Page 1097 – RTO Insider

May 25, 2020

Energy Harbor to Pay OVEC $32.5M in Settlement

Energy Harbor has agreed to pay Ohio Valley Electric Corp. (OVEC) $32.5 million and drop its attempt to abrogate a 30-year power purchase agreement signed by its predecessor, bankrupt FirstEnergy Solutions (FES).

In a settlement lodged with FERC on May 19, the companies said Energy Harbor will assume FES’ obligations under the multiparty intercompany power agreement (ICPA) as of June 1 and pay OVEC $32.5 million “for any cure costs associated with such assumption.”

OVEC agreed to waive all claims against FES and Energy Harbor arising prior to June 1 and withdraw a complaint it filed with FERC before FES’ bankruptcy and its appeal of the bankruptcy court order confirming FES’ reorganization.

Under the ICPA, which runs through June 30, 2040, OVEC provides power from its two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — to Energy Harbor and seven other corporate “sponsors.” FES signed the ICPA in 2010, taking a 4.85% “power participation ratio,” which required it to pay about $30 million annually to cover OVEC’s losses.

Bankruptcy Filing

OVEC filed a complaint on March 26, 2018, asking FERC to rule that allowing FES to reject the ICPA under the Bankruptcy Code without first obtaining commission approval violated the Federal Power Act. FES filed its Chapter 11 bankruptcy petition five days later.

In October 2018, OVEC filed a proof of claim seeking $531 million for damages from FES’ rejection of the contract. OVEC also sought $29.3 million for power it provided to FES while the company was in bankruptcy.

FES changed its name to Energy Harbor upon emerging from bankruptcy in February, with former bondholders owning 50% of the equity. In March, FERC ordered a paper hearing to consider FES’ attempt to void the OVEC contract and PPAs with renewable generators as part of its bankruptcy proceeding (EL20-35). (See FERC Sets Hearing on FirstEnergy PPAs.)

The commission acted after the 6th U.S. Circuit Court of Appeals issued a mandate overruling a U.S. bankruptcy court’s May 2018 injunction preventing FERC from issuing any order requiring FES to continue complying with the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.

On May 19, the commission granted OVEC and Energy Harbor’s request to extend the briefing schedule in the case for 30 days to “allow OVEC to avoid incurring the time and expense of preparing a reply brief that they state is likely to be unnecessary due to” the settlement.

Litigation Costs, Time

OVEC and Energy Harbor said they called a truce to end litigation that could have continued for years and cost millions.

“The parties’ disputes have involved complicated legal and factual issues, with appeals now having made their way to the United States Court of Appeals for the Sixth Circuit multiple times,” they said. “There is no doubt that the litigation between FES and OVEC has been hard-fought, complex, time-consuming and costly.”

The companies also said the settlement will ensure bigger recoveries for FES’ creditors. “Creditors of FES will no longer be diluted by OVEC’s asserted claim, which, assuming the estimated recoveries in the disclosure statement, would have been entitled to receive cash distributions of over $160 million if allowed in full.”

The Bankruptcy Court for the Northern District of Ohio will hold a hearing June 16 to consider the settlement.

Looking Forward

The deal also will allow Energy Harbor’s management “to focus on the growth and success of the reorganized business,” the companies said. OVEC will waive its claims against FES, including its rejection damages claim of $531 million.

Energy Harbor and OVEC pledged to work together “to reallocate to EH the right to offer its ‘power participation ratio’ share of OVEC’s ‘available energy’ … through the offering of energy and capacity” in PJM.

Energy Harbor said that while it continues “to believe that the costs associated with the ICPA are burdensome to their retail business, [Energy Harbor] understand[s] that OVEC is focused on improving its operational cost structure and that recent Ohio state legislation will assist OVEC in maintaining financial stability while doing so.”

Ohio House Bill 6 authorized a surcharge on electricity customers to subsidize OVEC’s coal plants in Ohio and Indiana and FES’ — now Energy Harbor’s — Davis-Besse and Perry nuclear plants.

“The reorganized debtors believe that operational improvements and cost savings can be achieved through their ongoing participation in OVEC pursuant to the ICPA, and they are ready, willing and able to assist in those efforts.”

Pitch to Investors: Nuclear Power and Retail

Energy Harbor emerged from bankruptcy with low debt and largely subsidized generation, winning it investment-grade ratings from Moody’s Analytics and Standard and Poor’s.

In March, the first month after emerging from bankruptcy, the company reported $142 million in revenue and a $124 million net loss, driven largely by $153 million in losses on nuclear decommissioning trust investments. It also repurchased $113 million in company stock, part of a plan to purchase up to $800 million in shares over nine months. Its adjusted cash flow for the month, including its nuclear fuel amortization expense, was $23 million.

An investor slide deck posted May 10 touts the company’s carbon-free nuclear generation and its retail sales operation, which it says will generate $200 million in annual cash flow by 2022, when it says more than 95% of its free cash flow will come from carbon-free sources.

Energy Harbor owns about 7,200 MW of capacity, including three nuclear plants: Beaver Valley Power Station in Shippingport, Pa. (1,872 MW); Davis-Besse Nuclear Power Station in Oak Harbor, Ohio (908 MW); and Perry Nuclear Power Plant in Perry, Ohio (1,268 MW). The company rescinded plans to retire Beaver Valley in March, citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative. (See Beaver Valley Nuclear Plant to Stay Open.)

