Page 1111 – RTO Insider

October 7, 2018

Can Calif. Go All Green Without a Western RTO?

By Hudson Sangree

California may be able to meet its goal of relying entirely on renewable and other zero-carbon electricity sources by 2045, but it’s going to be more difficult and more expensive without a wholesale market that includes multiple Western states, advocates of CAISO regionalization contend.

“This is essentially like leaving one of your best tools on the workbench when you’re trying to build a very complicated project,” said Carl Zichella, western transmission director for the Natural Resources Defense Council, a staunch proponent of a Western RTO. “You may end up with something jury rigged.”

Gov. Jerry Brown, CAISO leaders and other promoters of regionalization held the same opinion when they tried to pass AB 813 this year. The bill, which failed, would have started the process of turning the ISO into a multistate entity by creating a governing board independent of the governor and legislature.

Supporters reasoned it would greatly help California achieve a carbon-free grid if in-state generators could more easily sell excess solar power to neighboring states and buy clean energy from states that produce more wind and hydroelectric power.

Mojave Desert solar arrays are a large part of the state’s renewable energy production. | *U.S. Dept. of the Interior*

Solar power in the Mojave Desert, for instance, peaks in the late afternoon when it’s often least-needed in California but could be useful in states one time zone to the east — where residents of Arizona, Colorado and Montana are arriving home from work, turning on their TVs and adjusting their thermostats.

Wind from southeastern Wyoming and eastern New Mexico, meanwhile, could provide power after sunset in California, which currently relies on natural gas plants to meet each evening’s peak demand.

Wind power in Wyoming could help California meet peak demand, replacing natural gas. | *Bureau of Land Management*

That was a major reason behind AB 813. The bill stalled in the Senate Rules Committee on the last night of the legislative session Aug. 31. It was the third time in three years that efforts to turn CAISO into an RTO had fizzled. (See CAISO Expansion Bill Dies In Committee.)

In contrast, lawmakers passed, and Brown signed, the session’s other major piece of energy legislation, SB 100. The new law establishes an ambitious timeline for California to rely increasingly on renewable and zero-carbon energy sources, with the goal of achieving 100% carbon-free electricity by 2045. Along the way, it requires the state to accelerate its renewable portfolio standard program to approximately 50% by 2026 and 60% by 2030. (See Calif. Gov. Signs Clean Energy Act Before Climate Summit.)

That’s a daunting challenge. In 2017, California got about a third of its electricity from natural gas-fired plants and more than 40% from hydroelectric, solar, wind and other renewable sources, according to the California Energy Commission. Ending the reliance on natural gas to meet peak demand will be difficult, especially because wind and solar often aren’t available during the morning and evening peak periods. (The state’s last nuclear generator, Pacific Gas and Electric’s Diablo Canyon Power Plant, is scheduled to be retired in 2025.)

Mixed Reaction

For many supporters, the clean-energy and CAISO regionalization bills went hand in hand, with the goals of SB 100 achievable largely through a Western RTO.

“Right now, management of the Western grid that powers our homes and businesses is severely fragmented, with 38 separate [balancing] authorities managing electricity generation and flows over 14 states, two Canadian provinces and northern Mexico,” Zichella wrote in an NRDC opinion piece. “This makes it harder and more expensive to add renewable energy generation here and elsewhere in the region, because each time the electrons flow through one of the authorities, a new charge is added.”

Without regionalization, California will have to access other states’ electricity through bilateral contracts and pancaked transmission access charges, Zichella said in an interview with RTO Insider. “It’d drive the cost up dramatically not having them in the wholesale market where the lowest cost [power] is dispatched first,” he said.

Other interest groups supported SB 100 but not AB 813. They feared partnering with the coal-burning states of the Interior West could undermine California’s clean energy push. (Today, California has only one small coal-fired power plant and imports just a tiny percentage of its energy from out-of-state coal-burning generators, according to the U.S. Energy Information Administration.)

The Sierra Club, for example, hailed the passage of SB 100.

“It’s impossible to overstate how significant it is for a state as large and influential as California to commit to 100% clean energy,” the group’s executive director, Michael Brune, said in a Sept. 10 statement.

But the Sierra Club opposed creating a Western RTO, saying CAISO regionalization could result in “resource shuffling.”

“That is, it might actually encourage certain coal-heavy power companies to extend the life of their plants in one part of the West and shift the renewable energy to California,” the group said in a message opposing AB 813. “All that extended and increased use of fossil fuel plants to accommodate the ability of California’s ‘excess’ renewable energy to flow east and the Interior West’s supply to flow to California can add up to more localized air pollution, especially for communities already struggling with dirty air, and more greenhouse gas pollution.”

California can and should go it alone, those who opposed AB 813 but supported SB 100 argued.

“Rather than removing California authority over CAISO and eliminating a board appointed by the governor and subject to Senate confirmation, the legislature should direct CAISO to explore other measures that serve the goal of optimizing system operations, reducing GHG emissions, and addressing concerns about overgeneration and curtailment,” read a joint statement to the State Legislature by Sierra Club California, The Utility Reform Network, the State Building and Construction Trades Council of California and other labor unions.

California curtails large amounts of solar energy during many months. | *CAISO*

Among the coalition’s proposals was expanding the Energy Imbalance Market to include additional Western utilities and allow day-ahead scheduling. It said an expanded EIM would significantly reduce curtailments of renewable resources in California while allowing states to retain control over grid reliability, resource planning and transmission investment.

Steven Greenlee, a senior spokesman for CAISO, said the EIM helps avoid curtailment by selling renewable power on the real-time market and could do even more if day-ahead bidding is allowed. CAISO has a day-ahead market-enhancement initiative in the works, he noted.

“That’s going to help, but it’s still not quite as good as having a full-blown regional transmission market,” he said.

“It does appear possible to meet the 100% goal,” he added, “but the cost and challenge of doing so without a robust regional coordination effort will be significantly increased.”

Natural gas and renewables each make up a large part of California’s energy mix. | *California Energy Commission*

Some relatively simple methods could help reduce the state’s reliance on natural gas in accord with SB 100, he said. Such methods might include time-of-use rates to encourage consumers to use solar power when it’s most plentiful and demand response programs to alert consumers to change their energy use in response to peaks and troughs in electrical demand.

No Silver Bullets

Storage also could be a major piece of a solution, especially with improvements in cost and efficiency, Greenlee noted.

“Energy storage is going to be a game changer … if all of a sudden we see it go dirt cheap, and it’s just everywhere,” he said.

In February, FERC issued Order 841, requiring RTOs and ISOs to revise their tariffs to allow energy storage resources full market access and to ensure storage resources are eligible to provide all energy, capacity or ancillary services of which they are capable, while also enabling them to set clearing prices as buyers and sellers. Grid operators will also need to establish a minimum threshold for participation that doesn’t exceed 100 kW. (See FERC Rules to Boost Storage Role in Markets.)

