MISO’s Board of Directors last week cleared the Advisory Committee to create an 11th stakeholder sector while also instructing the committee to overhaul its sector design to produce a fuller participatory model.
The board said the committee’s recent recommendation to create a new “Affiliate” sector for hard-to-define members works only in the short term. It directed it to develop a long-term solution that guarantees all members full participation in the stakeholder process. (See MISO Advisory Committee OKs 11th Sector.)
In the meantime, MISO should file with FERC revisions to its Transmission Owners’ Agreement (TOA) to include the new sector, the board said.
Board Chair Phyllis Currie said the board met to discuss the proposal and agreed that it should be in place only until the AC creates a new proposal focused on fair participation for sectors and mindful of voting power. She also said the AC should ensure that sectors are divided into groupings of likeminded members.
“I say ‘short term’ because I think in the longer term, there still needs to be more discussion on how various sectors participate,” Currie said during a committee conference call Wednesday. The meeting took place via conference call instead of in New Orleans as originally planned because of the spread of the COVID-19 coronavirus. (See Virus Fear Sends MISO Board Week to the Web.)
Currie urged the AC to examine its current voting structure and think about affording members an equal voice. She said the board would give the committee a year to draft a fuller solution for incoming — and increasingly diverse — members.
The new sector would not be allowed a vote in either AC or Planning Advisory Committee matters, but it would have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.
The sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.
“I think other interest groups, other businesses, other NGOs will come to the table,” Director Nancy Lange told the AC.
The AC began debating the merits of an 11th sector last year when Lignite Energy Council, a North Dakota coal lobbying group, approached MISO about membership. The organization did not fit neatly into any of the existing 10 sectors and was almost relegated to the Environmental and Other Stakeholder Groups sector. But some AC members said it wasn’t appropriate for a sector to contain entities with diametrically opposed views and said the new sector was necessary to allow the Environmental/Other sector to have a singular voice. The Environmental/Other sector would be able to drop its “other” designation if FERC accepts the changes to the TOA.
Environmental/Other sector representative Beth Soholt said that, save for the Energy Storage Association, all other entities in the sector have an environmental focus.
So far, the proposed Affiliate sector seems destined for a fossil-fuel focus — at least at the onset. LEC indicated that it has drummed up interest among other entities interested in joining the new sector, including coal and iron mining organizations, coal trade organization America’s Power and various chambers of commerce.
LEC CEO Jason Bohrer said his organization had been “working on earning a seat at the table for the past 18 months.” He said the board’s decision was “a significant step in this long process.”
“We applaud the work of the MISO Advisory Council, the Board of Directors and MISO staff, as well as our partners like America’s Power, for their support of opening up the regional market planning stakeholder process to more voices and perspectives, which now will include coal producers along with chambers of commerce and other organizations that have strong electricity market interests,” Bohrer said in an email to RTO Insider. “We look forward to providing a strong voice for the coal miners and utilities who provide the electricity that is the ‘always-on’ backbone for the electric grid and the economy in our region.”
Hot Topic Panel Delayed
On the same conference call, the AC postponed the policy discussion portion of its meeting until June.
The committee was supposed to hold a panel-style discussion featuring industry experts as its quarterly hot topic discussion during the March Board Week. The panel was meant to focus on how RTOs deal with resource transition and would have featured one executive apiece from NYISO, CAISO and ERCOT. However, AC leadership said a panel discussion was too difficult to navigate in a teleconference-only format.
The wind and solar industries were disappointed last week that Congress’ massive $2 trillion stimulus bill did not include extensions of the production and investment tax credits.
In a joint letter to Congress, the American Wind Energy Association (AWEA) and the Solar Energy Industries Association (SEIA) said the COVID-19 coronavirus pandemic was causing “delivery delays, necessary employee absences, serious financing concerns, and project cancellations or postponements. This is jeopardizing the jobs of our combined 364,000 workers, threatening to sidetrack tens of billions of dollars in investment.”
