BOSTON — The New England Power Pool’s collaborative process to address climate change while preserving wholesale electricity markets won an endorsement from FERC Commissioner Cheryl LaFleur at the ISO-NE Consumer Liaison Group meeting Thursday.
LaFleur, a New England native, was referring to the Integrating Markets and Public Policy collaborative, which seeks to reconcile markets with state mandates to decarbonize the grid. (See Markets vs. Climate Goals the Subject at NECA Conference.)
Stakeholders are meeting into next year with the goal of having ISO-NE present Tariff revisions to FERC.
“I think there’s a lot in it for customers because we will still harness the power of the competitive market while also having the states address climate change [to see if] those are two things that can be reconciled,” she said.
One contentious point is that states have mandated clean energy procurements leading to subsidized out-of-market contracts that skew prices.
“What I’m worried about as we go forward is if we go without a plan and try to have it both ways: try to have a market that’s working … but then we get to a place where it’s not working and it begins to be cannibalized by the subsidized resources,” LaFleur said.
Noting the unlikelihood that the Trump administration would endorse a federal carbon tax, LaFleur said that the commission would probably look favorably on a state-based consensus that meets the regional goals along with market-based solutions.
“In my mind, Plan A is the region creates some kind of comprehensive plan that recognizes the state environmental goals and the [role of] pricing in the wholesale market and files it at FERC,” she said.
She said the two alternatives would have unappealing outcomes: The current state of affairs, with FERC acting as arbiter in the disputes between state governments, RTOs and market participants; or a de facto reregulation, as states more actively promote resource adequacy with preferences for cleaner energy sources, with out-of-favor generators then looking for their own state support.
“Pretty soon you realize the market’s pretty small and you’ve reregulated in a messy, expensive way. I don’t think that’s a good idea, particularly for a region that invented competitive markets, ISO-NE,” she added.
Adjustments Ahead
Besides an expected lessening of government activism in climate policy, LaFleur will have to adjust to being a minority member of FERC when three Republicans are expected to be nominated to FERC next year.
“[FERC commissioner] is my first government job and it’s only been for President Obama, so I’ll see what it’s like,” she said. LaFleur said the Democrats on the commission had a good working relationship with the former Republican members. “The only thing we’ve had that had a partisan feel was anything that relates to environmental rules.”
That could continue.
“One of the things everyone will be watching is where the new administration takes us in the intersection of energy and the environment,” she said.
Regardless of what the Trump administration does, LaFleur said, she’s on FERC for the duration.
“I plan to serve out my term until 2019. I don’t know what anybody else is going to do, but I know what I’m going to do,” she said.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee assigned two subcommittees to consider responses to discrepancies in day-ahead market make-whole payments.
ERCOT staff said it noticed a material increase in make-whole payments in November, which it said resulted from the implementation in June of NPRR617, which eliminated the caps on the first two parts of three-part day-ahead offers. It said a review determined the increase resulted from a mismatch between start-up and minimum energy costs used by the day-ahead market’s clearing engine and those used for payments.
None of the operating days met the 2% threshold to prompt resettlements. A software code fix corrected the problem effective Nov. 16.
The ISO is evaluating additional means of monitoring settlement outcomes “to more rapidly identify implementation issues or other anomalies in the future.”
TAC Chair Adrianne Brandt assigned the issue to the Commercial Operations and Wholesale Market subcommittees for further discussion and potential policy recommendations.
Committee Vice Chairs Approved
The TAC unanimously confirmed Oncor’s Martha Henson as vice chair of the Protocol Revision Subcommittee. The committee also unanimously confirmed the re-election of TXU Energy’s John Schatz as vice chair of the Commercial Operations Subcommittee.
The TAC approved three nodal protocol revision requests (NPRRs), one nodal operating guide revision (NOGRRs) and two revisions to the Settlement Metering Operating Guide (SMOGRRs).
The committee tabled a Commercial Operations Market Guide revision request (COPMGRR044), pending the COPS’ resolution of the related NPRR794. The changes relocate reporting requirements for unregistered distributed generation from the Commercial Operations Market Guide to the protocols.
NPRR773: Broadens the scope of acceptable letter of credit issuers, allowing electric cooperatives to post letters from the National Rural Utilities Cooperative Finance Corp. with ERCOT.
NPRR792: Aligns the nodal protocols with NERC’s definition for special protection system (SPS) and uses “remedial action scheme” and “automatic mitigation plan” in place of SPS for consistency purposes, when applicable. Also approved was the related PGRR051.
