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EPA Proposes to Revise Standards for New Coal Plants

EPA has issued a proposed rule to amend the New Source Performance Standards (NSPS) for greenhouse gas emissions from new, modified, and reconstructed fossil-fuel-fired power plants.  In 2015, under the Obama Administration, EPA promulgated a rule establishing that the best system of emission reduction (BSER) for newly constructed coal plants is partial carbon capture and storage.  At the time, EPA rejected arguments that partial carbon capture and storage was not yet an adequately demonstrated technology.  Opponents challenged the 2015 rule in court, but that case was put on indefinite hold in light of EPA’s announcement that, under the Trump Administration, it was reviewing the 2015 rule.

Today’s proposed rule would determine that the BSER for newly constructed coal plants is “the most efficient demonstrated steam cycle . . . in combination with the best operating practices.”  EPA explains that “primary reason for this proposed revision is the high costs and limited geographic availability of” carbon capture and storage.  As a result of the proposed new BSER, EPA is also proposing to establish higher greenhouse gas emission rates as the standards of performance for large and small electric utility generating units.

EPA projects, however, that the “proposed rule will not result in any significant carbon dioxide . . . emission changes or costs.”  It still agrees with the projections it made when it issued the 2015 rule, which anticipated that there will be few, if any, new coal-fired power plants that trigger these particular provisions.  Earlier this week, the U.S. Energy Information Administration issued analysis showing that U.S. coal consumption in 2018 is expected to be the lowest in 39 years, and that only one, relatively small new coal-fired generator is expected to come online by the end of 2019.

Comments on the proposed rule will be due 60 days after publication in the Federal Register.

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Virginia Proposes to Tighten Carbon Emissions Regulation

This week, the Virginia State Air Pollution Control Board approved the recommendation of the Virginia Department of Environmental Quality (DEQ) to promulgate a revised regulation limiting carbon dioxide emissions from fossil fuel-fired power plants in the state.  In response to a May 2017 executive directive issued by Governor McAuliffe, Virginia had previously developed a regulation to reduce Virginia’s carbon emissions by 30% between 2020 and 2030.  That regulation was based on an initial carbon dioxide base budget of 33 million or 34 million tons.

More recent air modeling, however, indicated a more favorable forecast of current Virginia emissions.  As a result, the revised regulation proposes an initial base budget of 28 million tons of carbon dioxide, which in turn would result in more stringent carbon regulation and an additional 5 million tons of carbon eliminated by 2030.

Like the previously issued regulation, the revision would link Virginia to the Regional Greenhouse Gas Initiative (RGGI).  DEQ’s press release on the proposed revision notes that “Virginia utilities are expected to participate in RGGI, the regional carbon cap-and-trade program covering fossil-fuel fired electric generating units in nine Northeast and Mid-Atlantic States (New York, Maine, New Hampshire, Vermont, Massachusetts, Rhode Island, Connecticut, Delaware and Maryland).”

There will be a 30-day public comment period on the proposed revision, which is expected to occur in early 2019 following Executive review.  The State Air Pollution Control Board then expects to vote on the proposal at its meeting in the spring of 2019.

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Fight Over PURPA Reform Continues at FERC

Last week, the National Association of Regulatory Utility Commissioners (NARUC) and a group of public interest organizations* filed comments at FERC that reveal divergent perspectives on how FERC should go about its reform of the Public Utility Regulatory Policies Act of 1978 (PURPA).  These comments follow former Chairman McIntyre’s announcement during FERC’s May 2018 meeting that the Commission would be “reenergizing” its PURPA review initiative.

In a proposal entitled Aligning PURPA with the Modern Energy Landscape (Attachment A to the comments), NARUC argued that FERC should exempt from PURPA’s mandatory purchase obligation “those utilities which are subject to state competitive solicitation requirements and other best practices that ensure all technologies access to the market.”  NARUC concludes that FERC should create a “yardstick of characteristics” as a guide to determine whether a utility that does not participate in a regional transmission organization (RTO) could nonetheless qualify for exemption of the must-purchase obligation under PURPA section 210(m)(1)(C):

EPAct ’05 permits FERC to exempt utilities from the requirements of PURPA if [qualifying facilities (QFs)] . . . have access to wholesale markets.  Sec. 210(m)(1) described two types of markets in subparagraphs (A) and (B), which FERC has interpreted to apply to six of the seven RTOs/[independent system operators (ISOs)].  For the seventh RTO/ISO, FERC found that ERCOT met the requirements of . . . subparagraph (C).  But subparagraph (C) is much broader than that; it could and should be applied to non-RTOs that have a sufficient measure of competitive access to QF technologies.

