Page 1143 – RTO Insider

February 14, 2020

MISO Planning Subcommittee Briefs: Feb. 11, 2020

The cost estimation guide for MISO’s 2020 transmission planning cycle will for the first time include upfront and long-term cost estimates for HVDC lines.

MISO circulated the draft guide for the 2020 MISO Transmission Expansion Plan (MTEP 20) at the Planning Subcommittee’s meeting Tuesday. The guide is used to evaluate alternatives to some of the proposed projects in the plan.

The RTO is proposing that the new guide increase the costs of lines, substation equipment, breakers and transformers across all voltage classes. Costs of land clearing are similarly set to rise, and costs for the land itself will go up almost across the board.

This year, MISO is also adding cost estimates for HVDC lines and their converter stations, Principal Transmission Design Engineer Devang Joshi said.

All project cost estimates include a 20% contingency cost adder and an additional 7.5% allowance for funds used during construction.

MISO is requesting stakeholder reactions to the cost estimation guide by March 13. It plans to post a final version to its website by June 23.

Extreme Event Results in

MISO’s recently completed an extreme events analysis for MTEP 19 finds the West planning region — Minnesota, Iowa, parts of the Dakotas and western Wisconsin — contains the highest potential for cascading failures on the transmission system.

However, reliability planners said only a few events show cascading failures out of the thousands of extreme events tested.

The annual analysis was performed with two-, five- and 10-year models using contingencies submitted by transmission owners and developed by MISO. Simulated events included single instances and combinations of substation, generation and transmission losses and natural gas pipeline outages.

MISO expansion planner Fatou Thiam said paired element outages on the system present the most common cause of hypothetical cascading in nearly the entire RTO. However, common right-of-way circuit outages are the most prevalent cause in lower Michigan.

After completing the analysis, MISO works with its TOs to pinpoint actions that would minimize the risk or severity of cascading failures. The extreme events study is meant to give TOs a better understanding of the effects of various low-frequency, high-impact events.

MISO is now in the process of compiling extreme event contingencies as part of its MTEP 20 reliability assessment. Additionally, the RTO is asking stakeholders how it might improve its process of developing and evaluating extreme events. Stakeholders are asked to respond in writing by Feb. 28.

— Amanda Durish Cook

February 13, 2020

What Spring Could Bring for PG&E

By Hudson Sangree

The countdown is on for Pacific Gas and Electric’s exit from bankruptcy, which all parties agree needs to happen by the end of June so the utility can participate in a state insurance fund to protect it from future wildfire liabilities, a key to its financial stability.

Lawyers for PG&E and its creditors, together with U.S. Bankruptcy Judge Dennis Montali in San Francisco, are trying to keep things moving toward that goal. Yet significant hurdles remain before PG&E — which the U.S. Energy Information A dministration calls the nation’s largest electric utility, with nearly 5.5 million customer accounts — can free itself from legal entanglements and political threats.

The repeated insistence by Gov. Gavin Newsom that PG&E must undergo a fundamental shift in its leadership and safety culture or face a state takeover recently was joined by a legislative proposal that would create a mechanism to seize the company from its shareholders. (See PG&E Tries to Appease Governor with New Plan.)

Another threat has arisen recently from wildfire victims who don’t want the federal and state governments taking nearly $4 billion from a $13.5 billion fire victims’ trust promised by PG&E. The 70,000-plus victims of utility-sparked wildfires in 2015, 2017 and 2018 must ultimately vote on PG&E’s proposed reorganization plan.

And the California Public Utilities Commission, led by Newsom appointee Marybel Batjer, must approve any restructuring plan, including under the auspices of Assembly Bill 1054, the measure that created the wildfire insurance fund last year.

PG&E has to overcome those hurdles and more in the next four-and-a-half months. Here’s a look at this spring’s agenda and possible hurdles.

Fire Victims Object

PG&E filed its proposed disclosure statement Feb. 7, an important step in its Chapter 11 reorganization. The document is intended to lay out in relatively plain language the terms of the utility’s restructuring so that fire victims and others can weigh the plan and eventually vote on it.

In particular, the document describes the creation of the $13.5 billion trust, funded half in cash and half in PG&E common stock. The expectation is that the stock will be liquidated over time to provide money to pay claims.

PG&E spring — Smoke from the Camp Fire in Paradise, Calif., filled the sky above the nearby town of Chico on Nov. 8, 2018, when 86 people died in a matter of hours.

Some victims don’t like the stock component. They’ve told their lawyers and Montali they worry the stock could decline in value if PG&E experiences financial setbacks after bankruptcy. Some fire victims wrongly believe they will be given stock directly in lieu of a check, the judge and lawyers said at PG&E’s latest bankruptcy hearing on Tuesday.

That’s why the disclosure statement says in bold letters, “No Fire Victim will receive stock of Reorganized PG&E Corp. directly.”

