ERCOT on Wednesday asked Texas regulators to dismiss a complaint by energy broker Aspire Commodities seeking to make generators repay the market an estimated $18 million as a result of a May pricing error.
The grid operator said the state’s Public Utility Commission should dismiss Aspire’s complaint because the broker failed to complete its alternative dispute resolution (ADR) procedure and also suffered no direct injury from the error.
ERCOT also asked the commission to deny Aspire’s request for a price correction for the May 30 event because its protocols don’t allow for price corrections “when a market solution is attributable to an external data error caused by an ERCOT market participant.”
“Requiring ERCOT to conduct price corrections in cases of external data errors would be imprudent, as this practice would lead to frequent price corrections and result in increased price uncertainty and market instability,” the grid operator said.
ERCOT noted that state agency rules require that a complaint made against it include a statement as to whether “the complainant has used the applicable ERCOT procedures for challenging or modifying the … conduct or decision.”
“Aspire fails to identify any provision … to excuse its failure to use the ADR process,” the grid operator said.
During a June meeting of the ERCOT Board of Directors, Vice President of Commercial Operations Kenan Ögelman said the event briefly resulted in $9,000/MWh prices when the security-constrained economic dispatch system received bad telemetry data. (See “Telemetry Data Blamed for Market Event,” ERCOT Board of Directors Briefs: June 11, 2019.)
He said the data indicated about 5,000 MW of resources wanted to move down during an interval. When the market didn’t respond quickly enough, the SCED engine used regulation-up to get the ramp it thought it needed. When energy prices hit their $9,000/MWh maximum, ERCOT operators reran SCED and corrected the data, but not before settlement prices reached as high as $1,500/MWh in some load zones for one 15-minute interval.
Ögelman said during the board meeting that staff would look into strengthening telemetry data and work with stakeholders to evaluate alternatives.
ERCOT declined to comment on staff’s work, saying it would not comment beyond its filing.
Adam Sinn, Aspire Commodities | Mays Business School/Texas A&M
In its complaint to the PUC, Aspire said it estimates ERCOT’s “fictitious price spike” cost the market almost $18.4 million. Aspire said it wasn’t a direct counterparty to the market, but it had exposure through its forward positions in the Intercontinental Exchange (49673).
“We simply cannot understand how anybody associated with the market cannot argue that repricing is absolutely required for this interval,” Aspire President Adam Sinn said.
“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the board in June.
Calpine admitted last week one of its IT employees had caused the error, and the company said it has asked ERCOT to reprice the 15-minute interval.
Avangrid reported second-quarter earnings of $110 million ($0.36/share), up slightly from $107 million ($0.35/share) in the same period in 2018, though first half net income was down about 7% from the first six months of last year.
A subsidiary of Spain-based Iberdrola, Avangrid owns United Illuminating, Connecticut Natural Gas, Central Maine Power, New York State Electric and Gas, and Rochester Gas & Electric.
In an analyst call on Wednesday, CEO James P. Torgerson said the company was “disappointed with the continued lack of wind resource that impacted most of our fleet.” (See Avangrid Earnings Drop on Weak Wind.)
The firm’s New England Clean Energy Connect transmission project is “on track,” he said, adding that the Massachusetts Department of Public Utilities recently approved 20-year contracts between Hydro-Québec and utilities Eversource Energy, National Grid and Unitil.
| Avangrid
In New York, NYSEG and RG&E filed their electric and gas rate cases in May for new rates effective in the second quarter of 2020, which includes requests for recovery of resilience investments and deferral of staging costs for storms. NYSEG was among utilities penalized last month by the New York Public Service Commission for safety and reliability issues. (See NYPSC Dings Utilities for 2018 Reliability, Safety.)
Central Maine Power is currently subject to hearings by the Maine Public Utilities Commission regarding the mismanaged introduction of a new billing system last year that saw some customers’ bills double or triple.
Torgerson said that the commission outsourced a forensic audit of the billing system and “concluded that it was billing things correctly.” He said the high bills were in part a reflection of a very cold winter. But for some customers, the company also failed to issue bills for a couple of months. In other cases, unpaid bills from one month got added to a second month.
“The issue really is … the fact that we didn’t provide the customer service that our customers expect,” he said. “Every individual has different circumstances, and we need to go through every one of those and work with the customer to make sure they understand what occurred … so that they can have confidence that actually their bill was correct.”
Commission staff are recommending a 75- to 100-basis-point reduction in CMP’s return on equity for one year until the company demonstrates that it has improved customer service “and gotten things back on track,” Torgerson said.
A Second Wind
Vineyard Wind, the company’s joint venture with Copenhagen Infrastructure Partners, had a rough start to the summer when the U.S. Bureau of Ocean Energy Management in June declined to issue its final environmental impact statement (EIS) on the 1,200-MW offshore wind project. This month, the Massachusetts town of Edgartown’s Conservation Commission denied a permit for the project’s transmission cables to come ashore on Martha’s Vineyard. (See “Land Ho is Wind Woe,” New England Officials Speak on Grid Transformation.)
On Tuesday, however, the Massachusetts legislature authorized the Barnstable Town Council to grant an easement at Covell’s Beach for Vineyard Wind to land its cables and build an interconnection to the New England grid.
The Massachusetts legislature on July 23 authorized the Barnstable Town Council to grant an easement at Covell’s Beach for Vineyard Wind to land offshore wind transmission cables and build an interconnection to the New England grid. | Vinyard Wind
On BOEM’s delay, Torgerson said, “We are confident that the pending reviews can be concluded shortly, and the final EIS released soon after. … We’re still working with them and pretty confident that we can get something done by the end of August, and that will keep us on track with our time frame.
“It would be challenging to move forward if we don’t get the final EIS in the next four to six weeks,” he said. “That having been said, it doesn’t mean the project is dead by any stretch. It just means we’re going to have to reconfigure things or do something differently.”
Laura Beane, head of Avangrid Renewables, said, “Right now, we are absolutely focused on getting to resolution under the current configuration and maintaining the current schedule. If we’re required to, I think we’ll look at other alternatives, but really our focus remains on maintaining our current schedule and working through these issues.”