NPRR803: Removes un-codified language from NPRR439, which was approved four years ago and updated a counter-party’s available credit limit for the day-ahead market’s current day.
NOGRR162: Establishes a process for resolving real-time data discrepancies that affect ERCOT’s network security analysis. NERC Standard IRO-010-2 (Reliability Coordinator Data Specification and Collection) requires ERCOT and applicable entities to have a mutually agreeable process for resolving real-time data conflicts.
SMOGRR018: A change sponsored by the Texas Industrial Energy Consumers will allow efficient private use network configurations without jeopardizing ERCOT-polled settlement metering requirements.
SMOGRR019: Makes several changes to the Settlement Metering Operating Guide, including a requirement that nameplate photos be submitted as part of site certification package for new or replacement instrument transformers.
Stakeholders also left NOGRR164 on the table until its accompanying protocol change (NPRR792) can be taken up by the board next week. The TAC will then conduct an email vote on the NOGRR.
CARMEL, Ind. — MISO has come up with two possible responses to its Independent Market Monitor’s suggestion to apply its 50-MW physical withholding threshold to affiliated market participants collectively, rather than individually.
MISO told the Resource Adequacy Subcommittee on Nov. 30 that the withholding threshold should either use allocations based on load ratio share, or the fixed 50-MW limit should be scrapped in favor of a new threshold based on percentage of generation assets.
MISO’s Cliff Risley said the downside to the load ratio share option is that market-sensitive information could be released inadvertently through how many megawatts each affiliate is awarded. Risley also said the percentage option could result in more allowed withholding overall and weaken capacity market efficiency.
MISO and the Monitor are proposing to set withholding limits on a company basis rather than the current market participant basis, which allows affiliates to hold back 50 MW apiece without overstepping the Planning Resource Auction withholding threshold. (See “MISO Takes 1st Steps in Monitor Recommendations,” MISO Resource Adequacy Subcommittee Briefs.)
Monitor David Patton said the two alternatives remove the “common incentive” for affiliates to withhold to boost prices for a sister company, but putting the 50 MW on a pro rata basis is “more draconian” than the current market rules.
“There are cases where withholding less than 50 MW is mitigated. You’ve now made the affiliation more stringent,” Patton said. He also said he didn’t know how the percentage method could be distributed fairly.
Some stakeholders argued that FERC Order 697 already prohibits coordination among affiliates that are franchised public utilities and the withholding proposal should only apply to affiliates not covered by the rule.
Risley asked for more stakeholder feedback before Dec. 14.
Projects Without GIA Counted in OMS-MISO Survey?
MISO’s Darrin Landstrom asked stakeholders if the RTO should include resources that have yet to secure a generator interconnection agreement in the annual OMS-MISO Survey.
| MISO
Currently, MISO only includes Tier 1 resources — those that have a signed generator interconnection agreement — into the survey’s regional and zonal weighted averages. The RTO is asking if it should include Tier 2 resources — projects still in the interconnection queue — into the survey totals, or create a separate survey category for them. RASC Chair Gary Mathis asked if MISO could use historical data to calculate the likelihood of projects being completed after they enter the final stage of the queue. Landstrom said the option could be explored.
Laura Rauch, MISO’s manager of resource adequacy coordination, reminded stakeholders that MISO’s ongoing effort to revise its queue rules could complicate the suggestions, as the queue’s stages and restudy periods could be changed.
Landstrom asked for input on the issue by Dec. 15.
IMM Clears Up Market Mitigation Application
The Monitor is proposing a Tariff change to make clear which resources are subject to PRA market mitigation measures.
IMM staffer Michael Chiasson said market mitigation will apply to “generation resources, including behind-the-meter generation, that are internal to or are pseudo-tied into MISO.”
Chiasson said MISO’s Tariff is currently unclear as to what resources are answerable to the Monitor; the edits would be made to Module D.
Demand resources, energy efficiency resources and external resources will be exempted from market mitigation measures, Chiasson said. He asked for stakeholder feedback by Dec. 14.
UPDATE: Quoting unnamed transition team officials, The New York Times, The Washington Post and others reported Dec. 7 that President-elect Trump plans to nominate Oklahoma Attorney General Scott Pruitt as EPA Administrator. Trump confirmed the reports Dec. 8.
By Rich Heidorn Jr.
President-elect Donald Trump is sending EPA watchers conflicting signals, interviewing potential agency heads who are vocal critics of climate science while also claiming an “open mind” on the issue.
