Stakeholders have responded to ISO-NE’s filing of a proposed two-stage capacity auction with a flurry of comments to FERC — many of them opposing the measure.
The vetting process for the Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, and the late changes made by the RTO, left state regulators and stakeholders divided. Vermont, Connecticut and Rhode Island opposed the CASPR proposal filed with FERC, while Massachusetts, New Hampshire and Maine supported it. (See ISO-NE Effort to Accommodate States Leaves them Alienated.)
The proposal (ER18-619) grew out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, launched in August 2016 to address state regulators’ concerns about ratepayer costs associated with policy-driven resources and generators’ fears that out-of-market procurements of renewable generation would suppress capacity prices.
Bay State Division
The controversy has even split officials within Massachusetts. In separate comments filed Jan. 29, the state’s attorney general urged the commission to reject or change the proposal, while the Department of Public Utilities “strongly” supported it.
Attorney General Maura Healey said in her filing that “the current incarnation of CASPR does not allow for any regular or reliable integration of sponsored policy resources” into the Forward Capacity Market.
| ISO-NE
Healey asked the commission to reject CASPR “because it will lead to unjust and unreasonable rates for New England consumers, who will pay twice for the same capacity,” and remand it with an order for remedial action to incorporate a mechanism like the “backstop” proposed by the New England States Committee on Electricity, which would guarantee entry into the FCM every year for a minimum of 200 MW of sponsored policy resources.
She also suggested the commission could remand the proposal with an order to reinstate the renewable technology resource (RTR) exemption to the minimum offer price rule (MOPR), which CASPR proposes to eliminate.
The DPU, on the other hand, argued that CASPR would “provide a competitive, market-based approach” to allowing policy-driven resource into the FCM and “prevent direct harm to Massachusetts ratepayers and the inefficient development of more generation resources than the region requires, while preserving competitive price formation and nondiscriminatory participation in New England’s FCM.”
Conditional Support
In its Jan. 29 filing, NESCOE said the RTO’s “commitment to monitor CASPR’s performance and to propose appropriate remedies is critical — and a condition of NESCOE’s support.” The group also pointed to the RTO’s pledge to work with stakeholders to “refine or replace” CASPR if it fails to achieve its intended purpose of accommodating state entry over time.
“ISO-NE must revise CASPR if it falls short of its intent to accommodate the participation of state-sponsored resources or if it proves inflexible to the execution of state laws, which are not static,” NESCOE said.
Calpine sided with the New England Power Generators Association in supporting the proposal, calling it “a considered and reasonable compromise to allow state-sponsored new resources into the Forward Capacity Market, while minimizing the impact on competitive market pricing.”
In guardedly supportive comments filed Jan. 19, NEPOOL noted that its Participants Committee failed in December to approve the CASPR proposal, with a 57.75% vote in favor (60% being required to represent substantial approval).
Despite that shortfall in institutional support, NEPOOL said its stakeholder process on CASPR “narrowed, and in many cases resolved, a number of complex and interrelated issues, and certainly broadened the understanding and perspectives of all interests in the region.”
NEPOOL predicted FERC would confront disparate opinions and urged the commission “to exercise caution in parsing through these concerns and their interrelationship with each other.”
Does the FCM Matter?
Consumer advocacy group Public Citizen questioned the RTO’s motives and the overall need for the FCM.
“By prematurely submitting this CASPR experimental rate design against the wishes of its stakeholders, it appears as though ISO-NE is more concerned with preserving its competitive markets from the encroachment of non-market capacity additions, regardless of whether extending a ‘market-based’ mechanism over policy-procured capacity will result in just and reasonable rates,” the group said.
Public Citizen argued that “the question should therefore not be how to force policy-deployed capacity into the … market, but whether the capacity market is needed at all. Because non-market factors are clearly adding adequate capacity for New England.”
In a joint filing, he American Wind Energy Association, Conservation Law Foundation, Natural Resources Defense Council, RENEW Northeast, Sierra Club and the Sustainable FERC Project urged the commission to either retain the current RTR exemption or direct the RTO to provide a sufficient similar, alternative mechanism that would enable state-mandated renewable energy resources to participate in the FCM and make the market account for the capacity contributions of these resources should CASPR fail to do so.
The groups encouraged the commission “to re-examine the logic of applying the MOPR to clean energy resources being driven by legitimate state policies, which we believe inappropriately encroaches on state authority while lowering market efficiency and imposing unjust and unreasonable costs on customers.”
ARLINGTON, Va. — FERC’s enforcement policy is unlikely to shift significantly despite the arrival of four new commissioners, a panel of present and former FERC staffers said Monday. But the commission should consider some process changes and provide more clarity in defining violations, several speakers said.
“I think the fundamentals of enforcement don’t change with any administration,” Tim Helwick, special counsel in FERC’s Division of Analytics and Surveillance, told the EUCI Financial Transmission and Auction Revenue Rights conference. “I think priorities can change with different personalities — it’s not a question of politics, just different personalities.”
Helwick’s comments came at the end of a 90-minute discussion before an audience of about 40 traders, regulators, and others that noted the growth of FERC’s enforcement unit since the Western Energy Crisis in 2000-2001. Once limited to a handful of staffers, FERC’s Office of Enforcement (OE) now numbers more than 200, with greatly expanded power to impose penalties under the Energy Policy Act of 2005.
“I think it’s too early to tell what type of change we’re going to see, and I don’t necessarily anticipate that we are going to see significant change,” agreed attorney Terence Healey, a partner with Sidley Austin and the only one on the panel without a FERC résumé listing. “You’re dealing with an agency that’s 200-plus folks that were there before the current administration. … I wouldn’t expect the fundamentals to change.”
Enforcement Director Larry R. Parkinson was appointed in April 2015, after five years as director of OE’s Division of Investigations.
He noted the commission’s annual enforcement report, released in November, indicated FERC would continue to focus on the same priorities in 2018 as in 2017: fraud and market manipulation; serious violations of NERC reliability standards; anticompetitive conduct; and conduct that threatens market transparency. (See Investigations up Sharply in FY 2017, FERC Report Shows.)
“I would take them at face value on that,” he said. “Whether certain cases on the edge should be brought, I could see changes like that.”
De Novo Procedures
He said the commission might consider changing its processes due to the number of enforcement cases ending up in federal court and because its decision to make early public disclosures about investigations has not worked as intended.
A 2009 policy change gave the Director of Enforcement authority to issue a Notice of Alleged Violations (NAV) that includes the identities of investigation subjects and a description of their alleged misconduct once the subject has responded to staff’s preliminary findings but before it finalizes its findings and the commission issues an order.