In addition, the company said it had purchased the 226-MW Patriot Wind project in Texas upon commercial operation in June and that it has 763 MW of renewables assets under construction and on track to come online by the end of this year. Avangrid also secured a power purchase agreement on its 140-MW La Joya ll wind farm in California.
INDIANAPOLIS — Most state regulators think it is time to begin preparing for a 100% clean energy future, based on discussions at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit.
In real-time voting during a panel Monday, 75% of regulators and industry staffers in the audience said it was time to begin prepping for a 100% clean energy future, with 4% saying the question could wait two to five years, 10% saying not for a while and 11% deeming the preparations not a priority.
Energy consultant Debbie Lew said 100% clean energy is within reach now.
“You can do 100% clean energy today; it just depends on how expensive it will be,” said Lew, who said the expense of synchronous condensers, grid-forming inverters and other power electronics quickly adds up. The effectiveness of a proliferation of four-hour batteries on resource adequacy also has a saturation point, she said.
The question remains, she continued, as to how smart and cost-conscious regulators and utilities are going to be during the transition. More accurate forecasting, price sensitive-demand response and effective curtailments can smooth the changeover, Lew said.
A 100% renewable future can be facilitated by larger regions with faster trading, a varied storage portfolio, demand-side flexibility, better forecasting and intermittent resources sometimes used for ancillary service dispatch, she said. “We tend to think of curtailment of wind or solar PV as a bad or ugly thing, but if we use that in combination with forecasting, we can use that as a reserve product. … It’s a technology that’s available right now.”
Lew said she can’t yet tell if there will be a need for regional energy markets after such a transition, but capacity markets could become more vital as seasonal, on-demand capacity becomes more necessary to cover intermittent resources.
“We’re really good at running energy markets, but is there much of a place for markets with zero-marginal-cost energy?” Lew asked.
Hawaii Public Utilities Commission Chair James Griffin said regulatory changes are a vital component to reaching 100% clean energy goals.
But Xcel Energy Director of Energy and Environmental Policy Jeff Lyng said a regulatory overhaul isn’t necessary to make the transition.
“Utilities have demonstrated that they can innovate and deploy [renewables] at scale,” Lyng said. He added, however, that small rule changes could be appropriate, in addition to the timely approval of pilots and generation projects and a continued focus on emissions control.
Lyng said Xcel worked with climate scientists to develop its 2050 zero-carbon goals, which line up with the target to keep global surface temperatures from rising beyond 2 degrees Celsius.
Griffin said the Hawaiian islands, which are especially susceptible to the risks of climate change, can’t afford to wait on high-tech solutions that will facilitate 100% renewable energy.
“Every time I’m told to slow down, I remind others that the status quo is the problem,” Griffin said.
Clean Air Task Force Executive Director Armond Cohen pushed back on the oft repeated conclusion that an 80% renewable mix is doable now, but a 100% renewable takeover remains out of reach. He said 100% clean energy is not an impossibility — it will just be expensive. Cohen also said he supports bills for 100% clean energy over bills that call for 100% renewable energy.
“I think that if we keep out options open, it’s totally doable,” Cohen said. “It’s going to be a lot of capex run very seldomly. … It gets very expensive very fast.” Cohen said an ideal, albeit wholly unrealistic solution, would be to cover the remaining 20% with zero-marginal-cost storage devices.
Multiple panelists repeated the call for federal-level carbon pricing to prompt more technology investment to facilitate renewable integration.
“Politics is going to be a big part of getting from here to there,” Sustainable FERC Project Director John Moore said.
He also said if he could have his way, the entire Eastern Interconnection would be consolidated into a single RTO to pave the way for renewables; however, he admitted such a scenario is unlikely.
FERC halted PJM’s plan to run its capacity auction next month in a surprise order issued Thursday, just hours after the Markets and Reliability Committee reaffirmed the RTO’s decision to move forward as planned.
The commission refused to “rule prematurely” on PJM’s request for clarification that if it ran the 2022/23 Base Residual Auction using the existing minimum offer price rule (MOPR) — while the revised version awaits approval — that FERC would enforce any new rates prospectively, saving the August auction from being rerun (EL16-49).
PJM argued that if the commission granted its request, filed in April, the “critical” confidence in auction results necessary for market participants would be preserved. (See PJM to Hold Capacity Auction in August.) The RTO’s Board of Managers also maintained that the rejected MOPR only impacts a small number of resources, meaning an updated commission ruling on the matter wouldn’t change prices too much within the current environment.
“PJM asserts that, here, refunds would not be warranted because the basis of the underlying complaint is that the relevant rates are too low, not too high, which is a required finding for refunds under Section 206 of the Federal Power Act,” FERC summarized in its ruling.
FERC advised PJM to cancel its August capacity auction. | PJM
PJM delayed the BRA once already after FERC ruled in June 2018 that the RTO’s MOPR was unjust and unreasonable because it didn’t address price suppression arising from state subsidies for renewable and nuclear power. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail.
PJM entities including American Municipal Power, Dominion Energy, Exelon, EDP Renewables, FirstEnergy and its subsidiaries, Talen Energy and its subsidiaries, the Electric Power Supply Association, Direct Energy, the American Wind Energy Association, the Solar Council and the Illinois attorney general’s office all filed in support of the RTO’s decision to run the auction in August, agreeing that further delays have proved detrimental to the market and interfered with the necessary forward pricing signals that sellers need.
The entities also agreed that should FERC reject the clarification, PJM should delay the auction because running it without the guarantee from the commission would “undermine the very certainty the BRAs are designed to provide.”
The Illinois AG’s office further argued that if FERC granted the request, it should also “address flaws in the existing capacity market rules that facilitate market power abuse by requiring PJM to release generator bidding data and to replace the algorithm that PJM uses to increase clearing prices above the highest bid.”
In the end, FERC advised PJM to cancel the auction until it provides a suitable replacement rate, though it’s unclear when that decision may come. ClearView Energy Partners speculates that if the commission doesn’t provide a ruling on the MOPR before November, PJM won’t have enough time to implement Tariff changes in time to hold the 2022/23 auction in April.
“We recognize the importance of sending price signals sufficiently in advance of delivery to allow for resource investment decisions,” FERC said. “However, we believe that in the circumstances presented here, on balance, delaying the auction until the commission establishes a replacement rate will provide greater certainty to the market than conducting the auction under the existing rules.”