In an interview with editors and reporters of The New York Times on Nov. 22, Trump said he has an “open mind” on humans’ role in global warming, appearing to soften his campaign pledge to withdraw the U.S. from the Paris Agreement.
Former vice president and climate activist Al Gore speaks with reporters after meeting with President-elect Donald Trump at Trump Tower in New York on Nov. 5.
On Monday, Trump met with former vice president and climate activist Al Gore at the invitation of Trump’s daughter Ivanka. Gore told reporters afterward the “lengthy and very productive session” was a “sincere search for areas of common ground.”
Politico reported Dec. 1 that Ivanka intends to make climate change “one of her signature issues.” Quoting a source close to her, Politicosaid Ivanka, who has endorsed liberal positions on pay equity and parental leave, “is in the early stages of exploring how to use her spotlight to speak out on the issue,” seeing herself as a “bridge” to moderate and liberal women.
That would put her in conflict both with her father’s prior statements on the issue and those of EPA transition leader Myron Ebell and the candidates rumored to be in the running to head the agency.
The Associated Press reported Nov. 29 that it had seen internal documents from the president-elect’s transition team that indicate the new administration plans to stop defending the Clean Power Plan in court. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
‘Bunch of Bunk’
Trump’s Chief of Staff Reince Priebus told Fox News on Nov. 27 that the president-elect’s “default position” on climate change is that “most of it is a bunch of bunk.”
“The only thing he was saying after being asked a few questions about it [by the Times] is, look, he’ll have an open mind about it, but he has his default position, which most of it is a bunch of bunk, but he’ll have an open mind and listen to people,” Priebus said.
Pruitt | ScottPruitt.com
On Nov. 28, Trump met in New York with two rumored EPA candidates, Oklahoma Attorney General Scott Pruitt, one of the state officials leading the legal challenge to the CPP, and Kathleen Hartnett White, former head of the Texas Commission on Environmental Quality, who has criticized “the imperial EPA.”
Other EPA candidates, according to Reuters, include two former EPA executives during the George W. Bush administration, energy attorney Jeff Holmstead and Mike Catanzaro, a lobbyist for CGCN Group. Venture capitalist Robert Grady of Gryphon Investors, who served in President George H.W. Bush’s administration, also is in the running, Reuters reported.
‘Looking Very Closely’
White | Texas Public Policy Foundation
Although Trump did not specifically mention the CPP during the Times interview, his moderate tone was a marked contrast to his previous bombast on global warming.
Trump was asked by Times columnist Thomas Friedman if he would “take America out of the world’s lead of confronting climate change.” Trump responded that he is “looking at it very closely.”
“I absolutely have an open mind. I will tell you this: Clean air is vitally important. Clean water, crystal clean water is vitally important. Safety is vitally important,” Trump said.
Editorial page editor James Bennet asked, “When you say an open mind, you mean you’re just not sure whether human activity causes climate change? Do you think human activity is or isn’t connected?”
Trump responded: “I think right now … well, I think there is some connectivity. There is some, something. It depends on how much. It also depends on how much it’s going to cost our companies. You have to understand, our companies are noncompetitive right now.”
White House correspondent Michael Shear followed up with a question about the potential of foreign leaders to impose tariffs on American goods to offset the carbon that the U.S. had pledged to reduce.
“I think that countries will not do that to us,” Trump responded. “I don’t think if they’re run by a person that understands leadership and negotiation, they’re in no position to do that to us, no matter what I do. They’re in no position to do that to us, and that won’t happen, but I’m going to take a look at it. A very serious look. I want to also see how much this is costing, you know, what’s the cost to it, and I’ll be talking to you folks in the not too distant future about it, having to do with what just took place.”
‘Hoax’
In a 2012 tweet, he called climate change a hoax created “by the Chinese in order to make U.S. manufacturing noncompetitive.” During the campaign, he said he would “cancel” the U.S.’s involvement in the Paris Agreement, which aims to limit global warming to 1.5 degrees Celsius above preindustrial levels. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
But in a video released Nov. 21, Trump also made clear that he will steer a different course than President Obama on energy policy, renewing his promise to “cancel job-killing restrictions on the production of American energy, including shale energy and clean coal.”
Trump and the Republican Congress could use the Congressional Review Act to cancel some of the Obama administration’s most recent regulations, including a Nov. 15 Interior Department rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.
The act allows an incoming Congress to reject regulations finalized within 60 days of the end of either the House’s or Senate’s sessions.