The company is retiring the coal-fired Units 1-4 of its W.H. Sammis Plant (669 MW) in Stratton, Ohio, at the end of this month, with a 13-MW diesel unit set to shut down next year. It had also planned to shutter Sammis’ coal-fired Units 5-7 (1,491 MW) in 2022, but FES rescinded the notice last year in response to Ohio House Bill 6. Its coal-fired Pleasants Power Station (1,278 MW) in Willow Island, W.Va., is set to retire in June 2022.

Energy Harbor rescinded plans to retire the Beaver Valley nuclear plant in March, citing Pennsylvania’s efforts to join the Regional Greenhouse Gas Initiative.

Three-quarters of its cash flow comes from nuclear zero-emission credits, plus capacity payments and retail sales, leaving only 25% “commodity exposed,” it says.

It notes its gross debt-to-cash-flow ratio is only 0.8, less than a third of the “peer average” of 2.9.

Another selling point: The “company [is] not expected to be a material federal cash taxpayer for [the] foreseeable future.”

May 25, 2020

SPP, Stakeholders Honor Nick Brown in Retirement

SPP staff and stakeholders on Friday lauded retired CEO Nick Brown for his leadership in building the RTO from a small regional organization into one that now reaches from the Texas Panhandle to the Dakotas.

Given the new normal, the celebration was a virtual one. Brown, sporting his usual SPP-logoed shirt, sat at home next to his wife, Susan, and watched as former and current staffers, directors, regulators and industry insiders praised him for the RTO’s success during his tenure.

Brown announced his retirement last July after 35 years with the grid operator, including 16 as CEO. (See SPP’s Brown to Retire as CEO in 2020.)

SPP Nick Brown — Nick, with his wife, Susan, responds to stakeholders during his virtual retirement celebration.

American Electric Power CEO Nick Akins invited Brown to Columbus, Ohio, for a game of golf and to share his expertise. The two were classmates at Louisiana Tech (Class of ’82), where they went by Nick A. and Nick B. to avoid confusion, and began working at Southwestern Electric Power Co. on the same day.

“He will leave a lasting legacy for SPP and the industry,” Akins said.

Former FERC Commissioner Colette Honorable, who also chaired the Arkansas Public Service Commission, toasted Brown with a glass of New Mexico bubbly and thanked him for exhibiting a collaborative approach with stakeholders, rather than “fighting everything at FERC.”

Omaha Public Power District’s Joe Lang recalled his first stakeholder meeting. Brown, as he always does during opening introductions, referred to himself as, “Nick Brown, SPP staff.”

“That’s when it hit me that SPP’s inclusive culture is driven from the top,” Lang said.

Harry Skilton, an SPP director for 18 years, welcomed the ex-CEO to the RTO’s alumni club.

“We’re a small group. There’s no dues or initiation ceremony,” Skilton said. “The only thing I ask of you is that anytime any of us should meet, to raise a good glass of claret to SPP and its motto, ‘Keep the lights on.’”

CEO Barbara Sugg credited her predecessor with inspiring her to reach beyond herself when she joined SPP. Sugg was appointed to replace Brown in January. (See SPP Board Taps Barbara Sugg as New CEO.)

“He believed in me. He saw things in me I didn’t see in myself,” she said. “He always set really high expectations and challenged us to meet those expectations. You can’t make people follow you. They follow you because you inspire them. I’m proud, I’m humbled, and I’m overwhelmed, in this crazy pandemic, to be stepping into his footsteps.”

Sugg assured those watching and listening that she will continue to “foster all those great things” Brown put in place.

“Nick poured his heart and soul and the vast majority of his life into SPP,” she said.

Brown’s retirement was effective in April. SPP had planned a dinner and celebration in his honor that month, but the coronavirus pandemic waylaid those plans.

Board of Directors Chair Larry Altenbaumer said, “It made sense to go forward at this time and conduct the event sooner, rather than later, in the same manner in which many of us are conducting our daily lives.”

When it came his time to speak into his wireless device, Brown recalled that when he joined SPP in 1985, SWEPCO CEO John Turk asked him whether he was sure what he was doing. After all, the organization only had five employees at the time, and Brown had already established himself as a gregarious, outgoing person.

“How are you going to be who you are when you love being around people so much?”

Brown, noting that SPP had about 300 stakeholders already, said he would do just fine.

“It’s just been a tremendous ride,” Brown said. “I’ve really kind of enjoyed having all of these weeks, from the official retirement day until today, spending time, thinking of each and every person who has touched me in this industry. We’ve shared blood, sweat and tears. This has been an exciting experience, that’s for sure, but things change and things move on.

Brown led the organization as it was recognized by FERC as an RTO and expanded into 14 states, admitting Nebraska utilities in 2009 and the Integrated System in 2015. SPP added a balancing market in 2007 and a wholesale day-ahead market in 2014, while also investing nearly $10 billion in transmission facilities. It became a reliability coordinator in the Western Interconnection in 2019 and will also manage an energy imbalance service market with eight western participants next year.

SPP’s membership will reach 100 members when EDF Renewables joins on June 1. The grid operator already has almost 24 GW of installed capacity and has produced as much as 78% of its energy from renewable sources.

The Board of Directors and Members Committee presented Brown with a resolution of “deep gratitude” recognizing his “unparalleled leadership.” Earlier in the day, they delivered to his house a bronze sculpture, titled “Place of Honor,” by his and Susan’s favorite artist, Colorado sculptor Joshua Tobey.

“I couldn’t be more pleased with the position the organization is in,” Brown said. “With the board and the management team, and with Barbara as the new CEO, the future is great. I’m really excited to watch the organization continue to prosper,” Brown said. “Thank you. Thank you. Thank you, very much.”

