UNITED STATES OF AMERICA
BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

Grid Reliability and Resilience Pricing)Docket No. RM18-1-000

COMMENTS OF THE ISO/RTO COUNCIL

The ISO/RTO Council (“IRC”)1 respectfully submits these comments in response
to the Federal Energy Regulatory Commission’s (“Commission” or “FERC”) October 2,
2017 Notice Inviting Comments, 2 the September 28, 2017 Notice of Proposed

Rulemaking by the United States Department of Energy (“DOE”),3 and Commission’s
Office of Energy Policy and Innovation’s (“OEPI”) October 4, 2017 request for

information.4 The IRC and its members support the Commission’s goals of promoting
competitive markets, facilitating appropriate price formation in those markets, and
fostering a reliable electric system. However, the proposal set forth in the NOPR is far-
reaching and would degrade the efficiency and effectiveness of existing organized

The IRC is composed of the Alberta Electric System Operator (“AESO”), the
California Independent System Operator Corporation (“CAISO”), the Electric
Reliability Council of Texas, Inc. (“ERCOT”), the Independent Electricity System
Operator (“IESO”), ISO New England Inc. (“ISO-NE”), the Midcontinent
Independent System Operator, Inc. (“MISO”), the New York Independent System
Operator, Inc. (“NYISO”), PJM Interconnection, L.L.C. (“PJM”), and the
Southwest Power Pool, Inc. (“SPP”). AESO is not subject to the Commission’s
jurisdiction and ERCOT is not subject to the Commission’s jurisdiction as it
relates to the issues raised in this proceeding. Thus, AESO and ERCOT are not
joining these comments. Individual IRC members may also file separate
comments.

Grid Reliability and Resilience Pricing, Notice Inviting Comments, Docket No. RM18-1-000 (Oct. 2, 2017).

Grid Resiliency Pricing Rule, 82 Fed. Reg. 46,940 (proposed Oct. 10, 2017) (“NOPR”).

Grid Reliability and Resilience Pricing, Letter Requesting Information, Docket No. RM18-1-000 (Oct. 4, 2017) (“OEPI Letter”).

wholesale markets, would provide improper incentives and disincentives to current and
future market participants, would not promote the goals stated in the NOPR (i.e.,

enhancement of electric reliability and resilience5), and would reverse the progress the
Commission and the nation’s regional transmission organizations (“RTO”) and

independent system operators (“ISO”) have made in developing robust and reliable
competitive markets. The NOPR’s broad cost recovery proposal also stands in stark
contrast to other types of narrowly-tailored cost recovery mechanisms like reliability
must-run (“RMR”) mechanisms, out-of-market compensation for units dispatched out-of-
merit for reliability or voltage reasons, or state renewable portfolio standards, each of
which are adjuncts to the competitive markets and operate in tandem with those markets.

Moreover, the NOPR proposal and rationale are vague in many respects, as the
many questions from Commission Staff set forth in the October 4, 2017 OEPI Letter
underscore, making it difficult to craft a final rule in this proceeding without substantial
additional consideration, dialogue, and evidence. As noted below, the proposed remedy

The NOPR refers extensively to “resiliency” and “resilience,” but contains no
definition of those terms. The NOPR also fails to identify with sufficient
specificity what “resiliency” problem that it seeks to address, which makes it
impossible for the Commission to articulate a rational connection between the
perceived problem and the drastic cost of service remedy that the NOPR seeks to
propose. Lacking such adequate definition and connection, the NOPR
undermines the Commission’s ability to engage in reasoned decision-making.
See, e.g., Occidental Petroleum Corp. v. SEC, 873 F.2d 325, 338 (D.C. Cir. 1989)
(“[I]n order to allow for meaningful judicial review, the agency must produce an
administrative record that delineates the path by which it reached its decision.”);
Chicago v. FPC, 458 F.2d 731, 742 (D.C. Cir. 1971) (“In the first place, review
would be a relatively futile exercise in formalism if no inquiry were permissible
into the existence or nonexistence of the condition which the Commission
advances as the predicate for its regulatory action. A regulation perfectly
reasonable and appropriate in the face of a given problem may be highly
capricious if that problem does not exist.”); Mori v. Dep’t of the Navy, 917 F.
Supp. 2d 60, 64 (D.D.C. 2013) (“An agency action that lacks explanation is a
textbook example of arbitrary and capricious action.”); see infra Section I.B.1.

would do little to support overall system reliability and may actually degrade that reliability as a limited class of units are being supported irrespective of each region’s specific needs, a unit’s location on the grid, or a unit’s ability to solve specific locational grid reliability issues.

In addition, the procedural timeframe for this proceeding is unreasonable. First,
the truncated period for public comment makes it impossible for interested parties to
provide thorough analysis and comments sufficient to enable the Commission to build a
comprehensive and meaningful record to aid its decision-making process. Specifically,
given the extremely short deadline for comments, the members of the IRC have not had
sufficient time to analyze comprehensively the potential impacts to reliability and market
prices that could result from the proposed rule, much less the magnitude of such impacts.
Of equal importance, the compliance timeframe set forth in the NOPR (i.e., tariff
revisions within fifteen days following the effective date of a final rule with
implementation to follow fifteen days thereafter) is arbitrary, unnecessary, and will not
promote the development of well-founded market design. That timeframe also
essentially prohibits opportunity for RTO/ISO stakeholder involvement in the
development of compliance proposals and little time for public comment and
Commission consideration once those proposals are filed.

Accordingly, the IRC urges the Commission to decline to adopt the NOPR as a
final rule. The IRC, however, responds to certain questions posed by Commission Staff
below.6

I.GENERAL COMMENTS

A.The NOPR Would Undermine Competitive Markets and Is Legally

Infirm

1. If Adopted, the NOPR Proposal Would Negatively Impact the

Competitiveness of Capacity and Energy Markets in a Manner
Detrimental to Consumers with No Concomitant Reliability Benefit

Providing guaranteed, full cost recovery for a subset of generators as proposed in
the NOPR (which presumably would allow full recovery of fixed costs for regions with
centralized capacity markets and full recovery of variable costs in energy markets) will
distort market prices, convert competitive market structures into a two-tiered
compensation system, and undermine, rather than enhance, reliability. The proposal
threatens to undermine price formation and competition in the nation’s organized
electricity markets.

The negative consequences of the NOPR proposal are obvious. By affording
certain generators guaranteed, full fixed and variable cost recovery for providing some
undefined “resiliency” benefit based on an arbitrary “fuel-security”7 standard, the NOPR
will shield eligible generators from the competitive forces that discipline market bidding
behavior and ensure that market dispatch and prices are based on least cost, security
constrained optimization of the resource portfolio.8 Generators that do not qualify for the

numerous OEPI Letter questions deserve thoughtful consideration and further discussion before any final rule is issued.

The NOPR establishes a ninety-day fuel supply as a requirement, but nowhere does the NOPR explain why ninety days is the appropriate or necessary standard, nor does it explain how such supply will be evaluated (e.g., ninety days’ worth of fuel for the resource operating at what level?) or by whom.

