Page 995 – RTO Insider

January 20, 2021December 7, 2023

DC Circuit Rejects Trump ACE Rule

The D.C. Circuit Court of Appeals on Tuesday rejected the Trump administration’s Affordable Clean Energy (ACE) Rule for regulating power plants’ greenhouse gas emissions, saying EPA’s rulemaking and its repeal of the Obama administration’s Clean Power Plan “hinged on a fundamental misconstruction” of the Clean Air Act.

Ruling on the last full day of Trump’s term, the court also said the ACE Rule’s delayed enforcement deadlines were “arbitrary and capricious.” It vacated the rule and remanded it to EPA for further action.

The case was decided by Obama appointees Patricia Millett and Cornelia Pillard in a 147-page ruling, while Judge Justin Walker — appointed last year by Trump — filed a 38-page opinion concurring in part and dissenting in part. (American Lung Association and American Public Health Association v. Environmental Protection Agency and Andrew Wheeler, Administrator, et al.)

The court, which consolidated 12 petitions for review of the ACE Rule, agreed with a coalition of state and municipal governments, utilities, and renewable energy and environmental advocates who challenged EPA’s contention that Section 7411 of the Clean Air Act only permits emission reduction measures that can be implemented at and applied to the generation source.

The court also ruled in favor of the Biogenic CO2 Coalition in finding EPA in error for saying states could not count biomass co-firing as a method of complying with numerical emission limits under ACE.

Section 111 of the Clean Air Act, which was added in 1970 (42 U.S.C. Section 7411), ordered EPA to regulate any new and existing stationary sources of air pollutants that contribute significantly to air pollution and endanger public health or welfare.

The court said Section 111 acts as “a catch-all” to prevent gaps in regulations controlling stationary source emissions. Section 111(b)(1)(A) says the EPA administrator “shall” regulate any category of sources that, “in his judgment … causes, or contributes significantly to, air pollution which may reasonably be anticipated to endanger public health or welfare.”

The court rejected an argument that a drafting error in the 1990 Clean Air Act amendments prohibits EPA from regulating carbon emissions under Section 111(d) because the agency already regulates mercury from power plants under Section 112.

“Policy priorities may change from one administration to the next, but statutory text changes only when it is amended,” the court wrote. “The EPA’s tortured series of misreadings of Section [111] cannot unambiguously foreclose the authority Congress conferred. The EPA has ample discretion in carrying out its mandate. But it may not shirk its responsibility by imagining new limitations that the plain language of the statute does not clearly require.”

The D.C. Circuit heard arguments on challenges to the CPP in 2016 but never ruled on it after Trump’s EPA said it planned to withdraw it. (See Supreme Court Blocks Clean Power Plan.) The administration said the rule violated the CAA because it endorsed generation shifting and emissions trading among permissible emission-control measures.

EPA contended “the plain meaning” of Section 111(d) “unambiguously” limits the best system of emission reduction to only those measures “that can be put into operation at a building, structure, facility or installation.” Based on that interpretation, the agency determined the best system of emission reduction was limited to seven heat-rate improvement techniques for existing coal-fired generators. (See EPA Finalizes CPP Replacement.)

EPA predicted that the ACE Rule would reduce CO2 emissions by less than 1% from baseline emission projections by 2035, a calculation that did not consider potential emission increases from the “rebound effect” — the possibility that coal plants could run more often due to the efficiency gains.

“The EPA left unaddressed in this rulemaking (or elsewhere) greenhouse gas emissions from other types of fossil fuel-fired power plants, such as those fired by natural gas or oil,” the court noted.

Best System of Emission Reductions

The court said EPA was ignoring its own precedents. “Nothing that the EPA identifies or that we discern in the relevant history shows the enacting Congress myopically ‘focused on steps that can be taken at and by individual sources to reduce emissions,’” it said.

“Where the characteristics of the source category and the pollutant at issue point to emissions trading programs or production shifts from higher- to lower-emitting sources as components of the ‘best system,’ the EPA has in the past consistently concluded that it had the authority to consider them,” the judges wrote, citing the 2005 Clean Air Mercury Rule, which included a cap-and-trade program to reduce emissions from coal-fired generators.

The court said EPA’s interpretation “effectively relegates federal regulators back to the sidelines where they stood before Congress overhauled the Clean Air Act in 1970 … [in which] a virtually unanimous Congress dramatically strengthened the federal government’s hand in combatting air pollution.”

In the 50 years since the amendments, the court noted, combined emissions of six key pollutants regulated under the National Ambient Air Quality Standards dropped by 73%. “The EPA’s new reading of Section [111] would atrophy the muscle that Congress deliberately built up.”

The court also rejected claims from two coal mining companies that contended the ACE Rule was illegal because EPA failed to make a specific endangerment finding for carbon dioxide emitted from existing power plants, citing the agency’s 2015 finding that GHGs “endanger public health, now and in the future.”

The statement reaffirmed its 2009 endangerment finding, which followed the Supreme Court’s 2007 ruling in Massachusetts v. EPA that carbon dioxide and other GHGs are “air pollutants” under the CAA.

Revised Deadlines

The ACE Rule also sought to extend state deadlines for the submittal of their emission-reduction plans from nine months to three years and EPA’s deadline to act on those plans from four months to one year.

The court said EPA “failed to justify substantially extending established compliance time frames, including deadlines that it has had in place since 1975,” citing the agency’s “failure to say anything at all about the public health and welfare implications of the extended time frames.”

“The EPA’s weak grounds for routinizing additional compliance delays in the amended implementing regulations are overwhelmed by its total disregard of the added environmental and public health damage likely to result from slowing down the entire Section [111](d) regulatory process.”

Opponents said the amended rules would allow a delay of up to five years between finalizing an EPA emission guideline and the beginning of emission reductions.

Dissent

Judge Walker, who previously clerked for then-Judge Brett Kavanaugh and Justice Anthony Kennedy, disagreed with Judges Millett and Pillard on EPA’s ability to conduct “outside the fence line” regulation. He also rejected EPA’s authority to regulate GHGs under Section 111.

“Hardly any party in this case makes a serious and sustained argument that Section 111 includes a clear statement unambiguously authorizing the EPA to consider off-site solutions like generation shifting. And because the rule implicates ‘decisions of vast economic and political significance,’ Congress’ failure to clearly authorize the rule means the EPA lacked the authority to promulgate it,” Walker wrote.

“In my view, the EPA was required to repeal the [CPP] and wrong to replace it with provisions promulgated under Section 111. That’s because coal-fired power plants are already regulated under Section 112, and Section 111 excludes from its scope any power plants regulated under Section 112. Thus, the EPA has no authority to regulate coal-fired power plants under Section 111.”

Walker also said Massachusetts v. EPA did not answer crucial questions. “For example, does the Clean Air Act force the electric power industry to shift from fossil fuels to renewable resources? If so, by how much? And who will pay for it? Even if Congress could delegate those decisions, Massachusetts v. EPA does not say where in the Clean Air Act Congress clearly did so.”

Reaction

Observers differed Tuesday on how the ruling might affect the incoming Biden administration’s efforts to address climate change.

