FERC rejected ISO-NE’s request to rehear its decision requiring the RTO to revise its energy storage rules to account for a resource’s state of charge in the day-ahead market (ER19-470-003).
The commission last November conditionally accepted ISO-NE’s Order 841 compliance filing, asking for additional changes to clarify the application of transmission charges to electric storage resources — an aspect of the ruling the RTO did not contest. (See Storage Plans Clear FERC with Conditions.)
But ISO-NE did seek rehearing of FERC’s determination that the proposal failed to show how the RTO would account for maximum run time and charge time, state of charge, and maximum and minimum state of charge in its day-ahead market, leaving storage resources open to infeasible schedules.
In its rehearing request, ISO-NE said that FERC erred in finding that the proposal failed to account for state of charge in the day-ahead market, contending that storage resources could account for their day-ahead state of charge by incorporating that state of charge into their maximum daily energy limit and maximum daily consumption limit parameters.
The 1,143-MW Northfield Mountain pumped storage hydro facility | FirstLight Power Resources
ISO-NE also argued that the commission’s requirement that the RTO “account for the resource’s state of charge at the start of each day-ahead market interval” would not prevent a storage resource from receiving an infeasible schedule.
In Thursday’s order, the commission emphasized that Order 841 defines state of charge (as a bidding parameter) as the level of energy that an electric storage resource is anticipated to have available at the start of the market interval rather than at the end.
FERC found the day-ahead market provisions in ISO-NE’s proposal do not comply with Order 841, which requires RTOs to account for state of charge so that electric storage resources can participate in the energy market without receiving dispatch points that violate their physical and operational limits.
“ISO-NE fails to recognize that its maximum daily energy limit and maximum daily consumption limit parameters only account for the cumulative amount of energy an electric storage resource can charge or discharge over the entire operating day, as opposed to at the start of each market interval,” the commission said.
The RTO had also contended that the commission had not given due weight to its efforts to integrate co-located storage resources into its markets. But FERC found that the fact that ISO-NE’s failure to account for state of charge and duration characteristics in the day-ahead market might better accommodate co-located facilities had no bearing on whether its electric storage resource participation model complies with Order 841.
The commission also found that issues regarding “the participation of electric storage resources co-located with other resources in ISO-NE markets are beyond the scope of this proceeding because Order No. 841 did not address co-location of electric storage resources with other resources.”
“We note, however, that nothing in the commission’s directives precludes ISO-NE from developing market rules tailored to electric storage resources that are co-located with generation,” the order said.
Finally, ISO-NE had argued that investing time and resources to change the day-ahead market on the current software platform would not be cost-effective while it is in the process of building a new platform. It requested that if rehearing was denied, the commission allow for an effective date of Jan. 1, 2026. FERC said it would address the effective date separately (ER19-470-004).
MISO is mounting a third attempt to gain FERC approval of a plan to overhaul the cost allocation design for economic transmission projects after two previous rejections.
This time the RTO will eliminate the local economic transmission project category from its proposal, a sticking point in the earlier filings.
FERC rejected MISO’s proposed cost allocation a second time on March 20, raising the same cost-causation issues that dogged the first filing (ER20-857). The commission took issue with MISO’s proposal to measure the value of a local economic project on a regional basis but cost-share only locally. The local economic project category was intended for smaller, economically driven transmission projects between 100 and 230 kV, where 100% of costs would be allocated to the local transmission pricing zone containing the line. (See Another Rejection for MISO Cost Allocation Plan.)
MISO said it will follow FERC’s recommendation to refile the regional allocation without including the local economic project category.
MISO Senior Manager of System Planning Jarred Miland said it would likely take months for stakeholders to reach consensus on how to treat 100- to 230-kV economically beneficial projects.
“We want to get this thing done, get this thing out. We feel we have support right now on the other parts,” Miland said during a Thursday conference call of the Regional Expansion Criteria and Benefits Working Group.
As in the first two filings, MISO’s newest proposal would lower the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV, eliminate the current 20% postage stamp allocation and add new benefit metrics for savings from the avoided costs for reliability projects and cost reductions related to the MISO-SPP transmission contract path. The proposal will also provide limited exceptions to the competitive bidding process if a transmission project were needed immediately for the sake of reliability.
“Everything will be pretty much like it was in the January filing. It’ll look pretty much the same; it just won’t have the local economic project component to it,” Miland said.
Clean Grid Alliance’s Natalie McIntire asked how economically beneficial projects between 100 and 230 kV will be treated going forward.
Miland said such projects would again be relegated to MISO’s “economic other” project category, which has no regional benefits test and dictates that smaller economically beneficial projects be allocated to the transmission pricing zone in which they are located.
However, he pointed out that the new lower voltage threshold for MEPs will most likely result in MISO approving more economic projects for cost-sharing.
Miland also said regional economic projects between 100 and 230 kV are rare in MISO.
“We haven’t seen much below 230 kV in the past, so I doubt we’ll see more in the future,” he said.
MISO said it will resubmit its regional cost allocation filing by the end of the month or in early May.
Miland said MISO will not collect stakeholder feedback on the refiling, added that FERC’s direction was specific enough and the RTO’s previous efforts have “already been a really, really long journey.”