The NOPR’s cost recovery proposal is far different from other, existing cost-
recovery mechanisms like RMR provisions, out-of-market dispatch and
compensation of units that address reliability and voltage issues, or state
renewable portfolio standards. In contrast to the NOPR’s proposed carte blanche

compensation will be competitively disadvantaged compared to eligible generators. Those select “eligible generators” (unlike the rest of the class of generators or demand response providers) will now have the opportunity to bid into the market at unrealistically low prices that have no relation to marginal costs, knowing that they will be made whole irrespective of their submitted bid, through the NOPR’s full cost of service payment guarantee. Accordingly, market prices, including prices in centralized capacity markets with regard to fixed costs and prices in energy markets with regard to variable costs, will be distorted from what would otherwise occur in a competitive environment. Congress’s and the Commission’s policy of fostering competitive economic outcomes in energy markets9 would be stymied by the NOPR proposal.

recovery of costs to all qualifying “fuel-secure” generators (with no apparent
requirement to justify costs and with no showing of need), Commission-approved
mechanisms like RMR provisions are limited in applicability, tied to specific,
identified needs, generally limited in duration, do not involve the full fixed and
variable cost recovery of the scope set forth in the NOPR, and therefore do not
have the price-distorting impact that the NOPR’s cost proposal would. Such
existing mechanisms have been designed to work alongside competitive markets,
not to supplant market forces.

See, e.g., Wholesale Competition in Regions with Organized Electric Markets,
Order No. 719, 2008-2013 FERC Stats. & Regs., Regs. Preambles ¶ 31,281, at
P 1 (2008) (indicating that national policy, as embodied in the Energy Policy Act
of 2005, “has been, and continues to be, to foster competition in wholesale
electric power markets”), as amended, 126 FERC ¶ 61,261, order on reh’g, Order
No. 719-A, 2008-2013 FERC Stats. & Regs., Regs. Preambles ¶ 31,292, at P 122
(stating that the “Commission’s policy continues to be to promote in wholesale
electric power markets” as ratified by Congress in the Energy Policy Act of
2005), reh’g denied, Order No. 719-B, 129 FERC ¶ 61,252 (2009); Promoting
Wholesale Competition Through Open Access Non-Discriminatory Transmission
Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Order No. 888, 1991-1996 FERC Stats. & Regs., Regs.
Preambles ¶ 31,036, at 31,644 (1996) (indicating that a “goal of the Energy Policy
Act [of 1992] was to promote greater competition in bulk power markets by
encouraging new generation entrants”), order on reh’g, Order No. 888-A, 1996-
2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,048, order on reh’g, Order No.
888-B, 81 FERC ¶ 61,248 (1997), reh’g denied, Order No. 888-C, 82 FERC

Moreover, the NOPR proposal would actually harm, rather than promote,
reliability. Contrary to the NOPR’s assumptions, reliability will be set back because the
NOPR’s pricing proposal would fundamentally alter the economics for all generators in
each region’s footprint. The NOPR proposal would provide compensation to particular
units that may otherwise retire because they are older, less efficient, and less reliable than
newer units.10 Supplanting newer, efficient units with older, less reliable ones in the
markets will threaten reliability and market efficiency. This problem will be exacerbated
because the NOPR does not outline any minimum performance standards or criteria for
determining whether eligible resources are situated in an optimal location to support
future reliability needs (including, particularly local reliability and voltage needs).

Likewise troubling are the improper incentives that the proposal would create for
state regulators and generator owners. By guaranteeing full cost recovery at the RTO
level for resources that are not subject to retail cost of service rate regulation, the NOPR
might encourage generator owners to seek ways potentially to try to remove resources
from retail rate base to take advantage of potentially more attractive cost recovery at the
wholesale level. The costs of such a shift may then be re-allocated from retail ratepayers
in a state to a larger number of customers at the RTO/ISO level (depending on the cost
allocation method that the Commission approves in each region). The proposal also
could encourage the restoration of retired and mothballed units that utilities and states
previously determined were no longer cost-effective and useful, because the proposed full

¶ 61,046 (1998), aff’d in part & remanded in part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).

cost of service recovery at the RTO level would artificially change the economics for such units.

2. Even If Carefully Crafted, the NOPR Could Create Tensions

Between the States and Federal Government

By picking winners and losers and favoring certain resource types over others (as
envisioned by the NOPR), the Commission may upset the delicate balance between
federal and state regulatory regimes. Federal imposition of guaranteed, full variable and
fixed cost of service recovery for select generation resources through the wholesale
markets may create new areas for conflict. Issues related to which ratepayers must bear
the burden of supporting the resources the DOE identifies as requiring such cost support
will engender considerable litigation and is an ironic example of a government solution in
place of reliance on competitive outcomes. Cost allocation conflicts will ensue both
among customers and states within a particular RTO and across RTO boundaries. In
particular, states within an RTO that do not have generation resources eligible for the
NOPR’s cost recovery mechanism scheme may be adverse to paying for a federally-
mandated cost of service guarantee for a unit in a neighboring state.

Furthermore, the Commission is currently evaluating the balance between state
and federal authority and its effects on wholesale markets in Docket No. AD17-11-000.11
The Commission has begun to build a record in that docket and should allow its ongoing

See State Policies and Wholesale Markets Operated by ISO New England Inc., New York Independent System Operator, Inc., and PJM Interconnection, L.L.C., Notice of Technical Conference, Docket No. AD17-11-000, at 1 (Mar. 3, 2017) (announcing a technical conference to discuss certain matters affecting wholesale capacity markets and stating that “there is an open question of how the competitive wholesale markets, particularly in states or regions that restructured their retail electricity service, can select resources of interest to state policy makers while preserving the benefits of regional markets and economic resource selection” (emphasis added)).

proceedings to continue, while allowing individual RTO regions to pursue specific reforms to the extent that they can justify such reforms, rather than rushing to adopt a NOPR proposal that may drive further conflict among states and stakeholders.

3. The Timeline Does Not Provide a Meaningful Opportunity for

Public Comment and Impairs the Ability of RTOs and ISOs to Comply with the Final Rule

The NOPR sets forth an extremely short time frame for the Commission to gather and consider public comment, and sets up an unrealistic expectation that RTOs and ISOs will be able to develop, submit, and implement compliance filings in sixty days—and only thirty days after the final rule is effective. The Commission should not place RTOs and ISOs in the untenable position of being unable to comply with the final rule by adopting such a short period for compliance.

The Administrative Procedure Act (“APA”) requires that the Commission

provide notice to the public and an opportunity for public comment before issuing a regulation.12 The APA prohibits Commission actions that are arbitrary and capricious,13 meaning that any final rule authored by the Commission must reflect reasoned decisionmaking based on substantial evidence in the record developed in the rulemaking proceeding.14 The extremely shortened timeframe set forth in the NOPR undermines the Commission’s ability to adhere to these statutory directives.