PJM spokesperson Jeff Shields said on Thursday that the RTO will follow the commission’s guidance.
“In its ruling today directing PJM Interconnection to postpone its capacity auction, the Federal Energy Regulatory Commission recognized that confidence in the auction and its results is vitally important to all of our stakeholders and the integrity of the market,” Shields said in an emailed statement. “We look forward to additional guidance from FERC on the design of PJM’s capacity market.”
Commissioners Debate
While concurring with the order, Commissioner Richard Glick issued a scathing indictment of FERC’s inaction on PJM’s proposed changes, saying the RTO and its 65 million customers deserve better.
“One year later, Commissioner [Cheryl] LaFleur’s description of the June 2018 order as ‘regulatory hubris’ seems more apt than ever after the commission has shown an absence of leadership that has caused us to drift rudderless into the position in which we find ourselves today,” he said.
As the lone dissenter on the June 2018 order, Glick said he agrees with his colleagues that running the auction next month provides only a “short-term palliative effect … that would be outweighed by the long-term uncertainty” of allowing capacity commitments under Tariff previsions found unjust and unreasonable, leaving PJM vulnerable to years of litigation.
But he blamed FERC for putting PJM in the situation in the first place.
“If ever the Pottery Barn Rule applied to a regulatory proceeding, it is this one,” he said, referencing what Secretary of State Colin Powell told President George W. Bush in the lead-up to the War in Iraq: “You break it, you own it.”
LaFleur took her previous criticisms a step further in her own statement.
“Given the passage of time, the uncertainty created by the commission might better be labeled an act of regulatory malpractice,” she said. “The commission, whatever concerns it has with the PJM capacity market, should not have put PJM, the states and customers served by its markets, and its stakeholders in this position.”
Commissioner Bernard McNamee — who joined FERC after the June 2018 order — called Glick’s usage of the Pottery Barn Rule “misleading.”
“To suggest the commission is the source of the problems presently facing PJM is to ignore nearly a decade of proceedings attempting to address the interaction between competitive markets and out-of-market subsidies,” he said. “More importantly, such a statement only makes sense if one ignores the impetus behind PJM’s original filing in Docket No. ER18-1314, which was PJM’s desire to address issues arising from state out-of-market support for generation resources in its footprint.”
Glick argued that McNamee “misses the point.”
“It was the commission — not PJM — that made the finding that has prevented PJM from running its capacity auction,” he said. “And it has been the commission — not any party to this proceeding — that has failed to act, even though we are now more than six months past the date promised in the June 2018 order. Meanwhile, neither the facts nor the law have changed, and the time for deliberation has long passed. The commission is now fully responsible for the damage done to date and whatever comes next.”
Chairman Neil Chatterjee did not weigh in on the controversy.
The federal judge overseeing PG&E Corp.’s Chapter 11 bankruptcy granted a motion by the California Public Utilities Commission on Wednesday to hold off on deciding whether to terminate the utility’s exclusivity period while it attempts to create a process for choosing among the several competing plans.
A group of unsecured bondholders on Tuesday had requested that Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California, terminate PG&E’s exclusivity — the time it has to offer a reorganization plan without the judge having to weigh competing proposals — in light of the enactment of Assembly Bill 1054 earlier this month.
“The debtors’ legislative requirement was addressed on July 12,” the ad hoc committee of senior unsecured noteholders told Montali in court papers. PG&E would have to emerge from bankruptcy by June 30, 2020, to take advantage of the measure’s provisions. The unsecured bondholders — a group of 25 banks, mutual funds and others — say that makes getting PG&E out of bankruptcy more urgent. They encouraged the judge to accept their proposal, which would pay off or refinance their notes.
“With the recent inception of the 2019 wildfire season and the impending June 30, 2020, deadline, it is now time to move these cases as quickly as possible towards emergence,” the bondholders’ lawyers wrote. “Unfortunately, to date the debtors have almost entirely failed to do so” and instead have sought legislative help to securitize equity in the company to protect shareholders and raise capital.
But on Wednesday, Alan Kornberg, an attorney representing the California PUC, told Montali that the commission is “keenly interested” in the bondholders’ plan, as well as a competing plan by insurers with more than $20 billion in unsecured claims against PG&E for payments made to wildfire victims.
Any exit plan would need to be approved by the commission, and it is “vital” that be done by the June 2020 deadline, Kornberg said. Both the commission and Newsom want a competitive process, and he acknowledged the request was an unusual one, “but we cannot permit competition to turn into chaos.” He asked Montali to give the commission and PG&E two weeks to work out a process and timeline for evaluating the different plans.
The bondholders’ lawyer, Michael Stamer, objected to the proposed delay, calling it “an unprecedented, undocumented road to nowhere.”
“Everyone is in violent agreement that every day counts, and two weeks is a long time,” Stamer said.
This did not persuade Montali, however. He noted that he had only received the bondholders’ 33-page plan Tuesday morning and finished going through it at midnight, indicating he was not prepared to rule on the exclusivity motion that day anyway.
Montali also noted that the bondholders were not the only ones seeking to terminate exclusivity. “The one thing we don’t need, more than anything, is a lot of lawyers writing a lot of briefings that don’t need to be written, and one judge reading all the briefs that don’t need to be read,” he said.
He set Aug. 9 to hear the results of the PUC and PG&E’s discussions, and Aug. 13 to rehear the bondholders’ exclusivity motion. A hearing to consider the insurers’ exclusivity motion was already set for that day.
Montali has wide latitude to consider the competing plans. He ended exclusivity early during PG&E’s prior bankruptcy case in the early 2000s, allowing the PUC to offer its own reorganization plan.
The judge warned PG&E’s lawyers in May he could revoke exclusivity if he saw fit. “This judge has never been a fan of exclusivity but is a fan of practical consequences,” Montali said. He explained at the time he did not want to deal with competing reorganization plans that might be unworkable.
“The proposal would hold PG&E accountable for wildfire liability, maintain price stability for PG&E’s ratepayers [and] contribute billions of dollars to California’s wildfire recovery fund,” the insurers said in a news release.
Their plan provides for payment of victims’ wildfire claims through a settlement trust, with a $5 billion contribution to the state’s recovery fund for future wildfire claims that was part of AB 1054.
