlawful
practice in connection with the CfD.
in

Contrary to the situation

Pub. Util. Dist. No. 1 of Snohomish Cnty. v. Dynegy Power

Mktg., Inc., 384 F.3d 756, 761 (9th Cir. 2004),59 relied upon by
Defendants, Plaintiffs are not asking that this Court determine
59

In Dynegy, "a utility providing electricity to consumers in
Washington state, has sued various generators and traders of
wholesale electricity for violations of California state
antitrust and consumer protection laws." 384 F.3d at 758. A
state or state agency was not a party to the suit.
108

a price or rate for CPV's energy and capacity sales that would
be fair.

Plaintiffs also are not seeking a determination that

CPV violated or breached its MBR Tariff.

The Court recognizes

that its determination vis-à-vis the Generation Order may have
collateral consequences and give rise to the implication that
the CfD is the type of agreement governed by CPV's MBR Tariff.
However, such implications do not deprive this Court of
jurisdiction to answer the question of whether the Generation
Order as a state action is unconstitutional.
Plaintiffs have challenged the Maryland PSC's ability under
the Supremacy Clause to issue the Generation Order, which
directed market participants to enter into the CfD with CPV.
While the Court's finding that the Generation Order is field
preempted raises the implication that the CfD, standing by
itself, is a FERC-jurisdictional contract as opposed to a purely
financial arrangement that is generally considered outside the
purview of FERC, such an implication does not strip this Court
of jurisdiction to decide the constitutionality of the PSC's
regulatory actions and to enjoin enforcement of an
unconstitutional state action.

109

c.

Resolution

When it issued the Generation Order, the PSC sought "to
ensure the continued, long-term reliability of the electricity
supply to Maryland customers" by securing the construction and
operation of a generation facility within SWMAAC.
RFP) at 1.

See P.2 (2011

By themselves, those actions and objectives of

securing the construction and operation of a generation facility
may not invade a federally occupied field and most likely do
fall within the permissible realm of regulation reserved to the
states under the FPA.

But, the FPA recognizes limits on the

permissible role of the states in regulating generation
facilities.

Specifically, when generators are selling energy

and capacity at wholesale, Congress intended the price or rate
of such sales to be regulated exclusively by FERC.

See supra

Part III.A.2; see also Miss. Indus., 808 F.2d at 1545 n.74
(explaining that "under the clear terms of the [FPA], the
Commission has been awarded jurisdiction over generating
facilities 'to the extent provided in other sections,' including
jurisdiction necessary to effectuate regulation of interstate
wholesale rates").

Because states have no authority, either

traditional or otherwise,60 to set wholesale rates, the

60

The Court does not agree with Defendants that the PSC's
actions are subject to a strong presumption against preemption
because states have traditionally occupied the field of
regulating the construction and siting of physical generation
110

compensation received by CPV for its wholesale energy and
capacity sales is exclusively subject to the regulation of FERC.
While there exist legitimate ways in which states may secure the
development of generation facilities, states may not do so by
dictating the ultimate price received by the generation facility
for its actual wholesale energy and capacity sales in the PJM
Markets without running afoul of the Supremacy Clause.
In the Generation Order, the PSC directed the Maryland EDCs
to enter into the CfD with CPV.

Under the CfD, CPV is

guaranteed to receive the contract price – an out-of-market
price set by the PSC – for its actual wholesale energy and
capacity sales up to 661 MW in the PJM Markets.

Based on the

evidence presented at trial as discussed herein, the Court finds
that the Generation Order sets or establishes the ultimate price
received by CPV for these wholesale energy and capacity sales.
The doctrine of field preemption forecloses state regulation in
a field occupied entirely by the federal government, even if the
state’s purpose is admirable or the state regulation does not
facilities. As explained herein, the PSC's objective certainly
fell within that traditional state purview continually
referenced by Defendants, but the manner in which the PSC
accomplished that objective involved establishing the amount
received by CPV for its wholesale activity in the PJM Markets.
Regulating in the field of wholesale price-setting is occupied
by FERC, so therefore the strong presumption against preemption
is not present. See United States v. Locke, 529 U.S. 89, 108
(2000). However, even if the strong presumption existed, this
Court would still conclude the Generation Order
unconstitutionally encroached into a federal field.
111

conflict with achievement of the federal scheme.
United States, 132 S. Ct. 2492, 2502 (2012).

See Arizona v.

Where Congress

intended FERC alone to regulate wholesale energy and capacity
prices, and this Court has found the Generation Order sets or
establishes the wholesale energy and capacity prices to be
received by CPV for its sales into the PJM Markets, the PSC has
encroached upon an exclusive federal field.

In line with the

principles of the Supremacy Clause, the Generation Order cannot
stand.
The Court finds that the Generation Order is field
preempted and, therefore, is unconstitutional as a violation of
the Supremacy Clause.

3.

Conflict Preemption

Conflict preemption exists "where state law 'stands as an
obstacle to the accomplishment and execution of the [Congress']
full purposes and objectives.'"

Freightliner Corp. v. Myrick,

514 U.S. 280, 287 (1995) (alteration in original) (quoting Hines
v. Davidowitz, 312 U.S. 52, 68 (1941)).

The Court's decision

that the Generation Order violates the Supremacy Clause because
it is field preempted, renders moot the question of whether the
Order would also be held to violate the Supremacy Clause because
it is conflict preempted.

112

The Court will not undertake an academic exercise to
hypothecate the findings that it would have made in a decision
holding that the Generation Order is not field preempted and
then hypothecate what would have been this Court's conflict
preemption decision with those findings substituted for those
actually made.
Accordingly, the Court simply will note that there are
reasonably debatable issues as to whether the Generation Order
violated the Supremacy Clause by virtue of conflict, as well as
field, preemption.

B.

The Dormant Commerce Clause (Count II)
As discussed herein, the Court does not accept any of

Defendants' plethora of contentions that would prevent
consideration of the merits of Plaintiffs' dormant Commerce
Clause claim.

However, on consideration of the ultimate issue,

the Court does not find that the Generation Order violates the
dormant Commerce Clause.

1.

Legal Principles

The enumerated powers delegated to Congress by the United
States Constitution include the power "[t]o regulate Commerce
with foreign Nations, and among the several States, and with the
113

Indian Tribes."

U.S. Const. art. I, § 8, cl. 3.

"Although the

Commerce Clause is phrased merely as a grant of authority to
Congress . . . it is well established that the Clause also
embodies a negative command forbidding the States to
discriminate against interstate trade."
Mo. v. Lohman, 511 U.S. 641, 646 (1994).