5 U.S.C. § 553(b).

5 U.S.C. § 706(2)(A).

See Seminole Elec. Coop. v. FERC, 861 F.3d 230, 234 (D.C. Cir. 2017) (“To
satisfy this standard, FERC must demonstrate that it has made a reasoned decision
based upon substantial evidence in the record, and the path of its reasoning must
be clear.” (quoting Entergy Servs., Inc. v. FERC, 568 F.3d 978, 981 (D.C. Cir.
2009))); Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327, 338 (D.C. Cir. 1985) (the

The NOPR was issued by the DOE pursuant to its authority under the
Department of Energy Organization Act, which requires a Commission response within
“such reasonable time limits as may be set by the Secretary.”15 Given the importance and
complexity of the issues involved in the NOPR and the significant potential consequences
to competitive markets and market design, sixty days for public comment and
Commission action is unreasonable. As the OEPI Letter and its numerous detailed
questions make plain, there are myriad issues and substantial policy questions that need
to be addressed in considering the NOPR proposal. Allowing the public only twenty-one
days from the issuance of the NOPR (and a mere thirteen days from its publication in the
Federal Register) does not afford the public an opportunity to provide robust comment on
and analysis of the NOPR proposal and the OEPI Staff’s many questions. Similarly,
allowing only fifteen days for reply comments, when thousands of comments are
expected to be filed, is equally unreasonable. This approach will undermine the
Commission’s ability to marshal the substantial evidence needed to make a reasoned
decision.

Likewise, the extremely short timeframe for RTOs and ISOs to develop, submit,
and implement their compliance filings deprives them and their stakeholders of the ability
to design effective compliance mechanisms following issuance of a final rule. As
discussed below, the NOPR would afford only forty-five days for the development and
submission of compliance filings, which would go into effect a mere fifteen days
thereafter. Given the complex market design issues involved, the need for what are likely

Commission’s decision must be supported by substantial evidence and be the result of reasoned decision-making).

substantial market rule and software modifications, the potential impact on other
processes RTOs and ISOs administer to promote and ensure reliable operations, and the
varying and conflicting stakeholder views that RTOs/ISOs will need to consider, the
timeline set forth in the NOPR is unrealistic and threatens the ability of RTOs and ISOs
to comply with the final rule in any meaningful sense in that short amount of time.

Finally, the NOPR provides no justification for such an expeditious timeframe.
The sixty-day mandate is unsupported by the DOE Staff Report, 16 which identifies
potential issues and areas for further study regarding future market concerns, but does not
outline any imminent threat or emergency that would mandate quick Commission action.
The development of just and reasonable rates and market redesigns cannot be made so
quickly, particularly given complex, region-wide issues like cost allocation. Rushing
through a final rule presents the real possibility of future court challenges on the basis
that the Commission acted arbitrarily and capriciously in its rulemaking process.

B.The NOPR Lacks the Basis to Justify Such Considerable Reform to

Existing Markets

1. The NOPR Fails to Provide Sufficient Justification to Satisfy the

Commission’s Burden under Federal Power Act Section 206

To change an existing tariff or practice affecting rates pursuant to Federal Power
Act (“FPA”) section 206, 17 the Commission must find that the existing practice is
“unjust, unreasonable, unduly discriminatory or preferential,” and that the remedial
practice it imposes is “just and reasonable.”18 As noted above, the Commission must

Staff Report to the Secretary on Electricity Markets and Reliability, U.S. Department of Energy (Aug. 17, 2017) (“DOE Staff Report”).

16 U.S.C. § 824e. Id. § 824e(a).

support its findings (both that the existing rate is unjust and unreasonable and the new
rate is just and reasonable) with “substantial evidence” in the record19 and provide a
“rational connection between the facts found and the choice made.”20 In other words, to
impose market reforms via rulemaking, the Commission must: (1) identify the issue and
the reforms it intends to address; (2) examine evidence relevant to this issue; (3)

determine whether the issue is of sufficient consequence as to make the existing rates unlawful; and (4) identify a just and reasonable replacement rate.

The NOPR fails to provide sufficient information and detail on which the
Commission may find substantial evidence to support the imposition of the proposed cost
of service rate recovery mechanism. Also absent is any indication of how the proposed
new rate is just and reasonable and not unduly discriminatory or preferential. The FPA
and judicial precedent both hold that, in changing a rate under section 206, the

Commission must show not only how the existing rate is unjust and unreasonable, but also how the new rate satisfies the statutory just and reasonable standard. Given the very prescriptive directive to establish a new rate (i.e., full cost of service rate recovery for generators that satisfy the requirements), the onus is on the Commission to demonstrate how this new rate is just and reasonable for all affected generators, across all markets, and to all ratepayers. The NOPR does not even mention this obligation.

5 U.S.C. § 706(2)(E).

Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983) (quoting Burlington Truck Lines, Inc. v. United States, 371 U.S. 156, 168 (1962)).

Rather, the NOPR recites facts from the past fifteen years regarding changes to
electric generation mix 21 and quotes selectively from a North American Electric
Reliability Corporation (“NERC”) report advising that “these changing characteristics
must be well understood and properly managed.”22 But no attempt is made to understand
the current resource mix or examine any effect on reliability from such changes. The
mere fact that there are changes in resource mixes cannot support adoption of disruptive
rules that could significantly adversely affect the competitive wholesale markets that the
Commission fostered pursuant to Congressional mandates in its Energy Policy Acts of
1992 and 2005.23

In addition, the NOPR does not tie cost recovery eligibility to any specific
identified grid need. Under the NOPR, all resources that satisfy the requirements will be
entitled to full cost recovery regardless of whether the resource is actually needed to
provide any reliability benefit. As the DOE Staff Report points out, other assets such as
transmission and energy storage resources also can provide benefits that should not be
ignored. The grid and market may already be sufficiently reliable and robust in an area
where an “eligible resource” is located, thereby obviating the need to compensate the
resource for providing what would essentially be a redundant service. Providing

NOPR at 46,943.

Id. at 46,943 (quoting NERC Letter to Secretary of Energy Rick Perry, May 9, 2017, Attachment “Synopsis of NERC Reliability Assessments” at 1); see infra Section I.B.3 (discussing NOPR’s omission of facts from discussion on the issues highlighted by the 2014 Polar Vortex).

Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005); Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776 (1992).

guaranteed and unlimited cost recovery for an unneeded service is contrary to the Commission’s obligation to ensure just and reasonable rates.

The NOPR proposal also exceeds the limited cost of service-type mechanisms that the Commission allows in certain limited and justified circumstances, such as the Commission’s policies addressing RMR units, for which a need must be demonstrated before such units are entitled to additional compensation. The NOPR does not discuss why a more limited and need-based remedy coupled with existing market mechanisms is insufficient to address the perceived problem. Instead, the NOPR promises full cost compensation regardless of whether a resource is needed or actually has been demonstrated to provide benefits or whether it already has a reasonable opportunity to recover its costs under existing market structures.

Finally, the NOPR presents more questions than it answers. For example: How is
the ninety-day amount of on-site fuel supply determined? Is it the amount of fuel supply
that would allow the unit to run at maximum output for ninety days? If it is an amount
less than that, how is the allowable amount determined? When there are multiple units at
a site, can they share ninety days’ worth of fuel and both qualify for the subsidy? If an
eligible resource runs for a day and thus consumes one day’s worth of fuel, is it
disqualified from further cost of service recovery until it receives another fuel delivery?
The lack of eligibility and performance standards in the NOPR makes it difficult for the
Commission to craft a solid final rule that satisfies the Commission’s mandate to ensure
just and reasonable rates while avoiding opportunities for manipulation and the potential
for parties to assert discrimination claims.

