UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Refinements to Policies and Procedures for MarketBased Rates for Wholesale Sales of Energy, Capacity
and Ancillary Services by Public Utilities
Docket No. RM14-14-000
COMMENTS OF THE
AMERICAN PUBLIC POWER ASSOCIATION AND
NATIONAL RURAL ELECTRIC COOPERATIVE ASSOCIATION
The American Public Power Association (“APPA”) and the National Rural
Electric Cooperative Association (“NRECA”) jointly submit these comments on the
Commission’s Notice of Proposed Rulemaking (“NOPR”) in this docket.1 APPA and
NRECA support the Commission’s continued re-examination of its market-based rate
program. APPA and NRECA members envisage wholesale electricity markets where the
presence of numerous power suppliers affords customers meaningful choices, prevents
sellers from exercising market power, and drives down prices to competitive levels.
Congress has mandated through the Federal Power Act (“FPA”) that public utility rates
for wholesale electricity sales be just and reasonable.2 In so doing, it has permitted
market-based rates only when the Commission has evidence that competition will prevent
the exercise of seller market power.
The NOPR proposes several worthwhile actions to clarify and streamline the
Commission’s policies and procedures for ensuring that public utility sellers will not be
1
Refinements to Policies and Procedures for Market-Based Rates for Wholesale Sales of Energy, Capacity
and Ancillary Services by Public Utilities, 79 Fed. Reg. 43,536 (July 25, 2014).
2
16 U.S.C. § 824d(a) (2012).
able to exercise market power. APPA and NRECA support these proposals, which are
described in Part II.A of these comments.
At the same time, however, the NOPR proposes other actions that would
weaken—and in some cases, unlawfully eliminate—the Commission’s ability to prevent
the exercise of market power by public utility sellers in wholesale electricity markets.
Therefore, in Parts II.B to F of these comments, APPA and NRECA:

Oppose eliminating indicative screens for sellers in regional transmission
organization or independent system operator (“RTO”) markets;

Caution that treating all long-term firm purchases and sales of capacity or energy
as the purchaser’s capacity in the indicative screens may not properly measure
seller market power;

Oppose using an annualized capacity factor to convert long-term firm energy
purchases and sales to capacity in the indicative screens; and

Oppose eliminating market-based rate sellers’ reporting of generation site
acquisitions.
I.
INTERESTS OF APPA AND NRECA
APPA is the national service organization representing the interests of not-forprofit, state, municipal and other locally owned electric utilities throughout the United
States. More than 2,000 public power systems provide over 15 percent of all kWh sales
to ultimate customers, and do business in every state except Hawaii. APPA utility
members’ primary goal is providing customers in the communities they serve with
reliable electric power and energy at the lowest reasonable cost, consistent with good
environmental stewardship. This orientation aligns the interests of APPA-member
2
electric utilities with the long-term interests of the residents and businesses in their
communities. Collectively, public power systems serve over 47 million people.
NRECA is the national service organization for more than 900 not-for-profit rural
electric cooperatives and public power districts providing retail electric service to more
than 42 million customers in 47 states. NRECA’s members include consumer-owned
local distribution systems and 65 generation and transmission (“G&T”) cooperatives that
supply wholesale power to their distribution cooperative owner-members. All or portions
of 2,500 of the nation’s 3,141 counties are served by rural electric cooperatives.
Collectively, cooperative service areas cover 75 percent of the United States landmass
and represent a significant segment of the energy industry. Cooperatives are incorporated
as private entities in states in which they reside and have legal obligations to provide
reliable electric service, at the lowest reasonable cost, to their customer members.
Many APPA and NRECA members obtain wholesale power supplies from
Commission-regulated public utilities under rate schedules and tariffs on file with the
Commission, including market-based rate tariffs. APPA and NRECA therefore have a
substantial interest in the rates charged by public utilities with market-based rate
authority.
Together, APPA and NRECA serve nearly 90 million electric customers in all 50
states. All of their respective members are publicly owned or not-for-profit load-serving
entities whose purpose is to provide reliable service at the lowest reasonable cost. Their
members participate in wholesale electricity markets throughout the Nation, and APPA
and NRECA have participated in all of the major Commission rulemakings and other
proceedings in recent years regarding the Commission’s market-based rate policies.
3
II.
A.
COMMENTS
Several of the NOPR’s Proposals Are Worthy Improvements and Should Be
Adopted
The NOPR proposes several worthwhile actions to clarify and streamline the
Commission’s policies and procedures for ensuring that public utility sellers will not be
able to exercise market power. The following proposals are straightforward and will
result in improvements to the Commission’s market based rate policies. Therefore,
APPA and NRECA support the NOPR’s proposals, as follows:
1. Requiring sellers to file the indicative screens in a workable, electronic
spreadsheet format (P 63);
2. Clarifying that sellers may perform simplified indicative screens assuming no
competing import capacity from first-tier markets (P 67);
3. Clarifying that sellers must report a change of status when they acquire 100
MW or more in any relevant geographic market, not just markets previously
studied (P 96);
4. Requiring sellers to include long-term firm purchases of capacity or energy in
change-in-status notices reporting net increases in the ownership or control of
generation capacity (P 100)—assuming the Commission also adopts the
NOPR’s proposal (PP 79–86) requiring sellers to report all long-term firm
purchases of capacity or energy in their indicative screens, which Part II.D of
these comments addresses below;
5. Clarifying that sellers reporting a change in status for a new affiliation must
include all new affiliates and assets in a revised asset appendix (P 106);
4
6. Requiring that any seller that has been granted a waiver of the requirement to
file an OATT for its facilities must cite the Commission order granting that
waiver in its list of transmission assets in the asset appendix (P 120);
7. Requiring the asset appendix to be filed in a workable, electronic spreadsheet
format that can be searched, sorted, and otherwise accessed (P 123);
8. Proposing that the Commission develop a comprehensive, searchable public
database of the information contained in the asset appendices that would
eventually replace the preformatted spreadsheets (P 126);
9. Requiring sellers to provide an organization chart in their market-based rate
initial filings, triennial updates, and change-in-status reports (PP 136–140);
10. Clarifying that any public utility seller’s exemptions from the Commission’s
accounting and cost-of-service requirements granted in orders accepting
market-based rate tariffs do not affect the seller’s obligations to comply with
such requirements under Commission-issued hydroelectric licenses (P 176);
and
11. Clarifying that an applicant for market-based rate authority must affirmatively
state, on behalf of itself and its affiliates, that they have not and will not erect
barriers to entry in the relevant markets (P 181).