A more serious problem, however, is that federal and state agencies, including the Federal Emergency Management Agency and the California Office of Emergency Services, say they will seek recovery of their wildfire claims, totaling as much as $3.9 billion, from the victims’ trust.

The case’s official Tort Claimants Committee, PG&E and others have objected to that outcome, which could unravel PG&E’s reorganization plan. They say the government agencies must pursue other means of compensation under the law.

Montali tried to reassure fire victims that highly experienced lawyers were addressing the matter.

“They are issues that are being dealt with by principal players,” Montali said at Tuesday’s hearing, in response to objections from one fire victim, Will Abrams, who has appeared in person at the bankruptcy court to voice his criticisms of PG&E’s restructuring plan.

A hearing on the government agency claims is scheduled for Feb. 26, and a hearing on the proposed disclosure statement is planned for March 10.

Montali noted that other individual victims have been writing to him, expressing their concerns.

“Please hold PG&E fully accountable,” Tina Rezler, a survivor of the November 2018 Camp Fire, wrote to the judge earlier this month. “The current amount set aside isn’t enough. Please do not allow FEMA, insurance companies or any other organization to take funds set aside for survivors that the funds are intended for.”

Rezler said she lost her home and dog in the fire, which tore through the town of Paradise in a few hours early on a Thursday morning, killing 86 residents and destroying more than 18,800 homes and businesses.

The other large, deadly fires that PG&E plans to pay victims for are the Butte Fire in September 2015 and the North Bay or wine country fires of October 2017. The latter fires in Napa and Sonoma counties included the Tubbs Fire, which killed 22 residents and burned down a residential neighborhood in Santa Rosa, Calif.

In all, more than 70,000 fire victims have filed claims, attorneys said. Once the court adopts PG&E’s disclosure statement, the victims will have the opportunity to comment and vote on the plan. PG&E has to mail out the disclosure statements and ballots by March 31, and ballots have to be returned to the court by May 15.

“We are weeks away from my being asked to approve a disclosure statement and supporting documents that will be designed to explain to them — every one of them, if they are inclined to read it — what should influence their decision,” Montali told Abrams. “You and all 70,000 fire survivors have the right to vote the plan down if you choose to. That’s the way the system was designed.”

Governor Objects, Too

Another major obstacle to PG&E’s hopes of exiting bankruptcy by June lies with Newsom, who has said on a number of occasions that he will seek a state takeover of PG&E if the utility doesn’t meet his list of demands, such as an entirely new board of directors and a mechanism for the state to quickly assume control of the company if circumstances warrant.

Recently, state Sen. Scott Wiener (D-San Francisco) introduced a bill, SB 917, that would allow a state-created public-benefit corporation to acquire a utility through eminent domain, moving its assets to a proposed new entity called the Northern California Energy Utility District.

The bill doesn’t specifically mention PG&E, but Wiener made clear his intentions at a Feb. 3 news conference, saying his bill would “put an end to the dangerous roller-coaster ride that we have been on with PG&E over the past decade,” the San Francisco Chronicle reported.

Another of the governor’s primary concerns is the tens of billions of dollars in new shares and bonds PG&E would issue to pay for its restructuring plan. Newsom has said an over-leveraged PG&E would be unable to pay for the estimated $40 billion to $50 billion it needs to upgrade and harden its aging infrastructure, the source of catastrophic wildfires and the San Bruno gas pipeline explosion of 2010.

On Tuesday, Newsom’s lawyers told Montali they wanted to question witnesses about PG&E’s plan, which could happen on Feb. 19, Feb. 26 or in sworn depositions, attorneys said.

While Newsom has no authority over Montali, the judge is taking the governor’s objections seriously because Newsom could have significant influence on the proceedings.

The California Public Utilities Commission, whose members the governor appoints, has responsibility for approving PG&E’s Chapter 11 plan under the commission’s order instituting investigation (OII) and under AB 1054. The measure, championed by Newsom and quickly passed in July, would give PG&E access to a $21 billion wildfire insurance fund, paid for equally by ratepayers and the state’s big three investor-owned utilities.

The bill requires PG&E to exit bankruptcy by June 30 to participate in the fund. The utility also must compensate victims of past fires ignited by its equipment and demonstrate that its post-bankruptcy governance structure is acceptable “in light of the utility’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the CPUC.”

PG&E was convicted in 2016 of six felonies related to the San Bruno pipeline explosion.

Without the AB 1054 funds to protect it from future liabilities, PG&E’s financial future could be in jeopardy and its bankruptcy plan could fall to pieces.

The CPUC is scheduled to gather evidence in its PG&E investigation during hearings from Feb. 25 to March 4 at its San Francisco headquarters.

February 13, 2020

NERC Developing Risk Mitigation Framework

By Holden Mann

MANHATTAN BEACH, Calif. — NERC and its collaborators are developing a framework for prioritizing known and emerging risks that they soon hope to hand off to the Reliability Issues Steering Committee (RISC) for further refinement.