May 25, 2020

FERC Rejects Complaints on PJM Seasonal Resources

FERC last week rejected requests to change PJM’s capacity market rules to accommodate seasonal resources, saying the complainants failed to prove current market rules are unjust and unreasonable (EL17-32, EL17-36).

The order was prompted by a December 2016 complaint by Old Dominion Electric Cooperative (ODEC), Direct Energy Business and American Municipal Power and a January 2017 filing by Advanced Energy Management Alliance (AEMA) over the procurement of capacity in PJM’s Reliability Pricing Model.

ODEC asked the commission to establish a proceeding to allow seasonal resources to participate in capacity auctions. AEMA said PJM’s move to 100% Capacity Performance resources was unnecessarily costly for ratepayers, citing studies that it said proved that all of PJM’s resource adequacy risk is in the summer.

PJM adopted the CP rules — which increased bonuses for overperformance and penalties for underperformance — in response to the 2014 polar vortex, when the RTO came close to shedding load with as much as 22% of its generating fleet on forced outages.

“The core of the complaints is that because PJM is a summer-peaking system, PJM could acquire more summer capacity than winter capacity at an economic savings without sacrificing system reliability,” the commission said. The complainants pointed to PJM data that they said showed that by increasing summer requirements by about 500 MW, the RTO could replace more than 17,000 MW of annual capacity with less expensive summer resources without jeopardizing reliability.

Reasonable Accommodation

The commission ruled in 2015 that using the same capacity requirement for winter and summer was justified by deteriorating resource performance and the change in the RTO’s resource mix. Allowing non-year-round resources to continue participating in the capacity market could lead to reliability problems in non-summer months when seasonal resources are unavailable, it said. The commission said PJM had provided a reasonable accommodation by allowing storage resources, intermittent generators, demand response and energy efficiency to submit aggregated offers.

The commission’s approval of CP was backed by the D.C. Circuit Court of Appeals, which ruled that the “law provides no basis to claim the commission cannot approve uniform performance requirements simply because those requirements will be easier to satisfy for some generators than others.”

In response to the commission and D.C. Circuit rulings, the complainants provided planning studies and other evidence that they said proved that PJM could meet its resource adequacy targets more cost-effectively by tailoring its procurements to recognize seasonal variation. Summer peaks can top 150 GW, while the winter typically peaks at less than 100 GW.

Although the commission held a technical conference in April 2018 to explore the issues raised by the complaints, it said there was insufficient evidence to overturn the CP rules.

PJM Seasonal Resources — PJM’s summer peaks can top 150 GW, while the winter typically peaks at less than 100 GW. | *PJM*

Data Limitations

FERC cited PJM’s warning that “modeling assumptions underlying the data on which complainants rely … warrant caution in interpreting the meaning of that data.”

While the RTO’s annual installed reserve margin study indicates that only a small amount of loss-of-load-expectation risk occurs in the winter, “recent operating experience suggests that such risk may in fact be higher,” FERC said.

PJM also said AEMA’s contention that an additional unit of summer-only capacity has 97% of the reliability value of an additional unit of year-round capacity was based on an incorrect premise that changing to seasonal capacity resources would not also change other modeling assumptions underlying the data.

“In light of these identified limitations in the data presented, we are not persuaded that the evidence complainants present is sufficient to show that the Capacity Performance model is no longer just and reasonable,” the commission said. “Ultimately, we are not convinced that it is necessary for PJM to abandon its single-product Capacity Performance model based upon the limited experience since the commission’s approval. As PJM argues, it deserves the opportunity to gain more experience with implementation of Capacity Performance and its rules over time to determine whether it provides performance and reliability during all seasons of the year.”

Glick Concurrence

Although the ruling was unanimous, Commissioner Richard Glick wrote a concurrence saying that “a seasonal capacity construct appears to be a more just and reasonable approach than PJM’s current one-size-fits-all” rules.

Glick said that while he agreed the complainants had not proved that the CP rules are unjust and unreasonable, “the record does, however, hint at a number of more fundamental problems with PJM’s capacity construct [that] merit a comprehensive review in PJM’s stakeholder process and, if necessary, by this commission.”

He said the evidence “underscores the difference between the reliability challenges in the summer and winter and … suggests that moving away from a uniform annual product could allow more resources to provide capacity, thereby increasing competition and promoting more efficient pricing.”

“Although the high reserve margins that help manage the summer-time peaks may also address winter concerns, they are not the most direct way to do so,” he continued. “The fact that having extra resources on the system may help manage non-peak reliability challenges does not necessarily justify PJM’s current approach or excuse it from pursuing means of addressing those challenges more directly and cost-effectively.”

Glick also pointed to the “unintended consequences” of PJM’s excess capacity.

“PJM, its stakeholders and this commission have devoted considerable time and resources to promoting proper price formation in PJM’s energy and ancillary service markets. Over-procuring capacity tends to dull those price signals, reducing, or altogether eliminating, many of the benefits of those price formation efforts.”

He also said he was troubled by “the implication of PJM’s statement that adopting a seasonal market could cause ‘premature resource retirement.’”

“PJM’s goal cannot be the protection of ‘conventional’ resources, nor should it spend its time fretting over the effects that a more efficient market design may have on the resource mix,” Glick said. “Instead, PJM should be focused on identifying the services the grid needs to remain reliable and structuring its markets to procure those services in the most efficient, technology-neutral manner possible. In any case, it is hardly ‘premature’ for a resource to retire because some other resource can more efficiently meet the needs of the market. That type of competition should be the goal of the capacity market, not a problem to be avoided.”