President Trump on Friday signed the bill, the largest stimulus legislation in U.S. history, as shelter-in-place rules grind the U.S. economy to a near halt.
The major provisions of the Coronavirus Aid, Relief and Economic Security (CARES) Act (S. 3548) include $1,200 checks for millions of taxpayers “as rapidly as possible”; programs to disburse nearly $900 billion in loans to business impacted by the pandemic; and an expansion unemployment benefits.
AWEA CEO Tom Kiernan said “relief provisions ensuring renewable projects can secure financing and meet safe harbor continuity schedules are critical to preserving a strong domestic clean energy sector. Making these adjustments to existing tax credits would provide the industry the flexibility needed to accommodate COVID-19 delays, without costing the federal government any additional money. … Without assistance, 35,000 American jobs, $43 billion of investment and $8 billion in payments to local communities are at risk.”
President Trump signed the CARES Act on March 27. | The White House
SEIA CEO Abigail Ross Hopper acknowledged that some of the bill’s provisions for individuals and displaced workers would benefit solar industry workers. But she warned that “as a result of this pandemic, the solar industry stands to lose half of our jobs.”
The tax credit extensions were also not part of a separate bill introduced by House Democrats while Senate leaders and Treasury Secretary Steve Mnuchin negotiated over the Republican-crafted CARES Act, though the House bill did include emission limitations for airlines. When Democrats blocked passage of the Senate bill March 22, Majority Leader Mitch McConnell (R-Ky.) the next day falsely accused them of holding up the bill over the extensions and emission limits.
“Democrats won’t let us fund hospitals or save small businesses unless they get to dust off the Green New Deal,” McConnell said. “They’re continuing to hold up emergency measures over tax cuts for solar panels.”
In truth, McConnell was outraged by Democrats blocking a procedural motion on the bill after he had rallied his caucus members to bite their tongues and pass a House Democrat-crafted bill the week before as an initial response to the crisis. Minority Leader Chuck Schumer (D-N.Y.) and his caucus were likewise peeved that Republicans had included a $500 billion fund in the CARES Act to bail out corporations harmed by the crisis without any oversight provisions. The partisan rancor led to a rare, actual debate on the Senate floor, between McConnell and Sen. Joe Manchin (D-W.Va.).
After two days of negotiations, however, the Senate ended up passing the bill early Wednesday morning, 96-0. The House of Representatives followed on Friday, passing the bill by voice vote, rather than unanimous consent off the floor as Speaker Nancy Pelosi (D-Calif.) and Minority Leader Kevin McCarthy (R-Calif.) had wanted, after Rep. Thomas Massie (R-Ky.) indicated he would object and attempt to force members to record their votes.
This forced 218 members of the House to travel back to D.C., some of whom drove to avoid flying, to assemble a quorum to block Massie’s motion — this despite the Centers for Disease Control and Prevention’s advisory not to have 10 or more people gathered in one place.
Trump signed the bill into law hours after the House passed it.
FERC last week rejected AMP Transmission’s request for a waiver of the commission’s Standards of Conduct and requirements to maintain an Open Access Same-Time Information System (OASIS) (TS19-1).
AMP Transmission (AMPT) is an affiliate of American Municipal Power that was created to own and operate the transmission facilities of AMP and AMP’s members. AMP has purchased a 138-kV ring bus from the city of Napoleon, Ohio, and plans to purchase a similar transmission facility from Wadsworth, Ohio, both less than 50 feet in length. It also owns a 1.84-mile, 69-kV transmission line and two 69-kV station facilities in Amherst, Ohio.
AMPT said it qualified for a waiver of the OASIS and Standards of Conduct requirements because its facilities are “limited and discrete,” geographically dispersed and do not form a contiguous network.
American Municipal Power headquarters in Columbus, Ohio | American Municipal Power
AMPT said its transmission function employees work independently from AMP’s marketing function employees and that it has contracted with Gridforce Energy Management to provide NERC transmission compliance services.
