PJM staff will recommend that the RTO’s Board of Managers approve its own capacity repricing proposal next month, ignoring an endorsement vote scheduled for Jan. 25 on an alternative proposal that had garnered more stakeholder support.
PJM CEO Andy Ott announced the decision Tuesday in a letter to stakeholders.
In addition to describing revisions to PJM’s proposal, Ott made the case for why the RTO’s proposal needs to be filed for FERC approval now and is superior to the proposal from PJM’s Independent Market Monitor.
“I do not make this recommendation lightly, recognizing valid concerns arise with any course of action PJM may take, including capacity repricing,” Ott wrote. “Despite all of our collective efforts in the stakeholder process, a workable consensus solution — or even a shared agreement on the nature and extent of the problem to be solved — appears unlikely.”
The filing would be the culmination of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) that dominated PJM stakeholder work in 2017. PJM said its plan would accommodate generator offers from state-subsidized plants by allowing them to bid into capacity auctions but ensure they don’t suppress competitive prices by removing those offers in a second “repricing” stage of the auction.
Several proposals like PJM’s arose to address perceived flaws in the concept, but the IMM’s proposal — fueled by concerns that PJM would unilaterally file its proposal without a clear stakeholder mandate — was the only one to receive endorsement to move forward, albeit slowly. The IMM’s “MOPR-Ex” proposal would extend the minimum offer price rule to all units indefinitely. (See MOPR-Ex Faces Uphill Battle as PJM Declines Recommendation.)
Ott’s Argument
Ott said PJM needed to seek approval quickly because of growing threats to PJM’s markets. He cited FERC’s rejection of the RTO’s 2012 MOPR compromise, the failure of a court challenge to Illinois’ zero-emissions credits program, and the “distinct potential” for additional state subsidies this year — likely a reference to New Jersey legislators’ consideration of a ZEC-style program. (See On Remand, FERC Rejects PJM MOPR Compromiseand NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
Ott said he agrees with the Monitor that MOPR-Ex “offers the most economically sound response to the issue” and “the most direct and effective means to preserve price integrity” necessary for the capacity market to work. But he said PJM’s proposal is superior to MOPR-Ex because it is “substantially less punitive and less likely to frustrate the operation of state programs.”
“PJM believes it is vital for the regional market design to respect individual state interests while protecting consumers in other states from potential cost shifts,” Ott wrote. “While MOPR-Ex would not prevent state programs from providing support to individual generators, it would most likely exclude generators obtaining this support from clearing the PJM Capacity Market. PJM believes this approach is not sustainable and does not strike an appropriate balance between legitimate state interests and wholesale market integrity.”
IMM Response
In an emailed response, the Monitor said it agrees with PJM that there is a conflict between state subsidies and competitive wholesale power markets.
“But the IMM disagrees with PJM’s conclusion that PJM must reflect state interests even when state subsidies conflict with the operation of a competitive wholesale power market,” Monitor Joe Bowring said. “PJM’s capacity repricing proposal would permit state subsidized resources to push competitively offered resources out of the capacity market. That outcome is inconsistent with competition.”
Bowring took issue with Ott’s characterization of MOPR-Ex, saying that it’s not punitive to require competitive offers and “prevent subsidized, uneconomic resources from pushing competitive, economic resources out of the market.”
He reiterated his oft-repeated refrain that “subsidies are contagious.”
“If one subsidy program is permitted to undermine the PJM capacity market, others will follow,” Bowring wrote. “The MOPR-Ex approach would provide a disincentive for subsidies and would require individual states to bear the costs of state subsidies rather than spreading the costs across the other states in PJM.”
Next Steps
Ott said PJM would request FERC approve its proposal for an effective date after the 2021/22 Base Residual Auction in May. He promised that “PJM will actively listen, consider, and engage on alternative design suggestions that stakeholders might offer in the course of the FERC proceeding.”
WASHINGTON — FERC Commissioner Neil Chatterjee acknowledged Tuesday he has suffered some growing pains in his transition from Capitol Hill partisan to FERC commissioner, saying he hadn’t fully appreciated the commission’s “fact-based, evidence-based approach.”
In a panel discussion, Chatterjee and Commissioner Cheryl LaFleur discussed the commission’s Jan. 9 ruling dismissing Energy Secretary Rick Perry’s Notice of Proposed Rulemaking (RM18-1) and previewed the docket the panel created to investigate RTOs’ resilience practices (AD18-7).
The session, sponsored by the Bipartisan Policy Center, attracted an audience that included the heads of groups representing the nuclear and coal industries, merchant generators, and state regulators. (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
Chatterjee, a Kentuckian and former energy advisor to Senate Majority Leader Mitch McConnell (R-Ky.), had pushed for “interim” financial relief for struggling coal and nuclear generators pending further proceedings but ultimately joined LaFleur and their three colleagues in the unanimous ruling.
“During my time in the legislative branch I had spent time with lawmakers of all political stripes who stressed the importance of fuel diversity and the need for an all-of-the-above energy strategy,” Chatterjee, a Republican, said. “And so initially I did express some sympathy for what the secretary had laid out. … That said I was also very clear that if the commission were to take any action, it would have to be legally justified, and that it would not distort markets.”
“As we went through the process I came to really appreciate the fact-based, evidence-based approach that the commission takes. I was aware of it prior to my confirmation, but once you really get in there and start doing the work, you realize we do things in a cautious, steady, legally defensible manner. As we … went through the record and did the analysis, I came to the conclusion that my colleagues did, which is that while I feel Secretary Perry asked the right question, he proposed the wrong remedy.”