2.The NOPR Is Inconsistent with the Sources It Cites in Support of

Its Proposal

The NOPR relies heavily on a few select sources to support both its call for urgency and its radical pricing proposal. In so doing, the NOPR cherry-picks certain excerpts from its sources and ignores other findings in those reports that undercut both its baseload compensation proposal and the haste with which it has insisted FERC adopt the rule. A more comprehensive reading of the sources cited in the NOPR reveals no need to rush to issue a final rule and provides no justification for imposing the NOPR’s compensation scheme on the markets.

Primarily, the NOPR relies on the DOE staff’s August 2017 report to the

Secretary of Energy analyzing electricity markets and reliability. However, contrary to the NOPR’s selective references to the DOE Staff Report, the report fails to identify any emergency that would justify adopting the NOPR proposal with such alacrity. In fact, the DOE Staff Report actually finds that RTOs and ISOs currently are effectively managing reliability and addressing market design and price formation issues, and that, while an adverse situation may arise in the future, such adversity is not imminent.24

Notably, the DOE Staff Report repeatedly stresses the importance of fuel
neutrality to the concepts of reliability and resilience, yet the NOPR appears to seek to

See, e.g., DOE Staff Report at 63 (noting that reliability today is adequate despite the retirement of eleven percent of the generating capacity that was available in 2002, but noting that it would not be prudent simply to assume that future reliability will mirror current trends); id. at 102 (“The centrally-organized markets are successfully achieving reliable and economically efficient delivery of wholesale energy in their short-term operations, but the changing circumstances portend potential long-term problems.” (emphasis added)).

promote specific fuel types (i.e., coal and nuclear) above other types.25 For example, the DOE Staff Report recommends that the Commission

should study and make recommendations regarding efforts
to require valuation of new and existing [essential

reliability services] by creating fuel-neutral markets and/or
regulatory mechanisms that compensate grid participants
for services that are necessary to support reliable grid
operations. Pricing mechanisms or regulations should be
fuel and technology neutral and centered on the reliability
services provided.26

The DOE Staff Report also quotes a report by the R Street Institute stating, “[f]uel
neutrality is essential for both monopoly-utility resource planning and competitive
markets to manage risk and achieve reliability efficiently.”27 These conclusions and
recommendations do not support the NOPR proposal to favor certain fuel types over
others.

The DOE Staff Report also does not justify the NOPR’s focus on providing full cost compensation for a subset of resources for their purported reliability and resiliency benefits. For example, the DOE Staff Report identifies other categories of assets and resources that also promote reliability and resilience, including, for example, investment in additional transmission infrastructure and electric storage resources.28

NOPR at 46,942 (discussing data on coal and nuclear retirements). DOE Staff Report at 126 (emphasis added).

Id. at 90 (emphasis added).

Id. at 73 (discussing the ways in which energy storage can provide grid-level
services); id. at 74-75 (“Transmission investments provide an array of benefits
that include providing reliable electricity service to customers, relieving
congestion, facilitating robust wholesale market competition, enabling a diverse
and changing energy portfolio, and mitigating damage and limiting customer
outages (resilience) during adverse conditions. Well-planned transmission
investments also reduce total costs.”); id. at 128 (recommending further research

Moreover, the NOPR is inconsistent with the Secretary’s letter accompanying it.
Rather than taking an “all of the above” approach as the Secretary suggested in his letter,
the NOPR ignores the benefits provided by other assets and instead focuses on certain
favored generation resources because they have the capability to store fuel. Any notion
of “fuel-neutral” or “all of the above” is absent from the NOPR’s compensation proposal.

Further undermining the rationale for the NOPR, the DOE Staff Report also relies
on and quotes the R Street Institute report, which explicitly eschews “bailouts for coal
and nuclear” and other subsidies because they “skew investment risk and can undermine
incentives for reliability-enhancing behavior.”29 Contrary to the NOPR, the DOE Staff
Report notes that, “[w]hile having fuel onsite reduces the risk that a generator will be
unable to operate when needed, every type of fuel and power generation source has
known vulnerabilities that can compromise its ability to perform reliably.”30 Thus, by the
DOE’s own assessment, on-site fuel is not the silver bullet to ensuring reliability that the
NOPR makes it out to be.31

The NOPR also quotes selectively from the DOE Staff Report’s discussion of
extreme weather events, calling attention to the fact that during the 2014 Polar Vortex,

regarding metrics to evaluate resilience provided by, among other things, transmission capability, demand response, and electricity storage).

Id. at 90-91 (quoting Devin Hartman, “Why Risk and Reliability Matter More than Fuel Diversity,” R Street Shorts No. 39 (May 2017)).

Id. at 91 (emphasis added).

See id. at 95 (“Still, fuel availability does not always guarantee dependable performance, particularly during extreme weather events.” (emphasis added)); id. at 98 (observing that, during Superstorm Sandy, “[t]hree nuclear reactors totaling 2,845 MW of capacity were shut down, and five operated at reduced levels due to” several factors including transmission and distribution outages and “precautionary measures to protect equipment”).

“American Electric Power reported that it deployed 89 percent of its coal units scheduled for retirement in 2014 . . . and Southern Company reported using 75 percent of its coal units slated for closure.”32 What the NOPR omits, however, is that the DOE Staff Report observes that the generating units in question were “older plants nearing the end of their useful lives,”33 meaning that market prices were not—and certainly were not the only— reason for such anticipated retirements.

Notably absent from the DOE Staff Report’s recommendations is any suggestion
of a proposal comparable to the NOPR. While the report does identify certain issues for
further research, including potential non-market structures to provide equitable
compensation for “desired grid attributes,” 34 nowhere does the report suggest that a
substantial threat is imminent necessitating hurried implementation of a rule to target
certain favored generation resource types. Indeed, the DOE Staff Report is devoid of any
suggestion that an emergency exists that compels the Commission to abandon its market
principles in favor of regressing to cost of service recovery for a subset of wholesale

energy market resources.Rather, the DOE Staff Report is measured in its

recommendation that the Commission continue its other pending market price formation

efforts and, as discussed above, focus on fuel-neutral market reforms rather than

subsidies to preferred generator types.35

NOPR at 46,942 (citing DOE Staff Report at 98). DOE Staff Report at 98.

Id. at 128.

See id. at 126.

3.References to Storm Damage Do Not Support Subsidizing Certain

Generation Resources

The Secretary’s letter transmitting the DOE’s proposal invokes “the devastation
wrought by the [2014] Polar Vortex, Superstorm Sandy, and Hurricanes Harvey, Irma,
and Maria” in support of guaranteed cost recovery for “fuel-secure” resources. However,
such storms have much greater overall impact on the transmission and distribution
infrastructure than generation resources. Poles and wires may be felled by strong winds
and may take significant time for service to be restored, as the lines are naturally spread
out over vast service territories and crews must travel to each affected line. By contrast,
generation facilities are generally manned and less susceptible to the destructive weather
forces. And, on-site fuel generally would not prevent operational issues resulting from
flooding or other damage associated with such storms. In any event, downed power lines
render generation resources undeliverable during and immediately following weather
events, whether or not those generators are able to operate and have ample fuel on site.