Previously, the commission kept investigations and the identities of investigation subjects private until FERC initiated an enforcement action or issued an order approving a settlement. FERC said it hoped the transparency would warn other market participants to steer clear of questionable trades and prompt them to bring evidence to staff.
“Maybe it’s time to rethink that. … because it’s something that’s not really produced what the commission intended it to be, which was to flag [concerns] for the market,” Healey said.
Healey also noted the increasing number of subjects choosing de novo hearings in federal court rather than having an administrative law judge rule on the merits of FERC’s allegations.
“At least six separate district courts have said if you remove [a case] to federal court, you get a trial” with the ability to supplement the administrative record created by Enforcement, cross-examine witnesses, and seek discovery, Healey said.
Healy said FERC could consider streamlining its process because it is subject to a five-year statute of limitations.
“FERC took the position that they satisfied the five-year statute of limits upon initiating an order to show cause,” he said. “ … We had a decision in the Barclays case that found it is satisfied when you file in federal court, and because of that, one of the respondents had his case tossed out.” (See FERC Settlement Cuts Barclays Market Manipulation Fine.)
The panelists said they saw no indication the new commission would consider licensing power and gas traders as is required of securities traders.
Licensing would be opposed strongly by traders and is “not likely in this administration,” said Chloe Cromarty, compliance manager for Mercuria Energy Trading and a former FERC analyst. “But all it takes is one big case to be a catalyst,” she acknowledged.
‘Vague Standard’
Panel moderator Shaun Ledgerwood, a principal in The Brattle Group and a former FERC economist and attorney, said the commission still has not provided a clear definition of “market manipulation.” Ledgerwood recalled asking for a definition during his job interview at FERC in 2008 and only being told, “You know it when you see it.”
“I thought, ‘Man, that’s a pretty vague standard,’” said Ledgerwood, who specializes in the economic analysis of market manipulation claims, “and as time has gone on, what I’ve seen is that the commission has tried to … show examples of what manipulation is … misrepresentation, gaming, cross-product manipulation … The reality is there is no definition yet of what exactly is manipulation nor — perhaps more importantly — what exactly is legitimate.”
Healey agreed: “We’re still struggling to try to understand what … FERC is going to view as manipulation. As of yet, we don’t have a district court that has actually opined on some of the back and forth on what fraud means.”
The lack of clarity creates headaches for compliance officials, Cromarty said.
She said her company runs its trades through screens to identify transactions that may trigger an investigation — for example, comparing proposed virtual transactions against financial transmission rights (FTR) positions or flagging trades involving new products or a marked increase in trade volumes.
“As a major FTR [financial transmission rights] trader, at any given time, we may hold more than 200,000 paths. Expecting one trader to know another trader’s position is not practical,” she said.
“One trader may hold an FTR position where another trader wants to execute some virtual trades — and we may be flowing physical power across that path as well,” she explained. “We’re making the decision to prohibit one trader from transacting — in my opinion, legitimately — in order to avoid tripping the [FERC] screens because any revenue we make from transacting in that way is not significant enough to justify the potential regulatory risk that we’re facing. From my perspective, I think that’s having a negative impact on liquidity.”
Ledgerwood agreed. “You know if you get involved in the [investigative] process, it’s likely to be protracted. Not only is that expensive, it also takes a lot of psychic energy away from traders and the companies and their compliance personnel.”
Healey and others said they recommend traders put their plans in writing when they adopt a new strategy or engage in a particularly complex transaction. “It’s not a silver bullet, but it does provide a contemporaneous account for the intent of the trader at the time,” Healey said. “So long as it’s truthful and contains all the information — otherwise it’s problematic for obvious reasons.”
RTO Officials Discuss FTR Changes
In an earlier discussion Monday, ERCOT’s Carrie Bivens, MISO’s Blagoy Borissov, and PJM’s Brian Chmielewski talked about how their regions addressed revenue shortfalls in their FTR markets, while a CAISO official acknowledged “revenue adequacy continues to be a challenge” in California.
Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, said the problem is a “misalignment” between CAISO’s congestion revenue rights auction and its day-ahead market.
Dominion Energy CEO Thomas Farrell expressed confidence Monday that his company’s lobbying in Connecticut and Virginia are on track to benefit the company.
Executives speaking during the company’s fourth-quarter and year-end earnings call also outlined strategies to take advantage of the recently enacted federal tax breaks and spoke about the political uncertainty surrounding the company’s bid to take over SCANA, the South Carolina utility beleaguered by a failed nuclear project.
The company announced it performed right in the middle of its guidance for 2017, reporting operating earnings of $3.60/share. Mild weather throughout the year reduced earnings by $0.10/share, though weather-normalized electric sales for the year increased 1.7% over 2016, led by growth and sales to data centers and residential customers.
Unadjusted earnings were $4.93/share for the year, thanks primarily to tax reforms that created a $988 million gain from adjustments to a deferred tax liability. Revenues increased 4% for the year to $3.21 billion but fell short of a consensus forecast of $3.47 billion.
Regulatory Progress and a Mystery Bill
“We have worked with the regulatory agencies, including the sharing of confidential financial information, to convey the actual cost of operating two dissimilar units in a high regional labor market,” Farrell told analysts, referring to this month’s preliminary report from Connecticut state agencies that determined the profitability of Dominion’s Millstone nuclear facility in Waterford, Conn., can’t be confirmed without additional financial disclosures from the company.
Dominion expects Connecticut state agencies to acknowledge the financial instability of its Millstone nuclear generation station. | NRC
The report, jointly developed by the state Department of Energy and Environmental Protection and Public Utilities Regulatory Authority, recommends a statewide procurement of carbon-free electricity from new and existing sources. Without additional information proving Millstone’s instability, its bids would be analyzed on price alone. With that information, the bids could be evaluated on broader criteria. A final draft of the report is expected Feb. 1.
“We are looking forward to the opportunity to compete with other non-emitting generating resources in a state-sponsored solicitation for zero carbon electricity,” Farrell said.
Paul Koonce, who heads Dominion’s generation arm, sounded eager to shut down any speculation about how Millstone might be bid into the solicitation. After misinterpreting a question about whether the plant would be bid into the process as an inquiry into the amount of its bid, Koonce declined to specify, calling the information “obviously competitively sensitive.” He said the state’s final report will likely lead to a request for proposals issued around May “and then we will submit our bid as any others.”
Farrell also addressed the potential benefits of a bill advancing through the Virginia legislature but offered scarce details.
“Virginia moves legislation through in a very rapid pace normally, and I don’t think this will be an exception,” he said. “We think there are some very good things in it. There are some things that we will have to accommodate ourselves to, but overall we think it’s a constructive piece of legislation for our state and our customers.”