Associated Indus. of
This negative aspect

of the Commerce Clause, or dormant Commerce Clause, prohibits
economic protectionism ("that is, regulatory measures designed
to benefit in-state economic interests by burdening out-of-state
competitors") on part of the States.

See New Energy Co. of Ind.

v. Limbach, 486 U.S. 269, 271, 273 (1988) (invalidating under
the dormant Commerce Clause a statute that provided a tax credit
for sales of ethanol produced in Ohio but not for sales of
ethanol produced in certain other states).

Such state economic

protectionism "violates the principle of the unitary national
market by handicapping out-of-state competitors."

W. Lynn

Creamery, Inc. v. Healy, 512 U.S. 186, 193 (1994).
In any dormant Commerce Clause challenge to state action, a
court must determine as a preliminary matter whether the state's
actions are of the type subject to the strictures of the dormant
Commerce Clause.

If the state's actions are not exempted from

the Commerce Clause, then the court must determine whether the
state has affirmatively discriminated against interstate
commerce or, though regulating evenhandedly, has unduly burdened
114

interstate commerce.

See Maine v. Taylor, 477 U.S. 131, 138

(1986); McBurney v. Young, 667 F.3d 454, 468 (4th Cir. 2012),
aff'd, 133 S. Ct. 1709 (2013).

Affirmative discrimination is

subject to strict scrutiny and will be prohibited unless
"'demonstrably justified by a factor unrelated to economic
protectionism.'"

McBurney, 667 F.3d at 468-69 (quoting Brown v.

Hovatter, 561 F.3d 357, 363 (4th Cir. 2009) (explaining that it
is insufficient for a dormant Commerce Clause violation that a
statute provides a benefit to only state citizens and that the
state action must discriminate against out-of-state economic
interests).

State regulation that incidentally burdens

interstate commerce is less rigorously evaluated and "will be
upheld unless the burden imposed on such commerce is clearly
excessive in relation to the putative local benefits." Pike v.
Bruce Church, Inc., 397 U.S. 137, 142 (1970); see also Yamaha
Motor Corp., U.S.A. v. Jim's Motorcycle, Inc., 401 F.3d 560, 567
(4th Cir. 2005) (quoting Pike, 397 U.S. at 142).

2.

"Exemption" from the Dormant Commerce Clause

Defendants contend that the PSC's challenged actions are
not covered by the strictures of the dormant Commerce Clause.
Defendants contend that in connection with issuing the
Generation Order, the PSC operated without Commerce Clause

115

confinement because: (1) state spending or subsidization to
advance a legitimate public purpose operates outside the
Commerce Clause; (2) the PSC acted as a market participant in
the new generation market; and/or (3) Congress has expressly
authorized states to discriminate against interstate commerce in
the siting of generation facilities.

a.

State Spending or Subsidization to Advance a
Legitimate Public Purpose

Defendants urge the Court to hold that the dormant Commerce
Clause does not apply to the PSC's actions because, by
ultimately requiring Maryland ratepayers to shoulder the
financial burden of the CfD, the PSC has merely spent money to
subsidize the construction of a power plant in order to advance
a legitimate public purpose.
[Document 146], at 43-45.

See Defs.' Post-Trial Br.

In essence, Defendants request this

Court to recognize a sweeping exception to the dormant Commerce
Clause that would permit a state or local government to
discriminate against interstate commerce so long as that
government’s actions can be categorized as spending or
subsidization to advance a legitimate public purpose.

For the

reasons stated herein, the Court declines to do so.
Defendants' spending and subsidy contentions are separable
into two distinct categories: (1) state or local spending on any
116

matter and (2) administration of state or local subsidies or
subsidy programs provided to private business.

In their post-

trial briefing, Defendants treat state spending generally and
state administration of a subsidy program as a single class of
state action wholly outside the Commerce Clause.

Yet, a state

subsidy is a sub-set that falls under the much broader umbrella
of state or local spending.61

The Court will address each

category separately.

(i)

Spending to Advance a Legitimate
Public Purpose

Relying on several Supreme Court cases addressing the
market participant exception and state laws that prefer public
entities, Defendants contend that the Supreme Court has made
clear that "governmental entities are not subject to Commerce
Clause scrutiny when they spend money . . . whatever the source
of the funding."
43-44.

See Defs.' Post-Trial Br. [Document 146] at

Plaintiffs assert that the Supreme Court has not

recognized such an exemption and has firmly rejected the
argument a state law to promote with the purpose of promoting a

61

In the general sense, a subsidy refers to a grant of money
or other pecuniary aid by a governmental body to another, such
as a private entity or group of private entities. See W. Lynn
Creamery, Inc. v. Healy, 512 U.S. 186, 194 (1994) (describing
money distributed to Massachusetts dairy farm producers from
state tax fund as a subsidy).
117

public benefit is necessarily insulated from the Commerce
Clause.

The Court agrees with Plaintiffs.

The Supreme Court jurisprudence relied upon by the
Defendants does not demonstrate a separate and categorical
dormant Commerce Clause exception for state activity pigeonholed
as spending money to advance public health, safety, or welfare.
Rather, those decisions indicate a recognition that (1) in
certain instances, when a state or local government spends its
own revenues, that government may be considered a market
participant free to operate without Commerce Clause hindrance
(White v. Mass. Council of Const. Emp'rs, Inc., 460 U.S. 204
(1983); Reeves, Inc. v. Stake, 447 U.S. 429 (1980)) and that (2)
in certain instances a state's favoring or benefiting a
government or public entity while treating all private companies
without distinction does not discriminate against interstate
commerce (Dep't of Revenue of Ky. v. Davis, 553 U.S. 328 (2008);
United Haulers Ass'n, Inc. v. Oneida-Herkimer Solid Waste Mgmt.
Auth., 550 U.S. 330 (2007)).
Specifically, in White the Supreme Court held that
"[]nsofar as the city [of Boston] expended only its own funds in
entering into construction contracts [to which the city was a
signatory] for public projects, it was a market participant,"62

62

In White v. Mass. Council of Const. Emp'rs, Inc., the city
executive order at issue also applied to funds received from the
118

and therefore the dormant Commerce Clause placed no limitation
on its ability to favor city residents in connection with those
contracts.63 460 U.S. at 209 n.5, 214-15.

In Reeves, the Supreme

Court held that South Dakota's construction and operation of a
cement plant rendered it a market participant and thus left the
state free to favor South Dakota customers over out-of-state
customers when selling the plant's output without implicating
the dormant Commerce Clause.