B.
Eliminating the Indicative Screens in RTO Regions Would Be Unlawful and
Is Unjustified
The NOPR proposes a “streamlined approach” under which “RTO sellers would
not have to submit indicative screens as part of their horizontal market power analysis if
they rely on Commission-approved monitoring and mitigation to prevent the exercise of
5
market power.”3 Thus, for both their initial market-based rate applications and triennial
market-power studies, RTO sellers “would simply state they are relying on such
mitigation to address any market power they might have.”4 Indeed, the NOPR’s
proposed regulatory text can be read to prohibit RTO sellers from filing indicative
market-power screens and to mandate that they state their reliance on RTO mitigation:
In lieu of submitting the indicative screens, Sellers in regional
transmission organization and independent system operator markets with
Commission-approved market monitoring and mitigation must include a
statement that they are relying on such mitigation to address any potential
horizontal market power concerns.[5]
Public utilities filing change-in-status notices could rely on such statements of reliance on
RTO mitigation “even where [the filer] may have market power.”6
The only rationale the Commission offers for this proposal is that its practice has
been to allow public utilities to obtain and retain market-based rate authority in RTO
regions, even when they fail the indicative screens, on the theory that RTO monitoring
and mitigation is sufficient to mitigate any market power they may have.7 While the
Commission proposes to codify this case-by-case practice as a blanket rule, the NOPR
does not address the lawfulness of such a rule. Whatever the Commission’s practice has
been, the proposed rule departs from the procedure the Commission heretofore has
purported to rely on in defending the lawfulness of its market-based rate program in the
appellate courts. Indeed, the proposed rule plainly contravenes the Commission’s
statutory directive to establish just and reasonable rates.
3
NOPR, P 36.
4
Id.
5
Id., P 37 (quoting proposed 18 C.F.R. § 35.37(c) (6) (emphasis added).
6
Id., P 39.
7
Id., P 34.
6
1. Appellate Courts Have Sustained the Lawfulness of Market-Based Rates
Under the FPA by Requiring the Commission’s Ex Ante Examination of
Seller Market Power
Congress enacted Part II of the FPA in order “to curb the abusive practices of
public utility companies by bringing them under effective control, and to provide
effective federal regulation of the expanding business of transmitting and selling electric
power in interstate commerce.”8 Section 205(a) states that “[a]ll rates and charges made,
demanded, or received by any public utility” for the sale of electric energy subject to the
Commission’s jurisdiction “shall be just and reasonable, and any such rate that is not just
and reasonable is hereby declared to be unlawful.”9 When the Commission waives its
prior-notice and cost-of-service filing requirements and grants a public utility marketbased rate authority, it does so upon a prior showing that the public utility lacks, or has
adequately mitigated, any market power.10 The Commission also requires many public
utility sellers to file an updated market-power analysis every three years.11 A public
utility with a market-based rate tariff may then make sales at changing market rates
without the prior notice and filing of each new rate, but the Commission requires the
public utility to file quarterly reports of its transactions after the fact.12
8
Gulf States Utils. Co. v. FPC, 411 U.S. 747, 758 (1973).
9
16 U.S.C. § 824d(a) (2012).
10
18 C.F.R. § 35.37 (2014). See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and
Ancillary Services by Public Utilities, Order No. 697, 72 Fed. Reg. 39,904 (July 20, 2007), FERC Stats. &
Regs. ¶ 31,252 (2007), clarified, 72 Fed. Reg. 72,239 (Dec. 20, 2007), 121 FERC ¶ 61,260 (2007), order
on reh’g, Order No. 697-A, 73 Fed. Reg. 25,832 (May 7, 2008), FERC Stats. & Regs. ¶ 31,268 (2008),
clarified, 124 FERC ¶ 61,055 (2008), order on reh’g, Order No. 697-B, 73 Fed. Reg. 79,610 (Dec. 30,
2008), FERC Stats. & Regs. ¶ 31,285 (2008),order on reh’g, Order No. 697-C, 74 Fed. Reg. 30,924 (June
29, 2009), FERC Stats. & Regs. ¶ 31,291 (2009), corrected, 128 FERC ¶ 61,014 (2009), clarified, Order
No. 697-D, 75 Fed. Reg. 14,342 (Mar. 25, 2010), FERC Stats. & Regs. ¶ 31,305, clarified, 131 FERC
¶ 61,021 (2010), reh’g denied, 134 FERC ¶ 61,046 (2011), aff’d sub nom. Mont. Consumer Counsel v.
FERC, 659 F.3d 910 (9th Cir. 2011).
11
18 C.F.R. § 35.37(a)(1).
12
18 C.F.R. § 35.10b (2014).
7
In California ex rel. Lockyer v. FERC,13 the Ninth Circuit rejected a facial
challenge to the Commission’s authority under the FPA to allow market-based rate
tariffs. The court held that such tariffs were lawful because two conditions were met.
First, the tariffs were conditioned on the Commission’s ex ante examination and periodic
re-examination of a public utility’s market power—which the court erroneously thought
occurred every four months rather than every three years.14 Second, the tariffs were
“coupled with enforceable post-approval reporting that would enable FERC to determine
whether the rates were ‘just and reasonable’ and whether market forces were truly
determining the price.”15 The court distinguished the Commission’s scheme from the
market-rate regimes struck down by the Supreme Court in MCI Telecommunications
Corp. v. American Telephone & Telegraph Co.,16 and Maislin Industries, US, Inc. v.