The Congressional Research Service has concluded the act would apply to regulations finalized after May 30, if Congress holds no more sessions this year, The Washington Post reported Nov. 22.
In contrast, an EPA regulation intended to reduce methane gas leaks was finalized on May 12, making it likely exempt from being reversed under the act, the Post reported. EPA said the rule, designed to reduce methane emissions from new or modified oil and gas wells, will prevent 11 million metric tons of carbon dioxide equivalent emissions by 2025.
DALLAS — Stakeholders working to improve SPP’s cumbersome Z2 crediting process for network upgrades met here last week to learn about how potential solutions might affect the RTO’s other functions — leaving one stakeholder pining for the good old days when he worked in an operations center.
Another stakeholder, the Kansas Power Pool’s Larry Holloway, expressed mild frustration as the Nov. 29 conversation turned to long-term and incremental long-term congestion rights (LTCRs and ILTCRs, respectively) and their potential addition to the Z2 process.
“There seems to be a bit of mission creep. I thought we were looking at a better way to do business with Z2,” said Holloway, KPP’s assistant general manager of operations. “I thought we were looking at a less complex way of handling [Z2] going forward and handling the burden of these historic costs. Now it sounds like we’re keeping Z2 and having another process moving forward.”
“Our goal is to come up with a better process,” Bruce Rew, SPP’s vice president of operations, reminded the task force. “We’re working through the process of how we would transition to a different process.”
SPP staff suggested LTCRs and ILTCRs could serve as potential alternatives to Z2 credits. LTCRs cover the entire June-May year and can be renewed annually or converted into TCRs. ILTCRs, already used by most RTOs, would provide the option of long-term rights for participant-funded transmission upgrades.
“The TCR process tries to forecast what the [congestion] pool will be,” said Charles Cates, SPP’s manager of transmission services, explaining that solving congestion at one point on the system can create congestion elsewhere. “A TCR is your share of the congestion pool. The value of the TCR may increase as more transmission requests come onto the system. Some bidders may try and predict where that congestion will be and seek TCRs.”
“I’d like to ditch this Z2 nightmare, but the problem is, [when] you give away the TCR to a project sponsor whose project resolves the issue and there’s no congestion, he’s getting nothing [of value],” American Electric Power’s Richard Ross said. “I’m afraid this will give incentives for some sort of twisted sponsorship where sponsors will want to solve some, but not all, of the congestion. If there’s still congestion and you’ve given that TCR away to that sponsor, it’s not available for that transmission customer that wants, needs and expects it.”
“I keep hearing the word ‘incentives,’ but we’re really looking at reimbursement mechanisms,” said Oklahoma Gas & Electric’s Greg McAuley, agreeing with Ross. “We’re looking to pay [upgrade sponsors] back and make them whole for what they’ve added to the system, but we’re not trying to provide incentives for new transmission construction.”
Cates noted SPP’s TCR market is still going through growing pains since it was implemented as part of the RTO’s Integrated Marketplace in 2014. In recent months, the TCR market’s funding has just reached a 90% funding level.
“To be fair, we don’t have much of an ILTCR market because no one takes them,” SPP’s Lanny Nickell said.
The TCR market’s inability to provide a one-for-one offset with hedges against congestion has become a growing concern for load-serving entities. They point to wind farms being granted non-firm service while being allowed to put physical energy on the system.
“How do they get away with not paying for non-capacity upgrades, and why are we being forced to pay for sponsored upgrades?” Ross asked rhetorically. “That doesn’t make a bit of sense. Why are we paying $10 for something that’s not worth a nickel?”
Kansas City Power and Light’s Denise Buffington, the task force’s chair, asked staff to provide more information on how the capacity versus non-capacity issue is handled in other markets. The task force will meet again before January’s Markets and Operations Policy Committee meeting in Dallas, where it will take an even deeper dive into SPP’s ILTCR proposal.
‘And’ vs. ‘Or’
The group also discussed SPP’s aggregate and planning studies, generation interconnection process and the auction revenue rights and TCR processes. Staff also explained the Z2 process was used as a mitigation for FERC’s concern about “And” pricing for service, embedded costs and any other upgrade costs.
In a 2001 order, the commission said the pricing of transmission service could reflect either the greater of the network’s average cost (with expansion costs rolled-in) or the incremental cost of the expansion, known as “Or” pricing. It prohibited pricing based on a combination of average and incremental costs, known as “And” pricing.