Then in September, Brown signed SB 700, which will provide an additional $800 million in incentives over the next five years for consumers to purchase behind-the-meter storage systems.

Batteries, which have been limited in their ability to store and disperse energy, are improving thanks to companies such as electric carmaker Tesla, which also manufacturers utility-scale battery systems.

Probably more significant going forward, however, are systems capable of storing hundreds of megawatts such as pumped hydropower.

Zichella noted, for example, that the Eagle Mountain Pumped Storage Project — a controversial proposal in the California desert near Palm Springs — could store output from 1,300 MW of inexpensive solar power by using it to pump water uphill during the day and then releasing the water at night to spin turbines that would help meet peak demand. He also cited a proposed utility-scale system in Utah that would use renewable energy to compress air into underground chambers and release it later in the day to generate electricity.

Then there are storage projects that look and sound like science fiction. The 110-MW Crescent Dunes Solar Energy Project in Tonopah, Nev., uses thousands of revolving mirrors, called heliostats, to concentrate solar energy on a 550-foot tower and heat molten salt to 1,000 degrees Fahrenheit. The salt is stored in a thermal container, where it retains its heat for hours. That heat can be used at night to boil water and turn power-producing steam turbines, which light up Las Vegas.

The Crescent Dunes solar storage project near Tonopah, Nev., concentrates sunlight to heat molten salt to 1000 degrees. | *Solar Reserve*

With such large-scale storage, “you could have a much smoother variability curve” from wind, which is unpredictable and intermittent, and solar, which traditionally stops working after the sun goes down, Zichella said.

“None of these things by themselves are silver bullets,” he said. But added together they could help California pursue its goal of all-green energy. Then again, he said, another run at regionalization will likely happen in the next legislative session. (See Western RTO Proponents Vow to Keep Trying.)

October 5, 2018

EIPC Finds Eastern Tx Planning Working Well

By Michael Brooks

Transmission planning in the Eastern Interconnection is well-coordinated among its planning authorities, ensuring NERC reliability requirements are met, according to a report released Wednesday by the Eastern Interconnection Planning Collaborative (EIPC).

The “State of the Eastern Interconnection” doesn’t get into the nitty gritty. At only 21 pages, it summarizes EIPC’s efforts since its formation in 2009 to examine the interconnection from the bottom up and ensure that planning coordinators’ individual regional transmission plans do not conflict with each other.

“The EIPC has completed a comprehensive description of Eastern Interconnection Planning Collaborative activities over the last decade, including results from its studies and analyses on the regional transmission plans of the major systems that make up the Eastern Interconnection,” said Stephen Rourke, vice president of system planning for ISO-NE and chairman of the EIPC Executive Committee. “The report details how the Eastern Interconnection grid is being planned in a coordinated manner, facilitated in part by the work of the EIPC.”

The Eastern Interconnection also includes the Canadian Maritime provinces: New Brunswick, Nova Scotia and Prince Edward Island. | *ERCOT*

EIPC is made up of 20 planning coordinators — including the five Eastern RTOs — in FERC-designated planning regions: the RTOs’ territories, the Florida Reliability Coordinating Council, South Carolina Regional Transmission Planning and Southeast Regional Transmission Planning. FERC Order 1000 only requires pairs of neighboring regions to coordinate their planning. SPP and MISO work together, for example, as do MISO and PJM — but PJM and SPP do not.

“EIPC efforts provide an additional forum to complement interregional coordination of the combined plans of the regional planning coordinators from an interconnection-wide basis,” according to the report. “While reliability requirements are achieved in the first instance at the regional level through regional processes, the work undertaken at EIPC confirms that the regional plans mesh properly into a combined plan for the interconnection.”

The heart of the collaborative’s work are its two “roll-up” studies, which involved combining the individual regional plans and their underlying data, such as resource mix and projected demand, into an integrated, interconnection-wide model.

The first study was conducted in 2014 for the summer peak hours in 2018 and 2023. The second, released in 2016, covered the 2025 winter and summer peaks.

As part of the latter study, EIPC identified several interconnection-wide power-flow interactions resulting from the regional plans that could cause constraints, leading planning coordinators to develop “conceptual upgrades” for inclusion in future planning cycles.

Another analysis in the study to locate potential constraints simulated 5,000-MW transfers between regions.

“The roll-up analyses demonstrate that the respective planning coordinator transmission planning and interconnection processes, which explicitly include requirements for coordination, have yielded transmission plans that are well coordinated on a regional and interconnection-wide basis,” the report says.

October 5, 2018

Overheard at 2018 NEEP Summit

MIDDLETOWN, R.I. — The increasing interplay between energy efficiency and electrification was a hot topic at the 2018 Northeast Energy Efficiency Partnerships summit Oct. 1 to 3. But industry leaders and experts also discussed how to measure the benefits of energy efficiency — and how to motivate consumers to do more to save energy.

“The truths of how we did efficiency 10 years ago are not necessarily how we’re going to be doing it the next five years,” said Carol Grant, commissioner of the Rhode Island Office of Energy Resources. “How can we bring more people into the drive, make more people aware?”

To get people to value efficiency, policymakers need to make it more visible, said Mary Sotos, deputy commissioner for energy at the Connecticut Department of Energy and Environmental Protection.

The department realized it needed to set priorities for its limited resources following a state budget crisis this year, which saw a third of energy efficiency funding swept into the general fund, Sotos said.

“One clear priority that came out of that process is that climate needs to be at the front of all of our efficiency work,” Sotos said. “One of the biggest sectors of emissions in Connecticut is actually our home heating. So about half of Connecticut is heated with delivered fuels — fossil fuel, heavy emissions.”

DEEP has long discussed applying a carbon or fuels charge, but officials now are uneasy about “creating another pot of money” that could be commandeered to fix a budget shortfall, she said.

The 2018 Northeast Energy Efficiency Partnerships summit was Oct. 1 to 3 | © *RTO Insider*

“We need to look at the resources we have, including our conservational management plan, and be willing to use those resources to make this transition away from fossil fuels,” Sotos said. “That’s something new for us.”

Energy marketing consultant Suzanne Shelton recommended brand marketing and psychological tactics to shift public perception — and find electricity’s equivalent to the “natural” in natural gas.

“We don’t know what we’re doing, we don’t think we need it, and we don’t think it works. That’s our huge problem with energy efficiency,” Shelton said. “Americans want to be greener. Forget education, that’s boring. Think of it in terms of engaging consumers, inspiring them, motivating consumers.”

Who Pays?

Utility and auto industry shareholders should be responsible for the costs of accelerating electrification, Rhode Island Public Utilities Commissioner Abigail Anthony said.