Superstorm Sandy well demonstrates the disparate impact of such storms on the
different parts of the electric infrastructure. NERC’s “Hurricane Sandy Event Analysis
Report,” evaluated the storm’s impact on the bulk power system, including both
generation and transmission assets. NERC found that “[w]hile there was sufficient
generation capacity available to meet the load as restoration progressed, there were
some cases where customer restoration was hindered by local area transmission
outages.”36 NERC’s evaluation found that “[o]ver the course of the event, 20,007 MW of

Hurricane Sandy Event Analysis Report, North American Electric Reliability
Corp., 5 (Jan. 2014), http://www.nerc.com/pa/rrm/ea/Oct2012HurricanSandyEvnt
AnlyssRprtDL/Hurricane_Sandy_EAR_20140312_Final.pdf (emphasis added).

generation capacity was rendered unavailable,”37 including nuclear, coal, and other fossil
fuel resources.38 In other words, NERC found that the operational risks arising from
severe weather events extend to the so-called “fuel-secure” nuclear and coal resources.

Also, 16,738 MW of fossil fuel generation became unavailable during the storm.39 However, NERC found that “this loss did not result in any capacity issues,” “[b]ecause of the amount of load preemptively off or unavailable to the distribution system.”40 As such, the loss of generation was not a significant contributing factor to the loss of service faced by customers during the storm.

In addition, the relative short duration of such events (usually numbered in the days or weeks) undermines the NOPR’s prescription for a ninety-day fuel supply. Even if access to fuel were interrupted, it is highly doubtful that such access would not be restored for a ninety-day period. Guaranteeing full cost recovery for retention of ninety days of on-site fuel appears unnecessary and would provide no ratepayer benefit, rendering such cost recovery unjust and unreasonable.

Id. at 5 (footnote omitted).

NERC also identified several generator operational risks from the storm, including: (1) increased potential for Loss of Off-site Power (“LOOP”) to nuclear generating facilities; (2) possibility of LOOP resulting from switchyard damage, or loss of normal condenser cooling and loss of availability of service water as a result of high water; (3) precipitator fly ash buildup and higher gas flow pressure because of operating without auxiliary feeds; (4) curtailments due to wet coal, which is normal during significant precipitation events; (5) danger from the loss of building siding; and (6) potential lack of fuel because of damage to the fuel provider’s facilities. Id. at 23.

Id. at 22.
Id.

II.RESPONSES TO SELECT OEPI LETTER QUESTIONS

A.Need for Reform

Question 2: The proposed rule references the events of the 2014 Polar
Vortex, citing the event as an example of the need for the
proposed reform. Do commenters agree? Were the
changes both operationally and to the RTO/ISO markets in
response to these events effective in addressing issues
identified during the 2014 Polar Vortex?

The NOPR asserts that the 2014 Polar Vortex “was a warning that the current and
scheduled retirements of fuel-secure plants could threaten the reliability and resiliency of
the electric grid.”41 However, the NOPR omits discussion of the impact of such severe
cold on so-called “fuel-secure” plants. In fact, the DOE Staff report recognized that
“[m]any coal plants could not operate due to conveyor belts and coal piles freezing.”42 In
PJM, of the approximately 40,200 MW of forced generator outages, coal steam outages
(considering all sources of failure) were the largest generator-plant-type category, at
13,700 MW, and nuclear outages totaled 1,400 MW.43 As a general matter, ISO-NE has
observed that a significant portion of the oil and coal units in its region could not
“provide reliable backup when gas problems arise due to increased outage rates, start-up

NOPR at 46,492 (citing DOE Staff Report at 98).

DOE Staff Report at 98. The DOE Staff Report also concluded that “[w]hile coal facilities typically store enough fuel onsite to last for 30 days or more, extreme cold can lead to frozen fuel stockpiles and disruption in train deliveries.” DOE Staff Report at 11-12.

Analysis of Operational Events and Market Impacts during the January 2014
Cold Weather Events, PJM Interconnection, L.L.C., 26 (May 8, 2014),
http://www.pjm.com/~/media/library/reports-notices/weather-related/20140509-
analysis-of-operational-events-and-market-impacts-during-the-jan-2014-cold-

weather-events.ashx.

problems, and other operational difficulties.”44 Thus, coal and nuclear resources were not unaffected by the severe weather. Nonetheless, “grid operators generally met demand, even under these severe conditions.”45

The 2014 Polar Vortex and earlier severe winter weather conditions did, however, highlight operational issues that contributed to the forced outages and poor performance, and compelled examination of the underlying causes and remedies. The regions most affected—PJM and ISO-NE—undertook detailed reviews to rectify those issues. PJM and ISO-NE each found that most, if not all, of the operational issues could be addressed if generation suppliers made investments in weatherization or increased operating budgets and commitments for future fuel deliveries.46 Both regions proposed (and the Commission generally accepted) market solutions that: (1) pay generation resources for better performance and allow recovery of investment in operational reliability of the resource, including forward fuel costs; and (2) impose a strong monetary penalty for poor performance—with limited to no exceptions.47

Filings of Performance Incentives Market Rule Changes of ISO New England Inc. and New England Power Pool, Docket No. ER14-1050-000, Attachment I-1a (Transmittal letter on behalf of the ISO) at 3 (Jan. 17, 2014) (“ISO-NE Pay-for-
Performance Transmittal”).

DOE Staff Report at 98.

ISO-NE Pay-for-Performance Transmittal at 3; Reforms to the Reliability Pricing
Market (“RPM”) and Related Rules in the PJM Open Access Transmission Tariff
(“Tariff”) and Reliability Assurance Agreement Among Load Serving Entities
(“RAA”) of PJM Interconnection, L.L.C., Docket No. ER15-623-000, at 19 (Dec.
12, 2014).

See PJM Interconnection, L.L.C., 151 FERC ¶ 61,208, at P 9 (2015), order on
reh’g, 155 FERC ¶ 61,157, at P 26 (2016), aff’d sub nom. Advanced Energy
Mgmt. All. v. FERC, 860 F.3d 656, 670 (D.C. Cir. 2017); ISO New England Inc.,
147 FERC ¶ 61,172 (2014), reh’g denied, 153 FERC ¶ 61,223 (2015), appeal

In addition, the NYISO implemented a number of operational and market changes to improve system and resource performance. The operational changes include new fuel monitoring capabilities for the generation fleet and improvement of gas-electric coordination and communication with natural gas pipelines and Local Distribution Companies. In November 2015, the NYISO implemented the Comprehensive Shortage Pricing project that augmented its procurement of reserve products to improve the responsiveness of the system to unplanned contingency events.48 The implementation included new locational reserve requirements, increased procurement targets and escalating price tiers to improve alignment of market signals with reliability needs. In addition, the NYISO implemented an improved ability to reflect day-ahead and intra-day supplier fuel costs in Generator offers to reflect the costs of operation during these extreme events. The changes NYISO has implemented since the 2014 Polar Vortex support improved supplier performance and resilience.

Since imposition of operational changes and these market reforms, ISO-NE, NYISO, and PJM have ably maintained reliability in their respective regions.

pending sub nom. New England Power Generators Ass’n v. FERC, No. 16-1023 (D.C. Cir. Jan. 19, 2016).