Glick also said excess capacity also has undermined the “underpinnings of PJM’s Capacity Performance proposal, which envisioned many penalty hours per year.”

“The commission’s recent decisions regarding PJM’s variable resource requirement curve and minimum offer price rule (MOPR) will only exacerbate that capacity glut, further reducing the chances of a Capacity Performance penalty. …

“Capacity Performance events will be even less likely after the issuance of today’s order on the operating reserve demand curve, which will result in PJM carrying reserves far in excess of its reserve requirement, further reducing the likelihood of a Capacity Performance event.” (See related story, FERC Approves PJM Reserve Market Overhaul.)

“If there is little-to-no prospect of a capacity shortfall, then it would seem correspondingly harder to justify the qualification restrictions, including the limitations on seasonal resources. I recognize that some of the capacity glut is the result of the commission’s actions, not PJM’s, and that this share may continue to grow as the consequences of the commission’s MOPR ruling play out. But that should not stop PJM from taking a hard look at whether Capacity Performance remains appropriate under current market conditions and, in particular, whether the barriers it created for seasonal resources should be removed.”

May 25, 2020

PJM Ordered to Revise Pseudo-tie Rules

PJM’s rules for pseudo-tied resources lack “sufficient notice and transparency” regarding how the RTO conducts its market-to-market (M2M) flowgate test and applies its electrical distance requirement, FERC ruled last week.

Acting on complaints by Brookfield Energy Marketing and Cube Yadkin Generation, the commission ordered PJM to amend its Tariff within 45 days to address the shortcomings.

Brookfield contended that PJM’s deliverability requirements and M2M flowgate test were interfering with the ability of the company’s Calderwood and Cheoah hydroelectric generation facilities in the Tennessee Valley Authority and Duke Energy balancing authority areas to provide capacity in the RTO. The commission ruled that Brookfield had not proven that PJM’s pseudo-tie requirements are unjust and unreasonable (EL19-34).

The commission also rejected Cube’s allegation that PJM applied the electrical distance requirement in an unjust and unreasonable manner to the company’s four hydroelectric resources. But the commission required the RTO to amend its Tariff to spell out the procedure in more detail (EL19-51). The Tariff defines “electrical distance” as “the measure of distance, based on impedance and in accordance with the PJM manuals, from the generation capacity resource to the PJM region.”

PJM Pseudo-tie Rules — Brookfield Energy Marketing’s Calderwood Dam is on the Little Tennessee River in Blount County, Tenn.

FERC ordered PJM to revise its Tariff to provide pseudo-tie applicants with results of their tests and related work papers and to post on its website the assumptions used in the tests. It also required the RTO to meet with applicants if requested to discuss assumptions, modeling and test results.

In a third order, FERC rejected a complaint by Tilton Energy alleging that PJM wrongly determined that Tilton’s pseudo-tie from the MISO BAA into PJM did not pass the M2M flowgate test (EL18-145).

The company filed a complaint after its 176-MW natural gas-fired generation facility in the MISO BAA was rejected by PJM because 44 of the tested flowgates failed the test. PJM uses the test to determine whether it can use a dispatchable internal resource to alleviate the impact on congestion caused by the external pseudo-tied resource.

The failed test prevented Tilton from participating in capacity auctions after the 2021/22 delivery year, despite having served as a capacity resource in two prior years.

The commission sided with PJM’s interpretation of its Tariff regarding the testing. “We find that PJM’s interpretation reasonably permits PJM to reject pseudo-ties that could create new coordination and congestion costs,” it said.

It said the fact that Tilton had previously been accepted as a capacity resource was irrelevant. “Tilton has not previously been subject to the flowgate test, given the five-year transition period for existing pseudo-tied resources,” it said.

May 25, 2020

FERC Partially Accepts Tri-State Order 845 Filing

FERC last week partially approved Tri-State Generation and Transmission Association’s Order 845 compliance filing, directing the Colorado cooperative to make additional changes within 120 days (ER20-687).

The commission on Thursday accepted most of Tri-State’s compliance filing but said the cooperative only partially complied with Orders 845 and 845-A’s requirements regarding surplus interconnection service and determining contingent transmission facilities. It directed Tri-State to describe the specific technical screens or analyses and the triggering thresholds or criteria it will use to determine which facilities are contingent facilities — unbuilt interconnection facilities and network upgrades upon which an interconnection request’s costs and timing are dependent.

Tri-State FERC Order 845 — Tri-State G&T’s service territory | *Tri-State*

It also ordered the cooperative to explain why it omitted the sentence “Surplus interconnection service requests also may be made by another interconnection customer” from its proposed large generator interconnection procedures. Surplus service is any unused portion of interconnection service.

FERC issued Orders 845 and 845-A in 2018 and 2019 to increase the generator interconnection process’ transparency and speed. The changes are grouped into three categories: improved certainty for interconnection customers; promoting more informed interconnection decisions; and process improvements. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)

The commission on Thursday also accepted Tri-State’s large generator interconnection agreement with Leeward Renewable Energy as a service agreement under the cooperative’s Tariff, effective Feb. 25, and established hearing and settlement procedures to address unresolved issues between Tri-State and Leeward (ER20-1045).

Tri-State became FERC-jurisdictional in March, when the commission recognized its status following last year’s addition of its first non-utility member. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 16, 2020.)

May 22, 2020March 11, 2025

NJ Regulators Weighing Input on Capacity Market Exit

The New Jersey Board of Public Utilities received dozens of comments Wednesday on whether to leave the PJM capacity market in response to the expanded minimum offer price rule (MOPR).