Additional electricity sales increase cash flow, and new load may result in infrastructure upgrades that provide earnings opportunities for the utility, or the utility could receive new incentive-based earnings to absorb increased electric load without new wires, Anthony said.

“From a regulator’s perspective, I am cautious that electric utilities aren’t promoting electrification at scale because they are holding out to see how much preferential regulatory treatment they can get first,” Anthony said. “Why take on any risk if regulators are willing to put all the risk on ratepayers? In any case, we’ll lose the public trust if we don’t have good evidence for asking ratepayers to make the first move in a new business.”

Grant gave a “shout out” to National Grid as the primary utility in Rhode Island: “I’m excited about the leadership they’re providing in continuing to push themselves … their talent and their innovation is really growing, and their focus on new approaches is exciting as well.”

In Connecticut, DEEP this year for the first time asked the utilities to say how they could help homes convert from their current fuels to air-source or ground-source heat pumps, which are good for both heating and cooling, Sotos said.

One challenge in the nation’s capital is that “our energy is too affordable,” said Tommy Wells, director of the D.C. Department of Energy & Environment.

The whole regulatory structure is geared toward keeping electric power rates low, he said, “so when advocates say we want energy to cost more so you use less, it goes directly against the whole construction of our regulatory scheme.”

“In D.C. we have the most valuable, highest renewable energy credits in the country for solar … but the uptake of solar on people’s homes … is slow because their power bills are so low,” Wells said.

Electrification Metrics

Sotos noted that by 2030 Connecticut will need to reduce greenhouse gas emissions across all sectors 40% below 2001 levels, and each year it must save 1.6 MMBtu of energy.

“It’s important to us to make sure that the metrics that we’re applying to our programs actually match what we are trying to accomplish, she said. “Depending on how much you value carbon, or other environmental impacts, the cost-effectiveness of certain programs can potentially look very different.”

Paul Hibbard of the Analysis Group said there are two basic components to measuring the value of energy efficiency and electrification: forecasting and assigning a value to carbon.

“Forecasting avoided costs is incredibly complicated … [it] is really comparing the world with efficiency investments to a world without those investments, and calculating the difference,” Hibbard said.

Assigning a value to carbon is more of a political decision, but it will grow increasingly important for directing investments and determining the right way to use public funding to focus investments, Hibbard said.

Solid metrics benefit the decarbonization effort by providing consistent approaches to evaluating cost-effectiveness in outcomes, said Bruce Biewald of Synapse Energy Economics. He also got “abstract and philosophical” about public policy.

“I have raised six kids … and you have some influence, a little bit of control, but you don’t really control them,” Biewald said. “And that’s also in this nexus of companies and government regulations, and laws and individual consumer choice. So when you see something failing, like the pricing or not pricing of carbon, there’s room for everybody in the solution. The idea that there’s one actor or one policy approach that’s going to solve this is not reasonable.”

Is electrification the new energy efficiency, or is it a new species altogether? asked Rich Sedano of the Regulatory Assistance Project.

Pasi Miettinen, CEO of energy analytics firm Sagewell, said his company gave up energy efficiency to focus on electrification for non-regulated utilities because the latter gives better results for a dollar spent. Nonetheless, “we look at it as one category, maximum yield for dollars,” he said.

Energy Security

Reducing carbon emissions is neither easy nor simple, said clean energy advocate Steve Cowell of E4TheFuture, an organization that promotes residential clean energy.

“Government funding versus regulatory versus market-driven investment, legislative mandates versus rate design, all these are pieces that we have to fit together,” Cowell said.

New England has enormous potential to bring offshore wind and other non-carbon imports into the region, and is also facing the recent or prospective retirements of some really important assets on the grid, said Deborah Donovan of the Acadia Center, a regional, nonprofit advocacy and research organization.

Regarding the wholesale energy market, the region is “in the precarious position of ISO-NE procuring gas capacity through the capacity markets and then saying ‘oh my gosh, we’re over-dependent on gas,’ and really putting their thumb on the scale when we’re confronted with issues like a request for retirement from the Mystic station up north of Boston,” Donovan said.

The region needs natural gas to generate power and to heat its buildings, but the fuel security issue is really just about winter peak hours, she said.

The grid operator sees a natural gas problem and says it must have a natural gas solution, but “we and a lot of other advocates are pushing to stop that. … [It’s] costly to the environment solution,” Donovan said.

Mark Kresowik of Sierra Club’s Beyond Coal Campaign said the Northeast states lead the country in energy efficiency, but he decried the “insanity of [CEO] Gordon van Welie in ISO New England proposing to spend hundreds of millions of dollars to bail out the Mystic plant and push billions of dollars in investment into gas pipelines for fuels that are mandated to decline by state policies.”

NEEP Executive Director Sue Coakley turned the discussion back to scaling up energy efficiency in buildings.

Cowell said New York has decided to eliminate any ongoing residential or energy efficiency work in buildings and homes.

“We had a very difficult stakeholder session a couple weeks ago where the Public Service Commission basically said it’s not worth it, we shouldn’t be helping people insulate and air-seal their homes,” Cowell said. “That makes it tough.”

Coakley suggested basing the argument for efficiency on the costs of storm damage: “You could insulate and air-seal your house for $5,000 to $20,000 and do a really good job, and instead we’re paying to repair houses from damage from bad weather.”

Leah Bamberger, director of sustainability for the city of Providence, said that following natural gas pipeline explosions near Boston in September, residents in homes knocked off the gas system were reluctant to accept space heaters for fears that their outdated wiring couldn’t handle the extra load.

Sotos said that DEEP is expanding its thinking on what constitutes barriers to adoption of energy efficiency measures, and it now realizes that structural issues in a house, such as a difficult to reach boiler, should qualify for state-funded remediation.

— Michael Kuser

October 4, 2018April 30, 2024

Trump Nominates DOE’s McNamee to FERC

By Rich Heidorn Jr.

McNamee | © RTO Insider

President Trump on Wednesday nominated the Department of Energy’s Bernard McNamee to replace former FERC Commissioner Robert Powelson — a pick that could be crucial to the administration’s efforts to support at-risk coal and nuclear generation.

Powelson, who left the commission in August to head a trade organization, was a vocal opponent of the Trump administration’s bid to provide price supports to coal and nuclear generators. McNamee, a former aide to Sen. Ted Cruz (R-Texas), was among the DOE officials who designed and lobbied on behalf of the plan.

Lobbying for Price Supports

Last November, McNamee joined FERC Chief of Staff Anthony Pugliese to make the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance (CEA) on the sidelines of the National Association of Regulatory Utility Commissioners’ Annual Meeting in Baltimore. Watchdog group the Energy and Policy Institute has described CEA as “a fossil fuel-funded advocacy group.” (See DOE, Pugliese Press ‘Baseload’ Rescue at NARUC.)