447 U.S. at 439-40.

With respect

to public entities, in United Haulers, the Supreme Court held a
"flow control" ordinance requiring all trash haulers to deliver
solid "waste to [a 'clearly public'] facility[y] owned and
operated by a state-created public benefit corporation"64 did not
discriminate against interstate commerce within the meaning of
the dormant Commerce Clause.65

550 U.S. at 334.

Similarly, in

federal government. 460 U.S. 204, 206, 208 (1983). The Supreme
Court found that to the extent the order applied to projects
funded in part with funds acquired by the city through federal
programs, the order had been specifically authorized by Congress
and thus fell within the congressional authorization exception
to the Commerce Clause. See id. at 212-16.
63
In White, the executive order issued by the city "required
that all construction projects funded in whole or in part by
city funds . . . should be performed by a work force consisting
of at least half bona fide residents of Boston." Id. at 205-06.
64
As to funding the facility, the defendant waste management
authority collected "tipping fees" from private trash collectors
to cover operating and maintenance costs, and if the costs were
not recouped through the tipping fees and other charges, then
the state counties served by the facility would make up the
difference. United Haulers Ass'n, Inc. v. Oneida-Herkimer Solid
Waste Mgmt. Auth.,550 U.S. 330, 335-36 (2007).
65
The Court reasoned that state governments are distinct from
119

Davis, the Supreme Court, relying on United Haulers, held that
Kentucky's tax exemption for state-issued bonds did not
discriminate against interstate commerce because Kentucky
treated all private bond issuers exactly the same.66

553 U.S. at

341-43 (recognizing that state tax exemptions for state-issued
bonds were a common and historically rooted practice).
Accordingly, the Supreme Court has by no means made clear
that when a state or local government spends money to advance a
legitimate public purpose it is free to discriminate against
interstate commerce or is considered not to discriminate against
interstate commerce.

Further, the PSC's actions at issue herein

are entirely distinguishable from the actions at issue in the
aforementioned cases.

Here, the PSC is not: (1) spending its

own funds to construct a power plant; (2) entering into a
contract to which it is a signatory for the construction of a
power plant; (3) owning or operating a power plant; (4) creating
a clearly public entity that will own and operate a power plant;
and/or (5) issuing bonds to generate state revenue to fund a
private businesses because the state "is vested with the
responsibility of protecting the health, safety, and welfare of
its citizens." Id. at 342. Thus, "[l]aws favoring local
government . . . may be directed toward any number of legitimate
goals unrelated to protectionism," unlike laws favoring in-state
business over out-of-state business. Id. 343.
66
Justice Souter, who delivered the opinion of the Court in
Dep't of Revenue of Ky. v. Davis, 553 U.S. 328 (2008), opined
that the Kentucky law would also evade dormant Commerce Clause
review under the market participant exception, but a majority of
Justices did not join in that portion of the opinion.
120

power plant.

To the contrary, the PSC procured a market actor,

CPV, to construct, own, and operate a private facility in the
interstate energy market and then used its regulatory authority
to order other market actors, and ultimately Maryland
ratepayers, to provide the Facility with financial backing.
Additionally, the Court does not find any basis for
recognizing the general "spending exception" advocated by
Defendants.

Such an exception would endorse a formalistic

approach to the Commerce Clause, long discouraged by the Supreme
Court.

See W. Lynn Creamery, 512 U.S. at 201.

As the Supreme

Court pointed out in the not-too-distant past: "The commerce
clause forbids discrimination, whether forthright or ingenious.
In each case it is our duty to determine whether the statute
under attack, whatever its name may be, will in its practical
operation work discrimination against interstate commerce."
Best & Co., Inc. v. Maxwell, 311 U.S. 454, 455-56 (1940).

In

addition to its reluctance in fashioning exemptions that place
form over substance, the Supreme Court has flatly cast aside any
notion that a state may regulate in a manner that discriminates
or burdens interstate commerce so long as it acts for a
legitimate public purpose.

See, e.g., Or. Waste Sys., Inc. v.

Dep't of Envtl. Quality of State of Or., 511 U.S. 93, 100 (1994)
(explaining the "purpose of, or justification for, a law has no
bearing on whether it is facially discriminatory"); Dean Milk
121

Co. v. City of Madison, 340 U.S. 349, 354 (1951).
The Court does not agree with Defendants' position that
subjecting the PSC's actions to the dormant Commerce Clause will
have severe adverse effects by raising questions as to whether
commonplace state spending activity, such as a decision to fund
the expansion of a state university’s campus with student
tuition, is permissible under the Commerce Clause.

There are,

of course, multitudes of state spending schemes that by their
nature most likely raise no discernible Commerce Clause issue
because those activities simply do not regulate commerce in any
meaningful sense or fall within an already recognized Commerce
Clause exception.
J., concurring).

See Davis, 553 U.S. at 358 (2008) (Stevens,
Just the same, one can certainly envision

state spending schemes that do give rise to significant Commerce
Clause concerns.

See W. Va. Univ. Hosps., Inc. v. Rendell, No.

1:CV-06-0082, 2007 WL 3274409, at *9-10 (M.D. Pa. Nov. 5, 2007)
(finding a Pennsylvania law that excluded all out of-state
hospitals that provide trauma care to Pennsylvania residents
from receiving trauma payments available to Pennsylvania
hospital invalid as unjustified facial discrimination against
interstate commerce).
Whether any particular state spending activity is subject
to, or passes muster under, the dormant Commerce Clause will
depend on the nature and contours of that particular scheme.
122

The Court will, therefore, address Plaintiffs' claim that the
specific actions taken by the PSC implicate and violate the
dormant Commerce Clause.

(ii)

State Subsidies

Defendants contend that the PSC's actions amount to a
constitutionally permissible subsidy program not subject to
dormant Commerce Clause scrutiny.

Plaintiffs assert that the

Supreme Court has never explicitly addressed the
constitutionality of subsidy programs in connection with the
dormant Commerce Clause and that, in any event, the PSC has not
directly subsidized anything.
The Supreme Court has yet to decide whether or not state or
local government subsidy programs are categorically outside the
dormant Commerce Clause.

See Camps Newfound/Owatonna, Inc. v.

Town of Harrison, Me., 520 U.S. 564, 589 (1997) (explaining that
there was no need to address the permissibility of a state
subsidy under the dormant Commerce Clause because the law at
issue was a tax exemption, which, although having the same
effect as subsidy, is constitutionally distinct under Supreme
Court jurisprudence); W. Lynn Creamery, 512 U.S. at 199 n.15.
However, the Supreme Court has made several statements with
respect to subsidies and the dormant Commerce Clause.