As with the first two filings, MISO will again include a promise to review the effectiveness of the cost allocation approach after three years.
SATOA Tech Conference Set
MISO faces another obstacle related to the allocation of transmission project costs: the lack of an approved cost recovery mechanism for its first storage-as-only-transmission-asset (SATOA) project.
FERC scheduled a May 4 technical conference to discuss possible shortcomings with MISO’s SATOA proposal. (See MISO SATOA Proposal Set for Technical Conference.) The commission said MISO officials should come prepared to answer several questions, including those regarding:
the proposed evaluation and selection of SATOA as transmission-specific solutions;
why SATOA shouldn’t be allowed access to energy markets;
how the existing formula rate provides a cost recovery process for SATOA;
the possible impact of SATOA on the generator interconnection queue; and
state-of-charge responsibility.
MISO’s 2019 Transmission Expansion Plan (MTEP 19) contains the RTO’s first-ever SATOA project — American Transmission Co.’s Waupaca-area energy storage project, intended to ease transmission reliability issues in central Wisconsin — which was withheld from final MTEP 19 approval as the RTO waited on approval for its proposed SATOA rules. MISO had planned to have its Board of Directors hold a special March vote on the project once it had FERC’s go-ahead for its rules and cost-recovery method. (See MTEP 19 Could Yield First MISO SATA Project.)
The American Wind Energy Association on Thursday reported a “banner year” for the wind industry in 2019 but also acknowledged the storm clouds gathering on the horizon.
John Hensley, AWEA’s vice president of research and analytics, said 25 GW of projects — representing $35 billion in investment capital and tens of thousands of jobs — are at risk because of the COVID-19 pandemic. He pointed to national lockdowns in India and Spain and a slowdown in China as disrupting the industry’s supply chain and delaying some projects.
“The U.S wind industry is not immune to COVID-19 yet,” Hensley said. “We’re being impacted like any other industry.”
Indeed, General Electric’s LM Wind Power plant in Grand Forks, N.D., announced it will close for at least 14 days as state officials linked 128 positive cases of the coronavirus to the factory, which makes turbine blades.
Repowering activities at Pacificorp’s Goodnoe Hills Wind Farm in Washington | AWEA
The industry faces several challenges. It and other clean-energy sectors lost more than 106,000 jobs in March, according to a report by BW Research Partnership prepared for climate advocacy group E2. And those sectors will have a tough time arguing to the Republican-controlled Senate for inclusion in any further stimulus legislation that Congress may — or may not — pass. (See Renewable Tax Credit Extensions Not in Stimulus Bill.)
Hensley said AWEA is working with Congress to gain some “immediate flexibility” and stave off further losses. He said an extension of the safe harbor continuity window for wind projects begun in 2016 and 2017 “will address the immediate impact the developers are experiencing.”
Having learned that tax equity is becoming a concern, AWEA is also pursuing additional relief in the form of direct tax payments.
“Congress has been supportive,” Hensley said. “We do hope to have their continued support, so that clean energy can continue creating jobs.”
Wind power capacity grew 9.6% in 2019, with an additional 9.1 GW pushing total capacity to 105.6 GW. | AWEA
Otherwise, AWEA had nothing but good news to report. According to its “Wind Powers America 2019 Annual Report,” wind turbines are now the single largest provider of renewable energy in the U.S., surpassing hydro power to account for 7.2% of the nation’s electricity production.
Wind capacity cracked the 100-GW barrier in 2019, reaching 105.6 GW with 9.1 GW of new capacity and $14 billion in new projects. AWEA said the industry employed 120,000 people and provided $1.6 billion in local payments to communities and landowners last year.
Developers delivered 55 projects in 19 states during 2019, with Texas and Iowa both adding more than 1 GW of wind capacity. Texas has 3.9 GW of wind capacity and Iowa 1.7 GW. Wind energy provided more than 20% of generation in Iowa, Kansas, Maine, North Dakota, Oklahoma and South Dakota.
All seven U.S. grid operators set records last year for wind output and, with the exception of ISO-NE, for wind penetration. ERCOT produced a record 19,672 MW of wind energy last year, and SPP established a top mark for wind penetration at 68.8% (since raised to 72.4% on April 2).
ISOs and RTOs set wind output and penetration records in 2019. | AWEA
Utility and corporate buyers, taking advantage of wind costs that have fallen more than 70% during the last decade, also set records in 2019 with more than 8.7 GW of new power purchase agreements. Berkshire Hathaway Energy and Xcel Energy dominate the market with more than 16 GW of capacity between them; Google Energy is the only corporate buyer among the top 10, with 1.4 GW of capacity.
AWEA said the industry began 2020 with a near-record project pipeline of 44 GW of capacity either under construction or in advanced stages of development. Hensley said that while the organization continues to see projects moving forward, “It’s too early to know the full extent of those delays on construction plans.”
“Affordable, reliable energy is not a luxury — it’s a necessity,” AWEA CEO Tom Kiernan said in a statement. “While we are now working to mitigate the significant disruptions from COVID-19, we know that we will meet these challenges with strong industry momentum.”
James Danly attended his first FERC open meeting as a commissioner Thursday, albeit virtually, as the proceeding was held by teleconference because of the COVID-19 pandemic.