Subrogation claimants would be paid 90% of their claims with shares in the company, “thereby reducing the amount of new money necessary for PG&E to exit Chapter 11,” they said.
Like the unsecured bondholders, the unsecured insurers stand to lose in the PG&E bankruptcy because they would have to get in line behind secured creditors whose claims will be paid first.
PG&E cited billions of dollars in wildfire liability when it filed for bankruptcy in January. The company has been blamed for starting major fires in 2015, 2017 and 2018, including last November’s Camp Fire, the deadliest in state history.
INDIANAPOLIS — Regulators should preserve the multiple incentives currently offered to transmission developers — and possibly consider creating new ones, two former FERC commissioners said Monday.
Speaking on a panel at the National Association of Regulatory Utility Commissioners’ 2019 Summer Policy Summit, former Commissioners Suedeen Kelly and Philip Moeller expressed support for incentives granted on a case-by-case basis, but they said the time may be ripe to create new categories of adders to encourage development.
Entitled “(Trans)Mission Critical? Reconsidering FERC’s Electric Transmission Incentives,” the panel focused on the commission’s recent Notice of Inquiry into transmission rate incentives and the ensuing comments from transmission owners, load, utilities, regulators and trade groups. (See Tx Incentives NOI Brings Calls for Broader Reforms.)
Virginia State Corporation Commissioner Judith Jagdmann, the panel moderator, asked if regulators view the incentives as a “fist on the scale or a thumb on the scale.”
Kelly, now a partner with the law firm Jenner & Block, said the incentives were designed to be a thumb. “It was clear from the beginning that you couldn’t incent something where rates were no longer just and reasonable,” she said of FERC’s philosophy behind creating incentives.
She said there wasn’t much common ground on specific, standardized incentives as she and her fellow commissioners were developing Order 697, issued in 2006.
“We agreed that incentives were necessary. We didn’t agree on what certain projects should be incented and not others. We couldn’t agree on the particulars. If you look at the rule, it reflects that. … We put the burden on the developer when they came to us” with an application, Kelly said.
Moeller, now executive vice president at Edison Electric Institute, said the incentive applications that started to come in after the 2006 rulemaking were generally on par with the commission’s expectations.
“I actually dissented from many incentive requests, and through my dissent, I was trying to create my own incentive policy, Kelly recounted. “Some of my dissents were an inchoate wanting to know more about the challenges and the benefits.”
Save the RTO Adder
RTO adders are still an important piece of encouraging transmission investment, Kelly said, especially in the West and Southeast, where participation in organized markets is less common.
“RTO membership was clearly something that the commission was trying to encourage. I think it’s taken for granted now, but 15, 20 years ago, it was really something different,” Moeller said.
However, the lone panelist without a regulator background argued for eventual phaseout of the RTO adder.
“We were concerned that the RTO incentive packages were too easily granted. It was becoming routine,” American Public Power Association General Counsel Delia Patterson said.
She said FERC has struck more of a balance between consumers and investors since its 2012 policy statement on transmission incentives, which was crafted to create a more rigorous standard for requesting incentives. Still, she said RTO membership is too commonplace to warrant the incentive.
But Moeller said it remains fair, also adding that between 2006 and 2012, transmission buildout was appropriately robust.
“I thought we went too far in terms of cutting things back in 2012. But I agree that transmission investment is necessary. … It’s so doggone hard to build for the most part,” Moeller said.
Risky Business
Kelly agreed that transmission construction is a risky venture: “It’s a very difficult decision in a public company to put up capital and make a transmission investment.”
During her time on the New Mexico Public Regulation Commission, Kelly said, she agonized the most over transmission siting decisions. “Nobody wants to put a transmission line in their neighbor’s farm or yard or along the edge of a national forest. It’s not a pleasant job.”
Asked whether they would prefer a case-by-case review or standardized incentive approval, the former commissioners still prefer the former — although Kelly thinks “slam dunk” incentives should be made into a standard.
Patterson concurred on the need for case-by-case review. “I trust my daughter, Emily, to make sure to pack a balanced lunch, but it’s up to me to verify that,” she said to audience laughter.
Moeller said FERC might consider additional incentives for transmission systems that are reinforced against intensifying climate change.
“What’s the value of electricity when you don’t have it? Many, many, many times more.”
PHILADELPHIA — PJM’s anticipated increase in renewables over the next decade won’t succeed without the support of more reliable fossil fuels and nuclear reactors, industry analysts said last week.
The predictions came during presentations at the Mid-Atlantic Renewable Energy Summit hosted at The Bellevue Hotel on Thursday, where experts from all corners of the energy sector gathered to discuss the future of PJM’s resource mix and the anticipated shift from policy-based investment to more economic drivers.
“The increase we’ve seen so far is nothing compared to the increase that looks like it’s coming at us in the future,” said Stu Bresler, PJM’s senior vice president of markets and planning. “We ain’t seen nothing yet.”
Data from the National Renewable Energy Laboratory and U.S. Energy Information Administration show PJM’s installed wind and solar capacity currently exceeds 11,000 MW — the majority of which joined the grid during the last 10 years. ICF Resources said 70% of the renewables scheduled for connection through 2030 will come online in New Jersey, Maryland and D.C., where elected officials have set aggressive clean energy targets and other policies to reduce the effects of climate change.
The Garden State alone will install 3,500 MW of offshore wind power over the next decade. It announced last month that Denmark-based Ørsted will construct the first 1,100 MW 15 miles off the coast of Atlantic City beginning in the early 2020s. (See Ørsted Wins Record Offshore Wind Bid in NJ.)
“We are living amidst a revolution right now, a revolution in terms of technology change, a revolution of climate change … and finally a revolution of electricity decarbonization,” said Stuart Caplan, partner at Troutman Sanders. “Beware of what you ask for … treat fossil fuels not as an enemy of renewables. The pendulums can swing quickly.”
Caplan said that the intermittency of current renewable technologies means fossil fuels will continue to have a place in PJM in order to “preserve balance.” In March, the Independent Market Monitor said natural gas-fired energy output exceeded coal in PJM’s market last year for the first time ever. (See Monitor Says PJM’s Capacity Market not Competitive.) Economists on Thursday said coal retirements in favor of more efficient combined cycle units will continue — but the cheap price will not, providing a valuable opening for nuclear energy in the market.