Primary Steel, Inc.,17 because of these two requirements:
The agencies in MCI and Maislin relied on market forces alone in
approving market-based tariffs. In contrast, FERC’s system consists of a
finding that the applicant lacks market power (or has taken sufficient steps
to mitigate market power), coupled with strict reporting requirements to
ensure that the rate is “just and reasonable” and that markets are not
subject to manipulation. Here, FERC required the wholesale seller to file a
market analysis every four months, and quarterly reports summarizing its
transactions during the preceding three months. These transaction
summaries include both long and short-term contracts, purportedly with
reports of some sales for intervals as small as ten minutes. FERC has
affirmed in its presentation before us that it is not contending that approval
of a market-based tariff based on market forces alone would comply with
the FPA or the filed rate doctrine. Rather, the crucial difference between
13
383 F.3d 1006 (9th Cir. 2004).
Id. at 1013 (“Here, FERC required the wholesale seller to file a market analysis every four months …”).
The Supreme Court later relied on the Ninth Circuit’s mistaken description of the Commission’s marketbased rate tariff system, see Morgan Stanley v. Public Utility Dist. No. 1, 554 U.S. 527, 537–38 (2008),
although the Court did not address the lawfulness of that system, see id. at 538.
14
15
Id. at 1013, 1014.
16
512 U.S. 218 (1994).
17
497 U.S. 116 (1990).
8
MCI/Maislin and the present circumstances is the dual requirement of an
ex ante finding of the absence of market power and sufficient postapproval reporting requirements. Given this, FERC argues that its marketbased tariff does not run afoul of MCI or Maislin, and we agree.[18]
Although the court found the Commission’s scheme to be lawful in concept, it held that
the Commission “failed to administer the tariffs in accordance with their terms and
abused its discretion in limiting available remedies for regulatory violations.”19 The
problem was the inadequacy of the reporting of actual charges, which the court found
essential to the lawfulness of the market-based rate tariffs:
Here, because the reporting requirements were an integral part of a
market-based tariff that could pass legal muster, FERC cannot dismiss the
requirements as mere punctilio. If the ability to monitor the market, or
gauge the “just and reasonable” nature of the rates is eliminated, then
effective federal regulation is removed altogether.[20]
The problem with the instant NOPR is that it would eliminate the other “integral
part” of a lawful market-based rate tariff—the Commission’s prior and periodic reexamination of the public utility seller’s market power. This requirement, too, cannot be
dismissed as a mere punctilio. Indeed, when the Ninth Circuit later upheld Order No.
697, it relied on the Lockyer analysis and emphasized that “FERC has adopted a rigorous
screening process to detect market power.”21 The NOPR, however, would eliminate that
screening within RTO regions.
The D.C. Circuit similarly has “required that, before FERC approves an
individual seller’s use of market-based pricing in lieu of cost-of-service regulation, it
must determine that ‘the seller and its affiliates do not have, or adequately have
18
383 F.3d at 1013.
19
Id.
20
Id. at 1015.
21
Mont. Consumer Counsel v. FERC, 659 F.3d at 917.
9
mitigated, market power in the generation and transmission of [electric] energy, and
cannot erect other barriers to entry by potential competitors.’”22 In Blumenthal v. FERC,
the D.C. Circuit held that the Commission could lawfully rely on its prior determination
that an individual seller lacked or had mitigated its market power, coupled with the
RTO’s post-transaction reporting, but an RTO assessment of the competitiveness of its
markets was not required: “In other words, what matters is whether an individual seller is
able to exercise anticompetitive market power, not whether the market as a whole is
structurally competitive.”23 The NOPR, however, would eliminate the Commission’s
analysis of seller market power in RTO regions in favor of relying on mitigation
measures under the various RTO tariffs.
The NOPR thus proposes a fundamental departure from the market-based rate
scheme that the courts have previously upheld. This departure would undercut the
lawfulness of public utility sellers’ market-based rate tariffs in RTO regions. Yet the
NOPR provides no legal or factual analysis showing that “RTO mitigation” standing
alone is legally sufficient to allow market-based pricing. The NOPR does not address the
specific mitigation measures of the RTO tariffs where the Commission’s proposal would
be effective. The NOPR’s general statement that RTO market monitoring and mitigation
has been “Commission-approved” does not constitute reasoned decision-making. In any
event, the Commission approved RTO mitigation as an addition to—not a substitute
for—the Order No. 697 requirement that sellers pass the indicative screens or otherwise
22
Blumenthal v. FERC, 552 F.3d 875, 882 (D.C. Cir. 2009) (quoting La. Energy & Power Auth. v. FERC,
141 F.3d 364, 365 (D.C. Cir. 1998) (alteration original)). Accord, Mont. Consumer Counsel v. FERC, 659
F.3d at 916–17.
23
Blumenthal, 552 F.3d at 882.
10
demonstrate that they lack or have mitigated their market power.24 No appellate court
precedent supports the lawfulness of market-based rates where the only check on seller
market power is RTO mitigation and the Order No. 697 requirements are eliminated. In
short, the NOPR does not provide a sufficient legal basis for the Commission’s proposal.
The proposal should be withdrawn.25
2. The Proposed Rule Would Effectively Deregulate Public Utilities’ Bilateral
Sales in RTO Regions
The proposed rule has a second legal infirmity that precludes its adoption in its
present form. The market-based rate tariffs of public utility sellers in RTO regions
authorize sales of energy, capacity, and ancillary services in bilateral markets within
RTOs’ footprints as well as the RTO-administered markets and auctions. The proposed
rule would apply to “RTO sellers,” not to RTO sales. “RTO sellers are sellers that study
an RTO as a relevant geographic market, including those that sell bilaterally.”26 The
proposed rule would authorize public utilities in RTO regions to sell in bilateral markets
within RTOs’ footprints without filing any market-power analysis and without any
Commission finding as to their market power. The Commission acknowledges that these
bilateral sales are not subject to RTO monitoring and mitigation.27
Order No. 697 at P 290 (“We believe that a single market with Commission-approved market monitoring
and mitigation and transparent prices provided added protection against a seller’s ability to exercise market
power but cannot replace the generation market power analysis.”). See also Order No. 697-A at PP 109–
110 (same).