Chatterjee said he was pleased that all five commissioners also agreed “that resilience is something that needs to be explored further. The commission has looked at these kinds of issues throughout the last number of years, but we’ve never had a really hyper-focused analysis on resilience.”
LaFleur, a Democrat, said, “I disagree with Neil a little bit on how much we’ve done on this issue in the past.
“Since I’ve been on the commission for seven and a half years, a large percentage of our work has been driven by relentless changes in the nation’s resource mix. … And I would say that’s been driving our market work, our reliability work, and our transmission work for much of the last decade.”
LaFleur said although the resiliency proceeding is important, “I think we shouldn’t let this swallow everything the commission is doing. We have to continue on all fronts.”
LaFleur said she opposed interim subsidies for coal and nuclear plants because the commission lacked robust factual basis for the action. She likened it to the high burden of proof required of those seeking a preliminary injunction, who must show they have a likelihood of ultimately prevailing.
LaFleur also parted with Chatterjee on definitions, saying she believes resilience is part of reliability.
“I think resilience is distinct from reliability,” Chatterjee said “ … Perhaps the threats of a loss of resilience aren’t as dire as some generators are making them out to be. But they’re certainly not as insignificant as some proponents of new generating sources are making it out to be.”
BPC President Jason Grumet, who moderated the talk, praised the commission and Chairman Kevin McIntyre for their response to the NOPR. “I think for anyone who mistrusts government action, the rigor, the integrity and the independence, and the unanimity that FERC was able to show is really, I think, one of the brightest moments in basic public service that I’ve seen in a while,” Grumet said.
On McIntyre’s handling of the NOPR, Chatterjee and LaFleur were in agreement. “He threaded the needle very well,” Chatterjee said.
With an Arctic cold front rolling through the southern part of its footprint Tuesday morning, SPP set a new winter demand peak of 42.71 GW. The previous mark of 41.01 GW — set Jan. 2 — lasted only two weeks.
The new record came at 7:24 a.m., and wind energy met just over 8 GW of the demand. Energy prices peaked at 11 a.m., with hubs averaging $496.67/MWh in the north and $478.49/MWh in the south.
ERCOT, which manages 90% of the Texas grid, expected to set its third demand record this winter during either the night of Jan. 16 or the morning of Jan. 17. The state has been hit with its second round of snow and ice this year, ranging from San Antonio to Houston.
The ISO’s current winter peak is 62.86 GW, set Jan. 3. That broke the short-lived record of 61.95 GW, set the day before.
Spokesperson Leslie Sopko said ERCOT has sufficient generation and transmission resources to keep up with forecasted demand.
“However, this is a fluid situation, and we will continue to monitor system conditions closely,” Sopko said.
The National Weather Service predicted Houston area overnight temperatures would fall into the teens to lower 20s F, with wind chill values possibly dipping into the single digits.
NYISO’s new five-year strategy calls for the ISO to align its competitive markets with New York’s efforts to promote clean energy and the “wave of change” sweeping the power industry.
All while still keeping an eye on long-term reliability for the state’s grid.
A look inside the NYISO Control Center, fully renovated in 2014 | NYISO
“Our [2018-2022] Strategic Plan reflects an approach of continuous adaptation to shifting market dynamics and a different industry paradigm,” NYISO CEO Brad Jones wrote in foreword to the plan, released Jan. 11. “It reaffirms our commitment to enhancing our markets, operations, and planning activities.”
Jones noted that “ongoing industry transformation” and New York’s “ambitious” energy policies will “redefine” the electricity system and wholesale markets.
“Long-term reliability depends upon finding ways to harmonize the competitive wholesale markets with the state’s actions to promote clean energy,” he said.
The broadly defined plan outlines several initiatives intended to help the ISO meet that goal over the next five years:
Enhancing energy and capacity markets to maintain reliability and improve the efficiency of markets.
Developing the tools necessary to operate the grid with increased numbers of distributed energy resources.
Assuming a pivotal role in integrating public policy objectives while maintaining fair and competitive markets.
Managing the increasingly “complex, costly” systems needed to run the grid and wholesale markets.
Becoming equipped to manage costs “in an environment of decreasing MWh throughput.”
The plan also lays out more concrete steps for NYISO.
| NYISO
To ensure reliability and competitive markets, NYISO will upgrade its energy management and business management systems and automate the interconnection queue. The ISO also plans to improve cyber security by improving security operations and enhancing perimeter defenses as well as overall security resiliency. (See RTO CEOs Discuss Cybersecurity, Integrating Renewables.)
Grid and market operations will incorporate new capabilities to support the integration of distributed energy resources (DERs) and improvements in wide area situational awareness in smart grid applications, the report said.
The plan also highlighted NYISO’s key accomplishments in 2017, which included publishing its DER Roadmap describing how the ISOs expects distributed energy resources to integrate into wholesale markets and working with the New York State Department of Public Service on pricing carbon into its wholesale electricity market. (See NYISO Readies Market for Energy Storage, State Targets.)
Power industry participants got their first “peak” at a potential organized market that could rival CAISO’s efforts to expand its own operations into the rest of the West.
During a conference call Tuesday, Peak Reliability and PJM Connext sketched out details on their proposed new Western electricity market, possibly setting up a battle with CAISO over who will oversee markets and reliability across the broad region.