SPP’s Tessie Kentner said any changes to the Z2 crediting process must not violate those principles. She said the commission accepted the RTO’s compliance filing and its use of Z2 credits for sponsored upgrades for Order 681, which requires organized electricity markets to make available long-term firm transmission rights.
“I think we have a deeper understanding of the complexity of Z2 and may have highlighted that Z2, as implemented today, still has many unknown impacts to participants,” Buffington said.
Ross did provide a moment of levity when he presented “Richard Ross Gold Stars,” in the form of Christmas ornaments, to SPP’s Steve Purdy and Charles Locke. Ross said it was a sign of appreciation to the two for representing the RTO’s position on Z2 credits.
“Somebody has to take the shots for the organization,” Ross said.
KEPCo Files FERC Complaint
The Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC under Sections 206 and 306 of the Federal Power Act and Rule 206 of the commission’s Rules of Practice and Procedure (EL17-21).
KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to KEPCo violated the RTO’s Tariff and the filed rate doctrine, and is “otherwise unjust, unreasonable and proscribed” by the FPA. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.
KEPCo COO Les Evans had hinted at the filing when his request for a waiver from directly assigned Z2 network upgrades was rejected by the SPP board in October. (See SPP Board Lets Action on Z2 Stand; Litigation Likely.)
Seven parties have already intervened in the case, including SPP members KCPL, Sunflower Electric Power, Western Farmers Electric Cooperative and the Arkansas Electric Cooperative Corp.
Competitive Transmission, Strategic Planning, Other Groups Meet
The Z2 task force’s meeting was just one of several held in Dallas last week in and around AEP’s offices.
The Competitive Transmission Process Task Force met Wednesday to revise draft revision requests that reflect input from the October Board of Directors meeting and to incorporate changes in SPP’s annual transmission revenue requirement template. The group will conduct a conference call next week to prepare for the January board meeting.
The Strategic Planning Committee met Thursday to review and discuss the operational challenges facing SPP as a result of the 22,000 MW of wind power in the interconnection queue.
Stakeholders shared their concerns that the expected expiration of renewable tax credits is leading to a surge of additional generation being added to the system, citing congestion concerns. Wind and solar resources account for 98% of SPP’s current generation interconnection queue.
The Public Utility Commission of Texas on Thursday approved a preliminary order outlining numerous issues NextEra Energy and Oncor must address to win approval of NextEra’s acquisition of Texas’ largest distribution utility.
Two of the PUC’s three commissioners, Chair Donna Nelson and Ken Anderson, also filed memos with additional questions for the docket (No. 46238).
“I want to be sure we cast a wide net,” said Nelson, who included a set of questions from the Texas Industrial Energy Consumers, during the commission’s open meeting.
She focused her questions on whether NextEra should be able to expense federal taxes for ratemaking purposes and if so, whether those savings should be shared with ratepayers. Similar directives from the PUC scuttled Hunt Consolidated’s attempted takeover of Oncor earlier this year. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
Nelson also asked whether NextEra’s commitment to preserve Oncor’s staffing levels for two years after the transaction’s close was enough time, and what would constitute a “material involuntary workforce reduction,” quoting from the company’s promise of no layoffs.
Anderson directed the companies to answer whether the recent appellate court decision regarding Energy Future Intermediate Holdings’ make-whole claims to lien holders would affect the transaction and require an amended application. (See Appeals Court Ruling for Bondholders Clouds EFH Reorganization.)
He noted the commission faces a hard deadline of April 29 to issue a decision on the transaction. Because the PUC is hearing the case rather than an administrative law judge, the commissioners will have some flexibility when they conduct a hearing on the merits Feb. 21-24, Anderson said.
“Everyone needs to be mindful that in the absence of a unanimous settlement, once the record closes, that’s it,” Anderson said. “There’s no sweeteners … there’s no ability to change the deal” without an amended application.
NextEra announced in late July it had reached an agreement to acquire Energy Future Holdings’ 80.03% indirect interest in Oncor for $18.6 billion. On Oct. 31, it announced an affiliate would acquire an additional 19.75% from a pair of private venture funds, for an additional $2.4 billion. NextEra also plans to acquire the remaining 0.22% interest owned by Oncor Management Investment, giving the Florida-based company complete control of the company.
| NextEra
Intervenors in the case include the Steering Committee of Cities Served by Oncor, the Office of Public Utility Counsel, the Texas Industrial Energy Consumers, IBEW Local 16 and NRG Energy.