Forty filings were made by the May 20 deadline set by the NJBPU, which initiated the investigation in March to determine if staying in the capacity market will increase consumer costs or impede Gov. Phil Murphy’s goals of 100% clean energy sources by 2050 (Docket No. EO20030203). (See N.J. Investigating Alternatives to PJM C apacity Market.)

Some stakeholders said the state should adopt the fixed resource requirement (FRR) because the expanded MOPR would hamstring its support for emission-free generation. Opponents said leaving the capacity market could end up costing state ratepayers millions, leaving them at the mercy of monopolistic generators.

PJM’s Independent Market Monitor released a report May 13 that concluded a statewide FRR would increase costs by almost 30% if prices were at the PJM offer cap of $235.42/MW-day but only 2.4% if prices equaled the $186.16/MW-day weighted average price for the state in the most recent Base Residual Auction. (See PJM Monitor Finds Capac i ty Exit Costly for NJ.)

Two clean energy advocates responded Wednesday with a report criticizing the Monitor’s analysis, saying it was skewed by assumptions that FRR regions would choose more expensive resources within their jurisdictions rather than cheaper imports. (See Report: Imports Key to Successful FRR.)

A fixed resource requirement for the JCPL locational deliverability area would mandate that at least 81.5% of its capacity be located in the EMAAC zone, with any remaining capacity located in MAAC (outside of EMAAC), according to PSEG and Exelon. | PSEG and Exelon

PJM also weighed in Wednesday, noting that New Jersey is a capacity-importing state with more peak demand than unforced capacity within its service territories. If all capacity resources in New Jersey agreed to serve the state in an FRR, PJM said, the state would still require slightly more than 5,000 MW of additional capacity.

The RTO said it would not judge the cost of an FRR for New Jersey, but it urged regulators to closely examine claims that an FRR would lower costs.

“PJM does not comment with respect to the cost of an FRR for New Jersey,” the filing said. “Instead, PJM cautions the BPU to look critically at any outright claims offered at this point in the proceeding that an FRR will prove less expensive for New Jersey consumers.”

Supporters

Perhaps the strongest endorsement for the FRR option came in a joint filing by Public Service Enterprise Group and Exelon, whose state-subsidized nuclear generators would be subject to the expanded MOPR. They said the FRR would allow New Jersey “to exert greater control over how their load-serving entities meet resource adequacy requirements.”

PSEG CEO Ralph Izzo said earlier this month it would be “logical” for the state to choose the FRR option. (See PSEG Turns Bulli s h on NJ FRR Option.)

The PSEG/Exelon filing said the FRR alternative could better support the clean generation goals in the state’s 2019 Energy Master Plan (EMP) by integrating with other programs like the Regional Greenhouse Gas Initiative (RGGI).

The filing also suggested integrating the procurement of capacity with the procurement of environmental attributes in the FRR “to standardize the state’s support for clean electricity resources and encourage competition among different types of clean resources.”

“Offshore wind projects qualifying for ORECs, new grid-connected solar resources qualifying for state support, and the nuclear plants selected to receive ZECs would compete to sell their capacity and attributes, bundled together, for an all-in price fixed at the outset of a long-term contract, less forecasted energy revenues (based on futures prices for energy at a liquid trading hub) and ancillary services revenues determined in advance of each delivery year,” the companies said.

“An integrated FRR procurement will allow New Jersey to fully and timely achieve its EMP goals at a lower cost for consumers than they would otherwise pay, by avoiding the inefficiencies that will result from FERC’s new bidding rules in the PJM capacity auction,” the filing said. “An integrated FRR procurement could also provide renewable developers with greater long-term certainty, reducing development costs.”

Also coming out in support of an FRR was Ørsted, which was selected by the BPU last June to develop the state’s first offshore wind project. (See Orsted Wins Record Offshore Wind B i d in NJ.)

Ørsted said current floor price estimates indicate its 1,100-MW Ocean Wind project, expected to be in service by 2024, will not clear future PJM capacity auctions and “may not be able to contribute to the state’s capacity needs.”

The FRR could provide a model for incorporating clean energy generation, the filing said, and the board should continue evaluating the impacts of other clean energy market mechanisms like carbon pricing.

“New Jersey should continue to be a national leader in clean energy development,” the filing said. “Any mechanism pursued by the board should appropriately value clean energy resources for both their reliability and environmental benefits, minimize costs to ratepayers and encourage economic development.”

The American Council on Renewable Energy (ACORE) requested that the NJBPU consider an “enhanced retail electric market” that could adequately procure resources aligned with the EMP’s clean energy objectives through modifications to its Basic Generation Service (BGS) default procurement program. The BGS auct i ons are held by New Jersey’s four distribution utilities to provide service to customers not served by a competitive retailer.

“New Jersey can ensure [that] enhanced retail electric markets are consistent with the EMP when coupling these reforms with a high-penetration renewable energy standard to directly drive deployment of carbon-free electricity and economy-wide carbon pricing to avoid carbon leakage,” the filing said.

Detractors

Critics of the FRR appeared to outweigh supporters. Among those opposing the FRR were Calpine, the Independent Energy Producers of New Jersey, Natural Gas Supply Association, PJM Power Providers Group and the Retail Energy Supply Association.