Vancouver, Wash.-based Peak has for months been developing a proposal to expand its Reliability Coordinator (RC) services into a new West-wide energy market. It has partnered with PJM, which brings extensive experience and sophisticated knowledge from its Eastern market covering 13 states and the District of Columbia. (See PJMUnit to Help Develop Western Markets.)
Peak and PJM officials said the market would be nodal, with locational marginal pricing, real-time and day-ahead energy transactions, financial transmission rights, consolidated credit and market settlement, and optional services if desired by participants. These could include ancillary services such as regulation and reserve markets, demand response, a capacity market, and other features.
“Together we have climbed quite a mountain if you will, and this is the next logical step,” said Brett Wangen, Peak’s chief engineering and technology officer. He added that members would have a direct say in the market design and governance with the goal of reducing operating costs and improving reliability. “We definitely have been hearing the message that the industry is in need of these tools.”
Peak and PJM say they will leverage existing market tools and services | Peak Reliability
Wangen also addressed CAISO’s own plans to withdraw from Peak and offer its own reliability services to Western participants. (See Horse is Out of the Barn for CAISO RC Effort.) The ISO recently said it plans to allow Peak participants enough time to review its new RC proposal and switch from Peak to CAISO for services by spring 2019.
“This urgency that is being created is a red herring,” Wangen said. “People believe they have to make a decision in the next few weeks … clearly that is not the case.”
Peak said it is fully funded to provide its current reliability services through August 2019 and it could explore full RTO status after it deploys a new market structure. The organization will continue to be funded at current levels through June 2020, assuming no other members withdraw before September 2019.
Peak/PJM’s Concept for new market offering | Peak Reliability
Peak pointed out that participants could keep Peak as their RC whether they join the Peak/PJM market, participate in other markets such as SPP or CAISO, or continue with self-scheduling and bilateral contracts. They can also use Peak’s balancing authority services or continue with separate balancing authorities regardless of market participation.
Peak said it is developing a straw design for its proposed market and will complete a business case by the end of March or beginning of April. It will then lock in a final design and develop a memorandum of understanding for participation.
CAISO cited increased costs when it announced its plans to depart Peak and provide RC services across the West at much lower costs than are currently charged by Peak. During a conference call earlier this month, ISO officials said they plan to quickly transition current Peak members to CAISO services.
CAISO last month also said it will enhance and expand its day-ahead market across the footprint of its Western Energy Imbalance Market. (See CAISO Plan Extends Day-Ahead Market to EIM.) Peak Reliability member Mountain West Transmission Group is also in discussions to join SPP, and has asked SPP to become its reliability coordinator if it links up with that market.
Peak in 2014 split off from the Western Electricity Coordinating Council, a North American Electric Reliability Corp. Regional Entity based in Salt Lake City, Utah.
Peak on Tuesday said that the partnership’s existing capabilities will allow a relatively quicker development of a market and that a multiple state/province market “offers public policy balance.”
FERC last week rejected a key part of PJM’s controversial proposal to reallocate uplift costs, saying it had failed to justify its plan to begin charging up-to-congestion (UTC) transactions (ER18-86).
The order addresses Phase 2 of a three-phase proposal by PJM to address how to spread the costs associated with uplift more equitably. PJM proposed allocating uplift to UTCs in the same way it is applied to incremental supply offers (INCs) and decrement demand bids (DECs). INCs receive balancing — or real-time — operating reserves. DECs, which are treated like demand, are allocated both balancing reserves and day-ahead operating reserves because they allocated equally to demand bids and exports.
UTCs aren’t allocated any uplift because they were originally created as a way for market participants wheeling power through PJM to hedge against real-time congestion. They later evolved into purely financial products through a series of market rule changes, prompting FERC to open a Section 206 proceeding in 2014 to determine whether they were being improperly favored compared with other virtual transactions. (See FERC Orders Review of UTC Rules.)
Following a lengthy stakeholder proceeding that failed to produce a consensus proposal, PJM proposed treating UTCs as a separate INC and DEC, with the source side receiving balancing operating reserves and the sink side being allocated day-ahead and balancing operating reserves.
PJM argued that although UTCs can change what resources are committed in the day-ahead market and therefore affect uplift, it was “effectively impossible” to measure the impact of individual transactions.
But FERC said because the RTO had “not attempted to quantify the approximate magnitude of UTCs’ impact,” the filing lacked justification for the proposed cost allocation.
“We find that PJM has not adequately justified its supposition that UTCs behave in the markets with sufficient similarity to paired INCs and DECs to support allocating uplift to UTCs in the same way it allocates uplift to INCs and DECs,” the commission wrote. “While PJM claims that its proposal treats UTCs equivalently to INCs and DECs, we find that the proposal essentially allocates uplift to a UTC twice because the proposed allocation methodology would allocate uplift to a UTC as if it were instead a separate INC transaction and a separate DEC transaction.”
Commissioners also questioned the argument that UTCs are identical to a combined INC and DEC because the latter clear the market separately — “allowing for the possibility that one side of a pair may not clear” — while UTCs clear as a whole.
Uplift Proposal Not Dead
While FERC shut the door on this proposal, it remained open to an alternative method for allocating uplift to UTCs, saying, “We recognize that it may be appropriate to allocate some uplift costs to UTCs.”