“For four years, state attorneys general used every tool at their disposal to reveal the shoddy legal arguments and fudged math behind the Trump administration’s anti-climate policies. The so-called ‘Affordable Clean Energy’ Rule was no exception,” said Jessica Bell, deputy director of the State Energy & Environmental Impact Center at the NYU School of Law. “Now the hard work begins to put in place a permanent, legally sound rule that will reduce carbon pollution from power plants as the broader economy continues to transition to clean energy generation. State AGs, the State Impact Center and clean energy allies are ready to get to work.”

Dorsey & Whitney attorney Megan Houdeshel, who represents mining, petroleum and chemical industry clients, said the ruling “is just the first example of many we are going to see in terms of industry uncertainty when it comes to Trump era regulations.”

“Whether it be courts overturning regulations, or the incoming Biden administration reversing course on executive orders and policy, companies should be ready for changes in environmental regulations applicable to their business and operation,” Houdeshel said.

“Quite a loss for [EPA Administrator Andrew] Wheeler and Trump on the way out the door,” tweeted Harvard Law School professor Jody Freeman. “Today’s decision clears the deck for the Biden EPA team to adopt a strong new rule for power plants and puts pressure back on Congress to pass a climate regime, because a fresh legislative approach would be most cost effective and comprehensive.”

But Craig Oren, a Rutgers Law School professor emeritus who specializes in the CAA and environmental law, responded with a caution. “This decision seems to say that Section 111(d) authorizes regulation away from any particular plant and may be used despite the mercury limits under Section 112,” he said. “But the Supreme Court is sure to reverse given the stay it issued against the Clean Power [Plan].”

January 20, 2021December 7, 2023

FERC Partially Accepts PJM MOPR Offer Floor Filing

FERC on Tuesday mostly accepted PJM’s tariff revisions accounting for when the default offer price floor exceeds the market seller offer cap (MSOC) under the RTO’s expanded minimum offer price rule (MOPR) (EL16-49-004, et al.).

In a ruling in October, the commission rejected PJM’s revisions to the MSOC, saying it had “never been a subject of” the MOPR proceeding and was beyond the scope of the compliance directive. (See FERC Acts on PJM MOPR Filing.)

But it recognized that sellers “may be left without a valid offer under potentially conflicting tariff provisions in circumstances where the default or resource-specific offer price floor for a particular resource is higher than the market seller offer cap for such resource.”

FERC directed that, in such a circumstance, the seller should submit an offer using the MOPR resource-specific review process. It directed PJM to make a change to Attachment DD of its tariff to say that any sell offer for a new entry capacity resource with a state subsidy shall have an offer price no lower than the applicable MOPR floor offer price, “unless the applicable MOPR floor offer price is higher than the applicable market seller offer cap, in which circumstance the capacity resource with state subsidy must seek a resource-specific value determined in accordance with the resource-specific MOPR floor offer price process to participate in a Reliability Pricing Model (RPM) auction.”

PJM Filing

FERC found PJM’s compliance filing, submitted Nov. 13, “consistent with the directives of the compliance order” with the exception of one provision regarding the MSOC.

PJM included the Attachment DD language directed by the commission but also proposed an additional sentence to the tariff, which stated, “In the event the resource-specific MOPR floor offer price is greater than the applicable market seller offer cap, the capacity market seller of such capacity resource may only submit an offer for such resource equal to the resource-specific MOPR floor offer price into the relevant RPM auction notwithstanding the provisions in Tariff, Attachment DD, section 6.4(a) or Tariff, Attachment DD, section 6.5(a).”

Despite changes to the methodology for calculating revenue offsets, the RTO said there could still be instances where a resource’s offer floor exceeds its MSOC and that the additional sentence addressed these circumstances.

The Organization of PJM States Inc. (OPSI) protested that the sentence was not directed by FERC and that the commission should not permit PJM to accept an offer higher than the applicable MSOC. The RTO should instead “determine that when the applicable offer price floor exceeds the applicable market seller offer cap, the seller should be permitted to offer at the applicable market seller offer cap.”

The commission rejected the additional sentence on the grounds that it exceeded the October compliance order, directing PJM to submit a new compliance filing within 15 days removing the sentence from the tariff.

“As PJM posits, we acknowledge that circumstances may occur where the applicable offer price floor, whether default or resource-specific, may be higher than the applicable market seller offer cap, either default or resource-specific, such as where a resource is treated as new for the purposes of the MOPR and existing for the purpose of the offer cap,” the commission said in its ruling. “We also agree with PJM that the compliance order found that, in these circumstances, the resource must use the resource-specific offer price floor.”

Other Rulings

FERC also granted PJM’s request to reinstate the deadline — 30 days prior to the capacity auctions — for submission of demand seller offer plans. The RTO explained that when it sought waiver of preauction deadlines in its March 18 compliance filing, which the commission granted, the RTO “inadvertently listed the preauction deadline for submission of demand resource sell offer plans as 21 days prior to the start of the capacity auction.”

However, PJM said the deadline for the submission of demand resource sell offer plans should remain 30 days prior to each auction, consistent with the provisions of the tariff.

The commission also denied a request from the Independent Market Monitor for clarification on the definition of fixed resource requirement (FRR).

“The compliance order accepted PJM’s proposal regarding excluding FRR revenue from the definition of state subsidy and acknowledged that FRR entities can be compensated in a variety of ways, including those recognized as state subsidies,” FERC said. “The Market Monitor posits broad hypotheticals regarding how this tariff provision may be applied in specific circumstances. We decline to address hypothetical applications at this juncture, as PJM will need to evaluate each application based on its specific facts.”

FERC Comments

The commissioners unanimously approved the order, with new Commissioner Mark Christie not participating in the ruling.

Commissioner Richard Glick said he concurred on the “relatively narrow determinations” in the order, but he wrote separately “to underscore my continuing disagreement with the conclusions that the commission has reached throughout this proceeding.”

Commissioner Allison Clements said she also concurred with the narrow determinations in the order because PJM’s filing “largely complies with those directives.”

Clements said while she didn’t participate in the previous orders, she “strongly” disagrees with a strict MOPR.

“I believe the commission must look forward, past the false dichotomy presented in this proceeding that implies that we must choose to either ‘protect’ the markets within the commission’s jurisdiction or to accommodate state public policy goals,” Clements said.

January 20, 2021February 19, 2025

FERC Ends Trump Era with a Busy Agenda

FERC spent its last open meeting during President Trump’s tenure welcoming a new member and rejecting proposed orders by outgoing Chairman James Danly.

Normally held on the third Thursday of the month, the commission’s monthly open meeting was moved to Tuesday, the day before President-elect Joe Biden’s inauguration. It was only one of many unusual aspects of the meeting.

Republican Commissioner Neil Chatterjee and Democratic Commissioners Richard Glick and Allison Clements voted against four proposed pipeline certificate orders brought to a vote by Danly, a Republican. The three also voted against granting rehearing of Order 871 — which barred natural gas pipeline developers from beginning construction before FERC fully acts on challenges to project approvals — and a proposed Notice of Inquiry on the White House Council on Environmental Quality’s updates to the environmental review process under the National Environmental Policy Act (NEPA). (See Trump Admin Proposes Streamlining NEPA Reviews.)