Farrell said it was “premature” to speak about it in any more detail because “there is still lots of work to be done on it,” but he assured analysts that “we’ll be in a position to talk about it, I think, more thoroughly on the next call” in three months.
Dominion’s Cove Point LNG terminal in Maryland will be online later this year, the company says. | Dominion Energy
Dominion’s executives said it’s hard to assess the impact of the federal tax cuts because the company operates in seven states. The company is assuming that the benefits will be passed through to customers for all of its state-regulated entities but acknowledged the improved profitability for all non-regulated and long-term-contracted businesses. However, the changes create “strong credit headwinds” for accrual-basis taxpayers like Dominion, and some of the benefit will be offset by delays in Dominion’s Cove Point LNG plant becoming operational, said Mark McGettrick, Dominion’s chief financial officer. He estimated the cuts will increase the company’s 2018 earnings by between $0.10/share and $0.15/share.
Tax Windfall
McGettrick confirmed that the federal tax breaks have allowed Dominion to begin plans to deleverage the holding company and clear away $800 million in debt. The cuts offset the delayed start at Cove Point, so the company could still issue $500 million in new shares earlier this month and reduce its capital expenditure budget by $1 billion while remaining committed to its current credit ratings, he said. He announced plans to increase the company’s credit facilities to $6 billion, which is in addition to a $500 million credit line being put together for its Dominion Energy Midstream Partners subsidiary in order to replace its existing credit line with the parent company.
“We’re committed to the ratings that we have. We will take the steps necessary to support that, and we took advantage of taxes to get a jump start,” he said.
While the credit expansion will increase liquidity, McGettrick assured the new shares were not issued to help finance the proposed SCANA takeover, which the company announced Jan. 3. The company will maintain a 6% to 8% growth rate through 2020, he said, and the SCANA deal could bump it above 8%.
“So with or without SCANA, we’re in terrific position with one of the best growth rates we believe in the industry and one of the highest dividend growth rates as well, but certainly SCANA would be a positive result for us,” he said.
Farrell said he expects SCANA’s shareholders to approve the deal in May and shrugged off what appeared to be a hostile hearing with South Carolina legislators earlier this month.
“We are optimistic that our proposal will be viewed favorably by lawmakers and regulators, and we can complete the transaction later this year,” he said.
Despite delays, executives were also upbeat about developments at Cove Point in Calvert County, Md. Construction is complete at the natural gas liquefaction plant, and the process to bring the cooling infrastructure online is underway. The plant will be in service by early March, Farrell said.
The company is also completing work on the $1.3-billion, 1,588-MW Greensville County Combined Cycle Power Station. The plant was 73% complete at the start of the year, with all major equipment in place, including the primary natural gas line. Metering and regulation controls are awaiting final approval, and the plant is expected to begin operating near the end of the year.
A solar developer is attempting to block a Michigan utility giant’s effort to halt its energy purchases under the Public Utilities Regulatory Policy Act (PURPA) for the next 10 years.
The conflict pits Cypress Creek Renewables against Consumers Energy, which supplies electricity to more than half of Michigan.
Consumers Energy in December asked the Michigan Public Service Commission (PSC) for permission to decline purchasing capacity from PURPA-eligible facilities, contending that it will not need any new generation over the next decade (U-18491). The company also requested that the PSC reset the value of Consumers’ avoided capacity cost to match MISO’s Planning Resource Auction price for all new PURPA-qualifying facilities’ offers to sell capacity. PURPA requires utilities such as Consumers Energy to purchase electricity from qualifying facilities at avoided-cost rates that reflect a utility’s own cost to build new generation.
In its filing, Consumers pointed to a 2017 case in which the Michigan commission ruled that the PURPA purchase obligation does not exist “if no additional capacity need is forecasted.” The company included a 10-year capacity proposition with its application.
But Cypress Creek this month filed in opposition to the plan, arguing that Consumers did not satisfy the grounds for a stay of PURPA obligations because the company could not prove it would be damaged in the absence of the waiver. The renewables developer also said a PURPA stay for Consumers would harm the public interest by hindering small solar development. Under PURPA’s implementation in Michigan, projects 2 MW and smaller are guaranteed a 20-year, fixed-price contract.
Cypress Creek’s complaint also contends that Consumers has itself admitted that it will need an additional 625 MW of renewable energy capacity to comply with Michigan’s 15% renewable portfolio standard.
Consumers Energy Campbell plant | Michigan Building Trades Council
Cypress Creek is joined in its arguments by the Environmental Law and Policy Center, which objected that Consumers’ 10-year capacity assumption “rests on faulty assumptions ― including an inadequate analysis of coal-plant retirements.” The environmental non-profit said Consumers failed to conduct a cost-benefit analysis on retirement of existing coal units, simply assuming that two units apiece at its Karn and J.H. Campbell plants will stay online through 2030. Consumers retired seven of its oldest coal plants in 2016, representing about 30% of its generating capacity.
$3 Billion, 700 MW
Cypress Creek said it has more at stake than Consumers in the debate over PURPA.
“The harm to Cypress Creek and other interested parties from granting a stay exceeds any harm to Consumers if a stay is not granted,” Cypress Creek said. The company said it is ready to invest $3 billion in low-cost, solar energy in Michigan through its affiliates, which already have approximately 700 MW of solar capacity under development in Consumers’ service area.
“These projects will be out on indefinite hold if Consumers’ request for a stay is granted,” the company said.
The company also alleged that Consumers’ timing of its application was opportunistic because the utility didn’t file for the waiver until after the Michigan PSC had set new avoided costs to file its application.
The PSC in November approved Consumers’ avoided cost rate at $117,203/megawatt year or $140,505/MISO zonal resource credit year (U-18090) but put the ruling on hold on Dec. 20, anticipating petitions for rehearing. A day later, Consumers filed its request for a stay.
“Consumers waited until after the Commission set new avoided cost rates to now claim that it does not have a capacity need,” Cypress Creek said.
Consumers maintains that PURPA will require it to purchase an additional 300 MW per year from qualifying facilities, burdening its customers “with up to $519 million of added expense over the next 20 years for a commodity that is unnecessary to serve their demand.”
Cypress Creek has found itself in a similar row over challenges to PURPA rates in Montana. The company has filed suit in both state and federal courts over the Montana PSC’s 2016 decision to first suspend, then slash PURPA rates and contract lengths offered to small solar producers. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)
“Topping the list regarding New York’s wholesale electricity market is the issue of pricing carbon,” said IPPNY CEO Gavin Donohue.