Proponents of the proposal, including PJM’s Independent Market Monitor, had argued that UTCs carry comparatively lower costs per transaction than do INCs and DECs but are not exposed to the same energy pricing risk, fueling their growth to 80% of the virtual transaction market.
Monitor Joe Bowring found hope in the commission’s ruling.
“The IMM is disappointed in the commission decision but is encouraged by the commission’s openness to UTCs paying uplift,” Bowring said in an emailed statement. “It is clear that the current rules, which entirely exempt UTCs from paying uplift, provide a noncompetitive advantage to UTCs over other virtual trading instruments, as evidenced by the fact that UTCs have pushed the other instruments almost completely out of the market. Any proposal to continue a noncompetitive advantage for UTCs, even a reduced one, will not resolve the market design problem.”
Ruta Skučas, who represents the Financial Marketers Coalition, said members are “thrilled” by the ruling but frustrated that PJM’s stakeholder process did not pre-emptively address FERC’s concerns. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
“We think FERC made the right call,” she said. “We also wish that conversations with PJM and the stakeholders would have been more productive over the five years of the [Energy Market Uplift Senior Task Force]. We spent the better part of two years arguing that a double deviation could not possibly be just and reasonable, instead of working on more productive solutions.”
FERC last week denied FirstEnergy’s request to transfer ownership of a struggling coal-fired merchant generator to a regulated affiliate, saying the deal isn’t in the public interest because it resulted from an “overly narrow” solicitation (EC17-88).
The affiliates argued that the transaction was ostensibly exempt from meeting a rule prohibiting cross-subsidization because it must also be approved by the West Virginia Public Service Commission, but FERC said that didn’t satisfy necessary standards.
“Applicants have provided no evidence that any ratepayer protections regarding cross subsidies are proposed in the proceeding before the West Virginia commission,” FERC wrote.
RFP
The issue dates to March 2017, when FirstEnergy merchant affiliate Allegheny Energy Supply requested permission to transfer ownership of the 1,159-MW Pleasants Power Station to Monongahela Power, with the latter assuming a $142 million obligation for pollution controls Allegheny installed at the plant.
Pleasants Power Station
Mon Power is a regulated utility in northern West Virginia, where Pleasants is located. The utility issued a request for proposals to acquire approximately 1,300 MW of unforced capacity and up to 100 MW of demand response in PJM’s Allegheny Power Systems zone after its 2015 integrated resource plan indicated it would begin having a capacity shortfall in 2016. Charles River Associates, which managed the RFP, identified 28 suitable prospects and recommended acquiring the Pleasants facility, located in Willow Island, W.Va.
Restrictive Requirements
FERC said the RFP was “overly narrow … because the stated objective could have been achieved if the RFP considered [power purchase agreements] and resources that were outside of the APS zone.”
Mon Power’s requirement that it acquire facilities — because of the “increased control and flexibility asset ownership affords,” it said — could instead have been an evaluation factor, “rather than eliminating from consideration an entire class of offers that could have been used.” The commission said two bids for PPAs that weren’t evaluated showed “the desire of bidders to offer PPAs.”
The utility had argued that getting a resource in the APS zone “eliminated” the risk of incurring Capacity Performance penalties because PJM allows resource performance to be netted within zones. But FERC called that risk “rare,” making the limitation “overly restrictive.”
FERC also criticized the RFP’s evaluation method for lacking transparent scoring criteria; announcing a preference for facilities that “can be cost-effectively and efficiently incorporated” into Mon Power’s existing “operating and corporate frameworks;” and using a 15-year net present value metric.
“While we acknowledge that the estimates of future expenses and revenues become more uncertain the further into the future that they are projected, and that the NPV contribution of the years beyond 15 is less important than those within the evaluation period due to discounting, ignoring those future years nevertheless would give advantage to a facility with a low purchase price and higher future costs, such as the affiliated Pleasants facility,” the commission found. “An NPV calculation that calculates the total value of the proposal, including a terminal value, would more closely capture the comparable economics of each proposal.”
Guidance
The commissioners also provided guidance for how Mon Power should have conducted the solicitation.
“While we appreciate and recognize Mon Power’s legitimate need to address a potential capacity shortfall and to provide for its future capacity and energy needs, it should do so in a way that provides non-affiliate competing suppliers with the same opportunity as an affiliate to meet the utility’s needs,” the commission said.
It disagreed with arguments questioning the need for generation or the accuracy of the load forecasts in Mon Power’s IRP, which it said is the role of the state PSC. FERC also dismissed concerns about Charles River’s independence and the restrictiveness of submission timelines.
Consumer advocates and environmental activists had opposed the proposal.
The West Virginia Consumer Advocate said the deal was an attempt to relieve Allegheny of “an aging coal plant that is no longer economic in the PJM” markets.
“In this decision, the FERC commissioners — four of whom were appointed by the current president — unanimously rejected a brazen attempt to force Mon Power … customers to guarantee profits for FirstEnergy and its shareholders,” said Earthjustice attorney Michael Soules. “This is a major victory for West Virginia customers, who would have likely paid hundreds of millions of dollars if FirstEnergy’s scheme had succeeded.”
FirstEnergy spokesman Todd Meyers said the company believes “the decision does not recognize the benefits this vital transaction would bring to our West Virginia customers, including reliable electricity and reduced electric rates, along with creating additional benefits for West Virginia’s economy.”
“We will thoroughly review FERC’s order and carefully evaluate our next options,” Meyers added.