But PJM and its Transmission Owners sector told FERC the waiver should be rejected because the marketing affiliates of AMPT will have access to nonpublic transmission information through its participation in the PJM Transmission Owners Agreement-Administrative Committee and other committees where planning or operational transmission information is discussed.
The TOs said that if the commission approved the waiver, it should prohibit AMPT from participating in PJM activities and TO meetings in which nonpublic transmission information is disclosed or discussed, noting that Old Dominion Electric Cooperative committed to similar conditions when it sought waivers from the commission.
The TOs expressed concern that a waiver would give AMP the ability to use nonpublic information available to PJM transmission operators to benefit AMP’s merchant trading — the kind of behavior the Standards of Conduct’s no-conduit rule was designed to prevent.
The commission agreed.
“We find that an entity like AMPT that participates as a transmission owner in an RTO or ISO cannot qualify for waiver of the commission’s OASIS or Standards of Conduct requirements on the basis that its facilities are limited and discrete,” FERC ruled. “Although AMPT’s facilities are limited in size, AMPT’s participation as a transmission owner in PJM qualifies its facilities as an integral part of the integrated PJM grid and therefore AMPT’s facilities cannot be considered as limited and discrete under our waiver precedent.”
The California Public Utilities Commission has established two building decarbonization pilot programs to jump start the state’s electrification of residential structures, devoting $200 million toward the effort.
The Building Initiative for Low-emissions Development (BUILD) program and the Technology and Equipment for Clean Heating (TECH) initiative were created under Senate Bill 1477, which the state Legislature passed in 2018. Lawmakers tasked the CPUC with implementing the programs.
“These two pilot programs are designed to develop valuable market experience for the purpose of decarbonizing California’s residential buildings in order to achieve California’s zero-emissions goals,” Commissioner Liane Randolph wrote in her proposed decision, which the commission adopted March 26.
“The BUILD program and TECH initiative are building decarbonization pilot programs intended to raise awareness of building decarbonization technologies and applications, test program and policy designs and gain practical implementation experience and knowledge necessary to develop a larger scale approach in the future,” the CPUC said.
The move comes amid efforts by some cities to require electrification of new, and in some circumstances, existing structures. Eliminating furnaces and water heaters that use natural gas could contribute significantly to California’s efforts to become carbon-neutral by midcentury, advocates contend. (See West Coast Pushesfor Building Electrification.)
Replacing traditional gas appliances such as water heaters with electric units is a key goal of electrification. | Edison International
The BUILD program is meant to incentivize technologies in new residential buildings that reduce greenhouse gas emissions (GHG) well beyond the requirements of the state’s building and energy codes.
The California Energy Commission will administer the program with CPUC oversight. At least 30%, or $60 million, of the total $200 million must be earmarked for new low-income housing under SB 1477.
“This percentage is not the ceiling for spending on low-income housing but rather, the floor,” the proposed decision says.
“The CEC should aim to design the BUILD program with the goal to deploy near-zero emission building technologies in the largest number of new residential housing units possible,” it says.
The TECH initiative is intended to promote the adoption of space heating and water heating equipment powered by electricity instead of gas in new and existing residential structures. A third party, still to be selected, will implement the program, with specific technologies still to be identified, the CPUC said.
“To accelerate market development and adoption of building decarbonization technologies targeted under the TECH initiative, we allow the implementer discretion to consider or build upon an array of tactics and approaches,” the CPUC said. “We decline to adopt a prescriptive list of eligible technologies and products until an implementer is selected.”
American Electric Power on Monday warned shareholders that the company’s financial condition and operations could be “adversely affected” by the COVID-19 pandemic as other utilities considered delaying spring maintenance.
In an 8-K filing with the Securities and Exchange Commission, AEP said it is working to mitigate the pandemic’s “potential risks” and that it will continue to review and modify its plans as conditions change.
AEP’s headquarters building in Columbus, Ohio.
“Despite our efforts to manage these impacts to the company,” AEP said, “their ultimate impact also depends on factors beyond our knowledge or control, including the duration and severity of this outbreak as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, we currently cannot estimate the potential impact to our financial position, results of operations and cash flows.”