Donohue said IPPNY would work closely with the carbon pricing task force set up by NYISO and the state’s Public Service Commission (PSC) “[to monitor] the process for fair and open competition in the wholesale electricity market for all solutions, especially generation, transmission, and energy storage — and the viability of existing investments operating in the competitive market.”
IPPNY has said it “strongly supports” a carbon pricing approach that would add a carbon value to a resource’s commitment and dispatch costs based on its emission rate, with the price-per-ton set by the PSC.
A number of elected state officials attended the Jan. 29 reception, including Sen. Joseph A. Griffo, (R-Rome), chairman of the Senate Energy and Telecommunications Committee, and Assemblyman Michael Cusick (D-Staten Island), chairman of the Committee on Energy.
PSC Commissioner Diane Burman also attended the event, which took place just hours after Gov. Andrew Cuomo released the state’s master plan for developing offshore wind. (See NY Offshore Wind Plan Faces Tx Challenge.)
Entering his fourth year as chairman of his committee, Griffo said he looked forward to working with IPPNY on free market issues — and the state’s master plan for offshore wind could “conflict with” the philosophy of free enterprise. He questioned the wisdom of the proposal to put a state agency — the New York State Energy Research and Development Authority (NYSERDA) — in charge of contracting for the energy output of offshore wind farms.
Griffo also said it was unlikely that he or IPPNY members would accept any form of utility-owned generation, which was one of seven market structure proposals in NYSERDA’s comments filed with the commission on Monday.
Cusick said he had “a good working relationship” with Griffo on several non-energy issues and looked forward to working together on energy.
“I just hope I’m not being set up here,” Cusick said, “but that’s just the instinctive reaction of a kid from Staten Island.”
Donohue said IPPNY was established in 1986 and last year he and other board members pondered “ways to breathe fresh life into the organization.”
A new plan released by the New York State Energy Research and Development Authority on Monday details how the state plans to develop 2,400 MW of offshore wind by 2030.
But a separate policy paper by the same agency outlines the challenges in meeting that goal — including the limited amount of transmission available to interconnect offshore wind during the program’s initial solicitations for 800 MW of capacity over the next couple years.
Block Island Wind Project | Deepwater Wind
The state’s master plan projects that the full deployment of offshore turbines by 2030 would reduce greenhouse gas emissions by more than 5 million short tons, or approximately one-third the expected reductions from new renewable energy projects developed to meet the 50% renewable electricity target under the state’s Clean Energy Standard. (See New York Seeks to Lead US in Offshore Wind.)
“While the federal government continues to turn its back on protecting natural resources and plots to open up our coastline to drilling, New York is doubling down on our commitment to renewable energy and the industries of tomorrow,” Gov. Andrew Cuomo said.
Lisa Dix, New York senior representative for the Sierra Club, said the master plan “shows that a commitment to a steady stream of projects over the next decade” will create thousands of jobs while increasing the state’s economic.
“But the state must act swiftly this year to issue a procurement and establish an enforceable long-term program, with a guarantee projects are built every year, the governor’s targets are met and the climate, economic, manufacturing and jobs benefits are realized,” she said.
In a Jan. 29 filing with the Public Service Commission, NYSERDA detailed how the wind energy areas available to compete for offshore wind procurements in 2018 and 2019 “are limited, dispersed and not readily expandable.”
New York Offshore Wind Areas of Consideration | NYSERDA
The agency said that an expandable “backbone” transmission system would offer the benefit of economies of scale and reduced barriers to entry, but it could also lead to overbuilding and stranded asset costs. A transmission system custom-built for a single offshore facility, the “direct radial” model, costs more and is limited in scope.
The real limit, however, is the industry’s nascent stage of growth. The federal government has so far leased only one area off New York City, the April 2017 lease to Statoil, which is capable of hosting approximately 1,000 MW. However, the policy paper said that wind projects off Rhode Island, Massachusetts and New Jersey could conceivably interconnect directly to New York or interconnect within an adjacent control area with energy delivered to NYISO, which would make them eligible for procurement under the Clean Energy Standard.
New York Offshore Wind Study Area | NYSERDA
“Offshore wind developers are ready to help New York meet the governor’s goals, and are particularly interested in when and how they can compete for contracts and invest in New York,” Anne Reynolds, director of the Alliance for Clean Energy New York, said in a statement. “The Offshore Wind Policy Options Paper lays out these procurement options. Nailing down these procurement details needs to be New York’s next step.”
Market Approaches
NYSERDA assumes that offshore wind deployments will be funded through a purchase obligation placed on load-serving entities and that procurement will be conducted through separate offshore wind solicitations, using a similar competitive process to that used for large-scale renewables under the state’s Renewable Energy Standard Tier 1 procurements.
The agency offered several market-based approaches to procurement, including fixed renewable energy credits, bundled power purchase agreements, utility-owned generation and split PPAs. It also floated three varieties of offshore wind RECs (ORECs): market, index and forward.
For procurements during the first phase of the offshore wind program, NYSERDA expects ORECs to be more expensive than RECs sourced from other Tier 1 projects because of the higher capital costs for offshore. And while the fixed REC process is well-established, the price premium for offshore RECs could leave the agency financially exposed because it would act as the central procuring agency for the certificates.
“To the extent that this premium would not be addressed through co-incentives, NYSERDA’s blended REC price would increase — likely significantly — compared to its REC resale price without offshore wind,” NYSERDA said. As a result, the agency might not be able to recover its costs through the sale of RECs and resort to the utility “backstop” funding obligation of the CES. The risk would be exacerbated by a fall in power prices.
How LSEs Could Pay
NYSERDA also said the PSC could employ an allocation mechanism that set LSE compliance obligation levels according to actual production from offshore wind projects. Like New York’s zero-emission credits, these ORECs would be non-tradable and allocated to LSEs based on load.
The NYSERDA paper concluded that “under the allocation structure, the design of the dedicated offshore wind obligation could be set to achieve a much greater match between REC supply and target. Perfect alignment between REC supply and target could be achieved by setting the target for each period upon conclusion of the period to match exactly the available offshore wind REC volume.”
While that approach would address NYSERDA’s exposure to REC price differentials, it would foreclose the possibility of developing spot market price signals for ORECs, the agency acknowledged. Still, it did not consider that a big drawback given that offshore projects are not likely to respond to market signals for a long time because of their risk profiles.
NYSERDA will host two public webinars Feb. 13 to provide an overview of the Offshore Wind Master Plan and the next steps that New York will take to develop offshore wind.
New Jersey Democrats last week introduced a reworked version of a nuclear bail-out bill that didn’t come to a vote in the state legislature’s recent lame-duck session.