Chatterjee, Glick and Clements also voted against a proposed order regarding PJM’s minimum offer price rule (MOPR). Republican Mark Christie, who joined the commission Jan. 4 after serving as chair of the Virginia State Corporation Commission, did not participate in the vote.

Christie also did not participate in orders on the Mountain Valley gas pipeline project, part of which would run through Virginia. With Chatterjee joining Danly, the commission deadlocked 2-2, meaning it did not legally act on them. Christie, however, has not recused himself from either proceeding.

One of the FERC chairman’s responsibilities is deciding what items get voted on and discussed at the commission’s open meetings. They usually include major actions, such as landmark orders, or topics of particular importance to the chair. Proposed orders are rarely rejected, as chairs usually attempt to build a consensus prior to voting on them. Prior to Danly’s chairmanship, the last time an order on the agenda was rejected came as a surprise, when former Commissioner Bernard McNamee announced he would be voting against an order approving the Jordan Cove LNG export terminal in Oregon after state regulators rejected a permit for the project’s developers. (See In Rare Surprise, FERC Declines to Act on Jordan Cove.)

After he became chair in early November, Danly began bringing to a vote notational orders, such as waiver requests, on which he dissented. And last month’s open meeting featured a presentation on a proposed order to show cause requiring FERC Won’t Meddle in CAISO Resource Adequacy, Yet.)

This month’s meeting was also unusual in that Danly responded to each of his colleagues’ opening remarks in which they explained why they were voting against certain orders. In doing so, Danly for the first time explained his philosophy for voting on orders he knows will fail.

Chatterjee criticized two proposals to deny requests for rehearing of FERC staff’s approval of compressor stations on the Sabal Trail Transmission natural gas pipeline in the Southeast U.S. (CP15-17-005) and the Algonquin Gas Transmission pipeline in the Northeast (CP16-9-011). Chatterjee said that the orders did not “appropriately consider the comments on environmental justice and COVID” or “take into account the comments made by nearby residents on safety.”

“The reason why I brought these up for a vote, knowing full well that there would be a great likelihood that they would be voted down, is because … far from ignoring comments, what I insisted was that there be an order that specifically addressed the comments,” Danly said. The Administrative Procedure Act “requires all comments to be responded to. And it is in fact fidelity to legal regimes that required me to offer these for” voting, he said.

Danly, however, also struck items from the agenda, which had already featured an unusually high number of omitted items. These included acting on its Notice of Proposed Rulemaking on transmission incentives (RM20-10); a complaint by Cricket Valley Energy Center and Empire Generating Co. asking the commission to order NYISO, Others Rebut MOPR Complaint to FERC.)

Footnote 134

The text of the orders that FERC rejected will not be published — at least not as they were drafted as of Tuesday. That includes an order that commissioners said would have caused further confusion about whether resources procured in state-directed default service auctions are subject to PJM’s expanded MOPR. (EL16-49-006, et al.).

FERC in October clarified that such auctions would not be classified as state subsidies, so resources procured in them would thus be exempt from the MOPR. (See FERC Acts on PJM MOPR Filing.)

Chatterjee on Tuesday maintained that the order made it clear that “revenue from a state’s nondiscriminatory and competitive default service auction would not, and should not, qualify as a state subsidy, thereby triggering the MOPR.” He also noted that FERC accepted, without any protests, a compliance filing in which PJM proposed tariff language that specified that default service providers complying with state RPS programs would be exempt from the MOPR.

However, a footnote in the order caused confusion among stakeholders, leading to a rehearing request from several generating companies who said the footnote’s language conflicted with that of the order itself.

Footnote 134 reads in part, “While this order accepts the exemption that PJM has proposed, it does not constitute a ruling that any particular state-directed default service auction actually meets these requirements. For example, we note that the New Jersey Basic Generation Service auction appears to give guidance that conflicts with the proposition it is ‘nondiscriminatory’ or ‘fuel neutral.’”

It’s unclear what exactly the proposed order on the rehearing request would have done, but Chatterjee said it “neither squarely addresses nor eradicates the confusion and the conflict created by the footnote. Instead, the order doubles down on it, and I can not support such a path. I continue to believe it was the right call to exempt default service auctions from the MOPR and accept PJM’s tariff language that did exactly that.” He said he would have supported an order that vacated the footnote and further clarified the commission’s position.

Glick also said the order “doubles down on the matter by refusing to vacate Footnote 134, even though it is directly contrary to tariff language that the commission approved in October. My argument is that you can’t have it both ways. … If the tariff language is valid, we must vacate Footnote 134.”

“This footnote will continue to create unnecessary uncertainty in a proceeding that has had a great deal of that,” Clements said. “I’m hopeful that the commission will promptly resolve the pending issues in this proceeding in the near term.”

Future of FERC Under Biden

During the meeting, Danly indicated he planned to continue serving on the commission “over the next few years,” even after President-elect Biden gives the gavel to either Glick or Clements. Danly’s term ends in 2023.

While many observers have viewed Glick as the obvious choice given his three-year tenure, ClearView Energy Partners said that it is possible that Biden selects Clements as the next chair, as her nomination to the commission was strongly supported by Sen. Chuck Schumer (D-N.Y.), who will become the Senate majority leader Wednesday.

Both Clements and Christie on Tuesday expressed their eagerness to work on the interaction between state policies and RTO markets.

In concurring on a separate order in the MOPR proceeding, Clements said, “I hope to immediately engage with my colleagues to work with states, the regional transmission operators, independent system operators and the stakeholder community to re-examine the current capacity market constructs and the interplay between state public policies and commission-jurisdictional organized whole electric markets.” (See related story, FERC Partially Accepts PJM MOPR Offer Floor Filing.)

“I hope that in the months ahead that this commission will examine comprehensively the issues related to state public policies and RTO markets … in a form in which all interested entities, including the states, of course, can voice their views,” Christie said in his opening comments. “This is a complicated issue. It raises several important questions and competing interests and competing values. … I hope we will examine this issue and all its aspects in a general forum.”

Chatterjee also said he looked forward to working on the commission into Biden’s term. He expressed hope that Biden, whom he called “a person of enormous compassion,” would bring “a return to the high standards of leadership and decency expected of the office.”

“It will be steadying to have his experience and leadership in the White House,” Chatterjee said.

Glick recalled ribbing Chatterjee at last month’s meeting when Chatterjee noted he was voting against an order for the first time. Glick had joked that voting “no” would get easier over time.

With the Democratic commissioners outnumbered at least until the end of Chatterjee’s term June 30 — and possibly longer — Glick said, “I hope that changes to a bunch of ‘yeses.’”

January 20, 2021December 7, 2023

NEPOOL MC Supports Changes to End Price Locks

NEPOOL’s Markets Committee voted Jan. 19 to recommend the Participants Committee support tariff changes to remove new-entrant rules for ISO-NE‘s Forward Capacity Market, which would prevent resources from locking in prices for seven years.

The revisions will bring the tariff into compliance with a December FERC order that found the rules to be an “unreasonable price distortion” and “no longer required to attract new entry.” (See FERC Orders End to ISO-NE Capacity Price Locks.)