Danly, who served as general counsel for the commission from September 2017 until March 31, did not issue any concurrences or dissents during the meeting, joining Chairman Neil Chatterjee in voting “aye” on the consent agenda. But he did give some insight into his priorities and regulatory philosophy during his opening remarks.
He listed “correctly incentivizing needed transmission,” ensuring electric reliability and “the efficient and thorough review of our certificate applications” as his top issues.
FERC’s approvals of gas infrastructure “have been challenged repeatedly with ever greater frequency in the courts, and we have a nearly unblemished affirmance rate for the last two and a half years,” he said. “That is a testament to the reasoned decision-making of the commission in issuing these orders and to the legal durability of the commission’s orders. … I am adamant that we continue to maintain those high standards in our certificate issuances.”
He also said he was “committed to further refining the pricings in our markets,” asserting that the commission’s rejection Thursday of rehearing requests on its order expanding the minimum offer price rule in PJM “marks an important step in ensuring accurate price signals in the capacity market. But I think there’s more to be done.” He said he was interested in looking at pricing in the energy markets, as well as “the price effects of the participation of non-energy-producing resources in the capacity market.” (See related story, FERC: RGGI, Voluntary RECs Exempt from MOPR.)
Danly concluded with his ideology. “We have to respect the federalist principles that are enshrined both in our authorizing statutes and the Constitution. You know, the commission is not in the business of — typically not in the business of pre-empting state actions. What we do is administer the matters in our jurisdiction, specifically the wholesale rates in interstate commerce. …
“We need to observe those lines of authority that Congress has laid out for us. And on that subject, I don’t think the commission should be quick to expand its jurisdiction. As tempting as it can be sometimes, Congress has laid those lines very scrupulously, and we should follow them scrupulously. …
“Reasoned decision-making is not simply a sine qua non. … It is what the entities who we regulate deserve. … I would like to see us dispense with as much case-by-case analysis as possible when unambiguous, bright-line rules are feasible.”
In his own opening remarks, Commissioner Richard Glick welcomed Danly and remarked on his impressive vocabulary, including his frequent usage of Latin terms. Because of that, he said, he had a Black’s Law dictionary on hand. At the end of the meeting, Glick explained that sine qua non meant “an indispensable requisite.”
Danly also announced the first two members of his staff, who followed him from the Office of General Counsel: Matthew Estes, a former colleague of his at Skadden, Arps, Slate, Meagher & Flom; and Kyrstin Wallach, a 2017 graduate of the George Washington University Law School.
Longview Power, a 710-MW supercritical coal-fired generator that claims to be the most efficient coal facility in North America, filed for bankruptcy Wednesday — for the second time.
Its first bankruptcy in 2013 — when it said malfunctioning equipment hampered its operations — resulted in lenders taking all the equity in the company.
This time, the company says it was done in by liquidity problems resulting from rock-bottom natural gas prices, the loss of a nearby mine, and warm winters and energy efficiency that suppressed demand.
The COVID-19 pandemic didn’t help either, CEO Jeffery L. Keffer said in a 21-page affidavit that accompanied the company’s Chapter 11 filing in U.S. Bankruptcy Court in Wilmington, Del. The company, which said the plant generated $28.1 million of adjusted EBITDA in 2019, has $355 million in debt.
Longview Power plant near Morgantown, W.Va. | Longview Power
But the company said it has a prepackaged agreement that will allow it to emerge with lower debt. The company has been approved for a Payroll Protection Program loan to cover the wages of its 140 employees and says it plans to continue operations uninterrupted — and even expand with a 1,210-MW combined cycle gas turbine (CCGT) plant and a 70-MW solar farm. Keffer noted, without apparent irony, that the additional generation would increase revenues “at lower fixed costs per kilowatt” than the coal plant.
But Keffer insists that the coal plant isn’t a white elephant. “Despite recent trends, the PJM region requires a dependable coal-fired option in place for when energy demands inevitably increase. At times of national crisis, dependable utilities are at their most essential, and one key feature distinguishes coal from other existing energy sources — it can be stored.”
The $2 billion plant in Maidsville, W.Va., was “the first clean coal facility,” Keffer said, with equipment designed to be “one of the most environmentally compliant and cleanest coal plants globally.”
With an 8,750-Btu/kWh heat rate, 20% more efficient than older technology coal plants, “Longview is the future of coal,” the company’s website boasts. Indeed, Energy Secretary Rick Perry deemed it so in a 2017 visit.
But after two bankruptcies, does Longview have a future, or are the plant’s owners whistling past the graveyard? And what does its struggles say about the fate of the nation’s less efficient coal-fired generators?
Michelle Bloodworth, CEO of coal trade group America’s Power (formerly the American Coalition for Clean Coal Electricity), said wholesale markets are failing to compensate coal plants for their resilience and fuel security attributes.
“The exorbitant support in the form of subsidies, over $100 billion, that renewable sources of electricity have received over the past several decades has only further distorted the electricity markets,” she said. “We remain concerned that unless action is soon taken to address these flaws, more coal plant owners could be in the situation that Longview Power is in — which will mean we risk further loss of an important piece of a diverse electricity grid.”