NJ Senate President Steve Sweeney (D)
The bill, submitted Thursday by New Jersey Senate President Steve Sweeney and Sen. Bob Smith, is supported by Public Service Enterprise Group, the operator and majority owner of the Salem and Hope Creek nuclear generating stations.
NJ Senator Bob Smith (D)
The senators introduced the bill a day after the Associated Press reported that it had obtained records showing that PSEG lobbyists worked with the administration of former Gov. Chris Christie (R) to strengthen language in the earlier version of the bill meant to keep the company’s financial information confidential. That version, which would have provided upward of $300 million annually to nuclear operators, failed when Speaker of the General Assembly Vincent Prieto declined to post it for a vote earlier this month. (See NJ Lawmakers Pass on Nuke Bailout in Lame Duck Session.)
PSEG said the language was standard and intended to protect proprietary information, but the revelation intensified criticism that the company’s nuclear plants don’t need subsidies to continue operating. PSEG has said the plants will become unprofitable within two years and that it will have to close them, putting thousands out of work and eliminating a zero-emission source of energy that produces 40% of New Jersey’s power.
Sweeney said the new legislation requires PSEG to show the need for the subsidy, which could cost each New Jersey electric ratepayer $41 per year. To address concerns by Gov. Phil Murphy that the previous version didn’t boost the use of renewable energy, the bill also includes provisions for energy-efficiency standards and solar energy credits, and would give neighborhoods a new way to invest in solar projects. The bill would also create a financial assistance program for offshore wind projects.
A controversial provision of the bill would prevent New Jersey’s Division of Rate Counsel from taking part in proceedings to determine whether the subsidy for the plants is necessary. Smith said the division is only allowed to participate in proceedings involving regulated companies, and the subsidiary of PSEG that operates the nuclear plants isn’t regulated by the state. Stefanie Brand, who directs the division, said it would have to be involved in proceedings involving the plants, or they would be “a sham.”
The earlier version of the bill was expected to be voted on in committee Thursday, but Sweeney moved back the vote to Feb. 5 to give interested parties more time to review the measure.
The Assembly has not taken any action on the bill.
Murphy Signs Order to Start Bringing State Back into RGGI
Murphy on Monday signed an executive order directing the heads of the Department of Environmental Protection and Board of Public Utilities to begin negotiations with states in the Regional Greenhouse Gas Initiative to determine the best way for New Jersey to rejoin it.
Christie had taken the state out of the regional cap-and-trade program, which caps the amount of carbon dioxide emissions for each state and requires power plants in each state to buy allowances, either through auctions or on the secondary market, for the carbon dioxide they emit.
Participating states use revenue from the auctions for energy efficiency and renewable projects. An analysis by Acadia Center found that New Jersey had foregone $232 million in RGGI auction revenue since Christie pulled it out of the initiative in 2011.
WILMINGTON, Del. — In a series of votes, stakeholders at last week’s Markets and Reliability Committee meeting declined to endorse any proposals to revise PJM’s capacity model, reiterating previously expressed support for the status quo.
The initial vote displayed in perhaps the most civil — and emphatic — way possible stakeholders’ disapproval of PJM’s decision to file its own changes for FERC approval instead of the plan endorsed by member committees.
At the behest of Bob O’Connell of Panda Power Funds, stakeholders postponed voting on the Tariff revisions previously endorsed by lower committees — an extension of the minimum offer price rule (MOPR-Ex) proposed by PJM’s Independent Market Monitor — to allow for members to register an advisory vote on the RTO’s proposed filing. That sector-weighted vote registered 3.93 out of 5 in opposition, definitively denouncing PJM’s plan, which would add a second stage to capacity auctions to isolate subsidized offers and subsequently revise the clearing price if approved. (See PJM Going it Alone on Capacity Repricing Plan.)
The unexpected vote came after PJM’s Stu Bresler defended the RTO’s decision and highlighted additional revisions from previous versions of the proposal, including an exemption from repricing for any generators of 20 MW or less and returning to the “net CONE [cost of new entry] times B” formula for developing subsidized units’ adjusted offers if their avoidable cost rate (ACR) couldn’t be used.
Several stakeholders critiqued the proposal.
“We’re concerned that what PJM has put on the table doesn’t quite get us there,” NRG Energy’s Neal Fitch said. He noted that his company has generally supported the two-stage repricing concept but prefers a version it proposed that would lower capacity commitments for bids that cleared in the first stage to address “in-between” units, with commitments for all resources then proportionally reduced below their offer amounts.
Carl Johnson, who represents the PJM Public Power Coalition, said the proposal goes “beyond accommodating state policies” and creates “a race to the bottom to secure state subsidies.”
“I just don’t feel like we’ve gotten” to the best option, said Greg Poulos, executive director of the Consumer Advocates of the PJM States.
“Subsidies are contagious. We think PJM’s proposal is not an adequate vaccine and MOPR-Ex is,” Monitor Joe Bowring said.
When focus returned to the MOPR-Ex proposal, proponents were left deflated by a series of failed votes. To acquire additional votes, the Monitor had previously revised the details of its proposal from the version that was endorsed by lower committees. However, PJM’s rules require a vote on the endorsed version, so stakeholders voted that down — with 3.83 opposed in a sector-weighted vote — so they could consider the revised version as an alternative proposal.
Exelon reiterated criticism of Bowring’s efforts to secure votes.
“They’re a product of wheeling and dealing to get a Section 205 filing,” Exelon’s Sharon Midgley said.
The Old Dominion Electric Cooperative and Panda received approval for some friendly amendments, but that vote failed the two-thirds threshold, with only 3.02. A vote without the friendly amendments followed, but that also failed with 3.19 in favor.
Transmission Flashpoint
Customers flexed their muscles at last week’s MRC meeting, rejecting proposed Manual 14F changes. The revisions, backed by transmission owners, would allow PJM to consider caps on construction costs when evaluating transmission proposals. A vote on the motion, which required two-thirds approval in a sector-weighted vote, instead received nearly two-thirds in opposition, gathering just 1.71 in favor out of 5.
The vote was prefaced by an alternative proposal brought by LS Power’s Sharon Segner that would require PJM to consider construction cost caps but also revenue requirement caps. Segner’s proposal garnered strong support from consumers, transmission customers and the Monitor, who urged support for any measures that increase competition.
The alternate proposal was the culmination of several months’ debate on the issue at special sessions of the Planning Committee, where proponents of additional cost-containment consideration consistently clashed with TOs, who argued that construction cost caps represented the limit of their willingness to compromise. (See “Cost Cap Discussion Continues,” PJM PC/TEAC Briefs: Jan. 11, 2018.)