The MC approved the action in a voice vote with one abstention.

The RTO noted that the two tariff revisions will only impact upcoming Forward Capacity Auctions, leaving in place locked-in prices for FCA 15 and earlier auctions. Price-lock elections for FCA 15 were made in June 2020 when suppliers submitted their qualification packages for new resources.

ISO-NE did not propose removing any tariff language because the remaining provisions for price-locked resources need to stay in place until the completion of all elections, which account for any permitted deferrals.

FERC said entry of new resources should be driven “at least in part” by future price expectations, but that the price lock interferes with that dynamic. By eliminating price risk, a new resource may lower its offer price to increase the likelihood of being selected in the auction. FERC said that if that resource represents the marginal resource, the lower clearing price “distorts the price signal sent by the FCM and reduces the price paid to all capacity suppliers in that auction.”

The commission added that it previously recognized that new-entrant rules could result in price suppression but ultimately found that it was “an acceptable byproduct of market rules that would attract new entry through greater investor assurance and protect consumers from very high year-one prices.”

Price-lock rules have been in effect since ISO-NE began its capacity market in 2006. The rules allowed capacity resources to sell at the same price for five years — extended to seven years in 2014 — with resources offering in FCAs at $0 after the first year to ensure that they cleared. Although this prevented them from taking advantage of higher prices, it was viewed as a shield against lower prices.

ISO-NE implemented several FCM changes when the price-lock period was extended, including a system-wide downward sloping demand curve to address capacity price volatility. It also implemented enhanced market scarcity pricing that increased reserve constraint penalty factors for 10- and 30-minute reserves and pushed up the price that resources are paid for energy and reserves in real-time during scarcity conditions.

When FERC approved the price-lock extension, it allowed ISO-NE to forego an offer floor for resources, which prompted a legal challenge from Exelon and the New England Power Generators Association. The D.C. Circuit Court of Appeals remanded FERC’s approval in February 2018, though the court did not vacate the rules. (See DC Circuit Orders FERC to Review ISO-NE Auction Orders.)

ISO-NE must file its compliance filing with FERC on or before Feb. 1. According to a voting memo from ISO-NE counsel Chris Hamlen, the RTO is tentatively planning to request an effective date of April 2, 2021 for the proposed revisions, a week before the FCA 16 show-of-interest window. FCA 16 is scheduled for February 2022.

January 20, 2021January 26, 2025

SPP Taps FERC Staffer for Policy Position

SPP has hired former FERC senior staffer Leonard Tao to serve as its first director of FERC policy, the RTO announced in a press release.

Tao will be based in D.C., overseeing FERC filings and working with federal government leaders on energy issues on behalf of SPP, effective Jan. 19.

“He will be a tremendous resource to SPP and our members as we move to a full-time presence in Washington, D.C.,” said Paul Suskie, the grid operator’s executive vice president of regulatory policy and general counsel.

“I am thrilled to join SPP at this exciting time as it moves forward with its Western real-time balancing market and transmission plans that will bring significant benefits to consumers,” Tao said.

Tao has more than 30 years of experience working on energy policy matters. As director of FERC’s Office of External Affairs he managed strategic communications with Congress, the states, consumers and industry. He was also a legal adviser to FERC Chairman Joseph Kelliher and represented the commission as a senior legal adviser in the Office of the General Counsel. The latter responsibilities included standards of conduct for transmission providers.

SPP told RTO Insider that with the industry’s continued evolution and constant change in Washington, this was the right time to join all the other multistate RTOs in maintaining a permanent presence near Capitol Hill.

He previously served as an attorney in the Office of Legal Counsel to the U.S. president and as an administrative hearing officer in the U.S. Department of Energy. He is a graduate of George Washington University Law School and earned an undergraduate degree in economics from the University of Illinois.

January 20, 2021December 7, 2023

TVA Munis, Co-ops Appeal for Unbundled Transmission Service

Four Tennessee Valley Authority power companies have filed a complaint with FERC, charging the agency is violating federal energy policy by denying them access to alternative power suppliers through its transmission grid.

The non-profit municipal and cooperative utilities recently argued that TVA cannot deny them transmission system access to purchase power from suppliers other than TVA. The utilities — Athens Utilities Board, Volunteer Energy Cooperative, Gibson Electric Membership Corp., and Joe Wheeler Electric Membership Corp. — said they “seek unbundled transmission service from the only transmission provider that can feasibly serve them, in accordance with [FERC’s] longstanding open access principles” (EL21-40).

Utilities on the TVA system use 20-year bundled power supply contracts that include both power and delivery service. However, the utilities filing the complaint are governed by an older version of the contract that allows for contract termination with five years’ notice. Newer versions of the contract permit termination only upon 20 years’ notice to TVA. The four utilities say they operate under the older version of the contract and are not eager to sign off on new versions.

The utilities also emphasized that the contract’s bundled rates “have steadily risen in past years.” In an affidavit, Gibson Electric CEO Daniel Rodamaker said TVA’s power costs “do not reflect rates that are reasonable and reflective of other power supply opportunities in the wholesale bulk power market.” Rodamaker said that after his co-op recently solicited supply bids, it became clear that TVA “cannot keep pace with the cost of alternative power supply.”

TVA spokesperson Malinda Hunter said it wouldn’t be fair to TVA’s nearly 150 other power companies were it compelled to let munis and co-ops deliver power from other suppliers using TVA’s system.

“This request would use the TVA transmission system in a way that would shift their costs for using the transmission system to the other 149 local power companies served by TVA,” Hunter said in a statement to RTO Insider. “That is fundamentally unfair, and it goes against the foundation of public power.”

Hunter confirmed that TVA denied the four companies’ request for unbundled transmission service “consistent with the TVA Board’s longstanding policy on use of the transmission system.” She said TVA’s contracts are “partnerships in which the benefits of public power and the related costs are shared” and pointed out that revenues from power sales provide other benefits to the region, including “river operations, flood protection and public lands management, as well as economic development programs that bring good jobs to the region and keep them here.”

Atlanta-based consulting firm EnerVision estimated that the four utilities could save $25 million to $480 million over 10 years if they were able to pair unbundled transmission service from TVA with alternate wholesale providers. The utilities, spread out across Kentucky, Tennessee and Alabama, said the savings would be significant to their ratepayers who, by TVA’s admission, inhabit some of “the most economically challenged areas of the country.”

“Dissatisfied with the excessive bundled rates paid under the power contracts and unwilling to submit to the draconian provisions of the new power contracts, petitioners have actively sought alternatives to their source of power supply for the sole purpose of lowering electric costs to their members/consumers,” the utilities wrote to FERC. “At every step, TVA has stymied their efforts and prevented any discussions regarding unbundled transmission service.”

Memphis Light, Gas and Water has also voiced discontent with what it deems a comparatively high TVA rate. Last year, it pursued its first-ever request for proposals for new energy sources, including Memphis Moves Closer to Breaking from TVA.)

The four utilities told FERC that TVA owns all nearby transmission facilities that can serve their loads.

“Petitioners are scattered throughout the TVA area, and none is particularly close to TVA’s interface with another transmission system. Short of taking the very expensive and duplicative step of constructing its own transmission lines, no [local power company] can feasibly reach an external supplier without service across TVA lines,” they said.