Question 4: The proposed rule references the retirement of coal and
nuclear resources and a concern from Congress about the
potential further loss of valuable generation resources as a
basis for action. What impact has the retirement of these
resources had on reliability and resilience in RTOs/ISOs to
date? What impact on reliability and resilience in
RTOs/ISOs can be anticipated under current market
constructs?

As an initial matter, in relying on the letter from the chairmen of the U.S. House
of Representatives and Senate energy committees, 49 the NOPR misinterprets
Congressional sentiments. First, the sentiments of Congress are best understood through
the legislation Congress has passed, and in the Energy Policy Acts of 1992 and 2005,
Congress expressed a desire that the Commission promote and facilitate the creation of
competitive energy markets.50 The NOPR would counteract those express Congressional
directives.

Regarding the impact of the retirements of coal and nuclear resources on
reliability in RTOs/ISOs, the markets “are currently functioning as designed—to ensure

NOPR at 46,943 (citing Letter from Lisa Murkowski, Chairman, U.S. Senate Committee on Energy and Natural Resources, Fred Upton, Chairman, U.S. House of Representatives Committee on Energy and Commerce, and Ed Whitfield, Chairman, U.S. House of Representatives Subcommittee on Energy and Power to Norman Bay, Chairman, Federal Energy Regulatory Commission (July 8, 2015) (on file with the U.S. Senate Committee on Energy and Natural Resources)). The chairmen requested that the Commission direct the RTOs/ISOs to find market solutions— not a reversion to cost-based ratemaking—to address the issue of baseload generation retirements, consistent with long-held Congressional policy of encouraging competitive wholesale energy markets. Specifically, the chairmen sought market reforms that would “[y]ield clearing prices in both energy and capacity markets that, in context, reflect true marginal cost of supply, promote necessary investment, and produce meaningful price signals that clearly indicate where new supply and investment are needed.” Id. at 2.

E.g., Energy Policy Act of 2005, Pub. L. No. 109-58, § 1281, 119 Stat. 594, 978 (2005) (“The Commission is directed to facilitate price transparency in markets for the sale and transmission of electric energy interstate commerce, having due regard for the public interest, the integrity of those markets, fair competition, and the protection of consumers.”).

reliability and minimize the short-term cost of wholesale electricity.”51 Indeed, such
retirements have not negatively impacted resource adequacy. Figure 4.2 of the DOE
Staff Report shows that each RTO/ISO’s region has maintained a five-year average
reserve margin of between fifteen and thirty percent, sometimes well in excess of their
respective targets, even in the face of significant changes in the resource mix.52

Given that reliability has been maintained throughout each RTO and ISO despite
recent retirements, the members of the IRC have not seen a negative impact on reliability
from the retirement of any resource.53 To the extent that a resource seeks to retire but the
RTO/ISO determines that such resource is required to maintain reliability, the RTO or
ISO may enter into a backstop agreement (e.g., an RMR agreement) to keep the resource
available—and maintain reliability—until a fix is in place. In addition, each RTO and
ISO currently has tens of thousands of megawatts of generation in its interconnection
queue, and has seen much new generation added over the past fifteen or so years. Taken
together, the NOPR’s proposed cost recovery scheme is not needed to maintain
reliability.

In fact, the proposal may erode reliability. Providing certain classes of generation
units full cost of service recovery without regard to their location or other unit-specific

DOE Staff Report at 10.

Id. at 66; see also id. at 65 (“NERC reports that all regions project more than sufficient planning reserve margins.”).

It should be noted that whether a generation unit retires “prematurely” is a subjective determination. The DOE Staff Report grappled with how to best address the assumption that baseload generation resources are being forced into “premature retirement.” Id. at 7-8. In the end, because “not every power plant retirement is cause for alarm” and “some observed power plant retirements were appropriate and consistent with markets,” the DOE Staff Report focused on “retirement trends.” Id. at 8.

reliability attributes could well discourage investment in new resources needed in other
parts of the system as investment dollars flock to support resources that enjoy the DOE’s
proposed cost of service guarantee. But reliability issues are often locational rather than
system-wide. The DOE proposal does nothing to add tools for RTOs to attract
investment in those areas experiencing reliability challenges and, if anything, makes the
task of attracting investment in those key areas of the system that much more difficult to
achieve.

B.Eligibility - Fuel Supply Requirement

Question 3: Does the vulnerability or non-availability of on-site fuel
supplies vary depending upon fuel type, location, region, or
other factors?

Of course numerous factors affect vulnerability and non-availability of on-site
fuel supplies. For many man-made and natural disasters, the presence of on-site fuel
supply would not prevent a resource from a forced outage or damage to the generation
unit, and a Nuclear Regulatory Commission directive can render unavailable to the grid a
single nuclear plant or an entire class of units notwithstanding the availability of on-site
fuel. Additionally, on-site coal piles are susceptible to freezing. An earthquake or
tsunami can damage a nuclear facility. Wildfires and flooding can ruin fuel stored on
site.

C.Implementation

Question 3: What is the expected impact of this proposed rule on entry
of new generation, reserve margins, retirement of existing
resources, and on resource mix over time?

The proposed rule’s compensation scheme would impact the RTOs and ISOs with
centralized capacity markets by discouraging, rather than promoting, new entry, and
could hasten, rather than forestall, retirement of existing generation. By providing full

cost of service recovery of fixed costs to a subset of favored generators, the NOPR
proposal if adopted would serve as a barrier to entry for new generation that lacks such a
subsidy in those regions with centralized capacity markets. In such markets, resources
that are not receiving such cost guarantees will be unable to compete with subsidized
resources, forcing more of those non-favored resources out of the market. By enacting
the subsidy, the Commission would merely be shifting the impetus to retire from one
category of generators to another. As the DOE Staff Report notes, “subsidies beget
subsidies,”54 and competition from resources that currently obtain subsidies “reduces
revenues for traditional baseload power plants by lowering the wholesale electric prices
they receive and by displacing a portion of their output.”55 It logically follows that
subsidizing “fuel-secure” resources would likewise distort prices in such capacity
markets and improperly displace other generation resources.

In the long run, the NOPR would also undermine efforts in such RTOs and ISOs
to develop a diverse resource mix, as subsidized generators will crowd others out of the
market. Further, if the NOPR applies to new resources, developers will target new
investment toward new generation resources that qualify as “fuel-secure” under the

NOPR, knowing that there will be relatively little risk that the developer will lose money
on its investment.56 However, resources that typically have much on-site fuel supply tend
to be fairly inflexible and unable to quickly ramp up or down to match swings in load.
Accordingly, there likely is a saturation point at which too many resources of a single

type negatively affects an RTO/ISO’s ability to meet demand and satisfy reserve requirements.

Finally, as discussed above, to the extent that a reliability concern arises from a
pending retirement, RTOs and ISOs have already adopted mechanisms to study and
postpone retirements until the reliability concerns can be addressed (e.g., RMR-type
mechanisms). Placing a broad, full (i.e., fixed and variable) cost of service recovery
mechanism on top of existing reliability-based mechanisms would serve only to incent
investment in generators that qualify for the NOPR’s subsidy, to the detriment of efforts
to maintain a diverse resource portfolio that can efficiently and economically supply
energy and reserves.