Star-Crossed
Longview has had a star-crossed history.
The plant was designed with infrastructure to allow for development of a second “clean coal” generator, including a 4-mile-long conveyer belt to carry coal to the plant from a nearby mine owned by a Longview subsidiary, Mepco Holdings.
But when the plant went into operation in 2011 following construction delays, unscheduled outages and extended planned outages left the plant running at a capacity factor of only 68%, well below its design level of 90%.
Longview began a multiyear arbitration with its building contractors; unable to repay a $1 billion loan that helped fund construction, it filed for Chapter 11 protection in August 2013.
It emerged from bankruptcy in April 2015, with the company winning repairs to the plant and a $325 million loan as the original lenders took all the equity in the reorganized company.
Where Longview Power says it resides on PJM’s supply curve | Longview Power
Since the repairs, the plant has generally operated at its design levels, Keffer said.
But it was saddled with high financing costs, including a $30 million senior note at 12%. Then, in 2018, Mepco discontinued operations at all of its mines, including the one supplying Longview, citing “the aging of the mine and adverse geological conditions” that reduced its productivity and made it uncompetitive.
With the 4-mile conveyor belt no longer of any use, the company spent $8.3 million on a dock on the Monongahela River to receive coal deliveries from other mines.
“Under normal operating conditions, the debtors’ steady cash flows enable them to reliably service their funded debt obligations and weather ordinary variations in customer demands, but recent extraordinary fluctuations in the energy market have presented the debtors with new balance sheet challenges,” the company said in its filing.
In addition to the “demand destruction” resulting from energy efficiency and warm winters in PJM, “the coronavirus pandemic has resulted in significant reductions in demand as industrial and commercial users are shut down throughout the region and country,” it added.
Although they designed the site to accommodate a second coal generator, company officials now say they will add a 1,210-MW CCGT and a 70-MW solar farm. “Realization of these development plans would provide operational and fuel diversity to help shelter Longview from the volatility of energy industry trends in the long term,” Keffer said.
Will the company get there?
Despite its efforts to reduce operating costs, renegotiate fuel contracts and seek cheaper financing, the company began “reviewing strategic alternatives” in January 2020. On March 31, the company and lenders reached a forbearance agreement on a $750,000 amortization payment due that day.
With that breathing room — and facing the inability to pay off a $25 million revolving debt that matured on April 13 — the company reached the prepackaged reorganization with its lenders. Twelve investment funds currently own almost 96% of Longview Intermediate Holdings, the plant’s parent company, led by KKR Credit Advisors with 42%. The Wall Street Journal reported that KKR will lose nearly all of its ownership in the deal.
Keffer said the plan will allow “a comprehensive balance sheet restructuring that will reduce Longview’s debt burden, increase liquidity and send a strong message to Longview’s employees, vendors and other business partners that Longview is well positioned for future success.”
Proportion of units recovering avoidable costs: 2011-19 | Monitoring Analytics
The deal will eliminate $350 million of first lien and subordinated debt and provide the company a $40 million
“exit facility” loan from secured term lenders that will take a 90% stake in the reorganized company. It also allows “unimpaired” payments to unsecured creditors to ensure “minimal impact on the debtors’ operations and their key business partners.”
The company asked the court to have creditors vote on the plan by May 1 and schedule a confirmation hearing on May 22.
But even if all goes as planned, Longview faces a difficult future.
The Independent Market Monitor’s 2019 State of the Market report said only 26% of PJM’s existing coal fleet was able to recover its avoidable costs from energy, capacity and ancillary services revenue in 2019, down from 68% the year before. New coal plants have not received enough net revenue to cover their costs in any zone in the RTO since 2009, two years before Longview began operation.
Conditions have worsened this year with day-ahead electricity prices at the PJM West hub averaging $19.83/MWh, a 47% drop from the $37.48/MWh average in 2018 and 2019, the company said.
Keffer had expressed confidence during Secretary Perry’s 2017 visit that natural gas prices would rise once more pipelines are built to take it from Pennsylvania and West Virginia. “The world is clamoring for our natural gas,” he said. “Once they start consuming that gas, your supply is going to start matching that demand. So the price is going to go back up.”
Natural gas is currently selling at about $1.40/MMBtu at the Dominion South hub, down from the $2.65/MMBtu average in 2018/19, Keffer said. “The price of natural gas is even lower in the immediate area where Longview operates due to the presence of shale gas,” he added.
His filing includes a 13-week pro forma projecting the plant will generate $20.3 million in revenue through July 10. Operating expenses of almost $25 million will leave it with a negative cash flow of $4.6 million for the period.
Expansion Plan
On the positive side, Longview said it will be able to add the combined cycle plant at $200 million less than the cost competitors would have to pay for a comparable new build in PJM, thanks in part to the Dunkard Creek water treatment facility, which can serve both Longview and the CCGT project.
Permitting for the CCGT project is expected to be completed during the first quarter of 2021.
Planned solar and combined cycle expansion at Longview Power plant | Longview Power
The solar project would involve 188,000 370-watt panels over 300 acres in Maidsville and Greene County, Pa. The solar project will include the laydown areas for the CCGT project — the areas used for receipt, storage and assembly — after the gas plant is completed, the company said.