The U.S. Bankruptcy Court in Delaware was to begin confirmation hearings for the exit of EFH (rebranded as Vistra Energy) from Chapter 11 bankruptcy Thursday, but those proceedings have been postponed until February. EFH filed a modified reorganization plan Thursday to compensate for the appeals court’s ruling that gives first- and second-lien noteholders an additional $800 million payout.
AEP Units’ Merger OK’d
Also Thursday, the PUC approved a State Office of Administrative Hearings’ proposal for decision in American Electric Power’s merger of its AEP Texas Central, AEP Texas North and AEP Utilities subsidiaries (No. 46050) into AEP Texas. An ALJ found the merger “consistent with the public interest if certain conditions are imposed.”
Those conditions include AEP maintaining separate divisions until the commission can approve consolidated rates and tariffs, AEP Texas providing rate credits to its customers and combining current reliability benchmarks into a single metric.
Anderson suggested modifying the proposed decision to direct AEP to prepare a study on consolidating the companies’ rates and share it with stakeholders.
“That will inform stakeholders, including [PUC] staff, whether to call AEP in for a rate case,” he said.
The commissioners and AEP representatives debated whether to set a June 2017 or June 2018 deadline for the study’s completion. They eventually settled on finishing the study “four months in advance of a rate case.”
“Our position is the rates are different in the two different areas,” said the industrial consumers’ Katie Coleman. “There will be winners and losers. We’re not sure if we want the rates combined.”
Actions Delayed
The commissioners delayed until its Dec. 16 open meeting a final rulemaking on distributed generation interconnection agreements (No. 45078) and final reports to the Texas Legislature on alternative ratemaking mechanisms (No. 46046) and competitive electric markets (No. 45635).
The New York environmental group Hudson River Sloop Clearwater sued New York regulators on Wednesday over their subsidies for upstate nuclear power plants.
Manna Jo Greene | Hudson River Sloop Clearwater Inc.
Clearwater wants the court to vacate the “Tier 3” requirement included in the state’s Clean Energy Standard, which would pay zero-emission credits to three generators that that could have closed as early as next year. Critics say the program could cost ratepayers $7.6 billion over 12 years.
The suit, filed in state Supreme Court in Albany, alleges the program was illegally enacted and fails the New York Public Service Commission’s mandate to provide just and reasonable rates.
This is the second legal challenge to the ZEC program. In October, fossil fuel generators and a trade association filed suit in federal court attacking the program on the grounds that the state was interfering in FERC-regulated wholesale markets. (See Federal Suit Challenges NY Nuclear Subsidies.)
ZECs “would bring about one of the largest transfers of wealth from the ratepaying public to a single corporate entity in New York state history,” Clearwater’s suit says.
The PSC last month approved Exelon’s purchase of the James A. FitzPatrick nuclear plant from Entergy, making it the sole owner of the three nuclear power plants on Lake Ontario, all of which are eligible for ZEC payments. Exelon also is the beneficiary of a bill approved by Illinois legislators Thursday to provide similar credits to keep its Clinton and Quad Cities nuclear plants operating for another decade. (See related story, Illinois Lawmakers Clear Nuke Subsidy.)
Clearwater says the PSC rushed the subsidy through the regulatory process in 14 days after a staff report first publicly broached the subsidy. The ZEC price will be determined by the federal “social cost of carbon.”
“Tier 3 contains many deficiencies, including implementing a program beyond the legal authority of the PSC, numerous assumptions and statements not supported by any technical basis, errors of fact and legal procedural defects preventing public comment and review in violation of multiple sections of the State Administrative Procedures Act,” the suit alleges.
A PSC spokesman defended the program. “Clearwater’s opposition to nuclear energy is based on ideology, not reality, and ignores the many benefits these upstate nuclear plants provide. Our zero-emission credit plan is a cheaper, sensible way to have the existing carbon-free nuke fleet serve as a bridge to renewables as opposed to importing fracked gas and using dirty oil,” spokesman Jon Sorensen said in a statement.
“Opposing this subsidy will demonstrate to the country that nuclear power is not where our dollars need to be spent. Many of these nuclear plants are aging, leaky and dangerous,” Manna Jo Greene, Clearwater’s environmental action director, said in a statement. “Clearwater strongly supports N.Y. state’s goal of 50% renewable energy generation by 2030 but opposes the nuclear subsidy. Moving toward a fully renewable energy economy as rapidly as possible is the direction that New York should model for the nation.”