The Electric Power Supply Association encouraged the BPU to “play a leading role” in developing regional solutions to meet environmental goals by working with PJM to consider adapting ISO-NE’s Competitive Auctions for Sponsored Policy Resources (CASPR) market design. Under CASPR, ISO-NE will clear the Forward Capacity Auction after applying the MOPR to new capacity offers to prevent price suppression. In the second Substitution Auction, generators nearing retirement that cleared in the primary auction could transfer their obligations to subsidized new resources that did not clear because of the MOPR.

The New Jersey Division of Rate Counsel’s comments focused on PJM’s Independent Market Monitor study, citing the estimates that a statewide FRR could increase capacity costs for New Jersey ratepayers by 29% on the low end.

The Rate Counsel discouraged making changes to the BGS auction, saying it was created to “ensure a stable and affordable supply of energy for residential and small commercial customers who do not wish to or cannot shop for their electricity from third-party suppliers.” It said the program has been a success in its current state by bringing customers the benefits of competition and a less volatile market.

The Rate Counsel urged the board to “proceed with caution” when considering the FRR because the option could bring “unwanted and expensive consequences,” including lack of competition and market oversight.

“Our aims should be to foster competition, avoid enhancing market power and protect New Jersey ratepayers from excessive rates,” the filing said. “While the FERC orders have certainly created roadblocks for the state to achieve its goals, we must make sure that our citizens continue to have safe, adequate and affordable service and that any action we take does not undermine that important, fundamental principle.”

May 22, 2020

Improper Email Delays CPUC Vote on PG&E Plan

The California Public Utilities Commission unexpectedly postponed its planned vote Thursday on Pacific Gas and Electric’s bankruptcy reorganization plan because a party to the proceedings improperly sent out a mass email earlier in the week.

“This proposed decision is being held because a party sent an ex parte communication by email on Tuesday,” President Marybel Batjer said. “This was a prohibited ex parte communication under state law and the CPUC rules of procedure.”

The CPUC was planning to vote on an administrative law judge’s decision to approve PG&E’s Chapter 11 plan with some modifications, including enhanced oversight by the commission.

CPUC vote PG&E — CPUC President Marybel Batjer

Batjer angrily denounced the party’s action and warned of possible consequences for issuing a communication during a required quiet period from May 15 until the Thursday vote.

“For my part, I am not pleased that an error in understanding our rules or a disregard for them will delay the vote on a proposed decision,” Batjer said. “We will implement this delay to ensure that we have very clearly taken the procedural steps we need to take to ensure we issue a legally sound decision.”

The email was sent by William Abrams, a wildfire victim and party to the CPUC proceedings, who sent an email with attached documents to hundreds of individuals on the CPUC’s service list.

“This is to notice the Commission and parties of this proceeding regarding my objections and those of the [Tort Claimants Committee] filed in the U.S. Bankruptcy Court (Case #19-30088-DM),” it said in part.

Abrams has represented himself in the bankruptcy court proceedings and has urged delay to more closely examine PG&E’s reorganization plan. He apologized in a notice to the CPUC Wednesday.

“My understanding was that posting publicly available documents to the docket for this proceeding was not a violation of the quiet period,” Abrams said. “However, I apologize if this was not in keeping with policies and procedures of this proceeding and of the commission.”

Batjer gave parties, including PG&E, a chance to respond to the email until midnight Thursday and insisted that the commission’s rules against ex parte communications during the “quiet time” before a vote be strictly obeyed.

“We will not tolerate any further delay to this proceeding,” Batjer said.

The CPUC could pursue “remedial action” if it finds a party intentionally delayed the vote, she said.

The vote will now be held on May 28, one day after a hearing is scheduled to start in the U.S. Bankruptcy Court in San Francisco on PG&E’s Chapter 11 plan. The quiet time for the next hearing will last from May 22 until the conclusion of the hearing, she said.

PG&E needs the bankruptcy court and CPUC to approve its reorganization plan by June 30 in order to participate in a state insurance fund for future wildfires. Massive fires sparked by its equipment caused PG&E to seek bankruptcy protection in January 2019.

May 22, 2020

Report: Imports Key to Successful FRR

A new study finds that analyses by PJM’s Independent Market Monitor predicting increased costs for regions that exit PJM’s capacity market are skewed by their assumptions and should be redone to presume exiting states will maximize imports to counter local market power.

“The reports’ cost estimates risk confusing or even misleading states to the extent they suggest confidence that FRR [fixed resource requirement capacity procurements] will yield higher prices than continued reliance on PJM’s RPM [Reliability Pricing Model],” said the report by Rob Gramlich, president of Grid Strategies, and consultant Miles Farmer, a former attorney for the Natural Resources Defense Council.

“At this stage, given uncertain market dynamics and questions surrounding how states and utilities may implement FRR, it is difficult for anyone to render a confident and accurate prediction of FRR prices. While Monitoring Analytics provides useful data and a structure to evaluate FRR costs, we recommend that it provide a more complete picture of the potential costs of FRR by conducting additional scenarios applying the reasonable assumption that FRR entities would competitively procure externally-located capacity.”

Gramlich and Farmer released their study Wednesday, the New Jersey Board of Public Utilities’ deadline for comments in its docket on the state’s options for ensuring resource adequacy. (See related story, NJ Regulators Weighing Input on Capacity Market Exit.) The report expanded on the critique Gramlich has made in recent forums with Joe Bowring, president of Monitoring Analytics. (See PJM Monitor Defends FRR Analyses in MOPR Debate and Moving Forward o n MOPR.)

The Monitor said its analyses in Illinois, Maryland and New Jersey indicate ratepayers are likely to see costs increase if their jurisdictions leave the PJM capacity market for an FRR. The reports also concluded that the expanded minimum offer price rule (MOPR) is unlikely to increase capacity costs, at least for the first couple of auctions. (See PJM Monitor Finds Capacity Exit Costly for NJ.)