The math for new gas and solar plants is more encouraging than that of coal. In 2019, a new CCGT would have received sufficient net revenue to cover levelized total costs in half of PJM’s 20 zones, the Monitor reported. Recovery was 98% in 2019 in the APS zone, where Longview is located.
New solar projects would have sufficient net revenue to cover levelized total costs in AECO, JCPL and PSEG, where renewable energy credit revenues are high, but not enough to cover costs in Dominion or DPL, the Monitor said.
NYISO on Tuesday floated a plan that would provide hybrid storage resources (HSRs) three options for participating in its energy and capacity markets.
Kanchan Upadhyay and Amanda Myott, NYISO energy and capacity market design specialists, respectively, presented an overview of the plan.
“The project seeks to explore participation options for co-located, front-of-the-meter generators and energy storage resources,” Upadhyay told the ISO’s Installed Capacity/Market Issues Working Group during a teleconference. “And we have seen that some of the incentives, along with improvements in flexibility and availability, are motivating developers to couple generation resources with storage resources, so we expect more and more of these kind of resources in future.”
NYISO wants to see HSRs participate under existing market models as much as possible. While that may necessitate minor modifications to existing market rules, it would allow for quicker implementation of changes. If existing market rules need to be modified, such changes will be developed for a potential vote at the Business Issues Committee by the end of 2020, Upadhyay said.
HSR participation options under consideration by NYISO | NYISO
The ISO is proposing that HSRs participate as distinct generators (Option 1); through an aggregation model to allow resource components within the HSR to share a point of interconnection (2); or as a self-managed energy storage resource (ESR) (3).
Installed capacity (ICAP) and unforced capacity (UCAP) for each resource component under Option 1 would be calculated based on the existing method applicable to that resource type, noting that UCAP is calculated using the availability-based method for ESRs and the performance-based method for intermittent resources.
The ISO would calculate ICAP and UCAP under Option 2 using the availability-based method, consistent with existing distributed energy resource rules, in which the upper operating limit of the entire HSR would be used to measure availability.
Under Option 3, ICAP and UCAP would also be calculated using the availability-based method, but using the upper operating limit of the ESR asset within the HSR to measure availability.
“There is no new option between deploying the ESR model and deploying the DER model,” said Michael DeSocio, NYISO director of market design. “Option 3 is an extension of the ESR participation model, which could be introduced before [new DER rules] because it’s really leveraging the ESR rules, procedures and modeling.”
“We think Option 2 is one that could be implemented along with or just after DER because it is leveraging the DER rules, procedures and modeling,” DeSocio said. “We are not prepared to change Option 2 today to allow these resources to provide operating reserves, mainly because the [Northeast Power Coordinating Council] rules that determine which resources can provide which reserves are pretty stringent.
“We would have to work with NPCC to see if changing these rules is even possible to do, and I also believe the rules in the Eastern Interconnect are very different from the rules in the Western Interconnect, which is mostly why you see large differences in reserve participation modeling between California and New York,” DeSocio said.
The ISO plans to continue discussing and developing market participation concepts for HSRs this quarter and present consumer impact analysis and a complete market design to stakeholders in the third quarter, Upadhyay said.
NERC’s team updating the requirements for determining and communicating system operating limits (SOLs) is preparing for a 45-day comment period and formal ballot to begin April 23 (Project 2015-09).
In a webinar earlier this week, standards drafting team chair Dean LaForest of ISO-NE said the team is hopeful that it has addressed industry objections raised in two previous ballots in 2017 and 2018 on standards FAC-010, FAC-011 and FAC-014. He acknowledged that the SDT’s efforts had not progressed as quickly as hoped over the past several years, due in part to a decision to expand its scope beyond NERC’s original mandate.
“Our drafting team was established to modify a succinct set of FAC standards,” LaForest said. “What has ensued since is a realization … that to do so properly seems to also include an alignment of other standards … that deal with SOLs and SOL exceedances.”
The team saw this move as necessary since exceeding SOLs could have impacts across utilities’ operations, but its widening focus troubled industry participants. Along with the original three standards, the proposal eventually involved changes to CIP-014, PRC-002, PRC-023, PRC-026, FAC-003 and FAC-013, and introduced a new standard, FAC-015.
In particular, the team’s last in-person meeting this year focused on criticism of the potential administrative burden of the logging and communication activities required by the proposed standards. (See SOL Project Team Preparing for March Posting.)
Flexibility in Exceedance Communication
The latest proposal includes several modifications in response to these industry objections. Significantly, requirements in FAC-011 were updated to provide a “clear, consistent framework for SOL exceedance determination” and a new method for communicating exceedances between reliability coordinators and transmission operators. Reliability standards TOP-001 and IRO-008 would also be impacted by the changes.
Taken together, the new requirements would enable RCs to set a threshold for communicating exceedances based on the risk posed to the bulk power system, rather than being tied to a specific number. The team hopes this move will provide operators with the flexibility needed to respond to changing local conditions.