24
25
In any event, given the absence of any legal and factual support for this proposal in the NOPR, the
Commission should not issue a final rule adopting the proposal without first providing a supplemental
notice and opportunity for comments.
26
NOPR, P 34.
27
Id., P 35.
11
Thus, for bilateral sales in RTO regions, the NOPR would eliminate the
Commission’s screening for seller market power required under Order No. 697 and
replace it with a non sequitur: the RTO seller’s statement that it is “relying on such
[RTO] mitigation to address any potential horizontal market power concerns,” 28 even
though its bilateral sales are not subject to RTO mitigation.
The NOPR’s only defense is to hypothesize that an RTO market’s very existence
“generally results in a market where prices are transparent,” and this “disciplines forward
and bilateral markets by revealing a benchmark price” and “provides a strong incentive
for the seller to offer at a competitive price in the forward and bilateral markets.”29 Yet
the NOPR does not state—much less demonstrate—that this supposed indirect incentive
will ensure that the resulting rates for bilateral sales are just and reasonable.
The proposed rule would rely on these market forces alone to prevent the exercise
of seller horizontal market power in bilateral sales in RTO regions. To this extent, the
NOPR is plainly unlawful under Supreme Court and circuit court precedent. Given the
anticompetitive conditions that led to the enactment of Part II of the FPA,30 “Congress
could not have assumed that ‘just and reasonable’ rates could conclusively be determined
by reference to market price.”31 As the D.C. Circuit has noted, “both we and the Ninth
Circuit have held that FERC violates its oversight duty when it imposes no reporting
28
See NOPR, P 37.
29
See id., P 35.
30
See Gulf States Utils., 411 U.S. at 758.
31
FPC v. Texaco, 417 U.S. 380, 399 (1974).
12
requirements on generators and instead resorts to ‘largely undocumented reliance on
market forces as the principal means of rate regulation.’”32
The NOPR’s claim that RTO markets will discipline market power in bilateral
markets is unsubstantiated and illogical. It assumes that buyers can purchase in RTO
markets when prices in bilateral markets are higher. But the NOPR elsewhere states that
spot-market purchases are not a substitute for long-term bilateral contracts.33
Recognizing this, the Commission’s Order No. 719 requires RTOs to dedicate a portion
of their websites for market participants to post offers to buy or sell power on a long-term
basis (one year or more), with the goal of promoting use of long-term bilateral contracts
not available in RTO markets.34 In particular, purchases from RTO-run capacity auctions
are not a substitute for self-supply arrangements and long-term bilateral capacity
purchases to meet the individual needs of load-serving entities, as APPA and NRECA
have argued elsewhere.35 Indeed, Chairman LaFleur has recently noted that RTO
markets were not designed to achieve goals such as fuel diversity or environmental
32
Blumenthal v. FERC, 552 F.3d at 882–83 (quoting Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d
1486, 1508 (D.C.Cir.1984) (footnote omitted) and citing Pub. Util. Dist. No. 1 v. FERC, 471 F.3d 1053,
1082 (9th Cir.2006) (holding that FERC could not defer to bilateral energy contract without adopting any
monitoring mechanism), aff'd sub nom. Morgan Stanley v. Pub. Util. Dist. No. 1, 554 U.S. 527 (2008)).
33
NOPR, P 76.
34
18 C.F.R. § 35.28(g)(2) (2014). See Wholesale Competition in Regions with Organized Electric Markets,
Order No. 719, 73 Fed. Reg. 64,100 (Oct. 28, 2008), order on reh’g, Order No. 719-A, 74 Fed. Reg. 37,776
(July 29, 2009), order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 (2009).
35
See Initial Brief of APPA and NRECA on Minimum Offer Price Rule Issues, Midwest Indep.
Transmission Sys. Operator, Inc., Docket No. ER11-4081-001 (Oct. 11, 2013); Post-Technical Conference
Comments of APPA, Centralized Capacity Markets in Regional Transmission Organizations and
Independent System Operators, Docket No. AD13-7-000 (Jan. 8, 2014); Post-Technical Conference
Comments of the National Rural Electric Cooperative Association, Centralized Capacity Markets in
Regional Transmission Organizations and Independent System Operators, Docket No. AD13-7-000 (Jan. 8,
2014).
13
goals.36 RTO markets and capacity auctions will not discipline prices in markets for nonsubstitutable products.
The NOPR’s legal and factual rationale for effectively deregulating bilateral sales
in RTO regions is wanting. For this reason, too, the proposed rule should be withdrawn.
3. The Proposed Rule Would Unlawfully Subdelegate the Commission’s
Statutory Responsibilities to Private Entities
The third legal deficiency of the proposed rule is its assumption that the
Commission can rely on RTO mitigation to substitute for Commission screening of seller
market power. By dispensing with the indicative screens, the NOPR would have the
Commission—no less than the “RTO sellers” submitting the statement—“relying on such
mitigation to address any potential horizontal market power concerns.”37
However, the existing RTOs and ISOs are not public agencies or regulators; they
are private, regulated public utilities under the FPA.38 Although the Commission requires
that RTOs provide for the monitoring of markets that the RTO operates or administers,39
RTO market monitoring units are private entities—RTO employees or independent
contractors—not de facto extensions of the Commission’s staff.40
In section 205 of the FPA, Congress delegated to the Commission the
responsibility to ensure that all wholesale electric rates of public utilities are just and
36
LaFleur highlights states’ role in market evolution, Megawatt Daily, May 1, 2014, at 21-22.
37
NOPR P 37 (quoting proposed 18 C.F.R. § 35.37(c)(6)).
