WASHINGTON — FERC Commissioner Bernard McNamee on Thursday announced he would not seek another term, opening up yet another slot on the commission for the White House and Senate to fill.
Speaking at the commission’s monthly open meeting, McNamee said he would at least complete the remainder of his term, which ends June 30, and serve beyond that date until the Senate confirms a replacement. Legally, if there is no replacement, he is allowed to remain on the commission past the expiration of his term until the end of the current Congress at the end of the year.
FERC Commissioner Bernard McNamee addresses staff in November 2019. | FERC
“I’m not just going to leave on June 30 if there’s no one to replace me … and leave the commission without a quorum,” McNamee told reporters after the meeting.
McNamee lives in a suburb of Richmond, Va., with his wife and 14-year-old son, who will be entering high school next year. But he said he stays in D.C. during the work week, only going home on the weekends because of the commute. “Depending on traffic, it can be either two hours and 15 minutes or it could be five hours,” he said.
“This has been one of the most interesting and rewarding jobs I have ever had,” McNamee said. “And I enjoy the work, the issues, the people; in short, I love this job. But I love my family more.”
He said he has no plans yet on what he will do after he leaves, but “I anticipate I’m still going to be active in addressing important energy issues facing the nation.” He also stressed both during the meeting and to reporters that he will be at the commission for at least five more months. “There’s a lot of work to get done here at the commission between now and the end of my term. I’m going to be fully engaged.”
President Trump nominated McNamee in October 2018, and the Senate confirmed him 50-49 later in December. (See Senate Confirms McNamee to FERC.) He filled a seat left open by Robert Powelson, who departed after only a year to become CEO of the National Association of Water Companies. During his last commission meeting in July 2018, Powelson also cited wanting to spend more time with his family as a reason for his departure. (See FERC Says Farewell to Powelson.)
FERC Chairman Neil Chatterjee told reporters he did not “foresee any change in direction” or reprioritization of work as a result of McNamee’s decision. “It’s entirely possible he could stay here until the end of the year,” Chatterjee said. “I can tell you with complete confidence that, barring some unforeseen incident, we will not lose a quorum this year.”
Trump nominated FERC General Counsel James Danly to be a commissioner last year, but he would fill a seat left open by the death of Commissioner Kevin McIntyre and serve a term to expire in 2023. Though his nomination advanced to the floor, the Senate did not act on it before the end of the year, meaning Trump must resubmit it, which he has yet to do.
“Given today’s announcement, the White House may have been waiting for McNamee to make his announcement to clear the way for nominating Danly to a longer term,” ClearView Energy Partners said. McNamee’s successor would serve a term that ends in 2025.
Regardless of the White House’s plans, Trump’s impeachment trial in the Senate grinds the body’s work to a halt for now.
“Given the beginning of impeachment proceedings in the Senate, we are not expecting any progress on nominations — should they even be made by the White House over the next several weeks — until that process concludes,” ClearView said.
FERC on Thursday declined to reconsider two orders upholding New England Power Pool’s gag rule but allowing an RTO Insider reporter to join the organization’s End User sector.
The commission dismissed NEPOOL’s request for rehearing of its January 2019 order rejecting a proposed change to the organization’s rules to prevent members of the press from joining (ER18-2208-002). The commission rebutted NEPOOL’s claim that FERC lacked jurisdiction, saying its membership rules “directly affect commission-jurisdictional rates” because members can vote on market rules.
Separately, the commission also denied Public Citizen’s request for rehearing of its April 2019 ruling rejecting RTO Insider’s complaint seeking to void NEPOOL’s policies prohibiting non-members, including the press and public, from attending stakeholder meetings (EL18-196-001). RTO Insider also had challenged a rule barring the press from reporting on what is said at the meetings.
New Hampshire Consumer Advocate D. Maurice Kreis turned his photo of Supreme Court Justice Louis Brandeis upside down in protest of FERC’s April 2019 ruling rejecting RTO Insider’s bid to force the New England Power Pool to open its meetings to the public and press. | D. Maurice Kreis
Public Citizen said FERC erred in finding that press or public attendance at NEPOOL meetings does not impact votes and therefore cannot impact rates. It also disputed the commission’s opinion on the limits on its authority to regulate RTO governance matters.