“We feel like this really allows the operators to focus on the critical activities of mitigating the SOL exceedance, rather than … [having] to have my operators pick up the phone … to tell someone else about something that happened five minutes ago,” said Stephen Solis of ERCOT. “That has been the focus of the last few months of intensive discussions on this particular subject, and we feel like we landed on a good spot [and] tied it to IRO and TOP standards so that the notification piece [doesn’t] take up a majority of the operator’s time.”
FAC Standard Changes Dialed Back
In another major update, the team decided to drop its proposed new standard, FAC-015 — which would have addressed criteria for determining SOLs — based on industry feedback that FAC-014 already meets this need without requiring a new standard. Instead, SDT members decided to add a new requirement to FAC-014 mandating that planning coordinators and transmission planners use facility ratings, voltage limits and stability criteria that are “at least as conservative as those used in operations.”
In addition to simplifying the SDT’s proposal, the change will also create a more straightforward case for retiring FAC-010, which relates to determining SOLs for system planners.
“As long as they are either more conservative than [those] used in operations, or they describe why they are not, they meet the intent of the requirement, and there is coordination between the limit assumptions used in operations and planning,” said LaForest. “We believe this will allow us to retire FAC-010 and still meet the original intent and purpose for the joint standards issued some 10-plus years ago.”
The judge in the Pacific Gas and Electric bankruptcy case on Tuesday prohibited the utility from paying its criminal fines from a trust fund meant to compensate fire victims. Instead, the company agreed during a hearing that it would pay its fines from interest on a separate escrow account.
The company agreed to plead guilty last month to 84 counts of involuntary manslaughter and one count of unlawfully starting a fire, with special circumstances including causing great bodily injury to a firefighter over the November 2018 Camp Fire. PG&E’s deal with the Butte County District Attorney calls for it to pay $3.5 million in fines and $500,000 to the prosecutor’s office to cover the costs of its investigation. (See PG&E to Plead Guilty to Killing 84 in Camp Fire.)
News that the utility planned to tap the victims fund for the fines caused an uproar among fire victims.
PG&E argued that it was required by the terms of its Chapter 11 restructuring agreements to pay the fines and fees from a $13.5 billion trust it plans to establish for more than 70,000 victims of blazes its equipment started in 2015, 2017 and 2018.
Paying the fines directly, in violation of the agreements, could allow the banks providing billions of dollars in backstop financing to back out of the deal, PG&E lead attorney Stephen Karotkin said during Tuesday’s hearing, which was held via conference call because of the coronavirus pandemic. He argued the company had been unfairly criticized for wanting to pay the fines from the victims’ trust.
“There was no sinister motive,” Karotkin said.
U.S. Bankruptcy Judge Dennis Montali said he couldn’t accept PG&E’s payment plan. Lawyers in the case had been masterful at preserving their clients’ legal rights, he said, “and my right here is to not tell the fire victims, ‘You’re going to pay $4 million to a company that has confessed and killed under the criminal laws.’”
The judge issued a tentative ruling Friday expressing similar sentiments.
“Some things not only have to be right, but they have to look right,” Montali wrote. “Telling fire victims that their money will be used to pay criminal fines and penalties does not look right even if digging through the [restructuring agreement] or the [reorganization] plan would lead to that literal result. Nor does saying to people who lost their homes and their loved ones that $4 million is ‘de minimis.’ This not only looks wrong, it is wrong.”
PG&E’s lawyers agreed that if the judge ordered it, the utility would pay its fines from interest accrued on an $11 billion escrow account it intends to establish for another group of claimants, insurance companies and hedge funds that hold third-party subrogation rights based on the prior payment of insurance claims.
Once the escrow account is funded, it will take about two weeks to accrue $4 million in interest, Karotkin told the judge.
PG&E, one of the nation’s largest utilities, filed for bankruptcy in January 2019 after two years of devastating wildfires. It’s hoping to emerge from bankruptcy by June 30 to avoid a threatened state takeover and to participate in a wildfire insurance fund established under state law.
The company has sent out approximately 250,000 ballots and disclosure statements to fire victims, creditors and others entitled to vote on its bankruptcy reorganization plan. The ballots are due by May 15.
The company has acknowledged its equipment ignited the Camp Fire, killing 84 residents and destroying 18,804 structures in and around Paradise, Calif. An 85th resident who died in the fire was deemed a suicide and not included in the charges.
[Updated to include MISO comments from conference call April 15.]
MISO’s eighth annual capacity auction marked the RTO’s first clearing price set by its cost of new entry (CONE), as prices in the Lower Peninsula of Michigan rocketed to almost $260/MW-day while all other zones cleared under $7/MW-day.
Zone 7 cleared at the CONE price of $257.53/MW-day for planning year 2020/21, beginning June 1.
The RTO’s CONE is used as the maximum offer and clearing price in the Planning Resource Auction. CONE represents the estimated annualized capital cost of constructing a 237-MW combustion turbine plant in different locations in the footprint.
Since beginning its capacity auctions in 2013, MISO has never experienced prices set by CONE. This year’s capacity prices in Lower Michigan are more than ten times the price of capacity paid in the last planning year.
The RTO said Zone 7 fell 123 MW short of its nearly 22-GW local clearing requirement and had to turn to other zones for capacity procurement, thereby triggering the CONE price. The RTO said only about 1,150 MW of load — 6% of Zone 7’s forecasted peak — must pay the CONE rate because MISO is mostly vertically integrated utilities that procure their own capacity outside the PRA.