FERC Chief of Staff Anthony Pugliese, left, and Bernard McNamee, center, head of DOE’s Office of Policy, made the case for coal and nuclear price supports at a breakfast meeting of the Consumer Energy Alliance on the sidelines of the NARUC Annual Meeting in Baltimore in November 2017. Michael Whatley, right, CEA’s executive vice president, moderated. | © RTO Insider

In January, FERC voted 5-0 to reject Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to save at-risk coal and nuclear plants and instead opened a docket to consider resilience concerns. In June, however, Trump ordered Perry to save coal and nuclear plants under an obscure Korean War-era law. That effort is still pending, although the Washington Examiner reported Friday that it may have stalled in the face of opposition by conservative, free-market groups.

A graduate of the University of Virginia and Emory University School of Law, McNamee has had a variety of political and legal jobs in Texas, Virginia and D.C. In addition to stints at the law firms of Hunton & Williams (now Hunton Andrews Kurth), Williams Mullen and McGuireWoods, he spent time in the attorney general’s offices in Texas and Virginia and was policy director for former Gov. George Allen’s (R-Va.) 2000 U.S. Senate campaign.

After serving as Cruz’s senior domestic policy adviser and counsel from July 2013 to November 2014, he spent a year as chief of staff to the Texas attorney general, where his LinkedIn profile said his work included “challenging the federal government on environmental regulations, defending religious liberty and promoting federalism.”

He first joined DOE as deputy general counsel for energy policy in May 2017 but left after 10 months to become the director of the Texas Public Policy Foundation’s Center for Tenth Amendment Action and Life: Powered, a project to “reframe the national discussion” about fossil fuels.

‘Blessed’ by Coal, Natural Gas

In an op-ed published in The Hill on Earth Day in April, McNamee defended fossil fuels against criticism over their environmental damage. “America is blessed with an abundant supply of affordable natural gas, oil and coal. When we celebrate Earth Day, we should consider the facts, not the political narrative, and reflect about how the responsible use of America’s abundant resources of natural gas, oil and coal have dramatically improved the human condition — and continue to do so,” he wrote.

He returned to DOE in June as executive director of the Office of Policy.

In July, McNamee defended the administration’s plans for price supports in a hearing of the Senate Energy and Natural Resources Committee. “A lot of the organized markets have distortions in them that aren’t representative of an actual free-serving market, so the thought is you need to remove some of those distortions and get some more parity,” McNamee said.

Reaction

Michelle Bloodworth, CEO of pro-coal group ACCCE, called Wednesday for McNamee’s “swift confirmation.”

“FERC has a critical role in assuring that wholesale markets value resilience attributes, especially fuel security. McNamee’s background and experience at the state and federal levels make him well qualified to be the next FERC commissioner,” she said. ACCCE says about 120 GW of coal-fired generating capacity, about 40% of the remaining fleet, has retired or announced plans to do so.

“If McNamee is confirmed to FERC, he will abuse that authority to lead the charge to force taxpayers to spend tens of billions of dollars to bail out old, expensive coal and nuclear plants, at the expense of cleaner, cheaper competitors like solar, wind and grid storage,” Mary Anne Hitt, senior director of Sierra Club’s Beyond Coal campaign said in a statement when McNamee’s name was floated as a potential nominee in August. “Trump is hoping to install a crony at FERC who will unfairly tip the scales in favor of propping up those failing industries.”

“Powelson’s departure was widely seen as opportunity for the White House to more closely align FERC with its own policies,” said Stoel Rives partner and FERC practitioner Jason Johns. “It is my belief that Powelson’s opposition to certain policy efforts came as a surprise to the White House, particularly the White House’s efforts to subsidize coal and nuclear facilities. I’m confident the White House is looking to address those surprises with this choice. ”

“FERC has a longstanding commitment to fuel-neutral regulation, but Mr. McNamee’s past writings and career track record suggest that he would seek every opportunity possible to support fossil fuels,” said John Moore of the Sustainable FERC Project.

Strategy

ClearView Energy Partners suggested McNamee, a Republican, might be paired with a Democratic nominee to replace Commissioner Cheryl LaFleur if the GOP retains a majority in the Senate. LaFleur, whose term expires June 30, 2019, is unlikely to be renominated, ClearView said.

However, Senate Majority Leader Mitch McConnell (R-Ky.) could push McNamee’s confirmation more quickly to restore the 3-2 Republican FERC majority, the consultants said.

Although LaFleur and fellow Democrat Richard Glick have repeatedly been on the losing end of 3-2 natural gas pipeline orders, the departure of Powelson has raised the prospect that pipeline approvals could stall in the face of 2-2 deadlocks.

Last month, E&E News reported that the Trump administration also was vetting Florida Public Service Commission Chairman Art Graham, a self-described conservative and nuclear power supporter, for a FERC seat.

October 4, 2018

CAISO Modifies CRR Plan, Seeks Quick Approval

By Robert Mullin

CAISO is asking FERC for expedited review of a revised proposal to protect electricity ratepayers from funding shortfalls in the ISO’s congestion revenue rights market.

The ISO filed the revision Monday after FERC last month rejected an earlier plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges (ER18-2034). (See FERC Rejects CAISO Congestion Revenue Scaling Plan.)

CAISO’s most recent filing notes that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019. The ISO’s Department of Market Monitoring has estimated that CRR revenue shortfalls — which are allocated based on power consumption — cost California ratepayers about $100 million a year.

Under the scaling plan FERC rejected on Sept. 20, CAISO proposed to compare the CRR auction revenue and revenue from counterflow CRR holders for each constraint to the payments due to prevailing CRR holders for the constraint. When it does not collect enough revenue to pay prevailing flow CRRs the full value for an interval, the ISO would have reduced the payments proportionally.

The plan called for scaling only the payments to holders of CRRs in the prevailing flow direction, while not scaling the payments due from counterflow CRR holders on the same constraint. The ISO contended that discounting counterflow CRRs would increase revenue insufficiency because those CRRs help fund prevailing flow CRRs.

congestion revenue rights crr caiso — CAISO said the trend of CRR revenue insufficiency has persisted into this year despite a recent uptick in congestion rents due to unusually high flow patterns. | *CAISO*

In denying CAISO’s proposal, the commission noted that it “has long held that counterflow and prevailing flow CRRs should be netted against one another such that the expected net value of two obligation CRRs of equal megawatts from A to B and B to A will be equal to zero.” The commission added that “we continue to believe that a symmetric approach is just and reasonable, while an asymmetric approach has not been shown to be just and reasonable.”

FERC also pointed out that the proposal would have the “undesirable” effect of reducing transparency in the CRR market.