FERC’s ruling last week that “resilience” is not simply a matter of onsite fuel supply won nearly universal praise outside the coal and nuclear industries.
Foley | American Council on Renewable Energy
On Tuesday, a coalition of clean energy advocates and trade groups for the wind, natural gas, solar and storage industries held a celebratory press conference where they praised the ruling as a win for consumers and a sign that the new commission — including three Republicans appointed by President Trump — will remain independent.
“FERC continues to demonstrate that it takes its independence very seriously,” said Todd Foley, senior vice president for policy and government affairs for the American Council on Renewable Energy.
“The professionalism of the [staff and commissioners] — in looking at the question posed by the secretary based on the record before them and thoughtfully determining a path forward — I think is encouraging,” agreed Malcolm Woolf, senior vice president of policy for Advanced Energy Economy.
But while the coalition found unity in opposing Energy Secretary Rick Perry’s price supports for coal and nuclear plants, their interests may diverge in the new docket the commission ordered.
FERC directed RTOs and ISOs to answer questions on how they assess and obtain resilience. The initiative could result in proceedings that pit renewables, natural gas and storage against each other — as well as nuclear and coal — in seeking compensation for their resiliency attributes. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Seeking Market Solutions, Fair Competition
FERC made clear in its ruling that it did not agree with Perry’s embrace of onsite fuel storage as a resiliency panacea.
“That’s maybe one element, but it’s certainly not the only element,” Woolf said. “What really matters is overall system reliability and resilience. We saw from the bomb cyclone of the last week that a nuclear plant — Pilgrim, otherwise perfectly reliable — was forced to shut down because of transmission issues.
“We’re confident [that] as they do this, [FERC] will recognize that advanced energy technologies, including distributed energy resources, energy efficiency, demand response, storage, renewables [and] natural gas … all have a role to play in making a robust system and that the market needs to value the attributes of all of those different technologies.”
Jason Burwen, vice president of policy for the Energy Storage Association, said at the press conference that his group will be watching “whether there will be an opportunity for market mechanisms to be employed such that the full range of resilience attributes — not just a single one like fuel assurance — can be valued and compensated. … Additionally, we look forward to seeing whether there will be a discussion of the infrastructure component of this — not simply the generator resources or demand resources side of this.”
Wiggins | U.S. Energy Association
The California Public Utilities Commission in 2013 ordered the state’s three large investor-owned utilities to add 1.3 GW of energy storage by 2024. The order implemented Assembly Bill 2514, in which the legislature ordered procurement of storage to reduce investments in new fossil fuel plants, integrate renewables and minimize greenhouse emissions.
Dena Wiggins, CEO of the Natural Gas Supply Association, said her group was “relieved” by FERC’s decision. “What we were looking for all along was a robust discussion that would value the attributes of all of the fuels. All of the fuels … bring something to the conversation.”
Whitten | SEIA
“It’s not only valuing those essential reliability services but … making sure there’s no discrimination as to who can actually compete to provide those services,” said Amy Farrell, senior vice president of government and public affairs for the American Wind Energy Association. “The market should reward the desired resilience attributes in a resource-neutral manner, with every provider being paid the same price for providing the same unit of service,” she added afterward.
“I think we’re all in violent agreement,” said Dan Whitten, vice president of communications for the Solar Energy Industries Association. “What we want is the opportunity to compete, and we think the FERC decision … presents that opportunity.”
The new proceeding ordered by FERC will require the RTOs to show how they are obtaining what NERC has named “essential reliability services,” including frequency and voltage support, ramping capability, operating reserves and reactive power. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)
| PA Consulting Group analysis
Last August, the American Coalition for Clean Coal Electricity (ACCCE) released a PA Consulting Group study it commissioned that ranked generation resources on 11 attributes, giving coal high marks in all but black start capability. (See Echoing DOE Report, Industry Study Touts Coal ‘Resiliency’.)
The report followed a study done by The Brattle Group for the American Petroleum Institute (API), which concluded that gas-fired generation is “relatively advantaged” in all but one of the 12 attributes it identified. (See NG Lobby Goes on Offensive vs Coal, Nukes.)
The next best alternative source, according to Brattle, was pumped hydro with 10. Nuclear and coal, the potential beneficiaries of policies favoring traditional “baseload” generation, fared far worse at five and four respectively, as did wind (one) and solar (two).
| The Brattle Group
The API-Brattle report ranked coal as “neutral” on two categories for which ACCCE claimed a full score — frequency response and ramp rates (referred to as “ramp capability” by ACCCE). API did not score three categories in which ACCCE said coal had an advantage over gas: onsite fuel supply, reduced exposure to a single point of disruption and price stability.
AWEA said the API-Brattle findings are “largely consistent” with those of the Analysis Group in a report the organization commissioned. But the wind group disputed Brattle’s designation of wind as “relatively disadvantaged” in frequency response, saying wind turbines “can provide frequency response that is an order of magnitude faster than conventional power plants.”
The Nuclear Energy Institute (NEI) responded that “the Brattle study reinforces the conclusion that grid reliability would be hopelessly compromised without nuclear energy.”
NEI CEO Maria Korsnick said last week that RTOs must take “prompt and meaningful action, including on issues such as price formation.”
“The status quo, in which markets recognize only short-term price signals and ignore the essential role of nuclear generation, will lead to more premature shutdowns of well-run nuclear facilities,” she said.