“What Public Citizen refers to here are, at best, indirect effects on rates, whereas it is direct effects that create commission jurisdiction,” FERC said.
Commissioner Richard Glick filed a concurring opinion agreeing that the commission lacks jurisdiction but urging NEPOOL to change what he called its “misguided” rules.
“NEPOOL meetings address a broad range of important issues, including, among other things, the reliability of the electric grid, state policies for addressing climate change and the integration of new technologies into the resource mix. The public and, by extension, the press have a legitimate interest in how NEPOOL, the entity charged with administering ISO New England’s stakeholder process, is considering these matters public of interest,” Glick wrote.
“To paraphrase Justice Louis Brandeis, sunlight is the best disinfectant, and it is hard for me to understand how barring public and press scrutiny will further NEPOOL’s mission or, ultimately, its legitimacy as the forum for considering how ISO New England’s actions affect its stakeholders.”
Tyson Slocum, director of Public Citizen’s energy program, said the group will “petition the courts to review this terrible and misinformed FERC order.”
RTO Insider correspondent Michael Kuser, an electric ratepayer in Vermont, has been attending NEPOOL meetings since May 2019, after the group granted him membership. But he remains barred from reporting what is said at meetings and must quote only from posted documents and statements obtained outside the sessions.
WASHINGTON — A top PJM official on Wednesday suggested states embrace carbon pricing rather than exit the RTO’s capacity market in response to FERC’s controversial order expanding the minimum offer price rule (MOPR).
“We’ve had a proposal on our website for two years now [on] how we would implement carbon pricing,” Craig Glazer, PJM vice president of federal government policy and a former Ohio regulator, said during a panel discussion sponsored by research group Resources for the Future (RFF). “We would do it with what I call a ‘coalition of the willing,’ because I don’t necessarily need all 13 states to agree to it. … But we could do this. … We’re anxious to move forward in discussions on that.”
Glazer said carbon pricing “would go a long way” toward addressing state concerns that they could pay twice for capacity — once through PJM’s auction and again through their renewable portfolio standards — under FERC’s Dec. 19 order requiring the RTO to expand the MOPR to all new state-subsidized resources.
Calpine, which led the complaint that prompted FERC’s order, has long supported carbon pricing, said Sarah Novosel, the company’s managing counsel and senior vice president of government affairs.
“The states should be able to … lower carbon emissions, but they should do it in a market-friendly way so we can maintain the benefits of the competitive capacity market that we’ve had for the last 20 years,” she said. “It would be such a shame to lose the competitive capacity market because people are upset by this order.”
Novosel acknowledged that the Regional Greenhouse Gas Initiative, which includes Maryland and Delaware in PJM, “doesn’t seem to be doing a whole lot” because its carbon auction prices have been low. “Let’s goose up that price or do some other type of carbon pricing that really puts a meaningful price on carbon. … If you get prices high enough … developers will come in, not with state contracts but because they see the market signal and they’ll develop the types of renewable or low- or zero-emitting generation that’s needed to hit the states’ goals.”
The other two panelists, Analysis Group’s Sue Tierney and Grid Strategies’ Rob Gramlich, also endorsed carbon pricing, but they said they predicted some states will leave the capacity market over the MOPR ruling.
‘FRRexit’
Tierney, who chairs RFF’s board of directors, said FERC’s attempt to protect the capacity market from price suppression from subsidized resources may have, ironically, mortally wounded the construct.
“There are so many states — and perhaps public power entities — who decide that this is not the way they want to go that there will need to be pathways … to figure out how people can exit the capacity market,” she said, noting that CAISO, MISO and SPP leave responsibility for resource adequacy to the states.
“The fact is states and utilities now can — and likely will — pull out of these markets in response. The mechanism is the fixed resource requirement [FRR]. It’s in the Tariff; no further changes need to be made,” said Gramlich, who dubbed the potential exodus “FRRexit.”
“I’ve had incredibly detailed conversations with state legislators about how it could be done,” he added. “They’re thinking about it in Maryland, New Jersey, Illinois. I’m hearing rumblings in Virginia. … A lot of states will say, ‘Screw it. I’m out.’”