“Nevertheless, TVA made clear, in its transmission service guidelines, in a newly restated TVA Board policy and in letters directly to petitioners, that it would not provide unbundled service across TVA transmission facilities to enable alternative power suppliers to serve [local power companies’] loads under any circumstances.”

The utilities said TVA has created a “supply monopoly within its considerable footprint that stifles all competition.”

“TVA has taken advantage of this arrangement to charge unreasonably high bundled rates, with no incentive to efficiently manage the costs it imposes on its captive wholesale customers,” they argued.

They explained that even though their current power contracts allow for termination, without open access to the TVA system, they “would have no choice but to duplicate the local existing transmission system” or sign the new power contracts, which “perpetuate” TVA’s monopoly on 20-year evergreen terms.

The utilities pointed out that “avoidance of duplicating bulk transmission systems” is fundamental to FERC’s open access policies. Further, they claimed that TVA members thwarted Warren Rural Electric Cooperative’s attempt 15 years ago to build transmission facilities that connected with external supplier East Kentucky Power Cooperative.

January 20, 2021December 7, 2023

FERC Orders Audits of All REs by 2023

FERC ordered NERC Tuesday to audit the compliance monitoring and enforcement programs (CMEP) of all regional entities by June 30, 2023, rejecting an alternative audit plan proposed by the organization last year as “insufficient” (RR19-7).

The commission’s order, issued at its monthly open meeting, follows a June compliance filing from NERC that was mandated by FERC in response to the organization’s five-year performance review. (See NERC Wins Another 5 Years as ERO.)

In that mandate, FERC expressed concern that NERC had failed to conduct the “comprehensive” CMEP audits that Appendix 4A of its Rules of Procedure (ROP) require it to perform on the REs at least once every five years, noting that the performance assessments for both 2014 and 2019 did not mention any such audits. The commission required that NERC produce any RE audits it had performed or outline a plan to perform them within the next 18 months.

In the June filing, NERC disclosed that it had “conducted two [CMEP] audits of the regional entities” since 2014, though these were “limited to … confidential information and conflict of interest procedures [and] internal controls evaluations of registered entities.” (See NERC Clarifies Audits, E-ISAC in Filing.) The organization also conducted two “non-CMEP” audits during the same period that examined REs’ implementation of the event analysis process and of Section 215 of the Federal Power Act.

FERC Rejects Alternate Audit Proposal

Rather than a plan for performing comprehensive audits in compliance with Appendix 4A, NERC’s June filing proposed ROP changes describing a new audit procedure. The proposal would see NERC expand its internal audit department — which currently focuses on NERC’s CMEP, Organization Registration and Certification Program, and bulk electric system exception activities — to include the REs’ versions of these programs.

Such audits would be conducted at least once every three years and would allow participation by representatives from FERC, which NERC suggested would be “more effective and efficient” than a five-year audit schedule. However, the commission rejected the plan, saying that “although [it] provides for a defined audit frequency, submittal of audit reports to the commission, and commission staff participation … it does not sufficiently assess the regional entities’ compliance and performance.”

FERC criticized NERC’s proposal for lacking requirements as to scope or procedural rules, with the internal audit department to set these for each audit. The plan also fails to explain how auditors will prioritize sections of the ROP for audit or to provide examples of previous audits that the commission can use to evaluate the proposal.

“In addition to the potential conflict of NERC evaluating its own CMEP and its relationship with the regional entities, a single audit evaluating NERC’s and the [REs’] CMEPs at the same time would appear to erode the ERO/[RE] structure required by Order No. 672,” the commission said.

Commissioners ordered that NERC proceed with audits of all six REs consistent with the existing ROP, including Appendix 4A, and that FERC staff be given the opportunity to observe the audits. Reports on the audits are due to the commission by June 30, 2023.

FERC accepted most other sections of NERC’s June filing, which included clarifications of the role of the Electricity Information Sharing and Analysis Center (E-ISAC) in developing reliability standards and the development process for reliability guidelines. Also approved was most of NERC’s follow-on compliance filing from September, which intended to clarify the process for issuing All Points Bulletins (APB) and added more specificity to NERC’s certification requirements. (See NERC Files ROP Changes with FERC.)

However, the commission also ordered further revisions to the ROP to “explicitly require NERC to share all APBs with the commission no later than the time of issuance.” NERC is required to report the changes to the ROP in another compliance filing, due within 120 days of the order; in that filing the organization is also ordered to further clarify whether the E-ISAC’s code of conduct could interfere with its information-sharing activities with NERC.

Shorter Assessment Timetable Proposed

In a separate Notice of Proposed Rulemaking (NOPR), FERC proposed shortening the time between NERC’s performance assessments from five years to three (RM21-12). The commission said the change would “provide better continuity” in its oversight of the ERO Enterprise, and the ability to identify potential performance improvements in a more timely fashion.

In addition, the amendment would allow FERC to request information on additional “areas of the ERO’s responsibilities and activities, or the regional entities’ delegated functions” beyond the statutory requirements of the performance assessment. NERC would have to honor any such requests submitted at least 90 days before the assessment’s publication date.

The NOPR would also require the ERO to solicit recommendations by industry stakeholders for improvement of its “operations, activities, oversight and procedures.” Such a solicitation would be aimed at identifying areas for improvement that could be addressed in the performance assessment and would occur independently of other recurring stakeholder surveys. Any comments received would be included along with the ERO’s responses in the assessment.

While all commissioners supported passage of the NOPR, they also emphasized that it is still only a draft proposal and industry feedback is needed. A joint statement from Commissioners Neil Chatterjee and Richard Glick asked specifically for feedback on “potential burdens” that the proposal could impose on the ERO Enterprise, a theme that Chatterjee pressed in his comments at Tuesday’s meeting.

“While I’m always open to new ideas to improve existing processes, I’m concerned that the additional layers of administrative process contemplated by this particular NOPR may miss the mark,” Chatterjee said. “I’m worried that the proposed reforms would result in little benefit while placing increased burdens on NERC and the regional entities that would ultimately distract from their important work.”

Comments on the NOPR are due 30 days after its publication in the Federal Register.

January 19, 2021

SPP MOPC Briefs: Jan. 11-12, 2021

SPP staff last week unveiled a proposed mitigation plan to reduce the four-year backlog in the RTO’s generation interconnection queue, a result of legacy study processes that can take as long as 485 days to complete — and longer if restudies are required.

David Kelley, SPP’s director of seams and tariff services, told the Markets and Operations Policy Committee that staff are currently working on their first cluster of GI requests from 2017 and are soon scheduled to tackle a second set.

“That’s just indicative of where we are,” he said during the Jan. 11-12 virtual meeting.

Kelley said that SPP’s new, streamlined three-stage study process, approved by FERC OKs New SPP Interconnection Process.)

SPP MOPC — SPP’s current generation-interconnection process timeline | *SPP*

“The three-stage process was not designed to get us out of the backlog we’re in,” he said. “We had a four-year backlog when we implemented the three-stage process, and we have it today. We still think the process will take too long to get to that point where we clear the backlog.”