GHG Emissions and Resilience
Some say resilience efforts also should consider the impact of fossil fuel generators’ emissions.
In his concurring opinion last week, new Democratic Commissioner Richard Glick noted the “irony that the [Department of Energy’s] proposed rule would exacerbate the intensity and frequency of … extreme weather events by helping to forestall the retirement of coal-fired generators, which emit significant quantities of greenhouse gases that contribute to anthropogenic climate change.”
Last month, fellow Democratic Commissioner Cheryl LaFleur said FERC’s environmental reviews of natural gas pipeline applications should consider “the downstream impacts on greenhouse gases.”
None of the three Republicans on the commission has publicly indicated they agree with the Democrats’ concerns, however. As a member of the Pennsylvania Public Utility Commission, Commissioner Robert Powelson was a strong supporter of the state’s shale gas development. Commissioner Neil Chatterjee, of Kentucky, is an unapologetic booster of coal.
“The fact is that we need an electric grid regulatory agency which prioritizes a rapid shift from dirty and dangerous fossil fuels to renewable energy and energy efficiency,” Ted Glick (no relation to Commissioner Glick), an organizer with the anti-gas group Beyond Extreme Energy, said after FERC’s rejection of the NOPR. “We doubt that FERC can become such an agency.”
Coal interests are certain to resist any new FERC rules that speed the erosion of their generation market share.
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Robert E. Murray, CEO of coal producer Murray Energy, said FERC’s ruling was a “bureaucratic cop-out” that exposed consumers to high costs and service interruptions.
“If it were not for the electricity generated by our nation’s coal-fired and nuclear power plants, we would be experiencing massive brownouts and blackouts,” he said, citing power prices that peaked at more than $500/MWh and natural gas prices that hit $175/MMBtu during the cold snap in early January. “At least 37,000 MW of supposedly natural gas-powered electricity were entirely unavailable due to the priority for home heating use and the inability of natural gas to flow at cold temperatures.”
What is “resilience?” How can you measure it? And how much can be achieved through just and reasonable rates?
Those are the questions FERC and grid operators will be answering following the commission’s rejection last week of Energy Secretary Rick Perry’s proposed rulemaking to benefit coal and nuclear generators (RM18-1).
FERC’s ruling created a new docket (AD18-7) and requires RTOs and ISOs to respond to two dozen questions about how they assess resilience. The commission said it will use the responses to determine whether additional action is necessary. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Defining, Measuring Resilience
FERC teed up the new proceeding by inviting comment on its suggested definition of resilience: “The ability to withstand and reduce the magnitude and/or duration of disruptive events, which includes the capability to anticipate, absorb, adapt to and/or rapidly recover from such an event.”
It also asked grid operators to identify what attributes contribute to resilience and how they will obtain them. They are likely to look to NERC’s definition of “essential reliability services,” which the commission also referenced in its order. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)
FERC offered less guidance on how the grid operators can measure resilience. There is no widely embraced equivalent to the one-day-in-10-years loss-of-load expectation used as a reliability benchmark.
Also unclear is how much it could cost to meet such a resiliency target; any proposal that increases costs is likely to face opposition from stakeholders serving load. In PJM, for example, load representatives — who have long complained of paying for excessive capacity reserve margins — are opposing the RTO’s “price formation” proposal that could boost costs by as much as 5%.
In FERC filings in October, RTO officials and their Market Monitors unanimously rejected Perry’s Notice of Proposed Rulemaking as expensive, inefficient and counterproductive. (See RTOs Reject NOPR; Say Fuel Risks Exaggerated.)
Predictions
Stoel Rives attorney Jason Johns | Stoel Rives
ClearView Energy Partners said it is “skeptical of FERC making findings within this docket that lead to determinations that existing tariffs in particular RTOs are suddenly unjust and unreasonable on resiliency grounds.”
“Substantive changes to energy market tariffs to increase compensation for ‘baseload units’” are unlikely, ClearView added. FERC “may be more likely to pursue a rulemaking, or set of issue-specific rulemakings or policies, instead.”
“I think it’s safe to say that what comes of compensating resources for ‘grid resiliency,’ to the extent it occurs, will look little or nothing like what Secretary Perry had intended,” wrote Jason Johns, a partner with Stoel Rives, in a blog post.
Prior Efforts
The commission started the grid operators’ 60-day clock with the issuance of the order, making the deadline for their answers March 9. Responses to the filings will be due in an additional 30 days.
The new proceeding will be informed both by state initiatives to preserve in-state generation and RTO efforts that began before Perry’s NOPR and the Department of Energy grid study that preceded it.
The coal and nuclear industries say the RTOs have not addressed market failures unfairly punishing their generators.
“The few revisions to existing RTO/ISO tariffs and related market structures and rules have so far been much too little and far too late,” the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association said in a joint FERC filing in October. “Without action by the commission to remedy these tariffs and market structures, the electric system will devolve to lose the value of fuel diversity and end up overwhelmingly dependent on intermittent renewable and natural gas generation.”
Below is a summary of the RTOs’ prior comments on their resilience efforts and issues that may factor in the new proceeding.
CAISO: Resilience ‘Mechanisms in Place’
CAISO told FERC last year that Perry’s proposed rule would not apply to it because it does not have a capacity market, nor coal or nuclear resources that would be eligible for compensation.