“The results also reflect the industry’s ongoing shift away from coal-fired generation and increasing reliance on gas-fired resources and renewables,” the RTO said in a release.
All other MISO capacity zones remained below $7/MW-day, with most around $5/MW-day:
Zones 1-6 — which include Minnesota, Iowa, Illinois, Indiana, Missouri, Montana, Wisconsin and the Upper Peninsula of Michigan — cleared at $5/MW-day;
Arkansas’ Zone 8 and Mississippi’s Zone 10 cleared at $4.75/MW-day; and
Louisiana and Texas’ Zone 9 cleared at $6.88/MW-day.
Additionally, external resource zones cleared between $4.89-$5.00 depending on where they connect to the MISO system.
The RTO received 141.5 GW worth of offers in this year’s auction, about 6 GW above the nearly 136-GW reserve margin requirement for June 2020 through May 2021. It expects an almost 122-GW coincident system peak this summer.
MISO also said the South-to-Midwest transmission transfer limit bound during the auction, causing a $0.25 price separation between the Midwest and South. The last time the transfer limit bound in the capacity auction was in 2016. Zone 9 also experienced a slightly more expensive clearing price than most other zones because of a higher local clearing requirement. MISO predicts zones will hit their summer peaks at different times and assigns separate local clearing requirements.
MISO stressed that it continues to have sufficient capacity in the footprint.
“This year’s results reflect adequate resource availability for the upcoming planning year,” MISO Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said. “The grid’s capability to effectively transfer resources among zones remains strong, and we appreciate our members’ participation.”
“Most of the zones cleared at a relatively low prices, reflecting trends we’ve seen over the last few years. The vast majority are well-positioned to meet their capacity needs,” MISO Manager of Capacity Market Administration Eric Thoms said during a special April 15 conference call to discuss auction results. “That’s indicative of the makeup of the footprint.”
But Thoms said Zone 7 has frequently been “very tight, capacity-wise.”
Thoms also emphasized to stakeholders that CONE is function of MISO’s FERC-accepted Tariff, and most load-serving entities in lower Michigan would not be exposed to the CONE price.
“Per the Tariff, if the zone is short of its local clearing requirement, it’s capped at CONE,” he explained.
Thoms also said Zone 7 was impacted by a new rule this year that prohibits resources from offering into the auction if they will be on outage for longer than 90 days of the first 120 days of the planning year. Thoms estimated that the rule impacted 200 to 300 MW of planning resources in Zone 7.
“Being that Zone 7 was tight on a razor’s edge … the outage policy contributed to the zone not being able to meet its local clearing requirement,” he said.
MISO fully expects to field more questions about Zone 7 at upcoming Resource Adequacy Subcommittee meetings, Thoms said.
“There’s going to be a lot of speculation about what this means for Zone 7 this summer,” Coalition of Midwest Transmission Customers attorney Jim Dauphinais said.
Before this year’s Zone 7 price, the most expensive capacity price ever recorded in MISO was the $150/MW-day in southern Illinois’ Zone 4 during the 2015/16 PRA. The price spurred allegations of market manipulation, a three-year FERC investigation and — five years later — a contested FERC assurance that nothing untoward occurred. (See FERC Shelves Grievances over MISO Capacity Auction.)
MISO said auction results line up with the annual Organization of MISO States-MISO resource adequacy survey, which predicted adequate reserves through 2022 but warned that Zone 7, Zone 4 and Indiana and western Kentucky’s Zone 6 have the greatest resource adequacy risks. Last year’s survey indicated a potential 0.9-GW shortage in lower Michigan in 2020. (See Supply Future Brighter, OMS-MISO Survey Shows.)
The RTO said conventional generation will provide about 80% of capacity this planning year. Coal is set to provide 34% of capacity, while natural gas will provide 38%. Nuclear generation again holds steady at about 9%.
However, MISO said renewable capacity continued to gain market share. It reported 850 MW of solar generation cleared this year’s auction — an increase of 25% from last year — and 3,275 MW of wind generation cleared, a 21% year-over-year increase. Demand-based resources also climbed, providing nearly 16 GW of capacity as compared to last year’s nearly 15 GW.
The RTO said will publish the cleared load-modifying resources to the nonpublic MISO Communications System by May 25.
A broad coalition of independent power producers and renewable energy and trade groups petitioned FERC Monday to convene a technical conference on integrating carbon pricing into organized wholesale electric markets (AD20-14).
“Currently, certain FERC-jurisdictional wholesale electric energy and capacity markets are grappling with how to reconcile wholesale markets and state policies related to reducing carbon emissions, which has a bearing on FERC’s jurisdictional scope, such as how these markets function and the prices charged therein,” the group said. “In recognition of the fact that a number of organized markets are considering how to incorporate carbon pricing into organized wholesale electric markets to better align with state and regional carbon pricing mechanisms, the time appears ripe for the commission to convene a technical conference or workshop on these issues.”