The Columbus, Ohio-based company said it has updated and implemented a company-wide plan that addresses specific aspects of the coronavirus pandemic. The plan provides guidance on emergency response, business continuity and precautionary measures to take on behalf of employees and the public, the company said.
“This is a rapidly evolving situation that could lead to extended disruption of economic activity in our markets,” AEP said.
Deferred Maintenance
As of Tuesday, other major utilities including Con Edison, Exelon, NextEra Energy, Entergy, CenterPoint Energy and Sempra Energy had not issued similar warnings to their stockholders.
AEP and other Edison Electric Institute members have pledged to suspend utility disconnects during the crisis.
DTE Energy announced March 23 that it is suspending all noncritical infrastructure and maintenance in response to the pandemic. “This move to keep employees home — in instances other than emergency response to customers — helps to ensure they do not add to the growing spread of the virus and further stress the health care system, equipment and services across the state,” it said.
“Right now, there’s definitely a lot of uncertainty regarding maintenance outages this spring,” said Maggie Cashman, a power market analyst for Genscape, during a webinar Tuesday. “The main concern that has been brought up … is the status of nuclear [refueling] given that they require a large number of contract workers from across the country.”
AEP companies operate in 11 different states. | AEP
NB Power has decided to delay the refueling of its Point Lepreau Nuclear Generating Station in New Brunswick, which had been scheduled for April, because of the outbreak.
In the U.S., however, “nuclear outages have gone largely as planned,” Cashman said, noting the refueling of NextEra Energy’s Seabrook plant in New Hampshire was expected to begin this week as scheduled. “Gas generation outages are much more likely to be postponed because they’re not critical and unnecessary for continued operation in the near-term.”
The Nuclear Energy Institute says 32 nuclear plants in 21 states are scheduled for refueling outages this spring.
The Nuclear Regulatory Commission is allowing reductions in non-essential maintenance work, Cashman said. Last week, the NRC said it will allow temporary waivers of its rules limiting the number of plant operators who can stay at work.
Supply Chain
Duke Energy made an 8-K filing March 27 on the pandemic saying it was “actively managing the materials, supplies and contract services for our generation, transmission, distribution and customer services functions” and has had “no issues of significance” in its supply chain. It said it would provide an update on the actual and potential business and financial effects of the pandemic when it announces first quarter 2020 financial results on May 12.
AEP said that while the company has instituted measures to protect its supply chain, global shortages will likely affect its maintenance and capital programs. AEP has enjoyed strong financial success lately. In February, it reported a total shareholder return of 30.5% in 2019, exceeding the 27.5% total return for the S&P 500 Electric Utilities Index. (See Renewables Key to AEP’s Performance.) However, the company’s stock has lost nearly 24% of its value since Feb. 18, when its share price hit a 52-week high of $104.97. Shares closed at $79.98 Tuesday.
New Jersey regulators have taken the first step in determining whether the state should remain in PJM’s capacity market or to go in a different direction to meet the state’s electricity needs.
The New Jersey Board of Public Utilities (NJBPU) voted March 27 to investigate if staying in the capacity market will impede Gov. Phil Murphy’s goals of 100% clean energy sources in the state by 2050 or increase consumer costs (Docket No. EO20030203). (See NJ Unveils Plan for 100% Clean Energy by 2050.)
If not achievable, board members have instructed staff to examine alternatives to the market.
“Taking control of our own resource mix may be the only way to stop the Trump administration’s attempts to prop up fossil fuels to the detriment of our clean energy program,” said NJBPU President Joseph L. Fiordaliso in a press release. “We will do everything in our power to prevent that from happening.”
[FERC on Tuesday extended the deadline for comments on PJM’s compliance filing in the MOPR proceeding to May 15, from April 22, in response to a request by the Public Utilities Commission of Ohio (ER18-1314-003). PUCO had sought a delay until the end of the coronavirus emergency or no earlier than June 1. Commissioner Richard Glick dissented, saying he would have granted PUCO’s request. Opposing the delay were the PJM Power Providers Group and the Electric Power Supply Association, which said in a joint filing: “PJM has not conducted a capacity auction since May of 2018 and the lack of market certainty has harmed both consumers and suppliers.”]