Glazer warned that the FRR could be an “incredibly inefficient solution” for the states to meet their resource adequacy needs.
“If I’m in Newark, N.J., for example, wind and solar … resources may be in a neighboring state, may be outside of the FRR zone. So, it certainly would be more costly.”
It could also result in over-procurement that depresses energy market prices, hurting renewables and nuclear generation, he said. “You could feel really good that you can control your destiny, but you may be hurting the very resources you want to attract.”
Don’t Overreact
Glazer said the order, which rejected many of PJM’s “MOPR-Ex” proposals, “might have made the process more administrative, more uncertain, than it needs to be.” But he said the worst-case scenarios are overblown.
“I want to ask that we slow down the hyperbole. This is a serious issue, but I don’t think it is the death knell of renewables or nuclear,” he said. “When you add the existing carveouts that FERC did for renewable portfolios, demand resources, existing public power … I don’t think, in the short run, this is [going to] have quite the impact that people think.”
Glazer said FERC’s ruling on PJM’s fast-start pricing proposal (ER19-2722) — which is listed on Thursday’s open meeting agenda — could improve price formation in the energy market. “If we get energy prices right, we can shrink the capacity market, which is a goal we all should have,” he said.
Tierney was less sanguine. “The idea that we’re going to get more and more revenue from the energy market [is] in some ways a leap of faith,” she said. “We have low natural gas prices; we have more and more of the resources with zero variable costs or very close to zero variable costs.”
She disagreed with the commission majority and fossil generators that the order creates a “neutral playing field,” saying she sides with Commissioner Richard Glick, whose dissent predicted the order will slow the transition to a low-carbon resource base.
She was also critical of PJM and its Independent Market Monitor becoming the “policy police” in determining which resources have received state subsidies and should be subject to the MOPR. “The courts are going to have a field day with figuring out what is a subsidy,” she said.
Glazer said PJM doesn’t welcome the role FERC has given it, saying the RTO is particularly concerned with how it and the IMM will review requests for unit-specific MOPR exemptions. “I could take an uneconomic plant and stretch it over a longer period of time and make it look economic. Or I could do the converse,” he said.
Appellate Review
Gramlich said FERC should issue its order on the rehearing requests quickly so the appellate courts can resolve questions over the ruling’s breadth and application. (See related article, PJM Industrials Challenge MOPR for Voluntary RECs.)
He said he expects the courts to overrule FERC based on the Supreme Court’s 2016 Hughes v. Talen ruling, in which it said Maryland regulators’ attempt to subsidize a combined cycle plant was improper because it was “tethered” to the generator’s participation in the federally regulated capacity market. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
“I think they will look at that and say, ‘Wait a minute, we can’t have reverse tethering either, where FERC gets to directly … target’” state subsidies.
Tierney said FERC’s argument that it “can go after state subsidies but not federal subsidies seems cockamamie.”
Novosel agreed. She said the courts might permit FERC to ignore the federal production tax credit and investment tax credit for renewables. “Where you have direct congressional action, you could say that Congress thought about it. But to say that any federal action was an act of Congress and so we can’t take action against it, I think it could be vulnerable.”
MISO’s industrial and transmission customers have banded together in a new complaint against the RTO’s seven-year-old cost allocation plan for baseline reliability projects (BRPs).
The Coalition of MISO Transmission Customers (CMTC), Industrial Energy Consumers of America (IECA) and LS Power on Tuesday filed a joint complaint with FERC alleging that MISO’s current location-based cost allocation methodology for BRPs doesn’t comport with the commission’s principle that beneficiaries of transmission projects should pay for them (EL20-19).
MISO’s BRP costs are allocated only to the local transmission pricing zone where a project facility is physically located. Costs are recovered by the transmission owner developing the project.
The complainants say the BRP allocation fails to identify beneficiaries “in a manner roughly commensurate with the costs to be allocated for each project,” violating the Federal Power Act’s standard on just and reasonable rates and cost-causation principle.
“MISO’s current cost allocation methodology for baseline reliability projects concludes, without any analysis of individual projects, that for cost allocation purposes, the only relevant beneficiaries of baseline reliability projects are the ratepayers in the transmission owner zone where the baseline reliability project is physically located,” the three organizations said.