Speaking to NERC’s Member Representatives Committee Feb. 5, NERC Chief Engineer Mark Lauby said that while NERC and the industry have “a host of different tools in our toolkit” to mitigate risk, the agency lacks a transparent process to help entities choose the best approach to manage a particular situation. The proposed framework is intended to fill this important gap.

NERC Risk Mitigation — Mark Lauby, NERC | © *ERO Insider*

“It seems like otherwise we just hold the risk up; we don’t really know what to do with it [and] what’s the best solution,” Lauby said. “With our eyes open, [we’ll be] able to take some action.”

Lauby described the preliminary framework — which he said was created by the ERO Enterprise, with additional input by the North American Transmission Forum — as a move toward this unifying approach, albeit one that still needs considerable revision before it is ready for deployment.

Rationalizing Existing Procedures

The developers’ work so far has focused on identifying six essential elements to be performed by ERO Enterprise participants including RISC and the new Reliability and Security Technical Committee (RSTC):

Identifying risks and creating a risk registry.
Prioritizing risks.
Identifying and evaluating mitigation strategies.
Deploying mitigation strategies.
Measuring the strategies’ success.
Monitoring the residual risk.

For this early stage the designers of the framework leaned toward incorporating existing processes into the new framework — for example, RISC already performs the prioritization function through its annual Reliability Risk Priorities Report. Lauby said that while “certainly we didn’t come up with” these functions, the work of the existing bodies could still go to waste if they are not integrated into a consistent procedure.

Guiding Principles Established

In addition to creating the basic framework, the designers also suggested a set of principles to guide how the ERO Enterprise prioritizes risk and decides on a specific response. Events are grouped into four main quadrants based on their likelihood and their potential impact on the grid. Low likelihood, low impact events can be addressed with robust baseline reliability requirements, while high impact events with a high likelihood should be dealt with through more active means such as NERC alerts and in-person assist visits.

The framework is still in a very early stage and has mainly been developed at a high level. As a result, NERC’s leadership sees a long road ahead before it takes a form that can be adopted by the ERO Enterprise and industry. Nevertheless, Lauby believes the work already done constitutes an important first step.

“Consider it — as we say in our transformation language — a mistake,” he said. “A lot of good ideas are there to begin with, but my suggestion will be to hand this off to the RISC [because] one of the things [assigned to] it … in the charter is to triage risk.”

February 13, 2020

Critics: Pa. RGGI Hearing Stacked with Detractors

By Christen Smith

A dozen testifiers told a Pennsylvania legislative panel last week that joining the Regional Greenhouse Gas Initiative (RGGI) undermines the state’s energy production dominance and does nothing to accelerate CO₂ emission reductions in line with national and global targets.

The House Environmental Resources and Energy Committee fielded comments from researchers, trade groups and labor unions about House Bill 2025, a proposal that delineates a legislative process for joining RGGI.

Noticeably absent, however, was anyone in favor of the program – an unusual occurrence for legislative hearings on proposed bills.

“We were not invited to testify,” said Julian Boggs, policy director of the Keystone Energy Efficiency Alliance. “It would be nice if we could have a constructive conversation in the legislature and say, ‘Hey this is what’s happening, what should we do with the proceeds?’”

Mark Szybist, senior attorney for the Natural Resources Defense Council, called the hearing a “staged burlesque.”

“I don’t know how you can have a fair hearing if you’re not even bringing in the state agency that’s working on this regulation,” he said. “There’s no way you can look at this and say it was a fair and balanced hearing or a hearing that was even intended to deliver facts or truly honest discussions about RGGI.”

One-track Hearing

HB 2025 is a result of Democratic Gov. Tom Wolf stunning the Republican majority in both chambers in October when he directed the state’s Department of Environmental Protection (DEP) to join the regional emissions reduction program. (See Pennsylvania Governor Signs R G GI Executive Order.) Delaware, Maryland and New Jersey are the only three PJM states currently involved in the program, with Virginia in line to join next.

According to a RGGI report released in October, participating states reduced their power sector carbon emissions by more than 50% between 2005 and 2017 despite an increase in their GDP. The nine participating states – either through regulation or legislation – cap power plant emissions on a quarterly basis and auction off credits to generators, who then purchase the allowances as proof of compliance. The proceeds return to participating states for reinvestment.

Majority Committee Chairman Rep. Daryl Metcalfe (R) told RGGI’s Executive Committee in a Jan. 16 letter that Wolf “simply and unequivocally” lacks the unilateral authority to join the program and that bipartisan and bicameral talks “are already underway” to stop it.