Proponents of additional cost-containment provisions argue they’re used in other RTOs/ISOs, but PJM staff warned that the differences in the RTO’s proposed procedures make adding those considerations impossible. PJM’s sponsorship model allows bidders to propose innovative solutions to RTO-identified problems, whereas other grid operators’ processes define the parameters of the project and ask bidders to compete on price and innovative rate-recovery strategies.
“If we’re going to pursue this approach … we’re going to have to look at the entire competitive construct because we cannot fit that amount of evaluation into the planning cycle we have,” PJM’s Steve Herling said. “It would require, I think, a fairly fundamental structural reworking. We can certainly do that, but we cannot proceed by simply shoehorning this into our current cycle.”
TOs criticized the lateness of the alternative proposal, pointing out that the primary proposal was developed through the stakeholder process while the alternative set a precedent that members can just bring their own proposals to the MRC when they don’t get their way in the lower committees.
The primary proposal included “considerable compromise,” FirstEnergy’s Jim Benchek said, and “holding [the issue] hostage” with an alternative proposal “to restart the debate” is “both wrong and a disservice to the stakeholder process.”
State consumer advocates defended the proposal, saying the focus should be on the quality of the proposal rather than when it was filed, and criticized the primary proposal for having no mechanism to hold contractors to the construction cost caps they set.
Segner’s proposal was seconded by Erik Heinle of the D.C. Office of the People’s Counsel.
“We believe this is really in the best interest not just of our consumers but everybody in this room,” he said.
EDP Renewables’ John Brodbeck asked whether either proposal moved the ball forward on the overall goal of getting transmission projects completed faster.
“The purpose here is really to evaluate what is the right project to expand the system, so we want to encourage innovative projects without impeding innovative rate structures,” PJM’s Sue Glatz said.
Proponents of the main motion beat a tactical retreat after its defeat, calling for a deferral on the alternative motion for more discussion at the PC. Several transmission customers agreed, and members approved a motion to defer the vote until no later than May’s MRC meeting.
Resilience Definition
PJM’s Chris O’Hara asked stakeholders for comments on the definitions of “resilience” proposed by FERC and the RTO. PJM’s definition is more concise than FERC’s, but it misses some of the mitigation nuance that the commission’s includes.
The commission has ordered RTOs and states to weigh in on the meaning of resilience after it rejected the Department of Energy’s Notice of Proposed Rulemaking that would have provided price supports to ailing coal and nuclear generators.
O’Hara asked for comments to be submitted by Feb. 9 so they can be incorporated into a discussion of the issue at the Feb. 13 Liaison Committee meeting and a special session of the MRC on Feb. 23. PJM’s responses to FERC are due March 9.
Generators Performed Better During Cold Snap than 2014
PJM staff said data show generators responded better during the cold snap than the infamous cold streak in January 2014 known as “the polar vortex,” proving that PJM’s subsequent Capacity Performance changes have had their intended impact.
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The difference from 2015 to 2018 in the fuel mix of the dispatched fleet during peak winter conditions showed that nuclear rose slightly while gas and coal declined slightly. Hydro disappeared, and oil increased from 4% to 10% while wind was stable at 2%.
PJM didn’t track the fuel mix during 2014, but the 2015 numbers “were about the same,” PJM’s Chris Pilong said. “We’ve done some checks.”
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Outages also decreased from their peak periods in 2014 to 2018. Outages that peaked at 40,200 MW on Jan. 7, 2014, were cut nearly in half during the peak period during the cold snap earlier this month. Outages on Jan. 6, 2018, totaled 22,906 MW. Coal outages decreased by roughly 6,600 MW to 7,095 MW, while overall gas outages similarly dropped about 6,200 MW to nearly 12,800 MW.
PJM staff plan to push back on a recent FERC order that denied the RTO’s plan for allocating uplift costs to up-to-congestion (UTC) virtual transactions. The move, part of which could include asking FERC to temporarily prohibit UTC trading, elicited disapproval from financial stakeholders.
“We essentially believe that FERC inserted its own judgement as to what was more just and reasonable than something else,” PJM’s Bresler said. “We believe they erred in doing so.” (See FERC: PJM Uplift Proposal for UTCs Falls Short.)
PJM will be requesting rehearing on the order, arguing that FERC’s logic is flawed in determining that it’s unfair to allocate uplift to UTCs in the same way it is applied to incremental supply offers (INCs) and decrement demand bids (DECs). Once an UTC clears, Bresler said, “substantively, there is exactly zero difference.”
Because UTCs are a voluntary product, Bresler said PJM is “very seriously considering” asking FERC to suspend them until there’s an approved way to allocate uplift to them.
“We think the current situation is inequitable … and as such, we think we need to deal with that as soon as we possibly can,” he said.
Several stakeholders, including Monitor Bowring, Susan Bruce of the PJM Industrial Customers Coalition and Joe DeLosa of the Delaware Public Service Commission, supported PJM’s plan, but financial traders criticized its characterization of UTCs as voluntary.
“I think the biggest substance is PJM is thinking about terminating a product that provides benefit to the stakeholders,” DC Energy’s Bruce Bleiweis said.
“That, we believe, has not been proven at all,” Bresler responded.
Vitol’s Joe Wadsworth suggested using an uplift allocation philosophy that FERC has previously outlined.
“I think you would get a lot of support from stakeholders on something like that,” he said.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 38: Operations Planning. Revisions developed from periodic review to include protection system/relay communication outages and PJM assessment of impact.
Tariff and Reliability Assurance Agreement revisions associated with the demand response subcommittee proposal for the relevant electric retail regulatory authority (RERRA) review of energy efficiency resource participation in the capacity market. (See “Rules Endorsed for Enforcing Regulator Requirements on EE,” PJM MIC Briefs: Jan. 10, 2018.)
A problem statement and issue charge at their first reading to address how gas-fired generators should be compensated if PJM orders them to switch to alternative fuel sources, such as oil or a different pipeline. (See “Emergency Pipeline Switching Instructions Sparks Rights Debate,” PJM MIC Briefs: Jan. 10, 2018.)
Members Committee
Stakeholders Endorse Proposals
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other Operating Agreement and Tariff changes:
Tariff revisions related to the procedures associated with the study of transmission service requests and upgrade requests in the new services queue process. (See “Interconnection Study Process to be Rearranged,” PJM Planning/TEAC Briefs Oct. 12, 2017.)
Tariff and Reliability Assurance Agreement revisions also endorsed by the MRC (see above).