They argued that MISO should return to using a BRP cost allocation based on a line outage distribution factor (LODF) methodology, the allocation method in place prior to 2013.
“Application of a previously accepted methodology as a replacement for a methodology determined to be unjust and unreasonable is an effective way to prevent irreparable harm to ratepayers arising if the unjust and unreasonable methodology restricts the [BRPs] from competition,” they urged.
The complainants also said that use of LODF or similar analysis to identify beneficiaries would open BRPs to competitive bidding, as the projects would no longer be bound to “arbitrary cost allocation rules restricting costs to local zones.”
“Limiting the recovery of costs to only those zones where the physical assets are located grants incumbent transmission owners in MISO a federal right of first refusal — the existing transmission owners in the zone where the project is located have the exclusive right to build the [BRP] without competition from other transmission developers,” they said.
Since 2013, MISO has approved an estimated $5 billion worth of BRPs in its annual MISO Transmission Expansion Plans (MTEPs). Last year’s nearly $4 billion MTEP 19 contained 113 BRPs at a combined $826 million. MISO’s Board of Directors voted early last month to approve the transmission package. (See MISO Board OKs $4 Billion MTEP 19.)
MISO in February will release modeling on the 2019 crop of BRPs. CMTC, IECA and LS Power said those models will demonstrate whether the projects will deliver regional benefits.
“It is highly likely that the models will show that many of the 113 [BRPs] will have regional benefits such that allocation of costs based exclusively on project location would be inappropriate,” the organizations said, adding a request for fast-track processing of the complaint because of “compressed” remaining timelines in MTEP 19.
IECA President Paul Cicio said action needs to be swift to return BRPs to an allocation based on cost causation.
“In recent years, the transmission portion of our electric bills have been the single highest increased cost as compared to all other energy sources, directly impacting manufacturing competitiveness,” Cicio said in a statement. “The existing MISO cost allocation methodology fails the commission’s obligation to ensure just and reasonable rates. … By charging 100% of the costs of every [BRP] only to ratepayers in the zone in which the project is physically located, MISO is violating these basic principles and is charging some ratepayers an amount that exceeds the benefit actually received from the project while undercharging others.”
Filing of MEP Cost Allocation Plan Imminent
Meanwhile, MISO will file this week to change cost allocation for its market efficiency projects (MEPs), despite similar stakeholder complaints that the proposal ignores the wider benefits of a class of projects.
After months of back-and-forth, MISO recently landed on a cost allocation proposal that lowers the MEP voltage threshold from 345 kV to 230 kV, eliminates the current 20% postage stamp allocation and adds new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path.
MISO’s new plan also eliminates the regional benefit-to-cost test on local economic projects between 100 and 230 kV, now proposing to perform only a local test on those projects. The RTO had previously proposed that such projects needed to pass a 1.25:1 benefit-to-cost ratio on a regional basis, though it only proposed to allocate their costs to the local transmission pricing zone where they are located. (See MISO Makes U-turn on Cost Allocation Policy.)
Still, multiple stakeholders said the cost-causation issues that prompted FERC’s June rejection of the first cost allocation plan remain, with some saying MISO is essentially ignoring the possibility that sub-230-kV transmission projects could be beneficial on a regional basis.
Built into the plan is a commitment that MISO will revisit the method after three years to take stock of its effectiveness.
The Governing Body of CAISO’s Western Energy Imbalance Market filled the second of two unexpected vacancies Wednesday, selecting Robert Kondziolka, who recently retired after four decades with Arizona’s Salt River Project.
Robert Kondziolka | CAISO
Kondziolka fills a seat on the five-member board left vacant when Travis Kavulla — a former member of the Montana Public Service Commission and energy director at R Street Institute, a D.C.-based think-tank — announced in August he had to resign from the Governing Body after accepting a job with a market participant. (See EIM Governing Body Gains Member, Loses Another.)
Kavulla joined NRG Energy as vice president for regulatory affairs in September. His three-year term on the EIM Governing Body had 22 months remaining.