CAISO “already has mechanisms in place that ensure” its resilience, the ISO said. “Regional planning, procurement, coordination, programmatic and reliability efforts in the CAISO [balancing authority area] have produced a diverse infrastructure and ‘set of tools’ that have enabled the CAISO to operate a system that has remained both reliable and resilient in the face of significant threats to the loss of supply such as with the restricted operations of the Aliso Canyon gas storage facility, the unexpected shutdown of the San Onofre Nuclear Generating Station, fires affecting transmission lines, severe droughts and the solar eclipse.”
ISO-NE: ‘No Urgent Need’
ISO-NE told FERC in October that “New England has no urgent need to rush to a solution, given that the three-year Forward Capacity Market has ensured resource adequacy until at least 2021, and the region has already taken steps to improve operating procedures and generator incentives to secure firm fuel supplies.”
Last week, the RTO asked FERC for approval of a controversial two-stage capacity auction intended to replace aging fossil fuel generators with renewable resources from state procurements. (See ISO-NE Files CASPR Proposal.)
| PJM
The RTO says it has improved gas-electric coordination to mitigate supply problems arising from natural gas pipeline constraints. Its Pay-for-Performance program, which offers compensation for dual fuel generators and increases penalties for those who fail to meet capacity obligations, takes effect June 1.
But New England remains vulnerable to the limits of its gas pipeline system, leading some to suggest resilience measures should include contingency plans that consider the loss of a pipeline supplying multiple generators.
“You’d probably be the market that keeps me up at night,” Commissioner Robert Powelson told ISO-NE Vice President of System Operations Peter Brandien in October, when RTO officials made their annual presentations on winter preparedness.
SPP, Exempt from NOPR, ‘Will be Engaged’
SPP was not covered by Perry’s proposal because the RTO lacks a capacity market. The RTO said last week it “applauds FERC’s decision and appreciates [its] commitment, through the opening of a new docket, to continue to ensure our nation’s electric grid is both reliable and resilient. As with all of FERC’s efforts, SPP will be engaged in this new docket.”
The RTO has been integrating increasing amounts of wind, thus far without reliability problems. Last month, the RTO set a new record for wind penetration (56.25%), lending credence to its claims that it can handle penetration levels as high as 75%.
SPP’s 40% capacity margin is well above the 12% minimum required by the SPP Tariff, Keith Collins, executive director of SPP’s Market Monitoring Unit, noted in comments to FERC in October.
MISO Welcomes ‘Broader’ Discussion
MISO spokesperson Mark Brown said last week the RTO is looking forward to a “broader industry discussion around resilience and its importance” with FERC, state regulators and other industry officials.
“As FERC noted in its order, MISO is involved in ongoing development of a long-term plan to address changing system needs as the resource mix evolves,” Brown said in a statement to RTO Insider. MISO’s plan involves multiple studies, including an analysis on the challenges of integrating growing volumes of renewable generation and how the natural gas supply affects its dispatch ability. (See MISO in 2018: Storage, Software, Settlements and Studies.)
The RTO has been stymied in its attempts to address resource adequacy concerns in Zone 4 in Southern Illinois, where Dynegy has threatened to close some of its coal-fired generation, citing insufficient capacity revenues.
The Illinois Clean Jobs Coalition responded to the FERC ruling by urging the ICC “follow the lead of FERC and reject Gov. Rauner’s proposal to bail out uneconomic coal plants in Illinois.”
The commission will hold another workshop Jan. 16. Final comments on the issue are due Jan. 30, and the commission is expected to issue a summary report by Feb. 26.
PJM Price Formation Proposal Faces Opposition
PJM responded to the DOE NOPR by calling for rule changes that would allow inflexible generators, including coal and nuclear plants, to set LMPs. At its final stakeholder meeting of the year, the RTO won endorsement for a stakeholder task force to examine the current rules and recommend fixes.
PJM estimates the energy market changes will reduce capacity market costs but still increase overall costs between 2 and 5% ($440 million to $1.4 billion annually). (See Rule Changes Could Spur $1.4B Jump in PJM Market Costs.)
Conesville Coal-Powered Plant
Monitors, regulators and other RTOs filed comments opposing PJM’s proposal in November. PJM Independent Market Monitor Joe Bowring said the plan would undermine the RTO’s markets and suggested that the RTO was acting in the interest of Exelon, which would be the biggest winner from a boost to nuclear plants. (See NOPR Reply Comments Bring More Criticism of PJM Proposal.)
Beginning in delivery year 2020/2021, all PJM capacity resources must meet the RTO’s Capacity Performance requirements. The CP program employs performance penalties and bonuses like ISO-NE’s Pay-for-Performance initiative.
ERCOT Joining with PUC on Response
At the Texas Public Utility Commission’s open meeting Thursday, Chair DeAnn Walker said she is working with ERCOT CEO Bill Magness and General Counsel Chad Seely to prepare a response to FERC’s order.
ERCOT’s markets are not regulated by FERC, but the grid operator is subject to mandatory reliability rules overseen by the commission and NERC. The PUC has always aggressively defended ERCOT’s independence from federal oversight.
Walker characterized the filing as informational, saying it would “explain how we do things here.” She said she, ERCOT’s leadership and Texas Reliability Entity CEO W. Lane Lanford “have similar thoughts about how broad” FERC’s request is. She promised further details for a February open meeting.