“Market participants could face difficulties valuing a counterflow hedge relative to a prevailing flow hedge, since one would be discounted while the other would not,” the commission said.

In its Oct. 1 filing, CAISO acknowledged that its revised proposal relies on “essentially the same methodology” found in its prior proposal, with one “important” modification: a provision to net CRRs with both prevailing flow and counterflow CRRs within a holder’s portfolio before scaling the payment to that holder.

“In this Tariff amendment, the CAISO proposes a methodology that ensures that a CRR holder with a prevailing flow CRR from A to B can offset its obligation by holding a counterflow CRR from B to A,” the ISO said. “The CAISO proposes to first net a CRR holder’s portfolio of obligation CRRs of prevailing flow and counterflow CRRs with modeled flows on a particular constraint. After it nets these flows, the CAISO then would implement the same procedure it previously proposed through which it would scale CRR payments based on day-ahead market congestion revenue collected on individual constraints.”

CAISO said that it was addressing the commission’s concerns by creating “a procedure through which it can ensure a CRR holder’s modeled flow in both the prevailing and counterflow direction on a specific constraint offset each other.” It contended that complete symmetrical treatment of CRRs would prevent it from addressing the CRR funding issue by Jan. 1, 2019, because it would require greater redesign of software enhancements already underway to support the rejected proposal.

“The CAISO is able to follow the commission’s guidance without a major redesign with the proposal it submits here today because it can net the prevailing flow and counterflow a CRR holder’s CRRs place on a constraint upstream in the process and then feed that information into the scaling methodology the CAISO developed as part of its original CRR Track 1B proposal,” the ISO said.

CAISO contends its proposal “completely addresses” the concerns spelled out in the commission’s Sept. 20 order.

“Because the CAISO’s proposal is just and reasonable and it can be implemented by Jan. 1, 2019, it is unjust and unreasonable to force the CAISO and market participants to have to deal with the risks of revenue inadequacy for another year,” the ISO said.

CAISO asked that FERC set a shortened comment period ending no later than Oct. 11 and issue a ruling by Nov. 9.

October 4, 2018

EIPC Finds Eastern Tx Planning Working Well

By Michael Brooks

The first study was conducted in 2014 for the summer peak hours in 2018 and 2023. The second, released in 2016, covered the 2025 winter and summer peaks.

Another analysis in the study to locate potential constraints simulated 5,000-MW transfers between regions.

October 3, 2018

UPDATED: Little Common Ground in PJM Capacity Revamp Filings

By Rory D. Sweeney, Amanda Durish Cook and Rich Heidorn Jr.

The first round of filings in FERC’s “paper hearing” on revisions to the PJM capacity market showed wide disagreement over the best way to address the impact of out-of-market subsidies on clearing prices.

Much of the debate in the dozens of filings focused on broadening the minimum offer price rule (MOPR) and modifying the fixed resource requirement (FRR), which were the basis of the hearing. But many stakeholders also proposed alternatives.

FERC ordered the hearing June 29 after concluding that increasing state subsidies for renewable and nuclear power were suppressing capacity prices. The commission’s 3-2 ruling required PJM to expand the MOPR to cover all new and existing capacity receiving out-of-market payments, including renewable energy credits (RECs) and zero-emission credits (ZECs) for nuclear plants. The MOPR currently covers only new gas-fired units.

The commission’s ruling rejected PJM’s April “jump ball” capacity filing (ER18-1314), granted in part a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding in a new docket (EL18-178). FERC also recommended creating an “FRR Alternative” allowing states to pull subsidized resources — and associated loads — from the capacity auction. (See FERC Orders PJM Capacity Market Revamp.)

PJM’s brief on Oct. 2 outlined its proposal for an “extended resource carve out” that builds on ideas it floated to stakeholders in August. (See PJM Unveils Capacity Proposal.)

The proposal would allow subsidized resources to obtain capacity commitments without clearing the capacity market, while creating a mechanism to restore prices to “the theoretically correct competitive level.”

The RTO said its proposal is intended to ensure both capacity offers and prices remain competitive and recognizes a bifurcated market will result in tradeoffs. “Making room, outside the auction, to accept subsidized generation as a PJM ‘capacity resource’ ineluctably will degrade auction prices. Unless the commission is prepared to accept a mechanism to adjust prices to their ‘correct’ level, this trade-off must be understood as an unavoidable consequence that comes once uneconomic resources are relieved from having to participate in the market.”

The Maryland Public Service Commission proposed what it called a “competitive carve-out approach” in which “a certain amount of load associated with the implementation of state policies is carved out of the existing capacity market and a separate competitive carve-out auction [is held] to meet the capacity needs associated with this amount of load.”

“This capacity would be provided by resources eligible to meet any state’s environmental policies,” the PSC wrote. “In effect, this proposed approach recognizes that, in the aggregate, resources eligible to meet states’ environmental policies and receive revenues for environmental attributes, may be capable of providing capacity to help meet the reliability requirements of all states and the region.”

It noted that the Organization of PJM States Inc. (OPSI) supported development of the idea.

‘Hokey Pokey’

The Electric Power Supply Association said the commission should prioritize protecting the capacity market from price suppression over accommodating state policies. It said the FRR Alternative would “effectively nullify” an expanded MOPR and could lead to the unraveling of the market.

“The FRR Alternative will actively push states towards the path of partial reregulation by letting them choose to be part in and part out of the [capacity] construct and, more importantly, away from reliance on competitive, organized markets,” EPSA said. It said the order would allow a state “to play the capacity market hokey pokey, putting its left foot into the [Reliability Pricing Model] market and pulling its right foot out.

“Even if the FRR Alternative provides greater transparency, that transparency does not make the resulting reregulation any more planned or any less damaging to what remains of the market,” EPSA said. “The only advantage of the transparency afforded by the FRR Alternative is that ‘investors, consumers and policymakers’ will have the opportunity to watch the collapse of the markets on the equivalent of a live-feed.”

Carbon Pricing

Eastern Generation, an EPSA member, filed a brief calling on the commission to treat the expanded MOPR as a “bridge” to PJM developing a mechanism for incorporating carbon pricing into its markets. “Carbon pricing is a more durable and sustainable long-term approach that will improve the efficiency of PJM’s capacity and energy markets while accommodating state and federal clean energy policies.”

A coalition of consumer advocates, environmentalists and industry stakeholders filed a joint brief arguing for prioritization of state interests.

“We frequently disagree on many issues before this commission, and some of us even disagree on certain aspects of this proceeding, such as the circumstances that should trigger a minimum offer price rule,” said the group, which includes consumer advocates from D.C. and Illinois, the Sierra Club, Natural Resources Defense Council, PSEG Energy Resources & Trade, Talen Energy, Exelon and the Nuclear Energy Institute.