38
See Cal. Indep. System Operator v. FERC, 372 F.3d 395 (D.C. Cir. 2004) (Commission lacks authority to
order ISO public utility to replace its board of directors); Pennsylvania-New Jersey-Maryland
Interconnection, 103 FERC ¶ 61,170, at PP 16–21 (2003) (explaining why PJM is a public utility).
39
18 C.F.R. § 35.34(k)(6) (2014).
40
See Elec. Power Supply Ass’n v. FERC, 391 F.3d 1255, 1265 (D.C. Cir. 2004).
14
reasonable. This is the only statutory standard for the lawfulness of wholesale rates.41
This Commission (subject to judicial review) is the only body that can apply and enforce
this statutory standard.42 The Commission cannot subdelegate this core statutory duty to
the regulated public utility itself—no matter how independent from other market
participants the Commission may require that public utility to be, and no matter how
expert or disinterested the public utility’s staff and contractors may be.
In U.S. Telecom Association v. FCC,43 the D.C. Circuit remanded an FCC order
delegating to state commissions certain functions regarding the unbundling of rates of
competing telecommunications companies. The court held that the FCC could not
subdelegate its statutory responsibilities to an outside party, whether public or private:
When a statute delegates authority to a federal officer or agency,
subdelegation to a subordinate federal officer or agency is presumptively
permissible absent affirmative evidence of a contrary congressional intent.
But the cases recognize an important distinction between subdelegation to
a subordinate and subdelegation to an outside party. The presumption that
subdelegations are valid absent a showing of contrary congressional intent
applies only to the former. There is no such presumption covering
subdelegations to outside parties. Indeed, if anything, the case law
strongly suggests that subdelegations to outside parties are assumed to be
improper absent an affirmative showing of congressional authorization.
…
We therefore hold that, while federal agency officials may subdelegate
their decision-making authority to subordinates absent evidence of
contrary congressional intent, they may not subdelegate to outside
entities—private or sovereign—absent affirmative evidence of authority to
do so.[44]
41
Morgan Stanley Capital Group v. Pub. Util. Dist. No. 1, 554 U.S. at 545.
42
Montana-Dakota Co. v. Pub. Serv. Co., 341 U.S. 246, 251 (1951).
43
359 F.3d 554 (D.C. Cir. 2004).
44
359 F.3d at 565, 566 (citations omitted).
15
The NOPR identifies no basis under the FPA to delegate its responsibilities to ensure just
and reasonable rates under section 205 of the FPA to the public utilities Congress charged
it to regulate.
C.
Eliminating the Indicative Screens in RTO Regions in Favor of RTO
Mitigation is Unreasonable and Unjustified—Especially Given the Current
Upheaval in Wholesale Electricity Markets
The appellate courts’ requirement of prior Commission findings regarding seller
market power is supported by basic economic theory: In a competitive market where
sellers are prevented from exercising market power, competitive pressure will hold down
prices to marginal cost, which satisfies the statutory requirement of just and reasonable
rates.45 No comparable economic theory supports relying on RTO mitigation of sellers’
horizontal market power. The Commission has encouraged the formation of RTOs to
address vertical market power in wholesale electricity markets.46 The Commission’s
regulations require RTOs to provide for market monitoring of the markets they
administer or operate to ensure that specific objective is met—that transmission service is
“reliable, efficient, and not unduly discriminatory.”47 As noted above, the adequacy of
RTO mitigation of horizontal market power in wholesale electricity markets is a fact-
45
See, e.g., Mont. Consumer Counsel v. FERC, 659 F.3d at 916; Blumenthal v. FERC, 552 F.3d at 882; La.
Energy & Power Auth. v. FERC, 141 F.3d at 365; Tejas Power Co. v. FERC, 908 F.2d 998, 1004 (D.C. Cir.
1990).
46
See Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 (Jan. 6, 2000), FERC Stats.
& Regs. ¶ 31,089 (1999), order on reh’g, Order No. 2000-A, 65 Fed. Reg. 12,088 (Mar. 8, 2000), FERC
Stats. & Regs. ¶ 31,092 (2000), aff’d sub nom., Pub. Util. Dist. No. 1 v. FERC, 272 F.3d 607 (D.C. Cir.
2001); See also Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1364 (D.C. Cir. 2004).
The Commission’s regulations require RTOs to provide the “objective monitoring of markets it operates
or administers” for a specific purpose: “To ensure that the [RTO] provides reliable, efficient and not unduly
discriminatory transmission service ….” 18 C.F.R. § 35.34(k)(6). Thus, while the monitoring requirement
includes assessing the effect of bilateral markets on the RTO and the effect of the RTO on bilateral
markets, see id. § 35.34(k)(6)(ii), it does not include assessing whether rates in bilateral power markets are
just and reasonable because of seller horizontal marker power.
47
16
bound matter. An administrative decision to rely on RTO mitigation of public utility
sellers’ horizontal market power—even if legally permissible—requires evidence,
analysis, and findings of fact and law regarding specific RTO tariffs and markets. But
the NOPR provides no such evidence, analysis, or findings.
In Order No. 697 and 697-A, the Commission declined to take this step and
determined to keep the requirements for indicative screens for sellers in RTO regions. 48
The NOPR provides no basis for concluding that intervening events have provided a
reason for the Commission to reverse course now.
Indeed, more recent experience suggests that RTO mitigation has not been
adequate to prevent the exercise of individual seller market power. In February 2010, the
U.S. Department of Justice filed a civil complaint alleging that Keyspan Corporation had
unlawfully restrained trade in the New York ISO capacity market, and Keyspan entered
into a stipulation to settle the case. Under the consent decree, Keyspan agreed to pay a
$12 million civil penalty.49 The Justice Department also settled a civil suit with Morgan
Stanley arising from the same facts; there, the consent decree required Morgan Stanley to
disgorge $4.8 million of revenues earned under the disputed transaction.50 In neither
instance did the ISO take any mitigation action.51
The inadequacy of RTO mitigation was most recently highlighted when the
Commission, deadlocked 2–2, took no action on protests of the most recent (the eighth)
48
See Order No. 697 at P 290; Order No. 697-A at PP 109–110.