D.C. Public Service Commissioner Greer Gillis said reaching the district’s goal of 100% renewable energy and 50% carbon emissions reduction by 2032 will be challenging, but possible. D.C. set the targets in December 2018, making it the most ambitious clean energy policy enacted nationwide, she said.
“We are very optimistic,” she said. “But I think one thing we are all concerned about is the pricing.”
Judah Rose, executive director of energy markets for ICF, said zero-emission credits and renewable energy credits will likely increase between 2022 and 2025, temporarily spiking energy costs. Post 2025, he said, the combination of carbon pricing and states meeting their renewable portfolio standard mandates will cause renewable energy prices to fall.
ICF’s market forecast assumes the implementation of a national CO2 program with a price of $4/ton, though Rose said the “real action” could happen through the Regional Greenhouse Gas Initiative, where policy in the participating states could create “big upward pressure” on the price of carbon. It wouldn’t wipe out gas development entirely, however.
“We still see huge economics for combined cycle units … mostly located in western PJM,” he said. “For coal and nuclear, we see unfavorable economics for both areas. In the long run, however, as gas prices increase and we have some kind of carbon price, we see nuclear becoming economic.”
New Jersey and Illinois have already enacted ZEC programs for their own nuclear plants, despite criticism that the subsidies distort prices in the wholesale electricity market. Ohio legislators also appear close to consensus on a bill to rescue FirstEnergy Solutions’ reactors at Davis-Besse and Perry nuclear plants near Lake Erie. (See Ohio Senate Clears Nuke Rescue.) Supporters of the programs argue PJM’s existing market structure doesn’t value the carbon-free reliability of nuclear energy and that allowing the units to retire would not only be irreversible, but foolish.
“Nuclear has to be part of the equation,” said Jason Barker, director of wholesale market development for Exelon. “If you take just the carbon output in one year of those three [retiring nuclear] units, it’s equal to all of the wind that’s ever been installed in PJM. It’s undeniable in the short run if we want to reach our societal targets.”
Exelon manages the largest nuclear fleet in the country, including the remaining operating reactor at Three Mile Island near Harrisburg, Pa. The company said in June it will deactivate the unit in September after state legislators stalled on a plan to keep it running via ratepayer subsidies and changes to Pennsylvania’s RPS. (See Nuclear Subsidies Still on the Table in Pennsylvania.)
“Because of the intermittency of current dominating renewables, we need something to pick up when the wind stops blowing and the sun stops shining,” Barker said. “We need to value the flexibility attributes of those units, and that will be what drives LMP.”
“So, if there were border adjustments … it would increase the energy value and therefore decrease the cost of the ZEC, therefore making the MOPR less destructive,” Barker said. “Depending on what this MOPR ruling looks like … the carbon pricing could be a substitute or a type of substitute in the absence of more global policy.”
LOS ANGELES — To open his presentation at Infocast’s California Energy Summit last week, Marty Niles, a veteran lineman and founder of Cantega Technologies, played a clip from the quiz show “Jeopardy!”
The deputy director of the National Security Agency said the No. 1 threat to the U.S. electrical grid came from these climbing rodents, host Alex Trebek said.
“What are squirrels?” a contestant answered correctly.
Niles, whose company makes Greenjacket covers for electrical equipment, then showed a series photos and videos in which birds and animals had become trapped in substations, transformers and conductors, sparking fires and explosions. Greenjacket’s covers could help prevent fires caused by animal damage, Niles said.
“We’re just another tool in the toolbox with regard to the fire suppression effort,” he said.
Niles’ presentation was one of several talks at this year’s summit that focused on the utility-sparked wildfires that have ravaged California in recent years. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
In a panel on wildfire prevention, panelists discussed the need for microgrids to maintain essential services — such as emergency shelters at schools — during incidents in which the main power supply was switched off or damaged.
Craig Lewis, executive director of the nonprofit Clean Coalition, said smaller-scale grids powered by renewable energy are essential, with California facing greater threats from massive fires fueled by climate change.
In the fire-prone Santa Barbara area, he said, electric infrastructure is crucial for pumping water uphill from coastal areas to battle mountain blazes.
“That water is absolutely critical for fighting fires,” he said.
Tim Hade, co-founder and COO of Scale Microgrid Solutions, said California is “on the path to having the most expensive and least reliable electricity in the United States” because of the wildfire threat.
Utilities have been using public safety power shutoffs to prevent their equipment from sparking fires during periods of low humidity and high winds.
With power shut off to entire communities, having microgrids as backup is crucial, Hade and others said. Those who depend on medical devices, for instance, can’t go without electricity.
“We need to reinvent electricity,” Hade said. “That’s the challenge.”
On the same panel, Sumeet Singh, vice president of Pacific Gas and Electric’s community wildfire safety program, said the bankrupt company has been making strides to head off wildfires before they start.
The company is widely blamed for causing the Camp Fire, which burned much of the town of Paradise in November, killing 85 people. PG&E equipment also sparked devastating wildfires in Northern California’s wine country in 2017 and in the Sierra Nevada foothills in 2015, the California Department of Forestry and Fire Protection has said.
The company recently issued a press release outlining the accomplishments of the program Singh heads. They included visual inspections of 96% of about 50,000 transmission structures in high fire-risk areas, the utility said. The company also said it had inspected 222 substations and nearly all its 700,000 distribution poles in high-risk fire areas.
PG&E has installed 430 weather stations since 2018, including 231 so far this year, it said.
In Paradise, PG&E is undergrounding new power lines where it makes most sense, Singh said. It’s also replacing wooden poles with composite structures. During the fast-moving Camp Fire, wooden poles toppled, blocking escape routes for some who died.
“I wish we could say undergrounding is a panacea,” Singh said. But it’s costly and time consuming, and while 1 mile of conductor is being undergrounded, many other miles of line remain at risk.
Another panelist, Diane Moss, founder and director of the Renewables 100 Policy Institute, said her friends from Germany were amazed to see overhead power lines in California that “reminded them of Africa.” Germany undergrounded most of its lines after World War II, she said.