Notably, the petitioners include both renewable energy advocates who support renewable portfolio standards and generators who say such state subsidies distort capacity markets. For example, the group includes independent power producer Calpine — whose complaint led to FERC’s December order requiring PJM to expand its Minimum Offer Price Rule (MOPR) to include all new state subsidized generation — and clean energy and renewable groups: Advanced Energy Economy, the American Council on Renewable Energy and the American Wind Energy Association.
A coalition of generators and renewable energy and trade groups asked FERC to hold a technical conference on integrating carbon pricing into wholesale electric markets, saying it should resume the discussion at the commission’s May 2017 conference (pictured). | RTO Insider
Also signing the petition were IPP groups the Electric Power Supply Association (EPSA), the Independent Power Producers of New York and PJM Power Providers Group, as well as several of their members, including LS Power Associates, NextEra Energy, Brookfield Renewable, Competitive Power Ventures and Vistra Energy. The Natural Gas Supply Association (NGSA) and think tank R Street Institute also joined in.
Notably absent was carbon pricing supporter Exelon, whose nuclear plants have benefited from zero-emission credits (ZECs) and would be subject to PJM’s expanded MOPR. Exelon did not immediately respond to a request for comment.
The request suggests the scope of the conference include a discussion of ways in which carbon could be priced and how wholesale market pricing and dispatch could account for compliance costs, including a look at existing constructs such as the Regional Greenhouse Gas Initiative (RGGI) and the California-Quebec cap-and-trade agreement, which last month won a preliminary ruling in a challenge by the Trump administration.
“We think the commission could grant the request, particularly if other stakeholders welcome the idea of a discussion,” ClearView Energy Partners’ analyst Timothy Fox said in a report to clients. “… If FERC expresses no interest in participating in such discussions, then green-leaning states that have decarbonization of their electric portfolios as a central goal may find the organized markets as presently structured pose an impediment instead of a vehicle to reaching their goals.”
2017 Conference
The groups said the technical conference should “pick up where the commission left off” in its May 2017 technical conference on the interplay between wholesale markets and state policy choices (AD17-11). (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
Fox said FERC’s June 2018 order that proposed a “carve out” for state-sponsored resources in PJM “appeared to be a solid move” in support of one of five potential pathways discussed by FERC staff at the conference, that of “accommodating” state policies. “However, we think the commission abandoned that path in its December 2019 order” directing PJM to expand its minimum offer price rule to cover all new state subsidized resources, he added.
Since the 2017 conference, NYISO has proposed introducing a carbon price in its wholesale market to accommodate the state’s approval of ZECs for some of its nuclear fleet.
PJM has released a study on how it could implement carbon pricing for a subset of its states, with border adjustments to counteract leakage. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.)
CAISO implemented a carbon adder in the Western Energy Imbalance Market for bids coming into California from states not subject to California’s cap and trade rules. (See FERC OKs CAISO Changes to EIM Bid Adders.)
The petitioners emphasized that they were not asking the Republican-controlled commission to institute a rulemaking nor suggesting that FERC direct implementation of a carbon pricing mechanism.
“The aim of the technical conference would be to facilitate a dialogue among a broad range of stakeholders and interested parties regarding the opportunities and challenges associated with integrating carbon pricing in the organized wholesale electric energy markets, in recognition that such carbon pricing may be an approach that furthers state policies while preserving the benefits of market-based approaches to electric energy markets.”
Jeff Dennis Advanced Energy Economy | Advanced Energy Economy
Jeff Dennis, managing director and general counsel of Advanced Energy Economy, said in an email that the “set of signatories … suggests alignment on the broad view that implementing carbon pricing in some form would be a good thing for the markets and for achieving decarbonization policy goals.”
” … As the petition notes, the signatories do not necessarily agree on all aspects of the role of carbon pricing in wholesale markets, including the degree and manner in which state policies will evolve in the future as carbon pricing is more broadly implemented in the electricity sector and beyond.”
Other members of the coalition issued statements in support on Tuesday.
“Calpine’s core principles include support for competition and environmental stewardship,” CEO Thad Hill said. “We believe that placing an economy-wide price on carbon will spur competitive markets to produce the most cost effective and environmentally responsible solutions.”
EPSA CEO Todd Snitchler said, “America’s competitive electricity markets are a success story — and market-based mechanisms such as carbon pricing could be a powerful tool as we write the next chapter.”
“Our hope is that FERC’s willingness to convene a broad stakeholder discussion on carbon pricing will prompt states to seriously consider it as a solution to meeting consumers’ needs and clean energy targets,” said Dena Wiggins, CEO of the NGSA.
PJM Power Providers Group President Glen Thomas said “the piecemeal carbon policies that are emerging in the PJM footprint are growing increasingly problematic and leading to less efficient markets for consumers. It is time for a regional and national conversation in order to evaluate whether there is a better regional solution out there. We hope that FERC accepts this opportunity to facilitate that conversation.”
Texas-based Vistra Energy “strongly believes that a nationwide carbon-pricing policy, like the [Climate Leadership Council’s] Bipartisan Climate Roadmap sets forth, is the most effective, achievable and fair solution,” said CEO Curt Morgan. “Our company also holds that regional carbon pricing is a worthy intermediate step and a discussion at FERC could facilitate further discussions at the ISO and regional level.”