49
United States v. Keyspan Corp., 10 CIV 1415 (WHP) (S.D.N.Y. Feb. 2, 2011) (Memorandum and Order)
(available at http://www.justice.gov/atr/cases/f266700/266778.htm.)
50
United States v. Morgan Stanley, 11 CIV 6875 (WHP) (S.D.N.Y. Aug. 7, 2012) (Memorandum and
Order) (available at http://www.justice.gov/atr/cases/f285700/285797.pdf).
51
For its part, the Commission found no violation of its market-manipulation rules. See FERC Enforcement
Staff Report, “Findings of a Non-Public Investigation of Potential Market Manipulation by Suppliers in the
New York Capacity Market,” Docket Nos. IN08-2-000 & EL07-39-000 (February 28, 2008).
17
forward capacity auction in ISO New England,52 but issued an Order To Show Cause
directing the ISO to show cause why it should not revise its tariff to provide for review
and mitigation of importers’ offers into the ISO’s forward capacity market.53 The
Commission’s order is directed at prospective changes to the ISO tariff and will not affect
the results of the ISO’s eighth forward capacity auction. That order also demonstrates the
inadequacy of the relief available under the ISO’s tariff. The ISO found that there was
insufficient competition system-wide in this auction,54 and that in such situations, some
suppliers “are likely to recognize that they can be pivotal and set the auction price.”55
Yet the ISO concluded that the auction results were consistent with its tariff, and it stated
that under that tariff, neither the ISO nor its independent market monitor reviewed the
merits of the generator’s eleventh-hour “Non-Price Retirement Request” that caused the
increase in the auction-clearing price.56 The joint statement issued by Commissioners
Clark and Bay explains well the potential market-power problems that the Commission’s
inaction has left unexamined and unremedied.57 The lessons of this episode are clear:
RTO tariffs cannot be relied on to mitigate market power; independent monitoring and
enforcement of public utilities’ market-based rate tariffs by the Commission is necessary.
52
See Notice of Filing Taking Effect by Operation of Law, ISO New England, Inc., Docket No. ER141409-000 (Sept. 16, 2014). (auction-results filing). See also Letter of Raymond W. Hepper to Kimberly D.
Bose, ISO New England, Inc., Docket No. ER14-1409-000 (July 17, 2014) (public version) (ISO-NE Letter
of July 17).
53
ISO New England, Inc., 148 FERC ¶ 61,201 (Sept. 16, 2014).
54
Order To Show Cause, P 4.
55
Id., P 5.
56
Id., PP 6-8.
Joint Statement of Commissioner Tony Clark and Commissioner Norman Bay on ISO New England’s
Forward Capacity Market Case, Docket No. ER14-1409-000 (Sept. 16, 2014) (available at
http://elibrary.ferc.gov/idmws/search/intermediate.asp?link_file=yes&doclist=14251982).
57
18
Moreover, in the RTO energy markets, RTO mitigation is practically nonexistent. The Commission staff’s recent report on “Common Metrics” reveals that RTO
mitigation occurs in about 1% of unit hours in most RTOs.58
Eliminating the Commission’s indicative screens for seller market power in RTO
regions is an especially bad idea now. Several factors are causing a profound upheaval in
wholesale electricity markets. The shale gas revolution and new and looming
environmental regulations—including the EPA’s Mercury and Air Toxics Standards and
its proposed Clean Power Plan—are causing the retirement of coal generation and the
building of new gas-fired generation. A new report from Sanford C. Bernstein & Co.
projects that by the end of the decade a “sea change” in the resource mix could occur,
with utilities reducing their burning of coal by 25% and increasing their consumption of
natural gas by 20%.59 These environmental rules, together with state renewable portfolio
standards and technological change, are also leading to rapid growth in renewable energy
sources. Chairman LaFleur has recently stated that “the nation is making substantial
changes in its power supply due to the increased availability of domestic natural gas and
its use for power generation, the growth of renewable and demand-side resources, and
new environmental requirements”60 and that the Commission “must be aware of, and
adapt to, these developments in order to carry out our responsibilities to promote
reliability and ensure just and reasonable rates for customers.”61 These impending
changes in the Nation’s generation mix, including its ownership, location, and diversity
58
Common Metrics, Commission Staff Report, Docket No. AD14-15-000, at 58 (Aug. 26, 2014).
59
SNL Financial, Bernstein projects ‘sea change’ as coal falls and gas, renewables grow (Sept. 8, 2014).
60
Written Testimony of Cheryl A. LaFleur, Senate Committee on Energy & Natural Resources 2 (May 20,
2014) (available at http://www.ferc.gov/CalendarFiles/20140520114322-LaFleurTestimony.pdf).
61
Written Testimony of Cheryl A. LaFleur, House Committee on Energy & Commerce 1 (July 29, 2014)
(available at http://www.ferc.gov/CalendarFiles/20140729091732-LaFleur-07-29-2014.pdf).
19
of fuel supply may have profound consequences for seller horizontal market power in
wholesale electricity sales in RTO regions. Present circumstances call for even greater
Commission vigilance over market-power issues, not a retreat.
Proposed changes in RTO markets also point to the need for greater Commission
oversight. The discussion at the Commission’s workshop in Docket AD14-14-000 on
uplift issues on September 8, 2014, suggests that RTOs are considering whether to
change their tariffs to incorporate uplift costs in higher energy prices. For example, PJM
has implemented closed-loop interfaces that create load pockets for the purpose of
allowing certain resources that would otherwise be compensated under uplift to set the
clearing price.62 In addition, PJM is developing a proposal for a new “Capacity
Performance Product” that would be available at all times when called upon and would
clear at a separate and higher price than would other capacity.63 Stakeholder comments
on the draft proposal have expressed concerns about its potential to create new
opportunities for the exercise of market power by generation owners, including
withholding capacity from the new product market.64 These tariff changes present new
issues of horizontal market power and again counsel greater Commission vigilance over
market power in RTO regions, not leaving it to RTO mitigation.