Hope Creek Nuclear Generating Station in New Jersey
State officials are concerned the MOPR will prevent new offshore wind generation and nuclear units receiving zero-emission credits from clearing the capacity market, forcing state residents to pay twice for capacity. The state has set a goal of procuring 7,500 MW of offshore wind by 2035. (See NJ Sets Schedule for OSW Procurements.)
The board directed its staff to conduct the process through written comments, technical conferences and public hearings.
The written comment period, which is open through April 29, asks for responses to several questions, including the following:
Can New Jersey utilize the fixed resource requirement (FRR) alternative to adequately satisfy the state’s resource needs?
Can it utilize the FRR to accelerate achievement of clean energy goals stated in its Energy Master Plan?
Can other mechanisms, such as a clean energy standard or clean energy market, facilitate the achievement of the state’s clean energy goals?
What “practical limits” may result from the state’s location along the Atlantic Ocean and the NYISO seam?
Should the state consider creation of a state power authority?
Cynthia Holland, director of BPU’s Office of Federal and Regional Policy, presented the investigation proposal at the March 27 meeting.
Board member Upendra Chivukula asked Holland if an exact timeline to come up with a resolution has been put in place. “This is an important initiative, so a timeframe will have some kind of inputs that come from the stakeholders,” Chivukula said.
Holland said besides the written comments that are to be filed by April 29, the staff does not yet have a finalized date for issuing its recommendations to the board.
NYISO stakeholders on Monday explored detailed assumptions and modeling descriptions for a study on transitioning the New York grid to a cleaner future.
Roger Lueken and Sam Newell of the Brattle Group presented the Installed Capacity/Market Issues Working Group (ICAP-MIWG) the thinking behind the study, which will simulate market operations and investment through 2040 to inform ISO staff and stakeholders on market evolution. (See NYISO Focus Turns to Grid ‘Transition’.)
“The model is reasonable for painting a broad-brush picture of how the supply and demand will look in the future,” Newell said. “It’s not a super granular model, it’s zonal, with a ‘bubble’ [representation] transmission layout and is a somewhat stylized representation of the generation fleet where we aggregate individual units
“There are a lot of unknowns currently about how we will meet the state goals, and what kinds of new resources will come in,” Newell said.
In conjunction with NYISO, Brattle developed a 5-zone “pipe-and-bubble” representation of the New York grid. | The Brattle Group
The modeling helps the ISO answer several questions, he said, such as what types of renewable resources will be needed to meet the Clean Energy Standard, including flexible resources and storage, and how electrification will affect load profiles and market operations.
“Wow, the world is so different now, three weeks after our last meeting, but we’re just building on what we did then to provide more detail on the assumptions and on some of the modeling approaches,” Newell said.
New York Gov. Andrew Cuomo in February proposed a budget amendment to speed up the permitting and construction of renewable energy projects in order to meet the state’s ambitious clean energy goals. (See Cuomo Proposes Streamlining NY’s Renewable Siting.)
The Climate Leadership and Community Protection Act (A8429), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
The CLCPA’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
Modeling Approaches
David Clarke, director of wholesale market policy for Power Supply Long Island, asked how the study would simulate the impact of shortage pricing on energy revenues in the CLCPA future, which might hinge on the supply-demand balance and the amount of surplus capacity in the system.
“We are only partly representing [shortage pricing] in the study,” Newell said. “First of all, we’re not necessarily representing all of the features of either extreme net load conditions that could lead to shortage pricing, nor are we fully representing the dynamic challenges of ramping, and so we’re not fully going to capture that, even if we do represent the upgrade in demand reserve curves in the model.
Electrification and climate change are forecast to affect load shapes. | The Brattle Group
“Secondly, we’re not actually designing this study to explore the different ways to implement enhanced shortage pricing, for example, through a richer demand curve,” Newell said. “That actually takes a lot of design and is tricky to do well.”