“Are we going to have to wait to do that?” Moss asked.
Abe Powell, chairman of the Montecito Fire Protection District Board, said he understood undergrounding 200 miles of line in Paradise would cost about $1 billion. Montecito, near Santa Barbara, was ravaged by the Thomas Fire in late 2017 and ensuing mudslides in early 2018. The death toll was 23. Southern California Edison has admitted at least partial responsibility. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
Powell, however, questioned whether undergrounding lines for one community is the best use of $1 billion.
“We haven’t thought this through all the way,” he said.
WASHINGTON — FERC on Thursday adopted two new rules intended to reduce paperwork for electricity sellers with market-based rate authority (MBRA), acting on a proposal issued more than three years ago (Order 860, RM16-17).
Currently, sellers are required to describe the activities of all their upstream owners, often requiring them to submit multiple amendments to their filings. Once the new rule goes into effect on Oct. 1, 2020, sellers will only need to identify their “ultimate” upstream affiliate — the furthest upstream owner.
Sellers will also no longer be required to report assets — such as generators and long-term power purchase agreements — owned by its affiliates with MBRA. They will also no longer have to submit corporate organizational charts. They will, however, be required to report assets owned by affiliates without MBRA, as these are relevant to the seller’s market power analysis, the commission said.
FERC will collect all seller information through a relational database to be created by the order.
“The relational database construct modernizes the commission’s data collection processes, eliminates duplications and renders information collected through its market-based rate program usable and accessible for the commission,” FERC said.
Types of market-based rate authority filings | FERC
Connected Entity Info Tossed
Under the proposal, sellers would have had to identify all affiliate owners with franchised service areas or MBRA, or that directly own or control generation; transmission; intrastate natural gas transportation, storage or distribution facilities; coal supply sources; or access to transportation of coal supplies.
Collectively known as connected entity information (CEI), this new class of information was panned by market participants in late 2015 and again in response to FERC’s proposed 2016 revision. (See FERC Issues Revised Connected Entity, Data Collection Proposal.)
Speakers at a 2015 technical conference and commenters on the proposal said it would create significant reporting burdens.
On Thursday, FERC declined to adopt the CEI provision, instead opening a new docket (AD19-17) “should the commission wish to consider this again in the future,” staff said.
This move was strongly criticized by Commissioner Richard Glick, who issued a partial dissent. “I’m really having a hard time figuring out how that’s any different from killing the proposal altogether, and that’s what I’m very much troubled by,” he said at the commission’s open meeting Thursday.
“In my opinion, through its actions today, the commission is dropping the ball to the detriment of consumers across the country,” he continued. He called CEI “critical” to preventing market manipulation and the exercise of market power. “What I want to know is, why was this information no longer considered to be necessary, or [do] we simply no longer care about how we’re addressing market manipulation?”
FERC also dropped the proposed requirement that traders of financial transmission rights and virtual products also submit affiliate information, which Glick also criticized.
“Virtual/FTR participants are very active in RTO/ISO markets, and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources,” Glick said in his dissent. “It may, therefore, be surprising that the commission collects only limited information about virtual/FTR participants and often cannot paint a complete picture of their relationships with other market participants.”
“Without the connected entity reporting requirements contemplated in the [proposal], the commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done,” Glick said. “That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”
“I know that there are some who will construe our decision not to move forward with the connected entities proposal as a lack of commitment to our Enforcement program,” Chairman Neil Chatterjee said before Glick spoke at the meeting. “To anyone with that misconception, let me be clear: Robust enforcement of our orders and regulations is and will remain one of the commission’s most critical objectives.”
Speaking to reporters after the meeting, Chatterjee said, “I respect Commissioner Glick, but I disagree with the point that he made. I think it’s a matter of good governance. We were ready to move forward with a piece of it; we weren’t ready on the connected entities part, so rather than hold up the MBR piece, which has been out there for three years, we moved forward with it.” He also said he didn’t think “it was a fair characterization” to say that opening the new docket ends the process.
The order is “a critical step in our ongoing efforts to modernize and, where possible, streamline the MBR program to ensure that we have the information we need to evaluate market power while not unduly burdening market participants,” Commissioner Cheryl LaFleur said. “I recognize that these reforms do not address all the issues the connected entities proposal would have covered, particularly with respect to financial market participants and traders. I made the pragmatic decision that it was important to move forward on the MBR improvements that have been held up for three years due to being placed in the same [proposal] as the connected entities.”
Commissioner Bernard McNamee did not participate in the ruling.
Screens Eliminated for 4 RTOs
FERC also approved eliminating the requirement for power sellers with MBRA to submit pivotal supplier and wholesale market share screens in PJM, ISO-NE, MISO and NYISO (Order 861, RM19-2). FERC will now presume that the grid operators’ commission-approved monitoring and mitigation rules provide adequate protection against market power abuse.
MBR sellers of capacity in SPP and CAISO, which do not have capacity markets, will still need to submit the screens. The order’s relief also does not apply to any participants in CAISO’s Energy Imbalance Market.
Effective 60 days after its publication in the Federal Register, the order’s relief would begin with MBR sellers scheduled to file their triennial updates for the Northeast region in December 2019 and June 2020, commission staff said.
Sellers filed almost 600 indicative screens over the last three years, according to staff. Once the rule goes into effect, sellers would be relieved of submitting more than half of those screens, they said.
FERC clarified certain details about its initial proposal, issued last December, but it did not decline to adopt or alter any of its provisions. (See FERC Proposes Market Screen Exemptions.) Though paired with RM16-17 for discussion at Thursday’s open meeting, it received little mention in comparison.
Rehearing Denied on Interlocking Directors
In a third ruling, the commission denied rehearing but made one clarification on its February order updating its regulations on commission authorization of interlocking positions between public utilities and financial companies. (Order 856-A, RM18-15-001). The revised rule provides an exemption for some applicants for interlocking positions between utilities and companies that underwrite public utility securities. (See “Other Rules,” ‘Boring Good’ Rulemaking Seeks to Clean up Order 845.)
The commission denied El Paso Electric’s rehearing request that FERC grant equal treatment to all interlocks authorized under section 45 of its regulations.