For

instance, in W. Lynn Creamery, the Supreme Court stated in dicta
123

that "[a] pure subsidy funded out of general revenue ordinarily
imposes no burden on interstate commerce, but merely assists
local business."

512 U.S. at 198-99 (holding that a pricing

program consisting of a subsidy and a nondiscriminatory tax on
all dairy farmers violated the dormant Commerce Clause because
the tax was effectively imposed only on out-of-state dairy
farmers).

In a case involving a discriminatory tax scheme, the

Supreme Court stated that:
The Commerce Clause does not prohibit all
state action designed to give its residents
an advantage in the marketplace, but only
action of that description in connection
with the State's regulation of interstate
commerce. Direct subsidization of domestic
industry does not ordinarily run afoul of
that prohibition; discriminatory taxation of
out-of-state manufacturers does.
New Energy, 486 U.S. at 278 (1988).67

67

Reference to direct subsidies by the Supreme Court is, in
some ways, rooted in the market participant exception to the
dormant Commerce Clause. In Hughes v. Alexandria Scrap Corp.,
426 U.S. 794 (1976), the Supreme Court first recognized the
market participant exception to the dormant Commerce Clause when
sanctioning a state's cash subsidy program. In New Energy Co.
of Ind. V. Limbach, the Supreme Court noted that simply because
a "tax credit scheme has the purpose and effect of subsidizing a
particular industry . . . [t]hat does not transform it into a
form of state participation in the free market" outside of
dormant Commerce Clause scrutiny under the market participation
exception. 486 U.S. 269, 277-78 (1988). The Court explained
that although it considered the cash subsidy program at issue in
Alexandria Scrap to be proprietary activity, not all state
subsidy programs necessarily fall into that characterization.
See id. at 277; Reeves, Inc. v. Stake, 447 U.S. 429, 440 n.14
(1980) ("We have no occasion here to inquire whether subsidy
programs unlike that involved in Alexandria Scrap warrant
124

At most, the Supreme Court's statements regarding subsidies
suggest that a "pure [state or local government] subsidy funded
out of general revenue" or "direct subsidization of domestic
industry" by a state or local government is generally
permissible under the Commerce Clause.68

The Supreme Court has

not given any indication that state activity that could be
labeled as an indirect subsidy or a subsidy equivalent — in that
it has the purpose or effect of funding domestic business –
necessarily is permissible under the dormant Commerce Clause.
To the contrary, the Supreme Court has subjected state laws that
have the purpose and/or effect of subsidizing only local
industry to dormant Commerce Clause scrutiny.

See Bacchus

Imports, Ltd. v. Dias, 468 U.S. 263, 265-66, 272 (1984) (finding
that a tax exemption for certain locally produced alcoholic
beverages violated the dormant Commerce Clause even though the
state’s asserted purpose for the tax exemption was an attempt to
characterization as proprietary, rather than regulatory,
activity."). Thus, the Supreme Court has recognized that a
state may be considered a "market participant" free to
discriminate against interstate commerce when administering a
subsidy program, but that simply because a state activity is
labeled as a subsidy or has that purpose or effect does not
automatically render the state's actions proprietary as opposed
to regulatory.
68
However, the Supreme Court's statements do not clarify
whether it considers a "direct subsidy" as: (1) an independent
category of state activity exempted from the dormant Commerce
Clause (i.e., permitting discriminatory direct subsidies); (2)
falling within the market participant exception; or (3) a type
of state action that is generally not considered as
discrimination or as a burden on interstate commerce.
125

subsidize financially troubled local business).69

The Supreme

Court has also refused to consider state laws that have the
purpose and/or effect of subsidizing a particular industry
necessarily to be a form of market participation, as opposed to
a form of regulation, by the state.

See New Energy, 486 U.S. at

277-78.
In the instant case, the PSC is not directly funding or
providing pecuniary aid to a domestic business through general
taxes, municipal bonds, or some other source of Maryland or PSC
revenue.

The PSC has elected to exercise its regulatory

authority over the Maryland EDCs in such a way as to order those
market actors to provide a local generation facility selected by
the PSC with 20 years of financing in the form of the CfD and to
permit the EDCs to recoup their losses and pass on their gains
to Maryland SOS customers through increases or credits on retail
electricity bills.

The PSC has also opted to use the open

market to earn revenues for its procured generation facility, as
evidenced by the fact that any payment obligation of the EDCs,
and, by extension, the Maryland ratepayers, under the CfD only
69

The Supreme Court does distinguish between a direct subsidy
and a tax exemption. The Supreme Court has explained that
although tax exemptions and subsidies serve similar ends, "there
is a constitutionally significant difference between" the two
because discriminatory tax exemptions have been considered the
type of state action "designed to give residents an advantage in
the market place [that] is prohibited by the Commerce Clause."
Camps Newfound/Owatonna, Inc. v. Town of Harrison, Me., 520 U.S.
564, 589-91 (1997).
126

arises if the generation facility actually sells its output into
the interstate PJM Markets.

Thus, the PSC's financing scheme is

constitutionally distinct from a direct subsidy in a dormant
Commerce Clause context.

See C & A Carbone, Inc. v. Town of

Clarkstown, N.Y., 511 U.S. 383, 394 (1994) (explaining that
where a flow control ordinance served the purpose of financing a
town-sponsored facility and that since the town "elected to use
the open market to earn revenues for its project, the town may
not employ discriminatory regulation to give that project an
advantage over rival business from out of State" and contrasting
that with a situation in which the town "subsidize[d] the
facility through general taxes or municipal bonds").

Placing

the ultimate financial risk of the PSC's decision to procure the
construction and operation of private facility in SWMAAC on
Maryland ratepayers is also distinctly different from a direct
subsidization.

See Alliance for Clean Coal v. Miller, 44 F.3d

591, 596 (7th Cir. 1995).

Indeed, holding that the PSC's

actions fall within the realm of subsidies noted by the Supreme
Court to be "dormant Commerce Clause friendly" would render the
adjectives "pure" and "direct" meaningless.
Accordingly, the Court finds the PSC's actions cannot be
characterized as a direct subsidization of the construction and
operation of a local generation facility, irrespective of
whether direct subsidies would be permissible under the Commerce
127

Clause.

b.