Kondziolka will fill out the remainder of that term, starting Feb. 1 and extending through June 30, 2021.
At SRP, Kondziolka held a half-dozen management positions, including director of transmission line design, construction and maintenance, and director of transmission and generation operations. At the time of his retirement he was a management consultant for grid resilience and security.
“Welcome, Rob. We look forward to seeing you soon,” Chair Carl Linvill said at the Governing Body’s meeting at CAISO headquarters in Folsom, Calif.
Kondziolka did not address the meeting.
Randy Howard, general manager of the Northern California Power Agency, served on the nominating committee that selected Kondziolka and presented its recommendation to the four current Governing Body members.
“We had a great set of candidates,” Howard said by phone. He explained that the committee came up with a short list from those who applied for the position or were identified by a search firm. The eight committee members had some trouble reaching a consensus but ultimately settled unanimously on Kondziolka, he said.
The committee said in a memo that it “believes Mr. Kondziolka would ensure the EIM Governing Body’s overall composition continues to reflect appropriate independence requirements and a diversity of experience, expertise and geography, as well as the continued effectiveness of the EIM Governing Body.”
The nominating committee included representatives from eight constituencies — EIM entities, transmission owners, public utilities, state regulators and the CAISO Board of Governors. John Prescott, vice chair of the Governing Body, also served on the committee, calling the nomination process “robust.”
Governing Body members Valerie Fong thanked the committee, saying, “I know these things take a lot of time, and I know that the nominating committee doesn’t take its responsibility lightly.”
The independence and geographic composition of the Governing Body, with representatives from Western states other than California, has been a main concern among participants in the continually growing EIM, which has become the major interstate trading market in the Western Interconnection.
Many from the interior West are wary of taking direction from Californians, but that hasn’t stopped the EIM’s growth. Three Colorado utilities recently announced they would join, as the EIM said its benefits to members had exceeded $800 million in the five years since its inception. (See EIM Lands Xcel, 3 Other Colo. Utilities.)
SPP is hoping to compete with the EIM with its Western Energy Imbalance Service but so far has gained little traction.
The EIM allows participants to trade wholesale electricity in real time across state borders. CAISO is considering expanding it to a day-ahead market.
Another unexpected vacancy on the Governing Body was filled in August, when the remaining three members picked Anita Decker as a colleague.
Decker, a Pacific Northwest industry veteran, filled the seat left vacant in April when Kristine Schmidt, the Governing Body’s inaugural chair, left to join the board of embattled PG&E Corp. (See PG&E Departure Leaves EIM Vacancy.)
Public Service Company of Oklahoma formally notified ERCOT on Tuesday that it will retire the coal-fired Oklaunion Power Station in the Texas Panhandle.
PSO filed a notification of suspension of operations for the plant, effective Oct. 1. Market participants have until Feb. 11 to file comments before the grid operator makes a final decision.
Oklaunion Power Station | AEP
American Electric Power, PSO’s parent company and the plant’s operator and majority owner, said in September 2018 that it planned to shut down Oklaunion by October 2020 over concerns that the plant’s production costs were no longer competitive. (See AEP Announces Closure of Oklaunion Coal Plant.)
The 34-year-old, 650-MW plant’s ownership is split among utilities in both ERCOT and SPP. AEP Texas owns a 54.69% interest in the plant. The other owners are the Brownsville Public Utilities Board (17.97%) in South Texas, PSO (15.62%) and the Oklahoma Municipal Power Authority (11.72%).
The retirement leaves ERCOT with 22 operational coal units, accounting for the mothballing of CPS Energy’s two J.T. Deeley units, which have 871 MW of capacity. ERCOT has lost almost 6 GW of coal-fired generation since 2017. (See CPS Energy Shutters Deely Coal-fired Unit.)
SANTA FE, N.M. — SPP and its stakeholders have begun to grapple with the complex issue of how to use battery storage, but they must first determine who will guide the process moving forward.
Meeting Jan. 15, the Strategic Planning Committee heard from some members who wanted to create a task force and others who pushed for a steering committee.
Larry Altenbaumer, chair of both the Board of Directors and SPC, posited that SPP should take a strategic approach to the issue. He suggested the SPC again take up the subject at its April meeting in Little Rock, Ark.