NARUC states that its proposal will allow competitive mechanisms rather than administrative proceedings to arrive at the least-cost procurement of energy resources for consumers.

By contrast, public interest organizations argued that in many regions without RTOs, QFs lack adequate markets in which to sell their energy and capacity, and that competitive solicitation in non-RTO states is not sufficient to provide QFs access to a nondiscriminatory market.  Public interest organizations argued that competitive solicitation is not required in many states and pointed out that many states don’t regularly hold competitive solicitations or make them open to all QFs.  In addition, these organizations argued that competitive solicitation “can be overly burdensome and costly for smaller facilities, depriving them of an opportunity to compete on equal terms because the administrative costs of participating in such a solicitation represent a higher percentage of the facility’s costs than for larger facilities.”

The public interest organizations concluded that FERC’s review of its PURPA regulations should include a 50-state survey of PURPA implementation by state regulatory authorities and nonregulated electric utilities in order to: determine where PURPA implementation does and does not comply with FERC’s regulations, investigate existing barriers in wholesale markets that prevent non-discriminatory access for QFs, and evaluate opportunities to strengthen PURPA’s implementation.

There is no clear timeline for FERC to respond to NARUC’s and the public interest organizations’ comments.


*The public interest organizations included the Southern Environmental Law Center, Environmental Law and Policy Center, Vote Solar, Pace Energy and Climate Center, North Carolina Sustainable Energy Association, Climate + Energy Project, Center for Biological Diversity, and the Sierra Club.

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PJM (and Others) Weigh In on the Place for Subsidized Resources in its Capacity Market

The first round of briefing in FERC’s paper hearing to consider the issue of “out-of-market” payments in PJM has concluded (Docket No. EL18-178).  On October 2, PJM filed its initial submission, which focuses on an expanded Minimum Offer Price Rule (MOPR) and a Resource Carve-Out.

PJM states that it designed its proposal with two broad principles in mind:

(i) an important underlying objective stated in the June 29 Order—namely that states which choose to support generation for policy reasons not recognized in the Commission-regulated wholesale markets assume all costs associated with this decision in a transparent fashion; and

(ii) an understanding the Commission, in setting just and reasonable rates, can exercise informed judgment to adopt reasonable balances and draw distinctions based on materiality to accommodate varying industry objectives in an environment of cooperative federalism.

PJM states that its proposed MOPR expansion would apply to all fuel and technology types, as well as to both new and existing resources (with limited exceptions).  The Resource Carve-Out would apply to resources subject to the MOPR that are receiving a state subsidy.  PJM notes that its limitations on the Resource Carve-Out include an “[a]cknowledgement that if the amount of capacity carving out becomes so large going forward, PJM and the Commission will need to evaluate whether the residual market is sufficiently robust to perform effectively and consistent with the [Federal Power Act].”

PJM’s proposal would consider any subsidy to be covered under the proposal except: generic economic development subsidies not specific to the electricity sector; a resource-specific subsidy that is 1% or less of expected PJM revenues the resource would get; renewable energy credit (REC) programs where the purchaser is not required by a state program to purchase the REC and does not receive any state financial inducement to do so; and federal subsidy programs enacted before March 21, 2016.

Numerous other parties filed initial submissions on October 2.  Reply briefs are due November 6.  And there are several pending requests for rehearing of FERC’s June 29 order that established this paper hearing.

Meanwhile, the proportion of natural-gas fired generation in PJM has increased over the past five years (similar to trends seen elsewhere in the U.S.).  Average annual capacity factors for natural gas-fired generators in PJM have been increasing, and there have also been additions of natural gas capacity in the region (primarily combined-cycle units).  These natural gas units have started operating more often as baseload units rather than load-following or peaking resources.  Lower natural gas prices (in part based on location) is the likely driver.

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