Market Participant Exception

Defendants assert that the PSC, on behalf of the Maryland
ratepayers, is a "financier" of a new generation facility and
thus should be considered a market participant in the market for
new generation facilities whose actions are therefore not
subject to the dormant Commerce Clause.

Plaintiffs assert the

market participant doctrine is inapplicable because the PSC is
not buying or selling anything in the new generation market.
The market participant exception permits a state to
discriminate against interstate commerce and prefer its own
citizens when it acts as a participant in the market, and not as
a regulator.

See Hughes v. Alexandria Scrap Corp., 426 U.S.

794, 802, 809-10 (1976) (finding that a law giving "Maryland
processors an advantage over . . . non-Maryland processors in
the competition for bounty-eligible hulks" was not subject to
the dormant Commerce Clause where Maryland had acted as a market
participant in using state monies to create and fund the
"bounties" and concluding that the state was free to favor its
own citizens in receiving such bounties).

The Supreme Court has

explained that the market participant exception makes "good
sense" because "the Commerce Clause responds principally to

128

state taxes and regulatory measures impeding free private trade
in the national marketplace.

There is no indication of a

constitutional plan to limit the ability of the States
themselves to operate freely in the free market."
U.S. at 436-37 (internal citations omitted).

Reeves, 447

That is, when

acting as a proprietor, states, like any private business,
should be able to make decisions without Commerce Clause limits.
See id. at 439.
Under the Generation Order and the CfD, the PSC is not
buying, selling, or directly paying for anything in the new
generation resource market.

The CfD requires the generation

facility to sell its energy and capacity to PJM in the PJM
Markets.

As the evidence at trial demonstrated, PJM sells the

energy and capacity that it purchases from generation resources
to LSEs within the PJM region, including the Maryland EDCs, who
then resell the energy and capacity to Maryland end-use
customers.

With respect to "payment," the PSC is not a

signatory to the CfD; that compensation scheme is between the
generation facility and the Maryland EDCs.

The EDCs have PSC

authorization to pass on losses and gains under the CfD to
Maryland ratepayers who pay the EDCs for retail electric sales.
Under this scheme, the PSC is not acting as a proprietor or even
directly participating in the free market or in a market it
created, and therefore is not entitled to be treated as a
129

private actor procuring a new generation facility for purposes
of the Commerce Clause.

Cf. Brooks v. Vassar, 462 F.3d 341, 357

(4th Cir. 2006) (finding that where Virginia elected to sell
alcohol from state-owned and state-operated stores, it was a
participant in the alcohol retail market and therefore could
elect not to sell out-of-state wines at its stores without
dormant Commerce Clause concerns).

Rather, as the face of the

RFP makes clear, the PSC is acting as a regulator of electric
distribution companies.

See P.2 (2011 RFP) at 1 n.1 (citing

regulatory authority relied upon by PSC in issuing the RFP).
The fact that this regulatory action may have the "effect of
subsidizing" the operation and construction of a local
generation facility, "does not transform it into a form of state
participation in the free market."

New Energy, 486 U.S. at

277.70
Accordingly, the Court finds the PSC's actions do not fall
within the market participant exception.

70

Furthermore, Defendants' contention that the PSC is acting
as a market intermediary on behalf of Maryland ratepayers to
finance a new generation facility and that the PSC is therefore
a market participant is without merit or legal support. If the
market participant exception were applicable solely because the
state government propounded to be acting on behalf of its
citizens (or some discrete group thereof), the exception would
swallow the rule.
130

c.

Explicit Authorization from Congress

Defendants assert that the PSC's actions cannot give rise
to a dormant Commerce Clause claim because Congress expressly
authorized the states to regulate freely the siting of
generation facilities within each respective state in Section
201(b)(1) of the Federal Power Act.

16 U.S.C. § 824(b)(1)).

Plaintiffs contend that Defendants have failed to meet their
burden of demonstrating a clear intent on behalf of Congress to
permit states to discriminate against interstate commerce.
In exercising its authority under the Commerce Clause,
Congress may "confe[r] upon the States an
ability to restrict the flow of interstate
commerce that they would not otherwise
enjoy." If Congress ordains that the States
may freely regulate an aspect of interstate
commerce, any action taken by a State within
the scope of the congressional authorization
is rendered invulnerable to Commerce Clause
challenge.
W. & S. Life Ins. Co. v. State Bd. of Equalization of Ca., 451
U.S. 648, 652-53 (1981) (internal citations omitted).

To exempt

the states from scrutiny under the dormant Commerce Clause,
"Congress must manifest its unambiguous intent before a federal
statute will be read to permit or to approve . . . a violation
of the Commerce Clause."

Wyoming v. Oklahoma, 502 U.S. 437, 458

(1992).
Section 201(b)(1) of the FPA provides, inter alia, that
FERC "shall have jurisdiction over all facilities for such
131

transmission or sale of electric energy, but 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).

In

examining the particular part of Section 201(b)(1) that
references states' existing lawful authority over hydroelectric
energy, the Supreme Court concluded that "§ 201(b) simply saves
from pre-emption under Part II of the Federal Power Act such
state authority as was otherwise 'lawful'" and that "[n]othing
in the legislative history or language of the statute evinces a
congressional intent 'to alter the limits of state power
otherwise imposed by the Commerce Clause.'"

New Eng. Power Co.

v. New Hampshire, 455 U.S. 331, 341 (1982) (citation omitted).
As later recognized by the Supreme Court: "Our decisions have
uniformly subjected Commerce Clause cases implicating the
Federal Power Act to scrutiny on the merits."

Wyoming, 502 U.S.

at 458.
The Court finds Defendants have failed to demonstrate a
clear and unambiguous intent on behalf of Congress to permit
states to discriminate against interstate commerce in connection
with the siting of generation facilities within a state.

3.

Proof of Discrimination

The Court has found that the PSC's actions challenged by
132

Plaintiffs do not fall within an established or recognized
"exception" to the dormant Commerce Clause.

As a result, "the

Commerce Clause stands as constitutional limitation on the means
by which [the PSC] can constitutionally seek to achieve [its]
goal" of incentivizing the development and operation of a
private local generation facility.

See Bacchus Imports, 468

U.S. at 271.
Plaintiffs bear the burden to demonstrate that the
Generation Order "'discriminates [against interstate commerce]
facially, in its practical effect, or in its purpose.'"

Yamaha

Motor Corp., 401 F.3d at 567 (alteration in original) (citation
omitted).