“It sounds like a really good idea that we need to work out,” Altenbaumer said.
SPP Senior Vice President of Engineering Lanny Nickell agreed that the decision should be a strategic one. “What degree does SPP want to invest in the growth of batteries?” he asked. “Once we know that vision about storage, that will help guide what we know about batteries.”
“Someone has to take on a big-picture view of this thing, to get the discussion going and organize it,” Midwest Energy’s Bill Dowling said. “We have to do some of this up front in an organized fashion. We have to organize this herd of cats.”
FERC in October found that SPP’s first response “generally enable[s] electric storage resources to provide all services they are capable of providing.” However, it also required the RTO to adopt Tariff rules covering minimum run-time requirements for resource adequacy. (See FERC Partially OKs PJM, SPP Order 841 Filings.)
“Energy storage has the potential to change the way this industry operates,” said Richard Dillon, SPP’s market policy technical director. “Until now, energy had to be generated immediately. Energy storage changes that paradigm.
“But Order 841 removes barriers to ESR participation. That can be too much of a good thing. It responds so fast that the rest of the system can’t keep up with it,” he said.
Dillon presented a white paper on energy storage to the Markets and Operations Policy Committee at its Jan. 15 meeting. He returned that afternoon to discuss the paper with the SPC.
The paper lists energy storage’s benefits as its flexibility and ability to inject or receive energy; its instantaneous response to grid events; its ability to balance supply and demand; and its potential as an economic market resource and an economic alternative to traditional transmission.
It says SPP should capitalize on ESRs’ flexibility, maximize their reliability and economic benefits, develop cost-recovery for ESRs, and resolve issues on whether they’re used as generation and/or transmission assets.
“We have a great asset coming into our region and we don’t want to limit it,” Dillon said.
Dillon said ESRs’ decreasing costs — an 87% drop in real terms from 2010 to $156/kWh last year, according to Bloomberg New Energy Finance — and recent tax law changes have significantly increased requests to interconnect the resources to the grid. SPP’s generator interconnection queue contained less than 1 GW of ESRs in 2016. By mid-2019, ESR requests had expanded to nearly 7 GW.
SPP’s accelerating energy storage growth | SPP
The white paper makes several recommendations that touch six different working groups and SPP’s Market Monitoring Unit.
Betsy Beck, with Enel Green Power NA, agreed with Hall. She said ERCOT felt things were moving too slowly and changed its approach.
“They put everything in. They’re moving really, really quickly to resolve these issues. It’s worked extremely well,” Beck said. “We need storage to come on and provide the maximum flexibility for ramping issues we’re seeing on the operational side.”
PJM industrial customers said Tuesday that voluntarily buying and selling renewable energy credits shouldn’t count as subsidies in the RTO’s capacity market, urging FERC to reconsider its broad definition of the word to exclude those transactions (EL16-49, EL18-178).
FERC, in its Dec. 19 ruling expanding PJM’s minimum offer price rule to all resources, said distinguishing between RECs mandated through state renewable portfolio standards and those bought as part of power purchase agreements is impossible. The new MOPR, meant to address price suppression from state subsidies, has drawn criticism from a broad section of stakeholders who say FERC went too far in attempting to control states’ generation choices. (See related story, PJM MOPR Rehearing Requests Pour into FERC.)
Both the RTO and the PJM Industrial Customer Coalition (ICC) note that if resources can certify that all the RECs it sold were voluntary — rather than within the confines of state-sponsored RPS programs — then those resources should be exempt from the MOPR. At the very least, PJM argued in its rehearing request, FERC should have adopted a “safe harbor” for voluntary REC transactions.
The ICC was joined in its rehearing request by the Illinois Industrial Energy Consumers, the Electricity Consumers Resource Council (ELCON), the Industrial Energy Consumers of America, the Pennsylvania Energy Consumer Alliance, the Industrial Energy Consumers of Pennsylvania and the American Forest and Paper Association.
Hershey’s original, now demolished chocolate factory in Hershey, Pa., in 1976. The company was one of many industrial market participants protesting FERC’s MOPR ruling.