“Welcoming Pennsylvania into your ranks without legislative approval would be foolish and harmful both to RGGI and our commonwealth,” he said. “This will leave both RGGI and Pennsylvania in an unwelcome state of limbo. It will complicate RGGI’s administration and likely take years to resolve. You will not be able to count on Pennsylvania’s participation in RGGI, but you will have to expend time and resources planning for it, nonetheless.”

Metcalfe’s office did not respond to RTO Insider’s request for comment on Wednesday regarding the hearing’s slate of witnesses.

Minority Committee Chairman Rep. Greg Vitali (D) said the tenor of the meeting disappointed him, as comments from his caucus members were routinely shut down to keep the hearing agenda on track.

“Most of the testifiers had a vested financial interest in the fossil fuel plants that would be targeted by RGGI,” he said. “It’s relatively safe to say that no pro-RGGI groups were invited and that was entirely Chairman Metcalfe’s decision.”

Vitali said Democrats and other RGGI supporters also believe the federal Clean Air Act gives Wolf and the DEP the power to join the program without the support of the Senate or the House of Representatives – though lawmakers would likely challenge that authority in court. Notably, other RGGI states have moved forward with the blessing of their respective legislatures, except Virginia.

“Even if the bill passes, the governor will almost certainly veto it,” Vitali said. “Even so, our committee will most likely vote on this bill.”

Rep. Jim Struzzi (R) introduced HB 2025 in November, with Reps. Pam Snyder (D) and Donna Oberlander (R) as co-sponsors.

“I’m trying very hard not to let my emotions or my bias into this because we are talking about the bill today,” Struzzi told the committee. “I represent hard-working Pennsylvanians who will suffer dearly if RGGI is implemented.”

No Apologies Necessary

Indeed, Struzzi’s concerns about RGGI’s impact on the state’s fossil fuel power generators were echoed again and again by testifiers who said the program produces no real benefits and will diminish energy production, force coal plants into early retirement and increase leakage throughout PJM.

“If you want to spend $5.5 billion per year with no significant reduction in emissions, by all means join RGGI,” said David Stevenson, policy director for the Caesar Rodney Institute’s Center for Energy & Environmental Policy. “But I don’t see this as a good idea for Pennsylvania.”

Stevenson said he’s spent nearly a decade studying RGGI impacts and argues that when comparing results from participating states to five who do not participate, emissions reductions are “exactly the same.”

Since 2005, per capita emissions reductions in both groups of states is 40%, according to Stevenson’s research. Coal production in both groups decreased 16%, while natural gas production increased 10%. GDP grew in both by 7.2% and electricity prices rose 50% slower in non-RGGI states. Stevenson concludes that pushing the state into the program will curtail energy-intensive businesses, further dragging down its economy.

It makes little sense then, Stevenson argued, to join RGGI when Pennsylvania’s booming natural gas exports have reduced carbon emissions nationwide by 308 million tons, far exceeding the 215 million tons it produces.

“Pennsylvania doesn’t owe anybody an apology about carbon dioxide emissions,” he said. “It’s done more than any other state in this country to reduce carbon emissions.”

Democrats on the committee challenged Stevenson’s research, insinuating that it was shaped by the Caesar Rodney Institute’s conservative donors. Vitali also pressed Stevenson to vocalize his opinion on climate change.

Stevenson said that donors don’t impact his research and some have even forgone financial support because of his conclusions.

“It is a certainty that carbon dioxide is rising in the atmosphere,” he said. “We have the ability to adapt and to use things that actually work, and one of those things that actually works is switching from coal to natural gas. I agree that it’s an issue, but I don’t agree that it’s a crisis.”

Szybist said Stevenson’s suggestion that RGGI doesn’t drive emission reductions was nonsensical. He cited a Duke University stu d y from 2015 that found while not all emissions reductions were attributable to RGGI, the program was still the single biggest factor, accounting for more than half.

“The fact that emissions went down under RGGI due to factors other than RGGI – the Great Recession and the boom in gas-fired generation due to fracking – isn’t evidence that cap-and-invest doesn’t work,” he said. “Had the start of RGGI not coincided with the Great Recession and the fracking boom, RGGI would have ensured that emissions went down anyway.”

Szybist also pointed out that RGGI “was never intended as an all-encompassing emissions-reduction policy.”

“It was intended as a way to ensure emissions reductions and generate funds to invest into other decarbonization strategies,” he said.

February 13, 2020

PJM Chooses CFO, Promotes Haque

By Christen Smith

PJM filled in key members of its executive team on Wednesday with the appointment of Lisa Drauschak as chief financial officer and Asim Haque as vice president of the state and members services division.

The two were promoted internally and will fill the roles left vacant last year by former CFO Suzanne Daughtery and Denise Foster. (See PJM CFO Retiring in Wake of GreenHat Default.)

“I’m delighted to have Lisa join PJM’s executive team,” CEO Manu Asthana said. “With her wealth of experience in financial management, Lisa brings strategic oversight, financial discipline and long-range strategies that will help PJM achieve its business objectives.”