Finally, a number of large utility mergers have now been proposed in recent
months, signaling further changes in the structure of wholesale electricity markets. In
62
See F. Stuart Bresler, III, Energy and Ancillary Services Uplift in PJM, FERC Docket No. AD14-14-000
(Sept. 8, 2014) (available at http://www.ferc.gov/CalendarFiles/20140905085408PJM%20%20Whitepaper.pdf).
63
See PJM Capacity Performance Proposal (Aug. 20, 2014) (available at
http://www.pjm.com/~/media/committees-groups/committees/elc/20140822/20140822-pjm-capacityperformance-proposal.ashx).
64
See, e.g., comments of American Municipal Power, Inc.; PJM Industrial Customer Coalition; PJM Public
Power Coalition; and New Jersey Board of Public Utilities (available at http://www.pjm.com/committeesand-groups/committees/elc/stakeholder-comments.aspx)
20
April 2014, Exelon Corporation announced it has agreed to merge with Pepco Holdings,
Inc. The merger is before the Commission in Docket No. EC14-96-000. Following up
on an announcement made in August, Dynegy Inc. filed applications with the
Commission on September 11, 2014, for approval of its concurrent plans to purchase
EquiPower Resources Corp. and Brayton Point Holdings LLC from Energy Capital
Partners LLC (Docket No. EC14-140-000) and to acquire ownership interests in certain
Midwest generation assets from Duke Energy Corp. (Docket No. EC14-141-000).
Dynegy has stated that the 12,500 MW of coal and gas generation it will acquire from
Duke and ECP will almost double its existing portfolio to nearly 26,000 MW. Apart
from outright utility mergers, hardly a day passes without an announcement that specific
generation assets are changing hands.
For these reasons, even if the Commission could legally do so, it is a poor time for
the Commission to drop the requirement of indicative screens in RTO regions and rely on
RTO mitigation to address all horizontal market-power issues.
D.
Treating All Long-Term Firm Purchases of Capacity and Energy as
Purchaser-Controlled Capacity May Produce More Consistent Market
Screen Filings, but it May Not Lead to Better Assessment of Seller Market
Power
The Commission’s indicative screens use “uncommitted capacity” to measure the
seller’s market shares and to perform the pivotal-supplier screen. The Commission
defines uncommitted capacity as capacity that is “owned or controlled through contract
and firm purchases, less operating reserves, native load commitments and long-term firm
sales.”65 Under Order No. 697, the Commission’s policy is that a public utility
65
Order No. 697 at P 38. See NOPR, P 73.
21
submitting an indicative screen should include purchased capacity as the submitting
utility’s capacity if the purchase contract confers operational control of the capacity to the
submitting utility.66 This policy aligns the indicative screens with the definition of
uncommitted capacity.
The NOPR states that this approach “may create errors or misleading results.”67
The buyer and the seller may not treat the capacity sale consistently, and if neither of
them counts the capacity as under its control, the capacity “disappears” from the
market.68 Franchised public utilities that rely on purchased capacity sometimes report
“negative market shares” under the indicative screen.69 The NOPR’s proposed solution is
to:
. . . require applicants under the market-based rate program to report all of
their long-term firm purchases of capacity and/or energy in their indicative
screens and asset appendices, where the purchaser has an associated longterm firm transmission reservation, regardless of whether the seller has
operational control over the generation capacity supplying the purchased
power.[70]
This would be only the “default approach,” however, since a public utility could provide
evidence that a long-term purchase should not be attributed to it.71
The NOPR cites four advantages of the proposal. First, “it will size the market
correctly” and “eliminate unrealistic results (e.g., negative market shares)….”72 Second,
it “will establish consistent treatment of long-term firm sales and long-term firm
66
Order No. 697, PP 157, 174. See NOPR, PP 73-74, 84 & n.102.
67
NOPR, P 75.
68
Id., PP 75, 83.
69
Id., P 75.
70
Id., P 79.
71
Id.
72
Id., P 81.
22
purchases in the indicative screens.”73 Third, it will “ensure consistent treatment of
owned or installed capacity and long-term firm purchases in the indicative screens.”74
Fourth, it will “help to ensure consistency between the SIL values reported in the screens
and the Commission’s accepted SIL values for the relevant market or balancing authority
area.”75
The proposal would eliminate the problem of disappearing capacity and
incorrectly sized markets by using an unambiguous default rule to assign control of
purchased firm capacity to the purchaser. This would produce more consistency in the
indicative screens filed by the buyers and sellers of long-term capacity and energy.
For the same reason, the proposal would also achieve the third cited advantage:
treating long-term firm purchases consistently with owned or installed capacity. That
begs the question of whether they should be treated alike. The NOPR would not change
the definition of uncommitted capacity, which requires ownership or control of the
capacity. Instead, the NOPR would assign all long-term sales to the buyer even if the
seller retains operational control under the terms of the contract.76 So the indicative
screens would no longer necessarily be measuring the seller’s uncommitted capacity
under the Commission’s own definition. The question is how often the resulting screens
would be wrong, and by how much.
The Commission claims that its experience suggests that attributing long-term
firm purchases to the buyer in all cases is a reasonable presumption because the contracts
73
Id., P 82.
74
Id., P 84.
75
Id., P 85.
76
Id., P 79.
23
are firm—i.e., uninterruptible for economic reasons—and because sellers must have
capacity to support firm energy sales.77 The relationship of these factors to the issue of
economic control of the generating assets is unclear, however.
If the Commission’s presumption is unwarranted, the proposal would mask the
market shares or pivotal-supplier status of sellers who retain operational control of the
generation they use to make long-term firm sales to utilities. The proposal would treat
any firm sale of capacity or energy for more than one year as if it were a permanent—
tantamount to an asset sale. Yet such sales may not change the market structure,
especially for capacity.