FTR Revisions Approved over Financial Dismay
Members endorsed revisions resulting from special sessions on financial transmission rights issues, but not before financial stakeholders lodged one final critique. Two of the less controversial sets of revisions — to address changes to long-term FTR modeling for future transmission expansion and streamlining management of overlapping FTR auctions — were endorsed by acclamation, while the final set required a sector-weighted vote. The revisions allocating any surplus funds from day-ahead congestion and FTR auction revenue were endorsed with a vote of 3.94 in favor out of 5. (See “FTR Changes in the Works,” PJM MIC Briefs: Dec. 13, 2017.)
“Those who bear the risk of FTR revenue shortfalls should also receive the benefit of FTR excesses,” Bleiweis said. “We’re getting away from that. … We’re going to end up with another series of protests before the commission.”
Wadsworth argued that PJM would be better served by allocating more auction revenue rights to transmission customers prior to the year so they can preserve their tradeable rights, rather than “just moving money around at the end of the planning year.”
Though ‘Not Perfect,’ Incremental Auction Changes Endorsed
Members endorsed proposed revisions to the Incremental Auction process with a sector-weighted vote of 3.38 in favor out of 5. The revisions would reduce the number of IAs from three to two following each Base Residual Auction. PJM says the change will reduce the opportunities for BRA sellers to “shop” for the cheapest replacement capacity while allowing them to cure a physical inability to satisfy their commitments. (See “Incremental Auction Revisions Endorsed,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
“It’s not the perfect, from anyone’s perspective,” Bruce said, but she urged members to endorse it as a “really quite good and, in fact, just and reasonable” alternative.
FERC Commissioner Cheryl LaFleur took time from a whirlwind listening tour of the Rocky Mountain region last week to visit the Colorado Public Utilities Commission and discuss the Mountain West Transmission Group’s desire to join SPP.
Appearing Jan. 25 before the PUC’s fourth information session devoted to Mountain West’s pursuit of RTO membership, LaFleur recalled sitting in on what she said felt like the “100th meeting” of Mountain West stakeholders as they discussed the subject. SPP’s and Mountain West’s utilities are now deep into negotiations over membership, accelerating a process that began last January when the group announced its intention to join the RTO. (See SPP, Mountain West Resolving ‘Contentious’ Issues.)
“You don’t go out on 200 dates if you’re going to break up,” LaFleur said. “There’ve been 100 since then, so it’s starting to seem pretty real.”
FERC’s most senior commissioner addressed questions from Colorado regulators, industry representatives and consumer advocates about jurisdictional issues, consumer representation in SPP and the new opportunities presented to Mountain West by recent structural developments in the Western Interconnection.
“These are exactly the kind of questions you should be asking,” she said. “There’s no time like now to ask questions of SPP, [of] the utilities that are coming to you for the authority to do this — of whomever is involved in this, because you have a critical role to play in making sure that what happens is right for the people in Colorado.”
The PUC has jurisdictional authority over Xcel Energy’s Public Service Company of Colorado and Black Hills Energy, both Mountain West members.
No Rubber Stamp
Colorado Commissioner Frances Koncilja, who has been organizing the information sessions, said she will invite CAISO, Peak Reliability and PJM to a fifth forum, in either February or March, to explain “what they think they can do for Colorado citizens.”
“This is not a decision this commissioner is going to rubber stamp,” Koncilja said. “I want to know what all the alternatives are.”
While SPP is intent on becoming Mountain West’s reliability coordinator (RC), Peak Reliability, the group’s current RC, has recently proposed to offer market services in the Western Interconnection through a joint effort with PJM. Further complicating matters, CAISO has also given 18-months’ notice that it intends to leave Peak and offer its own reliability services for half the RC’s price. (See Peak, PJM Detail Western Market Proposal and CAISO to Depart Peak Reliability, Become RC.)
LaFleur said the prospect of multiple RCs in the West will require a concerted effort by regulators and others involved to maintain the “situational awareness” developed by years of having only one.
“It will take work with multiple RCs, but I suspect if we do the work right, it can be done in the same way as we have multiple RCs in the East,” she said. “It will take some careful work to make sure the situational awareness between RCs is sustained and that everyone’s treated fairly.”
Consumer advocate Larry Miloshevich, with Energy Freedom Colorado, asked LaFleur how nonutility stakeholders could make their interests heard in the face of decisions that he said were being made behind closed doors “for reasons that are not all that clear.” Come to FERC, she replied.
“I hate to sound like a civics book, but the citizens are not unprotected. [FERC’s commissioners] are sworn to protect them. That’s our whole job. We’re not here for the utilities,” LaFleur said.
“There are probably political reasons why [Mountain West] kind of sought to be its own thing rather than being with other parts of the West, but that’s not for me to judge,” she said. “Yes, file those arguments. We’ll listen to them.”
LaFleur referred to FERC doctrine, saying the move to join an RTO “is a voluntary decision by the members who go in.” She said the commission learned this the hard way after considering a nationwide standard market design in the early 2000s.
“There was a revolution, almost coast to coast, with people saying, ‘We’ll decide who we want to sign up with, not FERC,’” LaFleur said. “FERC said, ‘If this market thing is going to take off, we’re going to let people come together and make their own decisions.’”
The commissioner extolled the benefits of RTO membership, pointing out that organized markets now cover two-thirds of the country and include regions with and without electric competition.
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“It’s worked across all different models. Why? Because you’re deploying resources over a bigger footprint, so you can run your systems more efficiently with less reserves to bring your energy to customers and hopefully keep your lights on at lower costs,” LaFleur said. “All this change, all this wind, all this solar … it’s made people stand up and say, ‘Wow, there might be something in this for our customers too.’”
It just had to grow organically in the West.
“If this came from Washington, it would be DOA. We’ve seen that through multiple attempts,” LaFleur said. “The best thing FERC could do is say nice things when invited to go somewhere but not do anything. It appears the time is approaching when we might have to do something.”
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week asked its Wholesale Market Subcommittee (WMS) to determine what went wrong during two recent market events.
On Jan. 22, ERCOT disabled the 69-kV contingencies being solved by the day-ahead market (DAM) software, with the exception of a contingency included in a real-time binding constraint during the previous 30 days. Staff issued a market notice at the time.
ERCOT’s Carrie Bivens said staff followed protocols by issuing the notice. “The alternative was aborting the DAM run,” she said.
On Jan. 23, real-time prices jumped to $5,800/MWh for 15 minutes, forcing ERCOT to deploy non-spinning reserves. Prices also exceeded the energy offer cap of $9,000/MWh during two five-minute intervals.