PJM Draushak Haque — Lisa Drauschak and Asim Haque | *PJM*

Drauschak joined PJM in 1999 as a controller and most recently served as executive director of corporate finance. She graduated from Villanova University in 1991 with a bachelor’s degree in accounting.

Haque joined PJM last year as its executive director of strategic policy and government affairs after serving as chairman of the Public Utilities Commission of Ohio. He will oversee state government and electricity infrastructure policy and members services.

Haque graduated from Case Western Reserve University with a bachelor’s degree in chemistry and political science in 2002, followed by a J.D. from The Ohio State University Moritz College of Law in 2006.

“Asim’s insights, leadership and ability to develop relationships are an asset to PJM as we continue to navigate the complexities that come with dynamic changes in the energy industry,” Asthana said. “I’m delighted he’s also joining the executive team.”

Drauschak and Haque will assume their new roles on Feb. 26.

February 13, 2020

Dominion: ‘No Near Term Impact’ from PJM MOPR

By Christen Smith

Dominion Energy executives told investors Tuesday that PJM’s expanded minimum offer price rule (MOPR) poses no near-term threat to its 2,600-MW offshore wind farm planned for 2026.

CFO Jim Chapman said Dominion’s balanced portfolio in Virginia will shield the company from any financial impact, but that electing the fixed resource requirement (FRR) alternative in the future remains a possibility.

“We don’t expect that that MOPR as proposed will have really any financial impact on Dominion,” he said. “As you know, our capacity and load in Virginia is pretty well balanced, so no near-term impact. And if we foresaw that some change with MOPR and PJM rules that would mean that we would not be potentially receiving capacity payments on new build generation, we could very easily … just elect that FRR option, which we think is pretty straightforward.”

In December, FERC expanded PJM’s MOPR to all subsidized resources entering the capacity market. Critics hold that the ruling will limit renewable energy development because offer price floors will push them out of the capacity market, while others insist capacity revenue factors little into renewable investment decisions.

Dominion MOPR — Dominion’s offshore wind project plans. | *Dominion Energy*

Dominion’s $8 billion offshore wind farm, the largest in the nation, will sit 27 miles off the coast of Virginia in federal waters. Dominion said ocean survey work will begin on the project in April, with construction slated for 2024. The company also confirmed Siemens Gamesa will provide the 210 turbines needed and that it contracted with three labor unions to perform the onshore interconnection work.

“We will continue to monitor that situation as it winds towards resolution,” Chapman said. “In the meantime, we do not see this as a material financial risk for our company given the even balance of supply and demand at Dominion Energy Virginia.”

Chapman’s comments came during a quarterly earnings conference call with investors where the company touted its progress on emissions reductions and improving its environmental, social and governance principles. The company reported a 33% increase in year-over-year earnings in its fourth quarter, totaling $4.48 billion.

Dominion CEO Tom Farrell said Tuesday that coal-fired generation produced just 12% of the company’s electricity last year, representing an 80% decline over the last 15 years. He said most current estimates suggest that “coal-fired generation today accounts for less than 8% of our total regulated investment.”

Farrell also expanded on Dominion’s plans to reach net-zero emissions by 2050, including extending licenses for its nuclear generation fleet; promoting customer energy efficiency programs, investing in wind and solar power; further reducing coal-fired generation; enhancing natural gas infrastructure leak detection; replacing legacy distribution lines; and repurposing agricultural methane emissions as renewable natural gas.

“We will never lose sight of our fundamental responsibility to customers, provision of safe, reliable and affordable energy,” he said. “Though certain approaches will undoubtedly evolve over the coming decades to reflect the most up-to-date assumptions, our commitment to net-zero emissions will not change.”

February 12, 2020February 19, 2025

PJM Seeks to Quell ‘Inflammatory’ Exit Talks

By Rich Heidorn Jr. and Michael Brooks

WASHINGTON — A top PJM official sought Monday to quell talk of an exodus from the RTO in response to FERC’s controversial order expanding the minimum offer price rule (MOPR), telling state regulators they shouldn’t lose sight of the RTO’s overall “value proposition.”

During a panel discussion at the National Association of Regulatory Utility Commissioners (NARUC) Winter Policy Summit, PJM Executive Director Asim Haque said the RTO hasn’t done an analysis on the rate impacts of FERC’s Dec. 19 order (EL16-49, EL17-178). Dissenting Commissioner Richard Glick said the MOPR expansion could add $2.4 billion in annual capacity costs.

But Haque said PJM is heartened by the Independent Market Monitor’s conclusion that the MOPR exemptions allowed for existing resources means that the order “may not have as deleterious an impact for state policy endeavors as at least initially perceived” in the short term.

Haque, a former Ohio regulator, said the order is not workable in the long term because it “needlessly frustrates state policy initiatives.” He said the RTO wants to work with stakeholders to “find that sweet spot between balancing those state policy priorities and wholesale market mechanisms.”