In their filing, the groups said they share FERC’s goal “of ensuring just and reasonable prices in both the short-term and the long-term through proper and sustainable operation of the PJM capacity market” and appreciate that the “order conveys a clear signal that states’ efforts to subsidize capacity resources will not be permitted to interfere with the efficient functioning of the PJM capacity market.”
But the ruling, they said, does not “enable its practical implementation without unlawfully upsetting existing commercial arrangements and market dynamics.”
“In a voluntary REC transaction, the RECs are not needed or used by the retail customer or its load-serving entity for state RPS compliance,” the groups said. “Because there is no nexus between the customer’s load and any state RPS, the generating resource does not obtain any state subsidy from its sale of the RECs.”
Hershey, the famed chocolate company, also filed a motion to intervene in the proceedings Tuesday upon learning that its pending PPAs that include voluntary REC transactions would be subject to the MOPR. The agreements were designed to help Hershey meet its greenhouse gas emission-reductions goals in line with the Science-Based Targets Initiative. The company said in its filing that FERC’s decision has “effectively stalled Hershey’s project and impeded its ability to meet Hershey’s environmental goals and the expectations set by the company’s consumers and investors.”
ELCON, in a separate filing it made against the MOPR, reiterated that such contracts should not be subjected to the new price floors.
“In particular, private capital that pursues voluntary capacity contracts in bilateral markets should not face administrative corrections,” the group said. “For example, corporate consumers are increasingly deploying their own capital to voluntarily purchase power through the bilateral market or procure renewable energy credits, which do not constitute subsidies. Voluntary payments received outside of the capacity market should receive categorical exclusion.”
CARMEL, Ind. — MISO navigated December with just one severe weather alert in its South region.
The RTO’s load averaged 74.3 GW throughout the month, down slightly from the 75.5-GW average a year earlier. However, the 95.5-GW peak on Dec. 19 bested December 2018’s 94.2-GW peak.
“Temperatures in December were slightly higher than last year and above the 30-year average,” Executive Director of Energy Operations Rob Benbow explained during an Informational Forum on Tuesday.
Benbow said prices were down significantly because of “surging” U.S. natural gas production. Day-ahead prices averaged $21.92/MWh and real-time $21.05/MWh — both down more than 30% year over year.
| MISO
The RTO’s lone operational alert for the month occurred Dec. 16-17 in MISO South, when multiple tornadoes formed in Louisiana, Mississippi and southern Arkansas. The severe weather alert never escalated to conservative operations instructions.
CEO John Bear said the reasonably mild winter conditions are not indicative of what’s to come in the footprint, cautioning that MISO was in the “calm before the storm” in terms of resource evolution.
2019 “was a very successful year,” Bear said. “We have a whole lot of heavy lifting in front of us in the next 24 to 36 months. … We’ve got a lot of big, meaty things on our plate this year.” Bear cited MISO’s ongoing market platform replacement as well as the resource availability and need project, which may entail changes to the Planning Resource Auction and capacity accreditation.
“It’s going to give us a tremendous amount of flexibility and transparency … as resources change,” Bear said of the new cloud-based market platform.
Four former FERC chairs celebrated two decades of RTOs Tuesday with a call for federal action to increase interregional transmission and price carbon emissions into energy markets.
Former Chair Jon Wellinghoff (2009-13) said Congress, which gave FERC authority to enforce mandatory reliability standards in 2005, should now give the commission the power to create a national transmission policy to move renewable power to load centers.
“I think it’s now time for the Congress to give FERC direction about our climate crisis and how the transmission system is going to address that,” Wellinghoff said during a webinar by Americans for a Clean Energy Grid. The hour-long session celebrated the 20th anniversary of FERC Order 2000, the December 1999 order that pressed transmission operators to join regional transmission organizations.
Wellinghoff — who was joined by former Chairs James Hoecker, Pat Wood III and Cheryl LaFleur — said FERC needs congressional direction on transmission siting and cost allocation. “Without those specific things being addressed in some congressional authorizations, I think FERC will continue to be moving around the edges of things. We really need to move beyond that to address the climate crisis that we’ve got before us.”
Hoecker (1997-2001), former counsel to the trade group WIRES, said Order 2000 was needed to address anticompetitive practices that continued despite the open access requirements of 1996’s Order 888.