It is not clear, for instance, that a franchised public utility that must purchase firm
energy or capacity to meet its service obligations should be attributed control of the
purchased capacity for purposes of assessing the market shares or pivotal-supplier status
of the selling utility. That a utility has “negative” uncommitted capacity simply means it
is net short. Adding back its long-term firm purchase may simply artificially depress the
market share of the seller utility or mask its status as a pivotal supplier in the relevant
market.
Thus, the proposal may fix some administrative problems in processing
indicative-screen filings, but it is not clear that the resulting indicative screens will
accurately reflect actual market shares or pivotal-supplier conditions. If adopted, the
proposal deserves continued monitoring against other measures of market power and
market performance.
77
Id., P 77.
24
E.
The Proposed Annualized Capacity Factor Conversion of Purchased Firm
Energy to Capacity is Unreasonable
The NOPR states that in the case of a long-term firm energy purchase, “the
purchaser must convert the amount of energy to which it is entitled into an amount of
generation capacity for purposes of its indicative screens and asset appendices …,” and
“[t]he seller under that power purchase agreement must do the same the next time it
submits a market-based rate triennial or change of status filing with the Commission, i.e.,
convert the energy into capacity ….”78 Both the buyer and seller must show how they
made the energy-to-capacity conversion.79
In footnote 98, the NOPR states that if the power purchase agreement does not
specify the capacity commitment, the conversion should use the following conversion
formula (for a one-year purchase):
[energy (MWh)/8,760]/capacity factor = capacity (MW),
where

energy (MWh) is the total amount of energy purchased over the
calendar year,

8,760 is the number of hours in the calendar year (8,764 in a leap
year), and

capacity factor is the “actual capacity factor achieved by the unit(s)
supplying the energy over the calendar year and is a measure of a
generating unit’s actual output over a specified period of time
compared to its potential or maximum output over that same
period.[80]
This proposed conversion mechanism has both theoretical and practical problems.
First, and most important, the formula calculates capacity as an average annual number,
78
NOPR, P 79.
79
Id.
80
Id., P 79 n.98.
25
whereas the peak capacity purchased during a shorter interval (usually one hour) in the
study period would be the more relevant number. An annual average will in almost all
cases be smaller than the capacity used to make the firm energy sale.
Second, the buyer may not have the capacity-factor information required for the
formula’s denominator, and yet the proposal suggests the buyer must make the
conversion in its filings before the seller must do so. This procedure may lead to
inconsistent capacity calculations by the buyer and seller, frustrating the purpose of the
main proposal regarding the treatment of long-term firm purchases. The seller, not the
buyer, should be required to file this information first.
Third, the capacity-factor calculation should not be performed with “calendar
year” data as footnote 98 states. The NOPR specifies a study period of December 1 to
November 30 for the market-power study. The capacity-factor calculation should use
data from the long-term firm energy purchase occurring during the study period.
F.
Ending the Reporting of Generation Site Acquisitions Is Unreasonable at
This Time
The Commission currently requires sellers with market-based rate tariffs to file
notices of change of status on a quarterly basis when they acquire sites for new
generation capacity development.81 The NOPR proposes to eliminate this requirement.82
The Commission’s rationale is that “[i]n the more than six years since issuance of Order
No. 697, intervenors have not challenged whether sites for new generation capacity
development created a barrier to entry.”83
81
18 C.F.R. § 35.42(d) (2014).
82
NOPR, P 89.
83
Id., P 90.
26
This proposal is unjustified, particularly now. The fact that intervenors have not
devoted the resources required to litigate the issue in the past is not a reason for the
Commission to ignore it in the future. The Commission’s approach should be forwardlooking, not backward-looking. There are important reasons why generation-site
acquisitions may create barriers to entry in the future.
As already outlined, a number of economic, technological, and regulatory factors
are combining to induce the retirement of substantial coal generation and the construction
of substantial new gas-fired and renewable generation in the coming years—the shale-gas
revolution; environmental regulations; renewable portfolio standards; and decreases in
the cost of renewable energy sources. As Chairman LaFleur has noted, the nation is
going through a significant change in energy supply.84
Where this new generation will be located will be an important issue. A
component of the new generation will be location-constrained renewable resources (wind
and solar). Because of constraints on gas pipeline capacity, the location of gas-fired
generation sites relative to existing and proposed gas pipelines is also critical. The
retirement of coal generation can change the economic and reliability factors that will
determine where new generation may be located. Because the location of the new
generation build-out may have important economic consequences, this is the wrong time
to ignore barriers to entry created by the acquisition of new generation sites.
84
See supra n.60.
27
III.
CONCLUSION
APPA and NRECA urge the Commission to (1) adopt the proposals in the NOPR
outlined in Part I.A above; (2) withdraw the proposal eliminating the indicative screens
in RTO regions for the reasons in Parts I.B and C; (3) monitor compliance with the
proposed treatment of long-term firm purchases and reassess its effects as recommended
in Part I.D; (4) modify the proposed capacity calculation as described in Part I.E; and
(5) withdraw the proposal eliminating the reporting of generation site acquisitions as
outlined in Part I.F above.
Respectfully submitted,
s/ Randolph Elliott
Delia D. Patterson
General Counsel
Randolph Elliott
Regulatory Counsel
American Public Power Association
2451 Crystal Drive, Suite 1000
Arlington, VA 22202
202-467-2900
dpatterson@publicpower.org
relliott@publicpower.org
s/ Paul M. Breakman
Paul M. Breakman
Associate Director –Regulatory Counsel
Pamela M. Silberstein
Associate Director – Power Supply
National Rural Electric Cooperative
Association
4301 Wilson Boulevard, Floor 11
Arlington, VA 22203
703-907-5844
Paul.Breakman@nreca.coop
Pamela.Silberstein@nreca.coop
September 23, 2014
28