D.Rates

Question 1: The proposed rule lists compensable costs that should be
included in the rate as operating and fuel expenses, costs of
capital and debt, and a fair return on equity and
investment. Are there other costs that would be
appropriate to be included in the rate? Would any of the
listed costs be inappropriate for inclusion?

The NOPR institutes a rate-setting regime whereby RTOs and ISOs would be
obligated to “establish a tariff that provides a just and reasonable rate” providing
“recovery of costs and a return on equity for such resources dispatched during grid
operations” that “include[s] pricing to ensure that each eligible resource is fully

compensated for the benefits and services it provides,” such that “each eligible resource
recovers its fully allocated costs and a fair return on equity.”57 The Commission should
clarify that it does not propose to put RTOs and ISOs in a rate-setting function by
requiring them to develop tariffs that assess what is a just and reasonable rate and a fair

return on equity for each eligible generator. Rather, the Commission should clarify that
the ISOs and RTOs would adopt tariff language allowing for cost of service recovery for
eligible generators, but each generator would be required to obtain approval from the
Commission that the cost of service rates they seek to recover under the RTO’s or ISO’s
tariff are just and reasonable. The Commission should be the authority to determine
which costs a generator would be permitted to recover as part of a Commission
proceeding in which interested parties, including the RTO or ISO if it chooses, are free to
participate. The Commission, not RTOs or ISOs, is the appropriate body to determine
just and reasonable rates, including designing a rate that “fully compensate[s]”58 each
eligible generator for all of its costs, which the NOPR defines to include “operating and
fuel expenses, costs of capital and debt, and a fair return on equity and investment.”59

The NOPR also fails to address the process for parties to challenge costs that are
flowed through the compensation regime established by the rule. Once the RTOs and
ISOs file their tariff mechanisms and generators complete their rate approval process at
the Commission, generators presumably would be permitted to flow through their costs
with little or no oversight. Under a cost of service paradigm, parties are able to challenge
whether an asset is used and useful and whether expenditures were justified and
prudently incurred. Historically, this opportunity was afforded whenever the utility
applied for a rate change. With the proliferation of formula rates (at least in the

transmission setting), the Commission has gone to great lengths to ensure that
transmission providers establish detailed formula rate protocols that provide opportunities

for interested parties to review and challenge costs and expenses before they are automatically flowed-through RTO rates. 60 None of these consumer protections are spelled out in the NOPR proposal.

Question 4: How would the requirement that eligible resources receive
full cost recovery be reconciled with the requirement, as
stated in the regulatory text, that resources be dispatched
during grid operations?

In markets where generation resources receive payments only when responding to
dispatch instructions, full cost recovery through the market does not appear attainable
absent a guaranteed must-run requirement. That is, the “full cost recovery” rate would
need to be designed based on a certain set of dispatch hours, i.e., the denominator in the
rate calculation. Without a predetermined denominator, it is impracticable to design a
rate that would allow a generation resource to recover its full cost of service solely in
response to market payments for dispatch. Stated another way, a cost of service rate is
antithetical to the competitive wholesale market construct, where generators are
compensated at the applicable marginal price during their run time.

See, e.g., Midwest Indep. Transmission Sys. Operator, Inc., 143 FERC ¶ 61,149, at PP 16-19, 34, 83 (2013) (requiring transmission owners to revise their formula rate protocols to improve transparency and establish informal and formal challenge procedures); see also Kansas City Power & Light Co., 148 FERC ¶ 61,034 (2014) (same); Westar Energy, Inc., 148 FERC ¶ 61,033 (2014) (same); UNS Elec., Inc., 148 FERC ¶ 61,032 (2014) (same); Louisville Gas & Elec. Co., 148 FERC ¶ 61,031 (2014) (same); Empire Dist. Elec. Co., 148 FERC ¶ 61,030, at P 4 (2014) (same).

E.Other

Question 1: The proposed requirement for submitting a compliance
filing is 15 days after the effective date of any Final Rule in
this proceeding, with the tariff changes to take effect 15
days after the compliance filings are due. Please comment
on the proposed timing, both to develop a mechanism for
implementing the required changes and to implement those
changes, including whether or not such changes could be
developed and implemented within that timeframe.

The proposed requirement that RTOs and ISOs submit their compliance filings a
mere fifteen days after the effective date of the final rule (and thus only forty-five days
after the rule is published) is unreasonable and contrary both to Commission policy and
past practices. The NOPR proposes a drastic redesign of existing competitive market
structures, but provides very little implementation details and no discussion about
acceptable cost allocation for the proposal. Given the dearth of specificity in the NOPR,
parties will be left guessing as to what might be an acceptable compliance proposal until
such time as the final rule is issued. Giving only forty-five days from that point will deny
RTOs and ISOs adequate time to craft compliant policies and develop tariff revisions.
Equally significantly, a forty-five day window from issuance of the final rule to
submission of compliance filings provides very little time for RTOs and ISOs to initiate
stakeholder discussions, let alone time for the RTOs and ISOs to consider what are very
likely to be highly disparate stakeholder views on the RTO/ISO’s compliance proposal.
Ironically, the NOPR specifically requests “detailed comments” regarding the “processes
for RTOs/ISOs to vet proposed changes amongst their stakeholders,”61 yet the proposed
timeline is insufficient to accommodate such stakeholder vetting. Accordingly, the

proposal significantly undermines RTO/ISO efforts to adhere to the Commission’s
longstanding policy that RTOs/ISOs consider the views of their stakeholders.62
The compressed, fifteen-day deadline from the submission of Tariff changes for implementation of the compensation mechanism is even more problematic. The considerable market design changes proposed in the NOPR will require substantial changes to market procedures and software,63 which cannot possibly occur within fifteen days after the tariffs are submitted. Changes of this magnitude often take months, if not years, to develop before they are implemented. The fifteen-day effective date proposal also deprives the Commission of sufficient time to consider RTO/ISO compliance proposals once filed, and provides very little, if any, time for public comment, which is contrary to notice and due process requirements of the FPA and APA.64 Finally, in the event that the Commission requires changes to an RTO’s original compliance proposal, such original compliance proposal, flawed as it may be, will already be in effect before the Commission orders changes. This will, by definition, result in customers being

See, e.g., Order No. 719 at PP 502-10 (requiring RTOs and ISOs to implement mechanisms to comply with RTO/ISO “responsiveness” criteria including:

(1) ensuring that the views of all customers or other stakeholders are brought before the RTO/ISO’s board; (2) fairness in balancing diverse interests;

(3) consideration of minority viewpoints; and (4) ongoing responsiveness).

Because the compliance proposals likely will not be finalized until shortly before submission of the compliance filings, software engineers will not be able to begin any meaningful development of the necessary software changes until the tariffs are submitted. The likelihood of having redesigned market systems in place to meet the fifteen-day effective date is slim.

Obviously, the Commission’s customary twenty-one day comment period for rate submissions cannot possibly be accommodated under the expedited schedule required by the NOPR.

subject to unjust and unreasonable rates for a period of time until compliance revisions are in effect.