“But as to the commission’s proposal regarding a resource-specific fixed resource requirement alternative (FRR-RS), the joint stakeholders strongly agree the commission’s decision should reflect certain basic principles: The commission should protect customers from paying for duplicate capacity and should preserve states’ ability to achieve clean energy policy goals without forcing states to withdraw altogether from the PJM market.” (See Zero-Emissions Backers Propose PJM Capacity Principles.)

In its standalone brief, Exelon called on the commission to “express its willingness to entertain a Section 205 filing from PJM incorporating carbon pricing.”

“Integrating a carbon price into PJM’s markets would reduce or eliminate the need for states to address carbon emissions from the power sector in other ways,” the company said.

PURPA Resources

Allco Renewable Energy said qualifying facilities under the Public Utility Regulatory Policies Act should have the option of choosing the FRR Alternative but should not be subject to the expanded MOPR, which it said would “unlawfully restrict, interfere and diminish the congressionally mandated right of a qualifying facility to sell energy and capacity.”

Columbia University’s Sabin Center for Climate Change Law insisted state environmental policies do not interfere with FERC-regulated markets. “Unless implemented with care, FERC’s proposed Tariff revisions could interfere with the operation of state clean energy policies, effectively preventing states from exercising their authority over generation,” it said. “There is no valid basis for concluding that REC, ZEC and other clean energy policies interfere with wholesale market operation.”

A Matter of State Jurisdiction

The Governors’ Wind and Solar Energy Coalition said FERC’s minimum bid requirement would intrude on states’ historical right to choose their own energy mix: “If the commission pre-empts or restricts the states’ ability to regulate environmental effects from energy power production, it would constitute a dangerous shift in the balance between state and federal authority.”

However, the Natural Gas Supply Association said it was “heartened” by what it called FERC’s “strong defense of the competitive markets it regulates.”

NGSA said PJM’s status quo would create an “untenable” environment where investment uncertainty erodes reliability and regulators pick winners and losers.

“It is no easy task to achieve a balance that allows states to make their own procurement decisions, while still ensuring those decisions do not harm the wholesale markets in your jurisdiction. Despite considerable pressure to disregard actions that erode the integrity of PJM’s capacity market, the commission had the courage to say, ‘no more,’” NGSA CEO Dena Wiggins wrote.

The American Coalition for Clean Coal Electricity and the National Mining Association also commended FERC on what they viewed as an effort to keep PJM’s market functioning through an expanded MOPR applied to all subsidies.

However, the groups asked for an exception to the MOPR: an exemption on a possible fuel security valuation in the PJM capacity market. They said a new MOPR shouldn’t “counteract federal efforts to ensure grid resilience and promote national security.” The groups urged FERC to require PJM to create a separate capacity auction for resources that can guarantee fuel security for a minimum number of days.

PJM’s “current market design is contributing to the loss of fuel-secure electricity resources, while encouraging reliance on pipeline-dependent and intermittent resources,” ACCCE and NMA said.

EPSA countered that any federal price supports for nuclear and coal units should subject them to the MOPR.

Other Out-of-Market Payments?

In arguing against an expanded MOPR, the Union of Concerned Scientists said PJM’s proposal “would arbitrarily provide an exemption for resources that have one kind of state-supported revenue, but not for other kinds of state-supported revenue.”

UCS argued PJM’s fleet of existing resources with state-sponsored out-of-market payments is “substantial” and greater in number than PJM has characterized.

“If the fundamental principles presented by both PJM and the commission are as important as suggested, and the commission has found that any price suppression due to out-of-market payments makes the PJM capacity auction results unjust and unreasonable, then there cannot be MOPR exemptions for investor-owned plants that have been receiving cost-recovery through state-administered rates,” UCS wrote. It also said PJM did not collect the list of states with out-of-market revenues for investor-owned generation through either a renewable portfolio standard, zero-emission credit program or regulated cost-of-service.

RPS National Map | *National Conference of State Legislatures*

“All of the states in PJM have one or more of these mechanisms that provide the means for generation to either enter or remain viable in PJM’s capacity market,” UCS said.

UCS said the fact that PJM’s Tariff allows zero-priced offers is evidence of state-supported cost recovery to keep resources viable in the capacity market.

APPA: Start Over

The American Public Power Association went for a scorched-earth approach, challenging PJM’s RPM itself.

The group argued PJM’s mandatory capacity market with a strict MOPR is “ill-suited” to achieving a diverse resource mix. It said PJM’s MOPR “now threatens to become an all-purpose restriction on any support for generation outside of revenues obtained through the PJM energy and capacity markets” and could “ultimately raise capacity prices without achieving any clear benefits.”

“The time is ripe to revisit the RPM construct in a comprehensive manner,” APPA said, rather than “doubling down” on a mandatory capacity construct with a “vastly expanded MOPR.”

APPA also argued self-supply resources used to meet the load of public power and cooperative utilities should not fall under an expanded MOPR, arguing vertical integration and tax-exempt financing do not constitute out-of-market support.

IMM’s ‘Sustainable Market Rule’

PJM’s Independent Market Monitor also suggested re-envisioning the RTO’s structure with what it calls a “sustainable market rule” that it argues is simple enough to be implemented in time for the next Base Residual Auction. While the Monitor attempted to differentiate its proposal from a MOPR, it would require all resources to offer into the BRA at their avoidable cost rate (ACR).

“A competitive offer in the capacity market is the marginal cost of capacity, or net ACR, regardless of whether the resource is planned or existing,” the Monitor wrote. “All capacity has a must-offer requirement and all capacity offers are included in the supply curve in the capacity market at competitive levels. All megawatts required for reliability are included in the capacity market demand curve (VRR curve).”

The Monitor acknowledged that load-side fears might be realized with this approach, but that “the possibility that customers may pay twice has been accepted by the courts” and FERC.

CASPR Appears

Vistra Energy and Dynegy Marketing and Trade proposed the Capacity Performance with Sponsored Supply (CaPSS), which it said is based on ISO-NE’s FERC-approved Competitive Auctions with Sponsored Policy Resources (CASPR) structure.

The two-stage auction would require all resources to offer in at their going-forward costs. PJM would create a table of resource-type ACRs, and any resource that believes its going-forward costs are below its applicable value in the RTO’s table would request a review to validate its argument. The second stage would be “purely voluntary” and allow existing resources that received a capacity obligation but are willing to permanently exit PJM’s markets to “give up” their obligations “in their entirety” to resources seeking subsidies that didn’t receive obligations in the first stage.

Next Steps

FERC faces a daunting task of threading the needle between at least eight proposed options for the MOPR and numerous modifications on both its FRR concept and PJM’s carve-out. Reply briefs in the docket will be due Nov. 6.