The ISO said it was the first time market prices reached the $9,000 price cap during two security constrained economic dispatch (SCED) intervals, pointing to ramping issues because of cold weather and higher-than-expected load around 7 a.m. Resource adequacy was not a problem, ERCOT said.
Staff’s David Maggio said ERCOT doesn’t intend to reprice the event, noting the systems were “working as expected.”
“We don’t see any issue with how things worked out,” he said.
Staff said the two events were unrelated, prompting Citigroup’s Eric Goff to respond, “They felt related to everyone.”
“The issue that caused the DAM software problem was unrelated to ramp constraining in real time,” Bivens said. “They just happened on the same operating day.”
The contingencies were restored Jan. 24 for the following operating day.
“We need a discussion at WMS, because you’re determining winners and losers when you turn off contingencies,” Morgan Stanley’s Clayton Greer said during the TAC’s Jan. 25 meeting.
The WMS next meets Jan. 31. The subcommittee will also provide real-time co-optimization training following its meeting.
ERCOT Sees 62% Drop in RUC Practices
ERCOT staff’s annual reliability unit commitment (RUC) report to the TAC last week revealed a more than 62% drop in the practice.
Maggio said that 562 instructed RUC resource-hours last year resulted in 534 effective RUC resource-hours, compared to 1,514 and 1,417, respectively, for all of 2016.
Of those resource-hours, 163 were successfully bought back, a clawback percentage similar to previous years. The total RUC make-whole amount was about $540,000, which was covered through capacity short charges.
The 534 effective RUC resource-hours were all a result of congestion (433), capacity (66) and Hurricane Harvey (35). No resource-hours were committed for ancillary service shortages, system inertia or extreme cold weather/start-up failures.
Maggio pointed to several recent improvements as causing the drop in RUCs, including reducing shadow price caps for transmission constraints from about $1 million/MWh to about $100,000/MWh and a nodal protocol revision request (NPRR744) that used a common trigger to fix the opt-out decision inconsistency between the SCED and settlements systems.
Staff and stakeholders are still working to improve both RUC functionality and transparency, Maggio said.
In other staff reports:
Assistant General Counsel Vickie Leady told stakeholders that staff have developed a definition of “affiliate” in line with the typical corporate use of the word. The proposed bylaw amendment clarifies when an affiliate relationship arises between two or more ERCOT members.
Members will be allocated almost $26,000 in resettlements from the Greens Bayou Unit 5 reliability-must-run contract, after certain costs were not fully settled before applicable true-up dates. The RMR, ERCOT’s first since 2011, was approved in June 2016 and terminated effective May 29, 2017.
Controller Sean Taylor said the ISO forecasts the system administration fee will be adequate and he “sees no need for a change” through 2019. Stakeholders had requested advance notice of any fee increases during the 2016-17 budget process.
Task Force Looks at Subcommittees’ Restructuring
Stakeholders agreed to form a task force to combine or restructure the TAC’s Retail Market (RMS) and Commercial Operations (COPS) subcommittees. The task force will begin its work Feb. 5, with the intention of reporting back to the committee for its Feb. 22 meeting.
Leadership from the two subcommittees met over the holidays and agreed on three options for restructuring them. The initiative is a result of the TAC’s annual structural review of its subcommittees and input from the Board of Directors’ Human Resources and Governance Committee.
Reliant Energy Retail Services’ Rebecca Reed Zerwas will lead the task force, after she was “‘volun-told’ to get this started.”
The RMS and COPS will continue in their current forms until a solution is endorsed by the TAC.
TAC Elects Helton Chair, Coleman Vice Chair
The committee unanimously elected Dynegy’s Bob Helton as its chairman, a position he has essentially held since September. Previously vice chair, Helton stepped into the role vacated by Adrianne Brandt, who left San Antonio’s CPS Energy to join Chair DeAnn Walker’s staff at the Public Utility Commission of Texas.
Diana Coleman, senior market specialist with the Office of Public Utility Counsel, was elected vice chair.
NPRR Clarifies ERCOT’s Jurisdictional Status Quo
The TAC unanimously endorsed NPRR861, which clarifies ERCOT can and will take all actions necessary to preserve its jurisdictional status quo and market participants with respect to FERC. Possible actions include, but are not limited to, ordering the disconnection of transmission facilities and denial or curtailment of an electronic tag.
The PUC in December instructed the ISO to draw up the NPRR over concerns that transmission projects along the U.S. border with Mexico may threaten ERCOT’s electrical separation from the rest of the country and the PUC’s exclusive jurisdiction over the Texas grid operator. (See “Fending off FERC,” Texas PUC Challenging SPP-Mountain West Intertie Costs.)
FERC’s jurisdiction is derived from the Federal Power Act, which gives the commission broad authority to regulate interstate commerce by public utilities. FERC does not have plenary jurisdiction over the ISO because the energy generated in the region is not transmitted in interstate commerce, except for certain interconnections ordered by the commission that do not give rise to broader jurisdiction.
The committee also unanimously endorsed six other NPRRs, a system change request (SCR) and a nodal operating guide revision request (NOGRR):
NPRR819: Removes language referencing “data errors” for resettlement of the DAM and real-time market (RTM); gives the ERCOT board authority to direct a DAM resettlement parallel to its authority to direct an RTM resettlement; removes references to undefined “declarations” of resettlements; changes the thresholds that determine a resettlement; and fixes a semantics error.
NPRR841: Determines in real time the day-ahead make-whole payment by incorporating the ancillary services infeasibility charge, approved with NPRR782, into the payment’s analysis.
NPRR842: Defines a “study area” as an ERCOT-designated “geographic region,” separate from a weather zone or load zone, used primarily for study purposes.
NPRR844: Corrects the current process of including capacity that is modeled but not yet commercially operational in the outage scheduler, which is then reflected in the outage report.
NPRR852: Creates a more efficient approval process when updating the congestion revenue right activity calendar; removes unnecessary “advisory approval” language; and moves the calendar’s approval from the TAC to the WMS.
NPRR855: Clarifies the criteria for including new and retiring resources in the seasonal peak average capacity estimation calculations used for ERCOT’s Capacity, Demand and Reserves report. The revisions apply to wind, solar, DC ties, hydro and all-inclusive generation resources within private-use networks.
NOGRR169: Aligns the guide’s language with NERC Reliability Standard PRC-002-2 (Define Regional Disturbance Monitoring and Reporting Requirements) to determine required locations for NERC-required disturbance monitoring equipment. This relieves the burden on facility owners to adhere to two vastly different requirements for the same purpose.
SCR794: Updates how the SCED limit is calculated by the Transmission Constraint Manager to consider how the megavolt-ampere flows compare to actual limits.