The drastically compressed timeframe for submission of compliance filings and
implementation is also contrary to the Commission’s customary practices when issuing
new market regulations. Given the complexity and significant impact of market design
changes, the Commission typically affords substantially more time to submit and
implement compliance filings after final rules are issued.65 Market-related rulemakings
that are far less complicated and far less controversial have afforded considerably more
time for submission of compliance filings and implementation than the NOPR proposes.

Question 2: Please comment on the proposed rule’s estimated burden of
$291,042 per respondent RTO/ISO, to develop and
implement new market rules as proposed, including the
potential software upgrades required to do so.

The estimated cost burden is unrealistically low. To implement the NOPR, each RTO must incur expenses related to, for example, market design changes, stakeholder meetings, tariff drafting efforts, software changes, and costs and fees associated with litigating regulatory proceedings. If experience is any guide, such efforts will be in millions of dollars for each RTO. The NOPR’s estimate is unrepresentative of the total cost of complying with a rule of this magnitude.

See, e.g., Settlement Intervals and Shortage Pricing in Markets Operated by Regional Transmission Organizations and Independent System Operators, Order No. 825, III FERC Stats. & Regs., Regs. Preambles ¶ 31,384, at PP 204-05 (2016) (providing 120 days for submittal of compliance filing); Demand Response Compensation in Organized Wholesale Energy Markets, Order No. 745, 2008-
2013 FERC Stats. & Regs., Regs. Preambles ¶ 31,322, at P 81 (providing 120 days for submittal of compliance filing), order on reh’g & clarification, Order No. 745-A, 137 FERC ¶ 61,215 (2011), reh’g denied, Order No. 745-B, 138 FERC ¶ 61,148 (2012), vacated, Elec. Power Supply Ass’n v. FERC, 753 F.3d 216 (D.C. Cir. 2014), rev’d & remanded, 136 S. Ct. 760 (2016); Order No. 719 at P 578 (providing six months for submittal of compliance filings).

Question 3: Please describe any alternative approaches that could be
taken to accomplish the stated goals of the proposed rule.

Rather than adopt a uniform cost of service compensation requirement for each
RTO/ISO-administered competitive wholesale market, the Commission should highlight
in its final action on the NOPR any issues identified by the Commission or public
commenters that warrant further evaluation, and then leave it to each RTO and ISO to
assess whether the issue is relevant to its market and, if so, propose a solution appropriate
for its market. As the DOE Staff Report recognizes and the Commission repeatedly has
acknowledged, each RTO/ISO market has different features and designs.66 Imposing a
one-size-fits-all solution to an issue that may not exist in all markets without any regard
for different market impacts, structures, and designs, is bad regulatory policy. When
promulgating new market requirements, the Commission frequently espouses a respect
for regional differences and flexibility, and in fact often eschews requests that the
Commission require uniformity.67 The Commission should not abandon this policy by
adopting the NOPR’s one-size-fits-all compensation proposal.

See, e.g., Order No. 719 at P 234 (“[B]ecause each market design is different, the changes to market rules should reflect each region’s market design.”); see also Electric Storage Participation in Markets Operated by Regional Transmission Organizations and Independent System Operators, Notice of Proposed Rulemaking, IV FERC Stats. & Regs., Proposed Regs. ¶ 32, 718, at P 2 (2016) (“Each RTO/ISO establishes the participation models for different types of resources and the technical requirements for providing services in a slightly different way.”); see also DOE Staff Report at 102 (noting that “U.S. market structures vary widely”).

See, e.g., Cal. Indep. Sys. Operator Corp., 134 FERC ¶ 61,211, at P 129 (2011)
(“The Commission has previously rejected requests to require a one size fits all
approach to resource adequacy and does so again in this proceeding.”); Frequency
Regulation Compensation in the Organized Wholesale Power Markets, Order
No. 755, 2008-2013 FERC Stats. & Regs., Regs. Preambles ¶ 31,324, at P 75
(2011) (declining to mandate standardized market rules, instead allowing RTOs
“flexibility to design market rules that accommodate their markets”), reh’g

III.CONCLUSION

For the foregoing reasons, the IRC members respectfully request that the Commission decline to adopt the NOPR as a final rule and instead adhere to its longstanding support for competitive markets. The reforms proposed in the NOPR would undermine markets structures that the Commission and the RTOs/ISOs have worked decades to develop and refine, and would degrade, rather than enhance, the reliability of the nation’s energy system. Rather than adopt the NOPR, the Commission should continue its efforts to incorporate state policies, enhance price transparency, and foster the consideration of reliability concerns in markets.

Respectfully submitted,

/s/ James M. Burlew Craig Glazer

Vice President-Federal Government Policy Suite 600

1200 G Street, N.W.
Washington, D.C. 20005 Craig.Glazer@pjm.com James M. Burlew

Senior Counsel

PJM Interconnection, L.L.C.

2750 Monroe Boulevard
Audubon, Pennsylvania 19403 james.burlew@pjm.com

/s/ Raymond W. Hepper

Raymond W. Hepper

Vice President, General Counsel, and
Secretary

Maria Gulluni

Deputy General Counsel

ISO New England Inc.

One Sullivan Road

Holyoke, Massachusetts 01040 mgulluni@iso-ne.com

denied, Order No. 755-A, 138 FERC ¶ 61,123 (2012); Order No. 719 at PP 59,
86, 160 (declining to mandate that RTOs develop standardized procedures for
demand response); Long-Term Firm Transmission Rights in Organized Electricity
Markets, Order No. 681, 2006-2007 FERC Stats. & Regs., Regs. Preambles
¶ 31,226, at PP 22, 84-85, order on clarification, Order No. 681-A, 117 FERC
¶ 61,201 (2006), order on reh’g, Order No. 681-B, 126 FERC ¶ 61,254 (2009).

/s/ Anna McKenna
Roger E. Collanton
General Counsel
Anna McKenna

Assistant General Counsel, Regulatory Andrew Ulmer

Director, Federal Regulatory Affairs

California Independent System Operator Corporation

250 Outcropping Way Folsom, California 95630 amckenna@caiso.com

/s/ Andre Porter

Andre Porter

Vice President & General Counsel Eric Stephens

Deputy General Counsel Michael Kessler

Managing Assistant General Counsel

Midcontinent Independent System
Operator, Inc.

720 City Center Drive Carmel, Indiana 46032 317-249-5173

aporter@misoenergy.org

/s/ Tam Wagner

Tam Wagner

Senior Manager, Regulatory Affairs Maia Chase

Senior Regulatory Analyst

Independent Electricity System Operator

1600-120 Adelaide Street West Toronto Ontario M5H1T1

Canada

tam.wagner@ieso.ca
maia.chase@ieso.ca

October 23, 2017

/s/ Raymond Stalter

Robert E. Fernandez General Counsel

Raymond Stalter

Director, Regulatory Affairs Karen G. Gach

Deputy General Counsel

New York Independent System Operator, Inc.

10 Krey Boulevard Rensselaer, NY 12144 rstalter@nyiso.com

/s/ Paul Suskie

Paul Suskie

Executive Vice President & General
Counsel

Richard Dillon

Director, Market Policy

Southwest Power Pool, Inc.

201 Worthen Drive

Little Rock, Arkansas 72223-4936 psuskie@spp.org