Haque downplayed PJM’s role as a policymaker, referring to it repeatedly as a “market administrator” and noted that FERC rejected both of its proposed options for addressing the concerns that state-subsidized resources were depressing capacity market prices.

He said discussions over whether states will leave PJM are “unnecessarily inflammatory,” noting that capacity represents less than 20% of generators’ revenues and that the RTO’s “value proposition” includes its energy and ancillary services markets, transmission planning and reliable grid operations.

“So, when you look at the … chunk that the capacity market takes up within that overall value proposition, we are talking about a portion of a portion of a portion of the overall PJM value proposition,” said Haque.

Christine Tezak, managing director of ClearView Energy Partners, agreed that states are unlikely to exit PJM altogether because of the energy market and the requirement to pay off regional transmission spending obligations. “But we think that the potential to opt out of [the capacity market] is on the table.”

She recalled FERC’s 2017 technical conference on capacity markets, where there was much discussion of “blending” state priorities with competitive market rules. (See RTO Markets at Crossroads, Hobbled FERC Ponders Options.)

“When you look at this order, there’s no blending. It is just a decision that the market comes first; everything else comes later,” Tezak continued. “If you look at this order, you start to wonder if joining PJM means that you have abdicated all resource adequacy authority.”

MOPR Contagion?

Mason Emnett, vice president of competitive market policy for Exelon, said the MOPR will push subsidized resources from the capacity market, leaving fossil fuel-fired generation as the marginal resources and threatening the future of the capacity market construct. If the expanded MOPR survives as is, he said, FERC will also apply it to ISO-NE and NYISO.

He cited the Electric Power Supply Association’s filings in January 2017 and April 2018 seeking expedited action on a complaint by the Independent Power Producers of New York over state subsidies (EL13-62). (The commission has listed the docket for action at the Feb. 20 open meeting.)

Although there is no open docket in ISO-NE, Emnett said, state commissions have asked to re-engage with the RTO on a market design accommodating state policies, with Connecticut seeking an analysis on alternatives like PJM’s FRR. (See Connecticut Weighs Pros, Cons of ISO-NE Markets.)

“If there’s a misalignment between what the states on behalf of their consumers are demanding and what the market is providing, that market does not survive,” Emnett said.

But Travis Kavulla, vice president of regulatory affairs for NRG Energy, an independent power producer (IPP), said the expanded MOPR will have little impact on renewables because of their falling costs. He noted his company’s business in ERCOT, where he said “the people who are placing bets are placing them on solar and demand response and not on combined cycle” plants. “If you were for some reason … to impose a capacity market on the state of Texas and establish some type of minimum offer price rule that will exist in PJM, those renewable resources will clear. They will be in the money.

“I think, ultimately, it’s much ado about nothing for renewables,” he said.

Tezak said the Base Residual Auction may need to shrink to its originally intended “residual” role.

“The problem is that the capacity market is mathematically perfect and politically problematic. And it has been from the beginning. It solves for too much capacity, as we’ve observed. The arguments we’re having are political in terms of: ‘What is the value of the things that aren’t included in the market?’” she said, referring to carbon emissions.

“If the capacity markets survive, I would expect them to change. And I think that we may have to come back to the conversations that we set aside [more than] a decade ago … which is, should you have varied tenors for capacity; should you have varied types of capacity?” said Tezak.

Change in Position for PJM?

Maryland Public Service Commission Chair Jason Stanek, who moderated the panel, asked Haque whether PJM’s “pretty pointed” Jan. 21 rehearing request represented a change in position by the RTO, which welcomed a new CEO, Manu Asthana, at the beginning of the year. (See PJM MOPR Rehearing Requests Pour into FERC.)

“I think it does reflect a change in the tenor of where PJM is situated,” Haque responded. “You have to understand that energy policy in the footprint is happening in the states. And it’s a trend that cannot be ignored.”

Maryland PSC Commissioner Anthony J. O’Donnell said later he wasn’t convinced that PJM has changed. “To now say, ‘We’re just the market administrator,’ I think, is a little rich, though I appreciate the change,” he said prompting laughter from other regulators. “You created this mess.”

Carbon Pricing

Most of the panelists were pessimistic at the prospects for the adoption of carbon pricing, which PJM officials have said could address state environmental concerns within a market construct. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.)

“It sounds pretty straightforward in theory, until you figure that there are 14 different opinions about how it might be applied and the value each particular state … may choose to assign to it,” said Tezak, referring to PJM’s 13 states and D.C. She noted that the states in ISO-NE, which she said are more “homogeneous” on environmental policy than those in PJM, were unable to agree on a way to increase the role of carbon emissions in its markets.

A more realistic approach might be greater reliance on bilateral contracts tailored to individual states’ priorities, Tezak said.