October 3, 2018

MISO Granted Longer Deadline for Offer Caps

By Amanda Durish Cook

FERC on Monday granted MISO a two-year lead time to implement a new offer cap into its fast-start pricing mechanism, while also directing the RTO to submit yet another compliance filing to meet Order 831 requirements.

The commission’s ruling set an Oct. 1, 2020, deadline for MISO to incorporate a $2,000/MWh hard cap for verified cost-based incremental energy offers into fast-start pricing (ER17-15 7 0-0 02).

miso offer caps fast start pricing — MISO’s Carmel, Ind. headquarters | © *RTO Insider*

In a March ruling on a previous compliance filing, FERC accepted much of MISO’s plan to permanently double its hard offer cap, but it also required the RTO to pledge to apply the new hard cap to adjusted energy offers from fast-start resources. (See FERC OKs MISO’s Doubled Offer Cap, Ord e rs Alterations.)

In the event FERC denied the extra time for implementation, MISO had also sought rehearing of the commission’s March order, warning it would otherwise need permission to “resort to manual processes” to enforce the caps. Citing the ongoing replacement of its market system platform, MISO contended it would likely need more time to “make appropriate adjustments to automate the requirements of Order No. 831” and “complete necessary system software changes.” The RTO also pointed out FERC granted ISO-NE a similar two-year lead time last November.

“We find that MISO has shown good cause for the granting of this requested effective date because it will allow MISO sufficient time for the development, testing and implementation of software needed to enable MISO’s existing market platform to apply the offer cap requirements to fast-start pricing,” FERC said.

One More Compliance Filing

Monday’s order also approved other revisions FERC had ordered in the March compliance filing, although it directed MISO to refine its proposed rules to address adders to the soft offer cap.

FERC accepted MISO’s fuller description of the data verification process for offers, how it would determine make-whole payments under the new offer cap and the process allowing market participants to dispute potential revenue sufficiency guarantee make-whole payments. The commission also accepted MISO’s clarification that its Independent Market Monitor will use data from its operating cost survey to determine facility reference levels. The IMM relies on the survey to collect operating cost data for market participants.

But in siding with the argument of a group of Midwestern transmission-dependent utilities (TDUs), FERC also directed MISO to submit another compliance filing to clarify that adders included in cost-based incremental energy offers above the soft cap of $1,000/MWh must be limited to a combined $100/MWh. MISO must also make clear those adders cannot be included in a resource’s after-the-fact make-whole payment, the commission said .

FERC also denied a request for a rehearing of its March order from the same group of TDUs, who argued the commission was too quick to accept MISO’s stance that outage risk is a verifiable component of energy cost rather than part of the $100/MWh adder above the soft offer cap. The TDUs argued it was arbitrary and capricious for FERC to find that outage risk is not an above-cost adder when it only used MISO’s rationale that outage risk is already included in a resource’s reference level in its current mitigation processes.

FERC didn’t bite at their argument.

“MISO explained that outage risk is a legitimate short-run marginal cost calculated separately for each resource based on validated data provided by market participants,” the commission wrote. “MISO also explained that incorporating this risk in a resource’s reference level continues MISO’s existing mitigation processes. As such, outage risk is a proper component of MISO’s reference level and is not an adder to verifiable costs pursuant to Order No. 831. Midwest TDUs have not proffered any arguments or evidence that contradicts MISO’s explanation of these risks.”

October 1, 2018

Overheard at NECA 2018 Fuels Conference

MARLBOROUGH, MASS. — Fuel security public policy and the role of traditional and non-traditional fuels in New England highlighted discussions at the Northeast Energy and Commerce Association’s 2018 Fuels Conference on Thursday.

“Natural gas is as pertinent and important as ever, particularly in New England,” Day Pitney attorney Joseph Fagan said.

“If it’s not easy — in this region especially — to site pipeline or gas infrastructure, it only makes sense that we’ll see virtual transportation become more important. It makes sense that LNG is going to become more of an issue,” Fagan said. “How is [ISO-NE] going to address fuel security and reliability when we have the reality that we have no new pipelines coming into this state … and we have a large plant [Mystic] that — unless things change — may be retired?”

NECA held their 2018 Fuels Conference on Sept. 27. | © *RTO Insider*

In July, FERC tentatively accepted a cost-of-service agreement between ISO-NE and Exelon for Mystic Generating Station Units 8 and 9, ordering an expedited hearing process on unresolved issues related to cost justification (ER18-1639). (See “Fuel Security,” Overheard at ISO-NE Consumer Liaison Group Meeting.)

The goal to reduce greenhouse gas emissions is driving policy in the region, said Brian Jones, senior vice president of energy consultancy M.J. Bradley & Associates.

“A lot of the resources that ISO New England manages today are a product of that and have to do with air quality and GHG,” Jones said. “Fuel supply is an obvious one, and pipeline constraints into the region are another. We face a lot of challenges, with six states that have pretty aggressive policies on energy and environmental issues, and I don’t think that’s going to change.”

Virtual Pipelines, LNG, RNG

A big chunk of heating demand met by gas cannot be substituted with renewables or energy storage, and Elon Musk has not yet invented a battery-powered heater, said Andrew Bradford, CEO of energy consultancy BTU Analytics.

“What the latent natural gas demand is in New England is a good question,” Bradford said. “We look at 0.75 Bcfd in winter, 1.5 Bcfd max, and 0.5 Bcfd on the peak price day and see there could be demand for around 2 Bcfd.”

Given the constraint on pipeline supplies, “for natural gas end-users in New England, there is no silver bullet,” he said.

There could be a large truck though. The lack of gas infrastructure has created a market for Xpress Natural Gas, a compressed natural gas distributor that now sends trailer trucks from its 40-Bcfd capacity terminal in Montrose, Pa., to inject into the Iroquois Pipeline at a terminal in New York.

Gary Ritter, XNG’s vice president of sales, said the company serves customers from Prince Edward Island to the Mid-Atlantic states, both companies lacking pipeline access and “to facilities on the pipeline grid, bringing incremental supplies to capacity-constrained areas.”

The Montrose terminal last winter loaded approximately 25 MMcfd filling some 60 trailers at an average capacity of 400 Mcf each.

Shaving of natural gas peak demand is the top use of LNG in New England, such as at National Grid’s waterfront facility in Salem, which holds 12 million gallons of LNG, the equivalent of 1 Bcf of natural gas, said Jonathan Carroll, director of U.S. business development for Energir, formerly Gaz Metro, the largest gas distributor in Quebec.

“This facility or facilities like it are very common in New England,” Carroll said. “As a matter of fact, there are close to 40 of these peak-shaving facilities in the region. Some actually have liquefaction and can produce their own fuel; others do not.”

In addition, he said there are currently three LNG projects under development in the region: Granite Bridge, Northeast Energy Center and REV LNG.