FERC last week approved PJM’s cost-responsibility assignments for its updated Regional Transmission Expansion Plan, dismissing complaints from Dayton Power and Light that one of the projects should have been allocated completely to Dominion Resources (ER16-2539).
DP&L protested PJM’s request that the costs to rebuild the Carson-Rogers Road 500-kV transmission line in Virginia (project b2744) be distributed as part of regional reliability maintenance and should instead go completely to Dominion. DP&L said PJM’s choice wasn’t the most cost-effective, as the grid operator had presented a $24 million option at its Transmission Expansion Advisory Committee meeting in May but selected a $48.5 million project proposed by Virginia Electric and Power Co. because it also resolved a local-planning criterion for Dominion.
Carson – Rogers Project Map | PJM
Additionally, DP&L argued the reliability violation came from an outdated load growth forecast and that “updated forecasts suggest that there may be no regional reliability violation.”
“Dayton Power contends that there appears to be a disconnect in PJM’s planning process such that a generation interconnection study, using one set of assumptions, may permit the interconnection of a generator without charging the generator for network service upgrades, while an RTEP study, using a different set of assumptions may find that there are network service upgrades that are needed with that generator interconnecting,” FERC summarized in its ruling.
PJM responded that DP&L was missing the point of the filing and should have raised any concerns it had at the May TEAC meeting. The RTO said the filing is for FERC to determine if PJM’s decisions conform with FERC’s approved methods, not whether individual allocations are accurate.
It’s also not a question of cheapest option, PJM said, but most cost-efficient and effective according to its engineering analysis. Although it reviewed other proposals, it explained, none of them also addressed the local criterion concerns.
Dominion said that just because the project also solves its local issue doesn’t mean it’s not suitable for inclusion in the RTEP.
The commission said “Dayton Power has not supported its assertion that this issue was not adequately vetted within the stakeholder process. We find that while Dayton Power disputes PJM’s selection of project b2744, Dayton Power makes no assertion that the process that PJM undertook in selecting project b2744 in the PJM regional transmission plan for the purposes of cost allocation is inconsistent with Schedule 6 of the PJM Operating Agreement.”
The Western Energy Imbalance Market’s governing body voted to implement procedures to ensure market participants have input into CAISO policy initiatives that affect the market.
The CAISO staff’s proposed “guidance document” sketches out how ISO staff will interact with the EIM, providing a schedule for notifying the governing body about ISO initiatives and laying out the processes by which body members and EIM participants will provide feedback on proposed policy changes.
ISO staff initiated development of the document in October in response to a recommendation by the EIM’s Transitional Committee — the West-wide stakeholder group charged with developing the market’s governance plan. That committee decided to leave it to market participants to parse out that plan into specific procedures. (See CAISO Seeks Process to Keep EIM, Governing Body in the Policy Loop.)
“The Transitional Committee envisioned a more user-friendly document, something that’s different from corporate bylaws or the charter for EIM governance,” CAISO General Counsel Dan Shonkwiler told the EIM governing body during its Nov. 30 meeting. “It may be a more accessible document for stakeholders trying to understand what you do and how to interact with you.”
EIM Map | CAISO
Not a Rubber Stamp
Governing body member Valerie Fong said her support for the guidance document came only “after a number of questions and comments that were addressed and are answered very specifically through” the final proposal.
“This isn’t just a rubber-stamp ‘OK,’” Fong said ahead of the vote to approve the document. “It took a lot of work on Dan’s part to consider the comments and suggestions — and the questions” submitted by EIM stakeholders.
The proposal still requires approval by the ISO board, which is expected to issue a decision on the matter during its December meeting.
Significantly, the guidance document provides solutions to the overlapping authority between the ISO board and the EIM governing body resulting from the EIM’s delegation of a portion of its authority over Federal Power Act Section 205 filings to the ISO.
The document describes how ISO staff and board members will interact with the EIM governing body to determine whether a proposed Tariff amendment affecting the EIM falls under the body’s “primary authority” — giving EIM leaders the right to effectively approve or reject an amendment.
In those instances, the ISO board — which technically retains final authority over all Tariff changes — is expected to give “great deference” to the governing body’s decisions and place those matters into a consent agenda.
The document also spells out an “advisory” — and non-voting — role for the governing body regarding policy initiatives covering general market rules that also affect the EIM.
‘Hybrid’ Initiatives
“Hybrid” initiatives — proposals that would amend multiple Tariff provisions affecting both the EIM and the ISO at-large — will get more complicated treatment. In cases when the EIM is the key driver of an initiative, primary authority will fall to the governing body. In other cases, the body could retain primary authority over just EIM-specific portions of a broader ISO initiative — a sort of line-item veto power.