Kavulla acknowledged the difficulty of achieving consensus on carbon pricing, saying that informed NRG’s proposal for FERC-approved, state-run clean energy procurements, “not unlike what the Southwest Power Pool has for resource adequacy, or what exists in the Western Energy Imbalance Market.”

He said a return to bilateral contracts could lead to higher prices because default energy suppliers in restructured states “are not appropriately incentivized to get the best deals. Either they’re affiliates of the people who are generation, number 1, or 2, they’re complete pass-through entities who don’t earn any margin or loss whatsoever on the power they procure.”

Emnett said Exelon, whose nuclear units receive subsidies subject to the MOPR, would support technology-neutral payments for carbon-free generation but that NRG’s proposal is unrealistic. “Instead, we’re trying to work with the states to use the tools that they do have available and avoid the harsh customer impacts of the MOPR,” he said.

Auction Timing

Emnett said Exelon agrees with the Maryland PSC that the capacity auctions should be delayed until 2021 to allow more time for the states to react to the ruling. PJM’s effective reserve margin is above 30%, he said, “so there isn’t a need for new generation at this point.”

Haque said the earliest PJM could run the next capacity auction is December 2020, after receiving an order on its compliance filing, which is due to FERC by March 18. That gives states time to explore their option to abandon the capacity market for the fixed resource requirement (FRR), he said. Delaying the auctions longer could mean default service providers will include a “risk premium” in their bids, increasing prices, Haque said.

Tezak said energy retailers also favor an earlier return to auctions because “they have no ability to forecast what their [capacity] costs are going to be.”

NRG circulated a handout that said customers in FRR markets in Ohio and Virginia have paid up to four times more for capacity than those in the rest of PJM because of reduced economies of scale. Kavulla said FRR also would result in a “re-monopolization” of the power sector that would create barriers for innovative technologies such as demand response and storage.

Changes on Rehearing, Appellate Rulings?

Tezak said her company is advising its institutional investors to exercise “caution” because of the possibility of changes in the rule on rehearing or in the appellate courts.

“There’s probably not a lot of durability to the MOPR order,” she said. “One of the things that we see as a big wild card is whether the position on self-supply, in particular, shifts. That would probably extinguish a lot of the criticism, [though] not all.” (See MOPR Ruling Threatens to Upend Self-supply Model.)

Tezak also noted that FERC has yet to act on rehearing requests on its original June 2018 order that found the existing MOPR unjust and unreasonable. “So, there could be all sorts of cascading legal weirdness that turn up that make assuming that this is as positive for the IPP community as it looks at first blush to be probably less beneficial in reality.”

Chatterjee Defends Order

In a press conference at the NARUC meetings on Tuesday, FERC Chair Neil Chatterjee defended the Dec. 19 order, which he and Commissioner Bernard McNamee supported.

Like Haque, he cited the Monitor Joe Bowring’s support for the ruling. The IMM requested clarification on some points but said the order “defines a clear, consistent and comprehensive approach to the PJM markets and to the role of subsidized resources in the markets.”

Bowring is “someone who’s very well respected in the field. Nobody would question his motivations,” Chatterjee said.

He also expressed skepticism that states will leave PJM. “Let’s see how this shakes out; let’s see how the auctions go; let’s what the impacts on these generators are before anyone makes these kinds of decisions,” he said. “I think when folks do the analysis and see what the benefits of participation in organized markets [are], I would think a state would have to think twice before losing the benefits that their consumers enjoy. …

“I know there’s a lot of focus … on tension between the states and federal regulators, but there are also a number of areas where we are continually and actively cooperating in,” Chatterjee added, listing cybersecurity, innovation, “the energy transition” and the Public Utility Regulatory Policies Act as among the topics he has discussed with state regulators at the conference.

February 12, 2020

Traders Respond to IRC on Risk Management Efforts

By Christen Smith

The financial trading group behind a request to update decade-old RTO credit policies fired back Monday against claims that its filing proposes a “one-size-fits-all solution” that would trample on stakeholder processes.

The Energy Trading Institute (ETI) said stalling “centralized discussion and information sharing of best practices” would waste a “golden opportunity” for each RTO to learn from the experienced risk management professionals their organizations lack.

“The current efforts/discussions underway at the ISOs and RTOs to address credit practices do not go far enough or are not exploring the appropriate corrective measures to address credit risk and market participant exposure in today’s market dynamics,” the group said in its answer filed Monday (AD20-6). “The ISOs/RTOs and industry undoubtedly could benefit from a discussion on well-established industry best practices for credit and risk management.”

The ISO/RTO Council urged RTO Council Balks at Credit Rulemaking.)

IRC Risk Management — GreenHat Energy, which ran up huge losses in PJM’s FTR market, listed its address as a UPS store between a nail salon and a RiteAid. | *Google*

The IRC also challenged ETI’s premise that the rules should be standardized, saying “the underlying markets to which the credit policies apply are not standardized.”