Staff said the problem is that the queue has been formed by interconnection customers with different business purposes: some with a definitive proposal, and others that are simply speculating. Low financial commitments keep speculative customers in the queue, and the uncertainty triggers restudies that extend timelines.

“Left alone, the three-phase process will take too long to eliminate the DISIS backlog,” SPP’s Juliano Freitas said, referring to the definitive interconnection system impact study the RTO uses to cluster GI requests.

The three-stage process involves a thermal and voltage analysis, stability analysis and facilities study. It eliminates feasibility and preliminary queues, changes the amount and timing of security deposits, publishes study models earlier in the process, and allows penalty-free withdrawals when costs increase above certain thresholds.

Under the mitigation plan, Freitas said staff will remove the redundant facility study report for SPP and transmission owners and begin the first phase of a DISIS study in parallel with the preceding cluster’s second phase. Staff will also provide better cost estimates for each phase’s first decision point and implement a nonrefundable payment on the TOs’ interconnection facilities cost estimates for the first two decision points.

Freitas said these steps will save about 205 days for each DISIS cycle, beginning with the first 2018 cluster. Assuming a restudy for each cluster, including the two 2017 DISIS groups, he projected SPP would catch up by the end of 2024.

“I like the concept,” Southwestern Public Service’s Bill Grant said. “These queues are so saturated and don’t reflect the actual results of the queue studies.”

Stakeholder discussions have revealed “vastly differing views” as to what success looks like, staff said. Much of the developer community believes the three-phase process should be allowed to work before pursuing additional major overhauls of the GI process, they said, while a number of load-serving members have expressed significant concern with increased generator retirements and the ability to interconnect new generation to meet their service obligations.

“Staff is of the opinion that relying on the three-phase process alone won’t get us out of the hole anytime soon,” Kelley said. “We think success is measured when we reduce and eliminate the study backlog and we’re interconnecting new resources on a timeline that customers expect. It took us many years to get into [the hole], and it’ll certainly take us a while to get out of it. It’s going to take some pretty fundamental changes to the process.”

Omaha Public Power District’s Luke Haner said he was supportive of SPP’s proposals and urged the RTO to take steps to accelerate the process. “We would like to see serious requests sped up,” he said.

Al Tamimi of Sunflower Electric Power argued against a suggestion that cluster sizes be reduced to speed up the process. “I’m concerned we’re focusing on efficiencies and reducing the backlog, but we would be losing the quality of the studies,” he said. “I feel the quality of the studies need to be measured as you make those changes.”

“If your intention today was to get robust discussion, you got that,” Grant said. “I also heard people say, ‘The status quo is good; let’s work our way through it.’ The status quo is not good. Taking four to five years to get a [GI agreement] when you have load to serve is not acceptable, but I do think we’re on the right track.”

SPP COO Lanny Nickell admitted staff still have some work to do in generating consensus about the mitigation proposals. “For far too long, a majority of our members and stakeholders haven’t understood all the things happening behind the scene,” he said.

Nickell said staff need to further develop the proposal and share it further with stakeholder groups and the Board of Directors before it can begin drafting revision requests and tariff language.

SPP on ‘Cutting Edge’ with ESR Initiatives

SPP continues to grapple with how best to integrate electric storage resources (ESRs), belying at times its traditional “evolutionary, not revolutionary” approach to gaining stakeholder consensus.

The Strategic Planning Committee on Wednesday approved the Electric Storage Resource Task Force’s recommendation to continue developing rules to allow ESRs to participate in the markets as generation resources and transmission-only assets. The idea is to create a foundation for ESRs to eventually perform as multiuse transmission assets.

The task force said stakeholders and staff should complete rules and policies governing ESRs as transmission assets before evaluating their use in providing energy, capacity and ancillary services. Staff should continue to monitor rules being developed by other grid operators and regulatory efforts, it said.

“No RTO has it worked out. In some cases, we’re more on the cutting edge than normal,” Richard Dillon, SPP’s director of market policy, told the MOPC.

He said SPP now has a greater understanding of ESRs’ complexity. “By the same token,” Dillon said, “we don’t want an extremely complicated filing at FERC that gets rejected. We need to take smaller bites, so if revisions are necessary after FERC has seen [the proposal], we don’t take the ship down with one massive filing.”

Dillon serves as staff secretary on the Electric Storage Resources Steering Committee (ESRSC), which reports to the MOPC and is led by its chair, Evergy’s Denise Buffington. The group is responsible for coordinating and overseeing the stakeholder groups working on 37 different ESR-related initiatives spread over six issue categories.

Ten of those initiatives are focused on transmission, energy and capacity issues, work that had been on hold pending the task force’s recommendations. The initiatives encompass how to use ESRs for transmission only, energy and related services, and meeting resource-adequacy requirements. The ESRSC has determined that planning items, reliable-response items (capacity, fast start) and hybrid resources are high priorities.

Dillon said ESRs’ role as a distributed energy resource is out of scope. That issue will be taken up by another task force working on FERC Order 2222.

“If you look through all of the items, what I believe needs to be resolved first is the hybrid resource,” Dillon said. “Those are on our doorstep. We already have hybrid units we’re working around. We already have storage as transmission.”

The committee has engaged SPP’s Project Management Office to help with bundling the initiatives into a comprehensive project. It has also increased its membership to expand its experience and geographic representation, including a yet-to-be named representative from the Dakotas. Among the new members are Southern Co.’s Chase Smith, who chaired the ESR Task Force; Greg Rislov, an adviser to the South Dakota Public Utilities Commission; NextEra Energy Resources’ Matt Pawlowski; and attorney Heather Starnes.

EDP Renewables’ David Mindham complimented SPP on the governance structure, saying it would “bring clarity to the issues.”

“Clarity around these installations is really important for these developers,” he said.

Asked to endorse an ESR-related white paper, MOPC members instead agreed to send the document to the ESRSC and task force for their consideration. The Operating Reliability Working Group (ORWG) drafted the paper, which recommends that SPP manage the charging and discharging of transmission-only ESRs and coordinate any transmission operators’ reliability actions.

“I’m concerned about the arguments of the resources being treated differently without due cause,” the Advanced Power Alliance’s Steve Gaw said.

The committee separately approved two other white papers related to the ESR initiative:

the ORWG’s recommendation that SPP require ESR data for all unregistered behind-the-meter sites so it can determine their overall effect on the grid. The paper also suggests developing minimum ramp-rate requirements and determining the ESRs’ minimum and maximum limits for charging and discharging.
the Transmission Working Group’s (TWG) paper that included a recommendation to use a load-curve analysis to determine the ESRs’ required duration in the planning processes.

PTP Tx Revenue Service Tweaked

Members approved a Regional Tariff Working Group’s (RTWG) recommendation to modify SPP’s point-to-point (PTP) transmission service revenue allocation that essentially leaves the process in place.

Stakeholders have generally agreed that the current process is complex, prone to inaccuracies and lacks transparency. SPP currently splits its distribution of PTP service revenues to TOs 50/50, with half determined by the ratio of the annual transmission revenue requirement and half allocated by a megawatt-mile process.