EIM Governing Board members left to right: Fong, Prescott, Howe, Linvill, Schmidt | CAISO
The governing body will also have a voice in how any policy initiatives are designated with respect to primary authority, providing the body the right to challenge any “initial” designation made by ISO management.
In the event that the governing body objects to an initiative’s final designation, the body chair — currently Christine Schmidt — can trigger a dispute resolution process ultimately involving a joint session of the body and the ISO board.
In response to requests by current and future EIM members, the final document also clarifies that CAISO’s Department of Market Monitoring and Market Surveillance Committee should interact directly with the EIM governing body in the same manner in which both groups currently consult with the ISO board.
On Oct. 1, Arizona Public Service and Puget Sound Energy joined the EIM, which launched in November 2014 with PacifiCorp and NV Energy. Portland General Electric and Idaho Power are expected to join in 2017 and 2018 respectively. Others that have indicated an interest in joining are Mexico’s Baja California Norte, the Sacramento Municipal Utility District and Seattle City Light. (See Council OKs Seattle City Light Bid to Explore Joining EIM.)
CARMEL, Ind. — Some wind generators appear to be deliberately over-forecasting their output to inflate their revenues, according to MISO Independent Market Monitor David Patton, who called for rule changes to discourage gaming.
Patton said wind units on average produced 146 MW less than their MISO dispatch instructions in 2015 and 2016 (excluding economic curtailments and manual redispatch), a higher deviation than any other resource class in the RTO.
| Potomac Economics
Patton told the Market Subcommittee on Nov. 29 that much of the problem lies with MISO’s day-ahead margin assurance payment (DAMAP), which guarantees day-ahead profit when real-time dispatch is less than the day-ahead schedule. MISO uses wind operators’ forecasts to determine their dispatch level.
Two-thirds of MISO’s $7.5 million in DAMAP payments to wind resources in 2015 and 2016 was because of over-forecasting and only $2.5 million was spent on curtailment, Patton said. “Most of our wind DAMAP payments are unjustified,” he said.
Patton: Eliminate DAMAP for Wind
Patton said the DAMAP should be eliminated for wind resources once MISO adopts five-minute settlements. He reasons that because wind is a fast-ramping resource, operators will want to be paid in real-time prices rather than collecting DAMAP.
Patton also called for a change in rules that encourage wind generators to err on the high side in their forecasts to ensure they receive a dispatch signal that does not limit their output. Wind resources producing above their dispatch signal can be subject to excess energy penalties, but MISO settlement rules are less punitive for wind resources that fall below their forecast output.
Patton recommended wind suppliers be incentivized to submit accurate forecasts by giving them more “headroom” and relaxing excessive energy charges when the system is unconstrained. He also suggested MISO automate its validation of market participant forecasts.
“If we balance these objectives well, the wind suppliers will be happy, the grid operators will be happy and those that have to contribute to the DAMAP payments will be happy,” Patton said.
Over-forecasting leads to supply-demand imbalances, he said, with MISO deploying regulating reserves and under-utilization of the grid as the RTO dispatches the system to make room for the over-forecasted energy.
‘Sustained Biases’
Patton said that although larger wind producers generally have lower forecasting errors than smaller ones, “a number of large and small wind suppliers exhibit large sustained forecast biases.” Patton said over-forecasting is more prevalent in summer, when energy prices are higher.
He said wind operators might be violating their obligation to provide accurate information to MISO. He noted that FERC is similarly concerned about evidence of over-forecasting.
Patton also said more research is needed to put a price on how much the over-forecasting costs MISO and that he may offer more definitive solutions in his 2016 State of the Market Report.
MISO Responds
Jeff Bladen, executive director of market services, said MISO staff will work with the Monitor on potential fixes. “We aren’t seeing broad-based market manipulation for sure, but we may have a market inefficiency that we want to close up as soon as practical. Certainly there’s work in front of us to assess and get advice,” Bladen said.
DTE Energy’s Nick Griffin said he would like to see MISO and the Monitor provide similar deviation averages for other asset classes. But he said he could support removing forecasting capability from wind units if gaming is discovered.
“Wind resources are in a difficult position because they face different challenges than other resources,” Patton said. “They have to manage something that’s fundamentally different than other resources. When we suggest that wind resources should be treated differently, it’s because they have a challenge that other asset owners do not have to face.”