“The commission has recognized a difference between holding interlocks among two or more commonly owned or controlled public utilities, and holding an interlock between, for example, a public utility and an electrical equipment supplier,” FERC said. “Interlocks that fall under section 45.2 and are not between two or more commonly owned or controlled public utilities (and therefore are outside the scope of section 45.9a) are reviewed by the commission so that the commission can be sure that the ‘evils to be eliminated by the enactment of [Federal Power Act] Section 305b’ are not present. By contrast, for interlocks that fall under section 45.9a’s automatic authorization, the commission has found that the evils to be eliminated by the enactment of Federal Power Act Section 305b are not present because the potential for abuse would be unlikely to result from such interlocks.”
The commission did grant a clarification on another question raised by EPE, saying that “if, as a result of the change in FPA Section 305b(2) in 1999 and the corresponding changes to section 45.2 of the commission’s regulations made by Order No. 856, an individual no longer holds an interlock that requires commission authorization, that individual no longer needs to adhere to the requirements of [sections] 45 and 46 of the commission’s regulations governing commission approval of such interlocks.”
STOWE, Vt. — Mary Bimonte of Eversource Energy on July 16 presented a joint meeting of the New England Power Pool Reliability and Transmission committees with an overview of the regional network service (RNS) rates that became effective June 1.
Bimonte, a member of the Participating Transmission Owners Administrative Committee, showed the RNS rate increased $1.51/kW-year from last year to $111.94/kW-year, with the region’s aggregate annual transmission revenue requirement (ATRR) rising $41.3 million to nearly $2.19 billion.
Eversource subsidiaries Public Service Company of New Hampshire, NSTAR West and NSTAR East accounted for much of the ATRR increase, along with Vermont Transco and Maine Electric Power.
During a presentation of the five-year RNS rate forecast, Bimonte noted this year’s increase was 67 cents/kW-year short of projections made last year for 2019.
A summary of the RNS five-year forecast from 2020 to 2023 | ISO-NE
Modifying Interconnection Procedures
ISO-NE Director of Transmission Strategy and Services Al McBride led a discussion of proposed modifications to interconnection procedures — specifically, Planning Procedure No. 10 sections 7.7 and 7.8 — to clarify adjustments to interconnection capability following partial market exits.
According to the RTO’s market procedures, “permanent and retirement delist bids can be submitted for all or just a portion of a resource’s capacity. A partial delist bid allows a resource to remove the portion of its megawatts it cannot deliver from all ISO-NE markets or only the capacity market, depending on the type of delist bid submitted.”
“When a partial retirement delist bid clears in the Forward Capacity Auction, the resource remains active and its interconnection rights are reduced to the appropriate megawatt level,” according to the RTO. “When a partial permanent delist bid clears in the FCA, the qualified capacity value for the resource is reduced.”
In February, the NEPOOL Participants Committee approved the general changes, which include methodologies to update the levels of interconnection service available for generators (and external elective transmission upgrades) after the clearing of a retirement delist bid, permanent delist bid or substitution auction demand bid in the Forward Capacity Market.
The RC and TC will alternately discuss the specific proposed revisions ahead of a planned vote by the PC in November, with a tentative effective date of January 2020.
During the previous discussions, stakeholders identified circumstances where the winter capability of their generating facilities after a partial market exit may not be correctly calculated by the formulas currently contained in PP10, McBride said.
The RTO will propose a new section of the Tariff to capture the rules associated with the establishment and relinquishment of interconnection service amounts and plans to present the proposed revisions at the Aug. 21 TC meeting.
Operating Procedure Revisions
The RC voted to recommend that the PC support revisions to a handful of ISO-NE operating procedures slated to become effective Aug. 2, including:
Altering OP-24 to describe the confidential Appendix C as a list of transmission facilities for which transmission owners are required to report protection settings, characteristics, failures or degradation. RTO staffer Jerry Elliott presented proposed revisions reflecting that Appendix C previously included a diagram, but now includes a list. The proposed changes to OP-24 are conforming changes.
Revising OP–12 (Voltage and Reactive Control) and OP-12D (Voltage Schedule Annual Transmittal Form) to clarify local control center actions for providing voltage schedules to generators.
Revising OP-5 (Resource Maintenance and Outage Scheduling) to indicate that outage requests for import capacity resources are for notification purposes only. The motion passed with six opposed (two from the Generation Sector, two from the Supplier Sector and two from the Alternative Resource Sector) and three abstentions (one Generation Sector, one Supplier Sector and one Alternative Resource Sector).
Future Vote on OP-14E Revision
Elliott presented proposed revisions to OP-14E to incorporate energy storage as a type of asset-related demand that can be selected on ISO-NE’s form NX-12E.
The RC is scheduled to vote on the revisions at its Aug. 20 meeting, and the RTO is seeking a vote by the PC at its Sept. 13 meeting.
The changes include correcting terms defined in section I.2.2 of the Tariff or ISO-NE manuals, in addition to replacing the term “nominated consumption level” with the defined term “nominated consumption limit.”
The RTO also notified the RC of revisions to OP-10 Appendix A to update the contact information for the U.S. Department of Energy in cases of reporting major system disturbance, outage or incident. The revisions took effect immediately upon the notification.
Reactive Capability Auditing Tariff Changes
The RC voted to recommend PC support for proposed revisions to section I.2.2 of the Tariff to incorporate definitions for interconnection reliability operating limit (IROL) and system operating limit (SOL).
ISO-NE lead operations analyst Kory Haag said the revisions incorporate four new defined terms in the Tariff: reactive capability audit, reactive resource, IROL and SOL.
The meeting focused on IROL and SOL, which will now be defined as the meaning specified in the glossary of terms used in NERC reliability standards.
NERC defines IROL as “a system operating limit that, if violated, could lead to instability, uncontrolled separation or cascading outages that adversely impact the reliability of the bulk electric system.”
It defines SOL as “the value … that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria.”
The RC requested an Oct. 1 effective date for the definitions, following a vote by the PC in August.
Eversource Substation Upgrades
The RC voted to recommend that ISO-NE determine that three proposed substation upgrades by Eversource would not adversely affect the stability, reliability or operating characteristics of nearby transmission facilities.