When some megawatt-mile modeling effects forced the RTO to resettle revenues, engineering staff conducted a review in 2018 that found the process was developed 11 years ago using a source-sink methodology that current staff were unfamiliar with and resulted in more than 1 million combinations in the calculations.

Following a staff presentation on the issue last July, the MOPC directed the RTWG to simplify the process with the TWG’s technical input. (See “Point-to-point Revenue Allocation Sent Back,” SPP MOPC Briefs: July 15-16, 2020.)

However, the group was unable to reach consensus, settling for minor tweaks to the process that leave the status quo in place. The RTWG looked at 10 different options, but all shifted revenue between various TOs.

“So it’s up to staff to simply make it less burdensome?” American Electric Power’s Richard Ross asked.

“That’s fair,” SPP’s Charles Hendrix responded.

“The way I read the literal language, the only mechanism we would be given … would be simply to reduce the number of needed or requested reruns. Revenue shifts would be off the table,” SPP’s Nickell said.

The measure cleared the MOPC’s 67% approval threshold at 74%. Twelve of the 17 TOs and 28 of 36 transmission users voted for the motion.

Order 2222 Task Force Underway

Michael Desselle, SPP’s chief compliance and administrative officer, said the RTO has created a task force to take on compliance with FERC Order 2222, which directs grid operators to allow DER aggregators to compete in their markets. (See FERC Opens RTO Markets to DER Aggregation.)

The 16-person Order 2222 Task Force, comprising a cross-section of stakeholders and two regulators (Arkansas’ Ted Thomas and Missouri’s Scott Rupp), will be responsible for developing and approving policies and governing document changes to comply with the order. Evergy’s Grant Wilkerson will chair the committee, Desselle said.

The group has an ambitious schedule of 14 meetings over the next six months in order to meet FERC’s July 19 compliance deadline. SPP will propose a “reasonable implementation date” in its filing.

The task force will evaluate 10 policy issues, which include establishing minimum size requirements for DER aggregations that don’t exceed 100 kW.

Coming Soon: Order 1000 Task Force

MOPC Chair Buffington and Nickell, the committee’s staff secretary, are working to provide a “game plan” for yet another task force, this one charged with improving SPP’s Order 1000 selection process.

SPP followed a similar process after approving its first competitive project in 2016. In October, the RTO’s Board of Directors approved an industry expert panel’s (IEP) recommendation to grant SPP’s second competitive project, the 75-mile, 345-kV Sooner-Wekiwa project in Oklahoma, to Transource Missouri. (See Transource Tapped for SPP’s 2nd Competitive Tx Project.)

Staff in December reviewed with stakeholders initial suggestions to improve how it awards competitive transmission projects. The suggestions focused on the continued use of incentive points for future projects; whether to share with project bidders how the IEP will score proposals; and developing and publishing standardized scoring guidelines. (See SPP Out to Improve Competitive Tx Selection.)

“Those will be the conversations we have going forward,” SPP’s Ben Bright said. He noted that SPP has begun accepting applications for the pool of experts from which the IEP is formed to review competitive construction proposals in 2021. “We always need new experts.”

Buffington Lays out Goals

MOPC Chair Denise Buffington, Evergy | *SPP*

Buffington marked her first meeting as chair by outlining her goals, which include increasing stakeholder engagement in a committee that has grown to 104 members representing 10 sectors across 14 states.

“We’re excited there’s growth in SPP, but we’re interested in hearing new voices and ideas in our discussions,” she said. “We want to encourage new ideas to challenge traditional thoughts.”

Board Chair Larry Altenbaumer applauded the MOPC’s “diversity initiative,” saying he is “looking forward to hearing what comes out of that.”

2 HITT White Papers on Consent Agenda

The MOPC unanimously approved a consent agenda that included a pair of white papers stemming from the Holistic Integrated Tariff Team’s work.

The Market Working Group recommended approval of its white paper on offer requirements for variable energy resources in the day-ahead market. The study found wind resources’ effect on price divergence are largely dependent upon the offer behaviors … exhibited in the [day-ahead market] from both a financial and physical offer perspective.”

The MWG also combined with the ORWG and TWG on a second white paper that urged SPP continue supporting dynamic line ratings’ implementation and use, as they remain voluntary at the TO’s discretion.

The agenda also included the Project Cost Working Group’s recommendation for a $25.6 million cost reduction to SPS’ Multi-Hobbs-Yoakum 345/230-kV project in West Texas and a $5.1 million cost increase to an 230/115-kV SPS network upgrade north of Amarillo; withdrawal of RTWG RR334, which included the 20-year Integrated Transmission Planning assessment (ITP20) as an eligible study for determining competitive upgrades; and six revision requests:

MWG RR429: corrects and/or clarifies existing Market Monitoring Unit language in the Integrated Marketplace protocols. The changes do not change functionality or policy and do not require tariff adjustments.
MWG RR433: updates tariff and protocol language by replacing references to the jointly owned combined resource option that no longer exists under MRR266.
RTWG RR417: clarifies that no projects can be approved for construction from ITP20.
RTWG RR436: removes all facilities associated with an interconnection study preceding the Integrated System’s 2015 membership in SPP. Following the system’s integration, SPP completed a study that resulted in different network upgrades.
Staff RR424: removes duplicate language currently located in the system operating limit methodology.
TWG RR434: modifies outdated tariff language that is not consistent with current processes, including clarification that aggregate transmission service studies are now a six-month process.

January 19, 2021

Western RA Effort Could Wrest Some Control from States

A Western resource adequacy program proposed by the Northwest Power Pool could require state regulators and utilities to relinquish some control over their integrated resource planning (IRP) processes, according to a report discussed in a webinar Friday hosted by the Western Interstate Energy Board.

The biggest impacts would be on RA targets and resource capacity credits, while load forecasts and transmission expansion would also be affected, researchers at the Lawrence Berkeley National Laboratory, the University of Texas and WIEB concluded.

Resource capacity credits allocate values to categories of generation. If a regional RA entity and its members were to assign different values to wind and solar power, for example, the conflicting assessments could undermine Western RA efforts, researchers said. Local planners would have to defer to the regional entity in the case of disagreements.

“There should be a regional resource capacity accreditation process that would create capacity credits for different variable resources or, in general, all the resources,” Juan Pablo Carvallo, the report’s lead author and senior scientific engineering associate at Lawrence Berkeley, said.

Western resource adequacy — The footprint of Northwest Power Pool, in blue, covers eight states and two Canadian provinces. | *NWPP*

States would also have to defer to a regional entity to establish RA planning targets, he said.

If states wanted to be “super adequate” and have stricter RA criteria than a regional body “that would be perfectly fine … [but] it would be particularly problematic if it was the other way around. If some state, for some reason, had a lower reliability target than the regional level, that would create numerous problems,” Carvallo said.

The report, titled “Implications of a regional resource adequacy program on utility integrated resource planning: Study for the Western United States,” elaborated on the conclusion.

“States have historically assigned different capacity credit factors for similar resources — especially for wind, solar and demand response — which may create friction among members if some states recognize higher or lower capacity than others for similar resources,” it said.