NECA Fuels Conference fuel security natural gas — Kenzie Schwartz | © *RTO Insider*

McKenzie Schwartz, a National Grid gas analyst, said the market for renewable natural gas (RNG) is taking off because of support from state and federal policies, such as EPA’s Renewable Fuel Standard.

RNG is derived from biomass and is fully interchangeable with natural gas.

“We believe this can help National Grid move our industry toward a lower-carbon future,” Schwartz said.

National Grid pioneered technology in 1982 as the first utility to allow an RNG project to interconnect. Its Staten Island Landfill project is still in operation, injecting 2,000 dekatherms/day into the distribution system.

Electrification: How Much?

Emily Lewis, senior policy analyst for Acadia Center, an environmental advocacy organization, said that if states push renewable energy policies, wind and solar energy could generate 45% of New England’s electricity in 2030, versus 24% under current trends.

Lewis and Richard Murphy, energy markets director at the American Gas Association, debated how much electric heat pumps can reduce GHG emissions.

Repeating findings she shared earlier in the month at the ISO-NE Consumer Liaison Group meeting in Connecticut, Lewis said electrification of space heating, under current trends, would reduce GHG by 3% by 2030 and by as much as 16% under an accelerated policy scenario. (See Overheard at ISO-NE Consumer Liaison Group Meeting.)

Murphy countered with an AGA study that contends aggressive residential electrification of heating and cooling would reduce national GHG emissions by only 1 to 1.5% in 2035. (See State Regulators Hear Challenges, Promise of Electrification.)

There are three common themes in efforts to achieve deep decarbonization of the energy sector, he said. One is to dramatically increase efforts around energy efficiency. The second is to advance policies that would require up to 100% of all the electricity generated in the U.S. to come from renewable resources. The third is to replace all end-use applications from natural gas or fuel oil to electric alternatives, he said.

“The region uses more than twice as much energy in peak winter months as in the summer, so what would the overall cost be of converting residences away from natural gas and to electrification?” Murphy said. “When we look at the data in the residential market, we really start to think about the impacts on consumers.”

Approximately 60 million homes in the U.S. would have to be converted from natural gas heating to electricity, he said, which is a “massive undertaking” for such a modest environmental gain.

Oil Still Relevant

Oil comprises only 1% of New England’s power generation on average. But the fuel remains relevant at times, such as a cold snap last winter when oil accounted for 37% of the region’s electricity generation, said Kevin Grant, an oil trader at Sprague Energy.

The ability of oil to fill the fuel gap in winter is compromised by the cost of maintaining inventory, delivery logistics and the changed nature of the market, he said.

“Power generators, while still important, no longer drive the commercial oil market,” Grant said. “A fuel supplier is going to gear their operations to the customer who comes in 300 times a year, not once a year. Logistics is also an issue, with a limited number of barges and trucks. Transportation companies have right-sized their assets in response to market demand the same as everyone else.”

Stephen Leahy, vice president of the Northeast Gas Association, said, “Natural gas is the last fossil fuel left standing for power generation, but oil is still the No. 1 fuel consumed overall in Massachusetts in terms of total Btus. It’s mostly in the form of gasoline, but it’s still oil.”

How are we going to balance energy needs with environmental goals? asked Nancy Seidman, senior adviser to the Regulatory Assistance Project.

“The first principle is to put energy efficiency first,” Seidman said. “What it’s done for New England has been huge. … To have demand actually dropping is fabulous.”

— Michael Kuser

October 1, 2018August 5, 2024

PJM Members Vote to End FTR Liquidations

VALLEY FORGE, Pa. — The PJM Markets and Reliability and Members committees on Thursday approved Operating Agreement revisions that would eliminate the requirement that the RTO liquidate a member’s financial transmission rights when it falls into default.

The proposed changes are in response to the June default of GreenHat Energy, which could cost other members more than $145 million. (See Doubling Down — with Other People’s Money.)

PJM presented stakeholders with four packages of revisions at the MRC. Two of those had received a majority sector-weighted vote out of 24 proposals at a special committee session Sept. 18. Option B, Thursday’s winner, received 3.8 out of 5 in support, while Option J1 — which would have liquidated all of a defaulting member’s long-term positions except those remaining in the 2018/19 planning year, allowing them to go to settlement — received 3.3.

After the special meeting, Macquarie Energy, with support from Apogee Energy Trading and Vitol, offered two more proposals: B’ and J1′ (read as “B prime” and “J1 prime”), identical to B and J1 except that they would only apply to GreenHat’s portfolio. Macquarie said these proposals would allow for continued discussion of PJM’s liquidation process after dealing with GreenHat.

All four proposals included two identical provisions. One would ensure that the maximum $10,000 default allocation assessment is charged only once for a default that spans multiple years, rather than each year.

The other would allow those who sold FTRs to the defaulting member in a bilateral trade to take them back if their most recent auction clearing prices were less than the purchase prices.

Brian Wilkie of Rockland Electric Co. moved for considering B without the bilateral provision, which Exelon’s Jason Barker seconded. This proposal was dubbed B” (“B double prime”).

Dean Bickerstaff of Hartree Partners moved, with CPower’s Bruce Campbell seconding, that the MRC also consider Option K1B, which had only received 1.99 in support at the special meeting. K1B would have also allowed the 2018/19 positions to go to settlement, but it would have canceled all defaulting long-term FTRs. It also would have forced counterparties to the defaulters’ bilateral trades to reassume those positions.

Only B received the 3.34 sector-weighted supermajority support necessary to move on to the MC, with 3.73 in favor. B” received 1.88, B’ and J1 each received 1.8, J1′ got 1.44 and K1B 0.44.

At the MC later Thursday, Bob O’Connell of Panda Power Funds moved that the committee vote to accept the MRC’s vote as its own, but he withdrew the motion when DC Energy’s Bruce Bleweis called for a sector-weighted vote on it. Committee Chair Michael Borgatti, of Gabel Associates, called for a sector-weighted vote on B anyway, and the proposal passed with 4.01 in favor.

CFO Suzanne Daugherty explained that PJM will submit B as three separate “prongs” to FERC, with the $10,000 maximum and bilateral provisions in their own filings. Daugherty said this was done so that if the commission ends up rejecting one provision, it would not be forced to reject the entire package.

Members also reaffirmed their opposition to the status quo, with only 0.5 in support. If FERC rejects the proposal to eliminate the liquidation requirement, the RTO will ask in an amendment to a pending filing that the commission allow all of GreenHat’s positions to go to settlement until the end of February to allow for additional stakeholder discussion of alternatives to the status quo. PJM has asked the commission to allow the positions to go to settlement through Nov. 30, but FERC has not acted on the filing, nor on the RTO’s waiver request seeking permission to only liquidate prompt month FTRs.