He lamented that Order 2000 was not mandatory. While the six FERC regulated RTOs and ISOs are “a lot more complicated and sophisticated than we anticipated,” he said, all the Southeast and much of the West remains without access to organized wholesale markets today.
Hoecker “was Moses; he got to see the promised land. I was Joshua [who] actually got to walk through the muck to get into it,” joked Wood (2001-2005), referring to the compliance filings that FERC received in 2001.
Wood said he would have preferred the original plan to have four RTOs, one each in the Northeast, north Midwest, Southeast and West. “That would have been the best [design] possibly. But after multilateral settlement talks, it became clear that it just wasn’t going to work out for a number of reasons, both political and interpersonal and operational.”
As a result, the commission approved filings by PJM and ISO-NE to become RTOs and later helped craft MISO and SPP “from the ground up,” he said.
Wood said Order 2000 reduced opportunities for gaming, reduced generators’ profit margins and facilitated state retail access programs. He acknowledged the changes were not popular with generators, particularly those operating inefficient coal- and gas-fired generators that were displaced by more efficient units and renewables. “That’s how a market is supposed to work,” he said, noting the importance of transmission and price signals. “We saw this on about the fourth hour that MISO was open. We saw redispatch happening in real-time. It was fascinating to look at the heat map.”
Wood said the big question for RTOs now is how to deal with the increasing penetration of zero variable cost renewables, saying he’s been “intrigued” by proposals for having a separate clean energy attribute market.
“From the beginning, the goal was simply an economic goal. But now we need to also consider these non-economic factors such as carbon intensity that are important to now — probably — the majority of the states.”
LaFleur, who served as chair or acting chair during parts of 2013-17, said RTOs’ regional planning and operations allowed a faster and more efficient transition away from coal and toward natural gas and renewables. It also helped regions deal with their own challenges, said LaFleur, who joined ISO-NE’s board of directors after leaving FERC last year.
“ISO-NE built several billions of transmission in the first decade of this century that essentially eliminated generation congestion that had been a problem there for decades. PJM was able to seamlessly adapt to MATS [the Mercury and Air Toxics Standards] that drove a tremendous amount of coal-to-gas switching in PJM … . Because you had a market, you never felt the blow.”
LaFleur and her colleagues agreed that some rulemakings since Order 2000, including Order 1000, which sought to open transmission development to competition, have not met their goals. Wood said he’d like to see Congress give FERC “backstop” transmission siting authority, which the commission could use as a “hammer to get people to the [negotiating] table” on interregional transmission needed to deliver renewable power.
But he said policymakers must find a way to pay for the new infrastructure that doesn’t encourage customers to leave the grid altogether in favor of distributed generation.
Moderator Rob Gramlich asked the panelists to predict whether RTOs will take root in the West and Southeast. The Western Energy Imbalance Market (EIM) has steadily increased since 2014. In the Southeast, lawmakers in North and South Carolina are considering legislation to study creation of an RTO for their states following the billions lost on the cancelled expansion of the V.C. Summer nuclear plant.
“It’s hard to think that, after all the economic carnage that happened in the Southeast, people don’t figure out that organized markets [are] a damn good way to get transparency on future investment,” said Wood. “We can’t repeat those mistakes again where you’ve got utility-driven investment that gets no market check at all. At a minimum, the energy imbalance market concept — or what we always called the day-one market — clearly makes sense across the country, even in the vertically regulated areas of the country like the Southeast.”
RTO/ISO transmission projects enabled half of the U.S.’s 100 GW of wind capacity, according to Americans for a Clean Energy Grid. | Americans for a Clean Energy Grid
But he acknowledged the “politics of this probably haven’t changed at the congressional level, so we’ve got to win their hearts.”
LaFleur noted that the growth of the EIM has been driven by individual states and utilities, not a federal mandate. “I’d love to see that happen in the Southeast as well,” she said, cautioning against a fight over a federal mandate.
But Wellinghoff said a federal mandate is needed to prevent transmission owners from using threats to quit an RTO to exercise control over RTO management. “I think it’s a fight worth picking,” he said.