ETI asked the commission on Dec. 16 to schedule a technical conference by March 30 and convene a rulemaking to update FERC Order 741, its 2010 rulemaking on credit and risk management in the RTO/ISO markets.

The Institute said GreenHat Energy’s default on its 890 million-MWh financial transmission rights portfolio in PJM and RTOs’ slow adoption of credit policies to manage risks means the time is ripe for collaboration. In its answer, ETI points out that its rulemaking proposes “to explore common risk principles and risk management tools, such as the use of initial and variation margin and know-your-customer processes.”

“The technical conference and rulemaking process will allow parties to discuss the different methods to manage risk, the practical application of such methods and the tools available for implementation, which in turn will inform the ISOs’/RTOs’ efforts to protect their markets and their market participants,” ETI said. “This clearly is not a one-size-fits-all solution; it would allow the ISOs/RTOs and their stakeholders to work within a best-practices framework to implement credit and risk management policies and procedures appropriately suited for their respective markets.”

ETI also challenged IRC’s contention that RTOs have made significant progress on addressing credit reforms on their own. It said all regions save PJM still expect market participants to self-report rule violations. SPP lacks basic know-your-customer processes, while MISO could benefit from a deeper exploration of the practice, ETI said. The group did commend PJM, however, for hiring outside contractors to help design a margining model.

The Institute said FERC’s regulatory oversight means it must safeguard open and competitive markets from lackluster credit policies implemented by RTOs.

“The GreenHat default in PJM’s FTR market served as a significant eye-opener for the ISOs/RTOs and their stakeholders,” ETI said. “While it has been nearly two years since the default … the subsequent actions taken by the ISOs/RTOs to assess and improve their respective credit policies appear to be uneven in terms of whether they are addressing credit and to what degree, and include objectives that may not align with industry best practices for risk management.”

February 12, 2020

MISO to Debut Online Queue Requests

By Amanda Durish Cook

MISO is taking measures to speed up the initial step in its generator interconnection process through a more efficient application process.

Speaking during a Feb. 11 conference call, Jesse Phillips, MISO manager of resource utilization project management, said the RTO will revise its Tariff to convert its generator interconnection queue application from a print-and-send form to an instant, online submission. The new procedure will go live in April.

Prospective interconnection customers will also be able to upload documents and models with their application. MISO plans to hold a March 9 training session with stakeholders on the new tool. In the meantime, MISO is as k ing for stakeholders’ written reactions on the new process through Feb. 26.

The RTO has pledged to confirm receipt of online applications within five business days and notify customers of incomplete applications within 15 days. For complete applications, the new process will take about 30 business days.

MISO Online Queue Requests — MISO online GIP application | *MISO*

The online interconnection request is aimed at streamlining the queue process to save time.

MISO’s interconnection queue peaked at a proposed 101 GW worth of projects in 2019, but the volume has since declined to about 80 GW. Solar projects have become the dominant resource type in the queue at just over 46 GW, more than double proposed wind projects at 19 GW.

“The bottom line is that we’re catching up on the queue,” MISO Executive Director of Resource Planning Patrick Brown said at a Feb. 10 Entergy Regional State Committee meeti n g. Brown added that MISO plans to introduce more improvements to accelerate project processing and study.

MISO last year began building models in-house for studies required for the queue’s definitive planning phase. Staff at the time said ending the outsourcing of queue modeling work to third parties cut months of delay from the queue timeline. (See M I SO Makes Second Attempt at More Rigorous Queue.)

February 11, 2020

PJM Operating Committee Briefs: Feb. 6, 2020

VALLEY FORGE, Pa. — PJM under-forecasted the peak hour load on three days in January, staffer Stephanie Monzon told the Operating Committee on Thursday.

Monzon said lower-than-anticipated temperatures on Jan. 5 and 18 spiked load by as much as 5% above estimates. On Jan. 2, load rebounding faster than expected from New Year’s Day meant PJM’s forecast was off by more than 4%. The RTO commits to a 3% margin of error for daily load forecasts.

PJM Operating Committee — Daily peak forecast error in January | *PJM*

TO/TOP Matrix

The OC unanimously agreed to recommend TO/TOP matrix revisions to the Transmission Owners Advisory Committee for endorsement later this month.

The latest version of the matrix cuts about 20 pages of NERC standards that were retired in 2017. The slimmer manual will make the matrix easier for TOs and PJM’s auditors to use, staff said.

Manual 40: Training and Certification

The committee unanimously endorsed revisions to Manual 40: Training and Certification stemming from a periodic review. Various sections, including 2.3.4, 3.3 and 3.4, were updated to reflect correct operator/dispatch terminology and temporary waiver language for training and certification compliance. Staff also removed Section 4: PJM Operator Training entirely.

– Christen Smith