If Plaintiffs make such a showing, then the

Generation Order will be struck down unless Defendants
demonstrate "both that the statute 'serves a legitimate local
purpose [unrelated to economic protectionism],' and that this
purpose could not be served well by available nondiscriminatory
means."

Maine, 477 U.S. at 138 (citation omitted).

However, if

Plaintiffs demonstrate that the Generation Order "amounts to
simple economic protectionism, a 'virtually per se rule of
invalidity' has [been] applied" by the Supreme Court. See
Wyoming, 502 U.S. at 454-55 (1992) (citation omitted).

133

a.

"SWMAAC" Locational Requirement Does Not
Preclude a Finding of Affirmative
Discrimination

The fact that the locational requirement is defined as
"SWMAAC," which includes the District of Columbia and only part
of Maryland, does not "insulate" the Generation Order from
Plaintiffs' contention that by virtue of the locational
restriction in the RFP, the PSC affirmatively discriminated
against interstate commerce.

See C & A Carbone, 511 U.S. at 391

("The ordinance is no less discriminatory because in-state or
in-town processors are also covered by the prohibition."); Dean
Milk, 340 U.S. at 354 n.4 ("It is immaterial that Wisconsin milk
from outside the Madison area is subjected to the same
proscription as that moving in interstate commerce.").

Nor does

the fact that SWMAAC includes the District of Columbia make any
discrimination by the PSC no longer discriminatory.

See New

Energy, 486 U.S. at 274 (explaining that making a tax credit
available to some out-of-state manufacturers does not make the
credit not discriminatory); Alliance for Clean Coal v. Bayh, 72
F.3d 556, 560 (7th Cir. 1995) ("Protection of local, or even
regional, industry is simply not a legislative action that is
consistent with the Commerce Clause.").
The Court finds that there was little, if any, realistic
possibility that the generation facility in question would be
located in the District of Columbia.
134

Mr. Massey testified that

about 98% of SWMAAC geographically is within Maryland.
6 (AM) at 37:16-18 (Massey).

Tr. Mar.

In addition, evidence as to the

availability of useable sites in the District of Columbia,
established a high degree of improbability – if not
impossibility – that an acceptable facility could be located
there.

Moreover, the RFP required any proposal to include a

"[d]escription of the reliability and direct economic benefits
to Maryland ratepayers as a result of the Generation Capacity
Resource" and provided that in scoring bids, 2.5% of the nonprice score consisted of the "benefits to the State of
Maryland."

P.2 (2011 RFP) RFP at 10, 14-15 (emphasis added).

In any event, even if the facility realistically could have been
located in the District of Columbia rather than Maryland, this
fact would have no bearing on the affirmative discrimination
claim.
The Court finds that the PSC's regulatory action would be
repugnant to the dormant Commerce Clause if it discriminates
against economic interests outside a particular zone of the PJM
region.

b.

Differential Treatment of In-State and Outof-State Economic Interests

Plaintiffs assert that the evidence establishes that the
Generation Order discriminates against interstate commerce on
135

its face and in its practical effect.

Plaintiffs contend that

the SWMAAC locational requirement treats in-state and out-ofstate economic interests differently, "the former benefitting
from exclusive rights to participate in the RFP and the latter
precluded from participation."71
144] at 63.

Pls.' Post-Trial Br. [Document

Defendants contend that Plaintiffs have failed to

prove affirmative discrimination against interstate commerce.
The dormant Commerce Clause "prevents a State from
'jeopardizing the welfare of the Nation as a whole' by
'plac[ing] burdens on the flow of commerce across its borders
that commerce wholly within those borders would not bear.'"

Am.

Trucking Ass'ns, Inc. v. Mich. Pub. Serv. Comm'n, 545 U.S. 429,
433 (2005) (alteration in original) (citation omitted).
Precluding this type of state action enforces the principle that
"[t]he mere fact of nonresidence should not foreclose a producer
in one State from access to markets in other States."
v. Heald, 544 U.S. 460, 472 (2005).

Granholm

As the Supreme Court

explained in 1949:
Our system, fostered by the Commerce
Clause, is that every farmer and every
craftsman shall be encouraged to produce by
the certainty that he will have free access
71

A representative of PPL testified that PPL reviewed the
PSC's RFP but did not participate because PPL "did not have
generation asset facility [sic] that was in SWMAAC and available
to participate based on that requirement" and the "RFP acted in
a manner inconsistent with [PPL's] market principles." Tr. Mar.
4 (AM) at 71:9-24 (Alessandrini).
136

to every market in the Nation, that no home
embargoes will withhold his exports, and no
foreign state will by customs duties or
regulations exclude them. Likewise, every
consumer may look to the free competition
from every producing area in the Nation to
protect him from exploitation by any. Such
was the vision of the Founders; such has
been the doctrine of this Court which has
given it reality.
H.P. Hood & Sons, Inc. v. Du Mond, 336 U.S. 525, 539 (1949).
Discrimination for purposes of the dormant Commerce Clause
"simply means differential treatment of in-state and out-ofstate economic interests that benefits the former and burdens
the latter."

Or. Waste Sys., 511 U.S. at 99-100 (holding that a

greater surcharge on disposal of in-state waste than on disposal
of out-of-state waste facially discriminated against interstate
commerce).

For instance, states may not "provid[e] a direct

commercial advantage to local business."

Nw. States Portland

Cement Co. v. Minnesota, 358 U.S. 450, 458 (1959).

"Permitting

the individual States to enact laws that favor local enterprises
at the expense of out-of-state businesses 'would invite a
multiplication of preferential trade areas destructive' of the
free trade which the Clause protects."

Boston Stock Exch. v.

State Tax Comm'n, 429 U.S. 318, 329 (1977) (citation omitted).
The Supreme Court has considered states to have impermissibly
favored in-state economic interests over out-of-state economic
interests by: (1) providing only tax credits for in-state sales

137

of products actually produced in-state, New Energy, 486 U.S. at
271; (2) precluding out-of-state producers from shipping
products directly to in-state consumers, Granholm, 544 U.S. at
473-74; and (3) giving property tax exemptions to in-state
entities that primarily serve state residents but not to instate entities that principally serve interstate clientele,
Camps Newfound/Owatonna, 520 U.S. at 576-77.
The Court finds that Plaintiffs have failed to prove that
the SWMAAC locational requirement is facially discriminatory for
purposes of the dormant Commerce Clause.72

The mere fact that

the PSC sought to procure a new generation facility located
within SWMAAC does not, standing alone, discriminate against the
flow of interstate commerce.