Eversource crews work to restore power following a Jan. 20 ice storm in Connecticut. | Eversource Energy
Upgrades to the Andrew Square and Dewar Street substations in South Boston would entail the installation of two independent current differential high-speed protection groups on the K Street-to-Andrew Square 115-kV cables and the Dewar 115-kV cables to provide the selectivity to differentiate between a line fault and a transformer fault. The work will provide protection system fault clearing selectivity and design in compliance with Northeast Power Coordinating Council protection system design criteria (NPCC Directory 4 BPS). The proposed in-service date for both projects is in November 2019.
An upgrade to the Portsmouth substation in New Hampshire would entail the replacement of an existing 115/34-kV, 44.8-MVA transformer with a 62.5-MVA rated unit, the addition of a second 115/34-kV, 62.5-MVA transformer, installation of one new 115-kV bus tie circuit breaker, and installation of two new 115-kV circuit breaker disconnect switches. Eversource will also install one new 11-kV circuit switcher for high-side transformer protection and add two 7.2-MVAR capacitor banks, one on each 34-kV bus. The upgrade also will add a 34.5-kV bus tie circuit breaker, which will normally be open, with an automatic close function upon loss of a transformer. The proposed in-service date is June 1, 2020.
4 20-MW Solar Projects by FPS Approved
The RC voted to recommend that ISO-NE determine that implementation of four separate 20-MW solar projects proposed by Freepoint Commodities (FPS) would not adversely affect the grid.
None of the projects include energy storage, and each comprises 10 2-MW arrays.
Solar panels in Vermont like the 20-MW projects approved by the NEPOOL RC on July 16 | Green Mountain Power
SGC Engineering’s Jeff Fenn presented the separate project overviews, showing the solar farm in Plainfield, Conn., interconnecting to the 23-kV bus at the Fry Brook substation and with a proposed in-service date of December 2022.
The firm’s project in Fair Haven, Vt., will interconnect to the 46-kV line between the Green Mountain Power Fair Haven and Carver Falls substations, while the project in Shaftsbury, Vt., will interconnect to the 46-kV line between the GMP South Shaftsbury tap and East Arlington substation, both with a proposed in-service date of July 1, 2022. The project in Claremont, N.H., has the same in-service date.
Enhancing Competitive Tx RFP
ISO-NE Transmission Planning Director Brent Oberlin led a discussion of competitive transmission solicitation enhancements that included proposed clarifications to Attachment K of section II of the Tariff, the draft selected qualified transmission project sponsor (SQTPS) agreement, and to sections I.2.2 and I.3.9 of the Tariff associated with preparing for competitive transmission solicitations under FERC Order 1000.
Based on the results of the 2028 Boston Needs Assessment, which were presented to the ISO-NE Planning Advisory Committee in April, the RTO plans to issue its first request for proposals for a competitively developed transmission solution in December 2019. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)
Tx Cost Allocation Revisions
The RC voted to recommend that ISO-NE approve pool-supported costs for two projects by Avangrid’s United Illuminating subsidiary in Connecticut, including $11.24 million for work associated with the East Shore 345-kV circuit switcher replacement and $8.17 million to replace line optical ground wire and related fiber optic equipment on the 115-kV 1130 Line between the Pequonnock and Sasco Creek substations.
UIL determined that none of the costs associated with either upgrade can be considered localized.
Capacity Cost Compensation
The RC voted to recommend that ISO-NE designate PSEG Power’s Bridgeport Harbor gas-fired plant and the Wheelabrator North Andover waste-to-energy plant as dynamic reactive resources meeting the RTO’s capacity cost compensation program eligibility requirements.
The committee recommended the facilities be eligible for compensation associated with a qualified reactive resource designation effective Aug. 1.
RC Consent Agenda
The RC approved a consent agenda that included seven proposed plan application (PPA) notifications for Massachusetts solar generation totaling nearly 27.5 MW.
The list includes five projects being interconnected through Eversource:
Borrego Solar’s 3.75-MW project in Plymouth, interconnecting to the Valley substation, with a proposed in-service date of Dec. 31.
Borrego’s 4.999-MW project in Freetown, interconnecting to the Bell Rock substation, with a proposed in-service date of May 1, 2020.
CVE North America’s 2.5-MW/1.262-MW Wing Lane solar and battery project in Acushnet, interconnecting to the Wing Lane substation with a proposed in-service date of Oct. 31.
SunRaise Development’s 2.5-MW Cranberry Highway project in Wareham, interconnecting to the Tremont substation with a proposed in-service date of Dec. 1.
Syncarpha’s 4.99-MW Chester Road solar and battery project in Blandford, interconnecting to the Blandford substation with a proposed in-service date of Nov. 18.
Two projects will interconnect through New England Power:
Ameresco’s 2.5-MW Otter River Road project in Gardner, interconnecting to the Crystal Lake Substation with a proposed in-service date of Sept. 1, 2020.
NSTAR Electric’s 4.99-MW Denslow Road project in East Longmeadow, interconnecting to the East Longmeadow substation with a proposed in-service date of Nov. 15, 2020.
The consent agenda also included one PPA non-solar notification, the 1.5-MW Madison Business Park battery energy storage facility in Madison, Maine, which New England Battery Storage will interconnect to the Jones Street substation with a proposed in-service date of Jan. 1, 2020.
The agenda also included three Level I (for information only) transmission PPA notifications:
New England Power is updating the summer normal and revised winter line ratings to reflect current cable design on a new 345-kV underground line from the Wakefield Junction substation to the company’s border with Eversource at the Wakefield/Stoneham, Mass., town line; two new circuit breakers at the Wakefield Junction substation; and a new 345-kV variable shunt reactor. The proposed in-service date is in May 2021.
Eversource is updating the summer normal and revised winter line ratings to reflect current cable design on the installation of a new 8-mile, 345-kV underground cable circuit from the Woburn substation in Massachusetts to National Grid’s Wakefield Junction substation, in Wakefield, including 160-MVAR variable shunt reactors at each terminal. The work will expand the 345-kV switchyard at Woburn to be a breaker-and-a-half substation with four bays. The proposed in-service date is in May 2021.
Eversource is also rebuilding the existing 69-kV 667 Line from the Salisbury substation in Salisbury, Conn., to the Falls Village substation because of asset conditions. The proposed in-service date is Dec. 31.