“This report finds that for an efficient and effective operation of a regional RA program, states in the footprint will need to defer to the program’s definitions of resource adequacy targets … and resource capacity accreditation. States would effectively surrender control over those two assumptions and let the regional program define them,” it stated. Members of a regional RA program would also have to find ways to coordinate load forecasts and transmission planning instead of going it alone.

“These elements could continue to be developed by the [load-serving entities] under state IRP mandates, but coordination of input data, modeling assumptions and outcomes will be needed with the regional RA program,” the report said.

A regional entity could establish transmission plans from the top down or compile a larger plan from local planning efforts, Carvallo said.

NWPP launched its RA effort in 2019 after studies showed the Pacific Northwest could start to see resource shortfalls as soon as 2020 or 2021. As designed, the program would be voluntary but could impose mandatory RA requirements on entities that join to avoid LSEs “leaning” on the program to meet their own RA requirements.

NWPP’s sprawling footprint covers eight Western states and two Canadian provinces, meaning the RA program could potentially govern much of the Western Interconnection except for Arizona, California and New Mexico. (See NWPP RA Effort Quickly Ramping Up.)

The Northwest, California and other parts of the West face tightening supply caused by the retirement of coal plants and a greater dependence on wind and solar resources. Those conditions contributed to California’s energy emergencies last summer including rolling blackouts in August, and CAISO to Focus on Resource Adequacy in 2021.)

“Monitoring and maintaining RA is becoming increasingly complex and challenging due to plant retirements, higher penetration of variable renewable energy resources and COVID‐related load fluctuations that translate to higher uncertainty on the amount of generation that will be available during periods of peak demand,” the report, funded by the U.S. Department of Energy, said.

“This paper is primarily aimed at state regulators, public utility commission staff and resource planners from states in the NWPP footprint that are pondering how their IRP guidelines and regulations may need to adjust to operate jointly with a regional RA program,” it said.

SPP as Role Model

The study examined the experience of the Southwest Power Pool, which partly served as a role model for NWPP’s effort. SPP to Develop NWPP Resource Adequacy Program.)

“SPP is an interesting case study for this paper, because many LSEs in its footprint are required to conduct IRP while also complying with SPP RA requirements,” the report said. SPP and its members generally have been able to communicate and reach agreement on the types of issues that will likely arise in NWPP’s program.

“Ongoing work among states lead to consensus even when there were initial disagreements on a range of topics,”
the report said. “This relationship has made [local] IRP and SPP guidelines naturally follow each other as evidenced from IRP reports and statutes.”

LSEs, for instance, tend to defer to SPP on transmission planning because they “do not want to be redundant, and they inherit in their IRPs many of the assumptions coming out of the transmission planning process from the Southwest Power Pool,” Carvallo said.

The report said the “SPP experience shows that load forecasting can be left to the member entities in the regional program provided that they develop and share forecasts with standardized statistical characteristics.”

“Ultimately, interviewees from public utility commission staff from SPP states indicated that LSEs have an incentive to develop IRP assumptions that are consistent with SPP’s in order to fulfill their membership duties,” it said.

In the NWPP RA program, the report said, “LSEs should be able to develop NWPP‐aligned forecasts as part of their IRP processes and benefit from the public stakeholder engagement as long as IRP regulations in the NWPP states are based on a broad and flexible set of principles.”

January 19, 2021

State AGs Highlight Action Against Trump Admin

New York University’s State Energy and Environmental Impact Center released a new report on Thursday that recounts actions that state attorneys general took to mitigate the Trump administration’s weakening of regulations on energy, climate and the environment.

The report details measures by state AGs on clean energy, environmental justice and addressing per- and polyfluoroalkyl substance (PFAS) contamination. It also focuses on maneuvers in federal agency rulemaking processes and in court that prevented the administration from cementing its climate and energy policies and reversing regulatory protections for air, waters, wildlife, public lands and public health.

‘Strong Defense’

According to the report, state AGs worked together to prevent political appointees to EPA and the departments of Energy and the Interior from freely shunning rulemakings, delaying compliance deadlines and ignoring statutory directives from Congress.

“Putting up a strong defense has always been the focus of our work during this reckless administration,” Massachusetts AG Maura Healey said.

The AGs said they worked to uphold obligations to address power sector carbon emissions and keep auto emissions reductions on track. They sought to prevent unlimited methane emissions from the oil and gas industry and defeat the Department of Energy’s push for a bailout of the coal industry.

attorneys general regulation — Clockwise from top left: Stephen Read, State Energy and Environmental Impact Center; Maryland Attorney General Brian Frosh; Connecticut Attorney General William Tong; Massachusetts Attorney General Maura Healey; and Oregon Attorney General Ellen Rosenblum. | *State Energy and Environmental Impact Center*

“The Trump administration has spent the last four years doing the bidding of the fossil fuel industry, from rolling back limits on greenhouse gas emissions that undermine clean car standards to opening up protected areas to oil and gas drilling,” Healey said.

Oregon AG Ellen Rosenblum said that when the Trump administration took aim at California’s carbon cap-and-trade market with Quebec in 2019 with a lawsuit, her state joined more than a dozen others to defend the agreement. The Department of Justice alleged that California’s voluntary agreement with Quebec violated two rarely invoked constitutional provisions, the Treaty and Compact Clauses. In two opinions in March and July 2020, a federal district court rejected DOJ’s claims, noting that the California-Quebec agreement did not represent a “treaty” within the Constitution, nor did it rise to the level of a “compact.”

“The court saw right through the administration’s claims and rejected them outright,” Rosenblum said.

Maryland AG Brian Frosh said the Trump administration’s “zeal to prop up the fossil fuel industry caused them to embark upon a climate destruction program.”

“They refused to enforce and attempted to overturn dozens of rules that protect our climate and, not incidentally, our air and water,” Frosh said. The administration “tried to lift pollution caps on cars, trucks, industries, utilities, landfills [and] oil drilling. They have overridden the findings of scientists; they’ve ignored the opinions of experts.”

‘Collective Action’

In 2018, Connecticut AG William Tong and New York AG Letitia James sued EPA for its failure to meet its obligations under the Clean Air Act’s “Good Neighbor” provision, which requires action against upwind pollution sources that prevent downwind states from meeting required air quality standards under the National Ambient Air Quality Standards.

“Unfortunately, under the Trump administration, we’ve seen an aggressive, systematic effort to dismantle these basic protections,” Tong said.

The suit successfully found that EPA missed its deadline to promulgate federal plans to address upwind pollution and ordered the agency to do so by early December 2018.

When EPA responded with a rule that fell short of its CAA obligations, state AGs took the agency to the D.C. Circuit Court of Appeals and won. Tong, Healey and three other state AGs sued EPA again for dragging its feet and won again in July 2020, as the court cited the agency for its “failure to take immediate action.” The court gave EPA a March deadline to promulgate plans to reduce ozone emissions from upwind states. The AGs said the final rule will help protect millions of residents of downwind states from exposure to smog and other pollutants that cause asthma, lung damage and other respiratory harms.

Tong said the state AGs actions are “vindicated by core constitutional principles.”

“The environment, and our collective action on the environment and protecting the climate is in large part why we have a federal government because the federal government is there to help us accomplish the things as states that we cannot effectively do by ourselves,” Tong said.