The Generation Order does not

erect any barriers to the sale or transmission of electric
energy at wholesale in and out of SWMAAC and within the PJM
region or to providing a competitive advantage to an in-SWMAAC
generation facility selling electric energy at wholesale at the
expense of other generation facilities competing in the same
market.

CPV's facility would compete in the PJM Markets with

all other resources to sell its energy and capacity to PJM.

The

Maryland EDCs directed to enter into the CfD would likewise
72

Plaintiff's dormant Commerce Clause claim is limited to the
SWMAAC locational requirement. Hence, there is no contention
that the Generation Order sans the SWMAAC locational requirement
discriminated against interstate commerce by orchestrating longterm financing for a preferred market participant.
138

continue to purchase energy and capacity from the wholesale
energy markets, including from PJM in the PJM Markets.

Cf.

Wyoming, 502 U.S. at 455-56 (finding that a law that required
all in-state coal-fired power plants to burn a mixture of coal
containing 10% coal mined in the state discriminated on its face
and in practical effect against interstate commerce because such
a requirement explicitly operated to the exclusion of coal mined
in other states); Dean Milk, 340 U.S. at 350, 353 (holding that
a city ordinance that "ma[de] it unlawful to sell any milk as
pasteurized unless it has been processed and bottled at an
approved pasteurization plant within a radius of five miles"
from the city of Madison violated the dormant Commerce Clause).
Though the PSC has exercised its regulatory power to create
and sustain another competitor in the wholesale energy market
through indirect subsidization, the fact that the PSC limited
its financial backing to a yet-to-built facility in SWMAAC does
not equate to affirmative discrimination against interstate
commerce or out-of-state economic interests within the meaning
of the dormant Commerce Clause.

See generally McBurney, 667

F.3d at 469 (explaining that the dormant Commerce Clause "'does
not purport to . . . protect the participants in intrastate or
interstate markets, nor the participants' chosen way of doing
business'" (alteration in original) (citation omitted)).
Relying on Alliance for Clean Coal v. Miller, 44 F.3d 591
139

(7th Cir. 1995), Plaintiffs assert the SWMAAC "locational
requirement discriminates against out-of-state commerce
[because] it effectively displaces imported power with locally
produced power."

Pls.' Post-Trial Br. [Document 144] at 64.

However, the Seventh Circuit's decision in Alliance for Clean
Coal does not stand for the broad proposition that displacing
imported energy discriminates against interstate commerce.

In

Alliance for Clean Coal, Illinois passed a law that, while not
compelling all in-state coal burning generators to burn highsulfur coal mined in Illinois, implemented several statutory
mechanisms73 that significantly hindered, if not totally
prevented, Illinois utilities from switching to low-sulfur outof-state coal to meet environmental mandates.
96.

44 F.3d at 594-

Through these statutory mechanisms, the Seventh Circuit

held that Illinois discriminated against interstate commerce by
making out-of-state coal a less viable option for in-state
generators to meet environmental mandates.

See id. at 596.

Alliance for Clean Coal is less than comparable to the instant
73

For instance, the Illinois law: (1) required the state
regulatory entity to take into account the local coal industry
when considering plans to comply with sulfur-related
environmental mandates; (2) mandated that certain generating
units install scrubbers so that those units could burn the highsulfur Illinois coal; (3) guaranteed the cost of the scrubbers
would be passed through to consumers; and (4) required a utility
to get regulatory approval before changing its fuel source in a
way that would result in a 10% or greater decrease in the use of
Illinois coal. Alliance for Clean Coal v. Miller, 44 F.3d 591,
595-96 (7th Cir. 1995).
140

case because the PSC did not act for the explicit purpose of
protecting some in-state business, like coal mining, in the wake
of new federal regulation threatening to wipe out that local
business.

See id. at 594-96 (explaining that federal amendments

to the Clean Air Act "meant the end of the salad days for highsulfur coal-producing states such as Illinois").

Moreover, the

PSC has in no way regulated to make energy generated outside
SWMAAC a less viable and/or less competitive option for
distribution in Maryland.
Furthermore, the evidence does not support the claim that
the Generation Order will discriminatorily displace imported
power.

The Generation Order will add additional supply to the

wholesale energy marketplace, but whether or not any power is
displaced will depend upon demand and all the factors that play
into the market-based auction process administered by PJM.

If

demand for electric energy increases in proportion to the
capacity of a new facility, then the facility’s effect is
neutral.

Also, the generator called for in the Generation Order

would sell to PJM in the PJM Markets so that any displacement of
power will be the result of PJM's dispatch and procurement
models.

See Tr. Mar. 6 (AM) at 18:1-19:18, 22:5-10, (Massey).

Even absent the SWMAAC locational requirement, the procurement
of a new generation facility would have the same displacement
effects complained of by Plaintiffs because that facility would
141

still increase the available supply of electric energy and
capacity.
The Court does not find persuasive Plaintiffs' position
that the SWMAAC locational restriction discriminates against
interstate commerce because it requires economic activity to
take place in-state to the exclusion of out-of-state sources of
the same activity.

As discussed supra, the Generation Order

does not impose any hindrance on the ability of market
participants to buy and sell wholesale energy and related
products in the PJM region.

Therefore, the existence of a

facility in Maryland does not operate to the exclusion of
generation facilities outside of SWMAAC, which are still free to
supply electric energy to Maryland EDCs through the PJM Markets
or bilateral transactions.

The decisions relied upon by

Plaintiffs in support of their position are inapposite.

For

instance, in Tri-M Grp., LLC v. Sharp, the Third Circuit struck
down a residency requirement as facially discriminatory under
the dormant Commerce Clause because the regulatory scheme
required a contractor to set up and maintain a permanent office
location in the state to be eligible to pay lower apprentice
wage rates for work done on in-state public projects.
406, 412, 413 (3d Cir. 2011).

638 F.3d

The Third Circuit explained this

type of in-state presence requirement "forces out-of-state
contractors . . . to 'surrender whatever competitive advantages
142

they may possess' by burdening them with expenditures for a new
local operation, or with the payment of increased wages on their
contracts."

See id. at 427-28.

Here, the Generation Order does

not require any out-of-state competitor to establish a physical
presence in SWMAAC or Maryland to supply electric energy to
Maryland residents.74
Accordingly, the Court finds that the Plaintiffs have
failed to demonstrate that the Generation Order discriminates
against interstate commerce either facially, in its practical
effect, or in its purpose as a consequence of the SWMAAC
locational requirement in the RFP.

4.