FRR — State officials in Illinois, Maryland and New Jersey are considering alternatives to the PJM capacity market. | *Monitoring Analytics*

The Gramlich-Farmer report did not attempt to quantify the impact of an FRR, but it said “a reasonable set of assumptions yields lower price estimates for FRR than for continued reliance on RPM.”

The authors said any analysis should assume that an FRR service area located partially or fully within a constrained locational deliverability area (LDA) would seek to purchase as much capacity as possible at lower prices outside the LDA before “meeting the rest of internal load with internal generation.”

They said states should request that the Monitor provide them data on the maximum import capability into constrained zones, which will determine the minimum internal resource requirements.

“Monitoring Analytics reports all suffer from a central flaw: they assume that FRR entities would purchase as much capacity as possible from internal resources, importing capacity only to the extent ‘needed to cover any shortfall in meeting the FRR obligation,’ even where the FRR entity is located within a transmission-constrained area where local capacity prices are higher than those of the importing region(s),” the report said. “Monitoring Analytics never justifies this assumption, which leads to higher prices across all scenarios that modeled an FRR entity located entirely or partially within a transmission-constrained LDA.

“While this framing suggests an apples-to-apples cost comparison, in fact it yields skewed results that in effect presume an irrational capacity purchasing strategy by the FRR entity.”

Bowring continued to stand behind his analyses Thursday, saying, “It is extremely unlikely that the FRR approach will result in prices equal to or lower than market prices.”

He criticized the Gramlich-Farmer report’s references to the resource adequacy policies of MISO and CAISO, saying neither are markets. “MISO relies on cost-of-service regulation with its attendant high costs and lack of competition, and CAISO relies on an inefficient process of bilateral contracting for capacity.”

The report noted that the Monitor found a 5.4% reduction for an FRR in Maryland’s PEPCO LDA — which is not constrained by a binding transmission import limit — under a scenario in which capacity prices would be equal to the most recent Base Residual Auction.

Gramlich and Farmer also questioned why half of the Monitor’s scenarios assumes all suppliers — not just pivotal suppliers that possess market power — will be paid prices at the seller offer cap.

“Market power is a significant challenge that states, PJM and FERC should carefully address in designing and implementing FRR. But it is important to recognize that FRR does not ‘create’ market power, which flows from the underlying dynamics of market suppliers’ generation ownership and relevant transmission system constraints,” they said.

They also disagreed with the Monitor’s conclusion that the expanded MOPR will not increase costs in upcoming BRAs. Gramlich this week released a study projecting that the expanded MOPR will cost ratepayers $9.7 billion or more over the next nine years. (See New MOPR Analysis Sees Cost at $1B/Year.)

“MOPR will raise RPM costs to the extent it raises market clearing prices by causing higher priced supply offers and to the extent it forces customers to support the construction or retention of redundant capacity. MOPR also could increase the cost of state programs because state-supported resources that do not clear the capacity market may require more revenue from renewable energy credits (RECs) and other payments in order to cover their costs and be developed as the states desire.”

In contrast, Gramlich and Farmer said, FRR programs could procure capacity from state-supported resources at prices that reflect state subsidies. “The costs of state clean energy policies would also be reduced as compared to BRA with MOPR because state-supported resources could more confidently rely on capacity revenues.”

The authors said lower costs are likely under FRR because it would require only a 15% reserve margin — using a vertical demand curve and fixed MW requirement — rather than the 22% margin in recent RPM auctions, which uses a sloped demand curve. They cited an estimate from ICF that the lower reserve margin under FRR could reduce prices by $15 to $25/MW-day in the near term and $30 to $50/MW-day in the long term.

The study also said FRR would give utilities and states more flexibility because non-performance penalties could be assessed on a physical and portfolio-wide basis rather than as an economic penalty applied to individual units under RPM. They said unit-specific financial penalties have been a disincentive to renewables’ participation in the capacity market.

Bowring questioned why Gramlich and Farmer assert “that the weaker performance incentives in an FRR would be a good thing. “An essential point of the Capacity Performance design was to strengthen performance incentives. One of the strengths of well-designed markets is that investors bear the risks associated with the performance of their assets,” he said.

FRRs could make better use of seasonal resources than RPM, they said, citing a Brattle Group report that concluded separating summer and winter capacity markets in PJM would save consumers $100 million to $600 million annually.

FRRs also could obtain lower prices by giving sellers multi-year price locks. “Price formulas could partially or fully index to RPM. And the purchase could also be combined with energy, ancillary services or environmental attributes providing the purchaser and seller more certainty as to their total costs and revenues.”

The authors acknowledged that PJM rules bar utilities from returning to the capacity auction for at least five years after departing (though PJM allows an exception if state regulatory changes materially affect consumers’ retail choice options).

They also noted concerns that state regulators would have to prevent distribution companies from acting on incentives to favor their own generation under an FRR.

Under PJM rules, the entity responsible for obtaining capacity could be a utility, distribution company or state agency. Legislation pending in Illinois would give such responsibility to the Illinois Power Agency. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)

May 22, 2020

FERC Approves PJM Reserve Market Overhaul

FERC on Thursday approved PJM’s proposed energy price formation revisions, agreeing with the RTO that its reserve market was not functioning as intended (EL19-58, ER19-1468).