FERC’s influence on the future of coal and nuclear generation will not be limited to the new docket. It may again be asked to weigh in on whether state efforts to support in-state generators violate federal jurisdiction. The Supreme Court has ruled on three cases concerning state-federal jurisdiction since 2015. (See Court’s Reticence Frustrates Energy Bar.)
The commission already has pending a request from the Electric Power Supply Association to apply the minimum offer price rule to nuclear units receiving payments under Illinois and New York’s zero-emission credit programs. The ZEC programs are also being challenged in federal court. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)
NYISO Moving on Carbon Pricing
Despite the legal challenge to its ZEC program, New York officials last week continued working on their plan for funding the subsidies — integrating carbon pricing in NYISO’s wholesale electricity markets. (See New York Stakeholders Debate Carbon Policy ‘Issue Tracks’.)
“There is no imminent threat to reliability,” NYISO told FERC in October. During the 2014 polar vortex, NYISO noted, it set a new record winter peak load and “met all reliability criteria and reserves requirements without activating emergency procedures at any time during the winter operating period. It did so despite significant generator capacity derates on some of the coldest days, including generation resources that would appear to qualify under the NOPR as ‘eligible grid and reliability resources.’”
The ISO said it has made improvements to its energy, ancillary service and capacity markets, including basing the downstate installed capacity demand curves on peaking plant designs that include dual-fuel capability.
State Initiatives
Here are some of the state initiatives that could become factors:
The New Jersey Legislature is expected to consider a ZEC-style plan in its 2018-19 session. ClearView analysts last week gave the plan a 65% chance of success, saying the Democrat-controlled legislature’s refusal to consider the bill in the lame duck session was intended to deny outgoing Republican Gov. Chris Christie a policy “win.” (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
| Department of Energy, Staff Report to the Secretary on Electricity Markets and Reliability, August 23, 2017
Ohio lawmakers last year proposed legislation (H.B. 381 and S.B. 128) that would create a ZEC-style program that would benefit First Energy Solutions’ Davis-Besse and Perry nuclear plants, but the bills did not move out of committee. The term of Gov. John Kasich, who has opposed a nuclear “bailout,” expires in January 2019.
Connecticut is also considering whether it needs to sign a long-term power purchase agreement to keep the Millstone nuclear plant operating amid a dispute over the plant’s profitability. (See related story, Conn. Regulators Hear Conflicting Advice on Millstone.)
“We applaud the commission for upholding the rule of law and taking the only appropriate actions under the circumstances,” the National Association of Regulatory Utility Commissioners said in a statement last week. “We also appreciate FERC’s acknowledgment that resilience issues ‘extend beyond the commission’s jurisdiction’ and its explicit encouragement for interested entities to engage with state regulators and others to address resilience at the distribution level.”
Amanda Durish Cook and Tom Kleckner contributed to this article.
AUSTIN, Texas — Taking a cue from other state regulators, the Public Utility Commission on Thursday took its first steps in determining how to share federal corporate tax cuts with ratepayers.
PUC Chair DeAnn Walker directed staff to begin gathering information from utilities and considering legal options to recover the savings. She referred to 1987, “when similar things were done” following tax cuts under President Ronald Reagan.
Southwestern Electric Power Co., Oncor and El Paso Electric have already agreed to claw back tax savings during recent rate-case settlements. Two additional utilities are scheduled to undergo rate reviews in May.
The commission, which hopes to avoid a rulemaking, will take up the issue again during its Jan. 25 open meeting.
Commission to Strengthen Education Efforts with Legislature
The commission agreed with Commissioner Brandy Marty Marquez’ suggestion to “re-up” its efforts to educate state legislators and others about potential price spikes this summer in the wake of recent plant retirements.
“To quote someone else, this is an opportunity for our market’s finest hour,” Marquez said, referring to Winston Churchill. “I think we’re going to be fine … we just need to make sure people are educated about how our market works. People need to know what’s going on and prepare for it, because this is part of a natural cycle.”
Cheaper renewable and gas-fired energy has reduced coal generation’s share of ERCOT’s production to less than a third and led to a wave of coal-fired retirements last year. That, in turn, sliced the ISO’s planning reserve margin to 9.3% for this summer. (See Wind Nearing Coal as ERCOT Ponders Thinning Reserves.)
Walker said she has already briefed Gov. Greg Abbott on possible “price elevations” this summer. She decried comments made last year during PUC-led workshops on scarcity pricing and other price-formation issues in ERCOT’s energy-only market (47199). (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
“A lot of people used 47199 as rhetoric to scare people, including us,” Walker said. “We need to say we think we have this.”
Staff Publishes Revisions to IOU Earnings Reports
PUC staff on Friday published its proposal for revising the earnings monitoring reports that investor-owned utilities must file. The reports reflect the 12-month period ending Dec. 31 and are due by May 15.
Staff originally intended to make only minor revisions but added other modifications reflecting recent changes to federal income tax law and eliminating two schedules because of recent legislation.
Invenergy-CSW Energy Joint Venture Approved
The PUC approved a joint venture between Invenergy Renewables and CSW Energy to repower a pair of West Texas wind farms. Invenergy will become a 20.1% owner of the Trent Wind Farm and Desert Sky Wind Farm, with CSW holding on to the remaining 79.9% (47637).
Desert Sky Wind Farm | AEP
The wind farms currently have 207 1.5-MW turbines for a capacity of 310.5 MW.
CSW is a wholly owned subsidiary of American Electric Power, retaining its name following the 2000 merger between AEP and Central and South West.