Burden on Interstate Commerce

Plaintiffs contend that the Generation Order imposes a
significant burden on interstate commerce and that there is no
evidence in the record demonstrating that the Order was needed
to maintain reliability in Maryland.

Defendants maintain that

Plaintiffs have failed to meet their burden of demonstrating

74

The Generation Order also cannot be construed as an instate processing requirement of the kind considered to
discriminate against interstate commerce because it imposes no
requirement that Maryland EDCs purchase electric energy and/or
capacity from a generator located within SWMAAC. Cf. C & A
Carbone, Inc. v. Town of Clarkstown, N.Y., 511 U.S. 383, 386-87,
394 (1994) (finding that a local regulation had the practical
effect of discriminating against interstate commerce where it
only allowed a preferred local facility to provide commercial
service of processing waste within the town limits).
143

that the benefits of the Generation Order are clearly outweighed
by the burdens it imposes on interstate commerce.
State action that does not affirmatively discriminate
against interstate commerce may nonetheless violate the dormant
Commerce Clause if it places an undue burden on interstate
commerce.

See Yamaha Motor Corp., 401 F.3d at 567.

The Supreme

Court has noted:
[I]t must be borne in mind that the
Constitution when 'conferring upon Congress
the regulation of commerce, . . . never
intended
to
cut
the
States
off
from
legislating on all subjects relating to the
health, life, and safety of their citizens,
though the legislation might indirectly
affect the commerce of the country.'"
Huron Portland Cement Co. v. City of Detroit, Mich., 362 U.S.
440, 443-44 (1960) (alteration in original).
To determine whether state action burdens interstate
commerce in violation of the dormant Commerce Clause, courts
apply the Pike undue burden balancing test:
Where the statute regulates even-handedly to
effectuate
a
legitimate
local
public
interest, and its effects on interstate
commerce are only incidental, it will be
upheld unless the burden imposed on such
commerce is clearly excessive in relation to
the
putative
local
benefits.
If
a
legitimate local purpose is found, then the
question becomes one of degree.
And the
extent of the burden that will be tolerated
will of course depend on the nature of the
local interest involved, and on whether it
could be promoted as well with a lesser
impact on interstate activities.
144

Pike v. Bruce Church, Inc., 397 U.S. 137, 142 (1970) (internal
citation omitted).

The undue burden test is less scrutinizing

than the test for affirmatively discriminatory state actions.
See Yamaha Motor Corp., 401 F.3d at 567.
As discussed herein, Maryland has a legitimate interest in
ensuring that Maryland residents have available to them an
adequate and reliable supply of electric energy.

Presumably,75

Plaintiffs take the position that the SWMAAC locational
requirement constitutes an undue burden on interstate commerce.
The PSC regulated to finance indirectly the development and
operation of a generation facility within SWMAAC, which will
participate in the wholesale energy and capacity markets in the
PJM region like any other generation facility.

Other than

increasing the available supply of electric energy and capacity
in the PJM region by adding a new generation facility in SWMAAC,
the Generation Order does not affect the ability of other market
participants to sell energy and capacity in the PJM Markets.
The Court does not find evidence that the addition of a statesponsored market participant physically located within SWMAAC
imposes a burden, let alone an undue burden, on interstate
commerce.

75

Plaintiffs' position is not perfectly clear on this point.
145

Even if the Generation Order could be viewed as placing or
imposing some burden on interstate commerce, the burden would be
de minimis, and thus, not clearly excessive in relation to the
benefits to Maryland.

The soundness of the PSC's reasoning in

choosing to limit the RFP to generators physically located
within SWMAAC can, like the rationale for most regulatory
actions, be the subject of reasonable debate.

However, the

rationale reflected in the Generation Order and related
materials is not so irrational as to be outweighed by an
incidental burden on interstate commerce.
Accordingly, the Court finds that Plaintiffs have failed to
demonstrate that the Generation Order, as a consequence of the
SWMAAC locational requirement in the RFP, imposes an undue
burden on interstate commerce that is clearly excessive in
relation to the putative local benefits.

C.

Violation of 42 U.S.C. § 1983 (Count III)

In Count III, Plaintiffs claim that the PSC deprived them
of their federal statutory rights protected by 42 U.S.C. § 1983.
To the extent that Plaintiffs have not abandoned that claim, the
Court finds it meritless because the Fourth Circuit has "held
that the Supremacy Clause is not a source of substantive
individual rights that could support an action brought pursuant
to Section 1983." Md. Pest Control Ass'n v. Montgomery Cnty.,
146

Md., 884 F.2d 160, 162-63 (4th Cir. 1989) (per curiam).

IV.

CONCLUSION
For the reasons set forth herein, the Court decides that:
1. The Generation Order is violative of the
Supremacy Clause of the United States
Constitution.
2. The Generation Order is not violative of the
dormant Commerce Clause of the United States
Constitution.
3. Plaintiffs have not presented a viable claim
under 28 U.S.C. § 1983.

SO DECIDED, this Monday, September 30, 2013.

/s/__________
Marvin J. Garbis
United States District Judge

147

APPENDIX
TERM/ACRONYM
PSC
Order / Generation Order
EDCs
CfD

FPA
FERC
RTO
PJM region
PJM
LSE

RAA
BRA
RPM
RTEP
FRR
Uprate

TrAIL

EQR

DEFINITION
Maryland Public Service
Commission
Order No. 84815 issued by the
PSC on April 12, 2012
Electric Distribution Companies
Contract for Differences
entered into by CPV and the
Maryland EDCs pursuant to the
Generation Order
Federal Power Act
Federal Energy Regulatory
Commission
Regional Transmission
Organization
13 states and the District of
Columbia
PJM Interconnection, LLC
Load Serving Entity, an entity
that has state or local
authority to sell electric
energy to end-use customers
located within the PJM region
Reliability Assurance Agreement
Base Residual Auction
Reliability Price Model
Regional Transmission Expansion
Plan
Fixed Resource Requirement
Alternative
Action taken by an existing
generation facility to expand
its generation capacity
Trans-Allegheny Interstate
Line, a transmission line
constructed and placed into
service by PJM
Electronic Quarterly Report,
pursuant to a FERC requirement,
entities that have market-based
rate tariffs are required to
file on a quarterly basis a
report of all the transactions
and contracts entered into that
148

MOPR
PJM Tariff

are subject to the jurisdiction
of FERC. Tr. Mar. 7 (AM) at
114:16-115:8 (Knight).
Minimum Offer Price Rule
The Open Access Transmission
Tariff pursuant to which PJM
operates

149