“PJM made a persuasive case that its current reserve market design must be overhauled,” Chairman Neil Chatterjee said during the commission’s monthly open meeting, held by teleconference because of the COVID-19 pandemic. “PJM showed that the current market mechanism systematically fails to enable PJM to acquire within the market the reserves it needs to operate its system reliably and [that] it fails to send appropriate price signals for efficient resource investment.

“The fact that PJM operators regularly must procure thousands of megawatts of reserves outside of the market construct is evidence of a market design that is unjust and unreasonable.”

PJM filed its proposal unilaterally in March 2019 under Section 206 of the Federal Power Act because stakeholders could not come to a consensus on one plan. It was the culmination of a year’s worth of debate and discussion among stakeholders, RTO staff and members of the Board of Managers. (See PJM Files Energy Price For m ation Plan.)

The changes consolidate the tier 1 and tier 2 reserve products, align the products that PJM procures in the day-ahead and real-time markets and revise the height and shape of the operating reserve demand curve. “Together, these reforms will ensure that market forces, rather than out-of-market decisions, drive the procurement of reserves in PJM,” Chatterjee said.

PJM Reserve Market — PJM’s new operating reserve demand curve (blue) as approved by FERC, compared to a previously proposed version (green) and old version (red dotted line) | *PJM*

Commissioner Richard Glick issued a strong dissent, saying that “while I’m concerned that the commission made an unsupported finding that PJM’s existing rate is unjust and unreasonable, I’m even more concerned and particularly troubled that the commission accepted PJM’s proposal to revise the operating reserve demand curve. The commission is replacing marginal-cost pricing with an administrative adder that is going to force consumers to pay scarcity pricing all the time, regardless of whether there was actual scarcity or not. …

“How is it ‘market forces’ when we’re administratively drawing up a curve that makes no sense and the market wouldn’t support? We’re doing it, obviously, to raise prices,” he said. “PJM and others continue to treat low prices — due in large part to a significant amount of excess generating capacity — as a matter that requires market tweaks designed to raise prices. Instead of addressing the true cause of the problem, which is excess capacity, this commission continues to approve proposals that raise prices. And what does that raise in prices do? It further exacerbates the problem.”

The RTO had estimated in a December 2018 whi t e paper that the changes would result in increased costs to load of about $700 million annually, but Glick said the costs could reach up to $2 billion.

Chatterjee acknowledged that “these reforms will affect the amount of reserves procured and the energy and ancillary services revenues resources receive.” To counterbalance the costs to consumers, the commission directed PJM to recognize the new changes in its capacity market’s energy and ancillary services offset, a key variable in calculating the net cost of new entry (CONE) for resources in the RTO’s capacity auctions.

The offset is calculated using energy market results from the three calendar years prior to the Base Residual Auction. Therefore, “an historic energy and ancillary services offset would likely underestimate future energy and reserve market revenues, considering that PJM’s proposal will likely result in increases in the energy and reserve prices compared to the historic values,” the RTO said in the white paper.

Staff had proposed a mechanism that would have estimated the offset had the new rules been in place the previous three years, but the PJM board ultimately declined to include it in the filing. (See PJM Advances Own Energy Price F ormation Plan.)

FERC ordered PJM to submit a compliance filing in 45 days to implement the mechanism.

“Recognizing the interplay between these reforms and the pending capacity market reforms,” Chatterjee said, referring to the RTO’s pending compliance filing implementing an extended minimum offer price rule, “we’ve asked PJM to propose an implementation schedule that harmonizes the reforms while minimizing auction delays.”

FERC had not posted the order to its website as of press time.

May 22, 2020

Chatterjee Pledges to Serve Full FERC Term

FERC Chairman Neil Chatterjee pledged Thursday to serve his full term, saying his Facebook post suggesting he was considering a run for governor of Virginia was intended as a joke.

Chatterjee, a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), who has long been rumored to have political ambitions, created a Facebook gro u p titled “Hypothetical: Draft Neil Chatterjee for Virginia Governor 2021” on May 16. (See Chatterjee Explorin g Va. Gubernatorial Race.)

“Let me just be totally, totally clear on this, and I can’t stress this enough. What I did was write a light-hearted post to social media. It was clearly a joke and not serious,” he said in response to a question at his press conference after FERC’s monthly open meeting. “I cannot stress enough [that] my focus is on the work of the commission. I’m not focused on anything about my future until after the completion of my term at the commission, June 30, 2021. Period. Point blank.”

The filing deadline for the Virginia primary is April 25, 2021, more than two months before Chatterjee’s term expires. Under the Hatch Act, Chatterjee would be required to relinquish his FERC position before seeking office in a partisan election or soliciting political contributions. Gubernatorial candidates must obtain 10,000 signatures to get on the ballot in Virginia.

Chatterjee said it was clear fellow commissioner Richard Glick wasn’t taking his potential candidacy seriously. After making opening remarks at Thursday’s meeting, Chatterjee invited comments from Glick, who said jokingly, “Thank you governor. I mean Mr. Chairman.”

Nevertheless, Chatterjee’s Facebook group had attracted more than 300 members as of Thursday, and none of those who pledged their support and campaign contributions seemed to be aware it was meant as a lark.

“I was joking around with my friends on my personal social media to try to get a reaction from my [them],” Chatterjee said when asked whether he was concerned that his posting could cause confusion. “It was not something that was in any way meant for the broader public. Maybe I should have spent more time building pillow forts. There [are] only so many pillow forts you can build. I was goofing around.”

Under questioning, the chairman declined to say unequivocally that he would not be running for governor next year, repeating, “I will serve my term until June 30, 2021.”