In modeling generators, Lueken said the study is accounting for known retirements and additions to occur over the next few years and not just existing resources, as in the ISO’s 2019 Gold Book.
“So, for example, we are accounting for the potential for downstate peaker retirements due to the new NOx rule,” Lueken said. “We’re currently planning to assume that downstate peakers built before 1986 retire, that frame units built after 1986 retire, that the aero-derivative units built since 1986 could, instead of retiring, decide to economically retrofit. However, we’re reevaluating these assumptions based on the compliance plans the generators have submitted to the ISO.”
The new NOx regulations go into effect May 1, 2023, with initial rate limits of 100 parts per million on a dry volume basis, corrected to 15% oxygen. Generator compliance plans were due March 2, 2020. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
Modeling the capacity value of wind and solar. | The Brattle Group
The study also models the declining capacity value of wind, solar and storage.
“The capacity value of the 5,000th MW of solar will be much lower than the first MW of solar because as you get so much solar in the system, it tends to shift the hours that capacity is needed to other hours in which the solar is not generating,” Lueken said. “It’s the same for wind, and there’s a similar dynamic in place for energy storage.”
The high-level approach to develop the relationship between the amount of resources deployed and the capacity value of these resources entails varying the amount of each technology in turn while holding everything else constant, he said.
“For all the resources, the capacity value falls off quite a bit when you have 10,000 MW deployed,” Lueken said.
Capacity Market and Reliability
Clarke presented a study by PA Consulting and the Long Island Power Authority on how the transition to renewable energy resources will impact the ISO’s installed capacity market, moving to a system dominated by low variable-cost, high fixed-cost resources from one now dominated by the opposite: high variable-cost, low fixed-cost units.
“We are basing our capacity market on the premise that new capacity is needed,” Clarke said. “If you have to add capacity for something and it’s not monetized [in the capacity market], in this case greenhouse gas abatement, the premise that you’re going to need new capacity for reliability is really no longer a valid premise.
“Making a more granular market, making sure there are sufficient market signals for generators to recover the ‘missing money,’ breaking down what things capacity is providing, different kinds of capacity and paying them for things they are providing — that is the kind of approach I see as being necessary in the long run,” Clarke said.
Voluntary bilateral markets should continue, but the underlying market price should be disaggregated. These structural changes are necessary in the long run, as the existing structure may not best advance the state’s clean energy mandates, he said.
“As energy margins and prices are declining, [and] the needed capacity is facing retirement, we recognize the essential need for long-term support for renewable resources,” Clarke said.
Howard Fromer, director of market policy for PSEG Power New York, asked why a resource would need long-term support: “Is your own model still going to encompass out-of-market support? That seems to undermine everything you’re talking about in terms of [market] efficiency.”
“I don’t think it needs to,” Clarke said. “There will be attributes that will be monetized as we move in this direction, and attributes that aren’t, so to the extent that we have not monetized the attributes that we need, there will be need for renewable resources and out-of-market payments in the long term.”
The proper place to recognize the desirable attributes of renewable energy resources is in the energy market, said Mark Younger, president of Hudson Energy Economics.
“We have a multiyear effort to properly try and capture the value of those renewable attributes but have not yet been successful. But that is the proper way to capture it, to put a price on energy attributes and incorporate it into the market,” Younger said.
Storage resources would still have value in scarcity conditions requiring a price signal, “but it’s not a capacity signal. Trying to do it through a capacity price is a very blunt instrument being wielded by blind people,” Younger said.
Clarke said the paradigm of trying to include everything possible in a 2040 energy price was “not particularly workable.”
Clarke highlighted differences among those who would allow highly volatile and perhaps extreme energy and ancillary service prices driven by flexible resource shortages to provide the incentive for their construction from those that would assure development of sufficient flexible resources through a targeted capacity payment.
Offshore wind speed (and ultimately power) is more broadly distributed than conventional generation outages. | PA Consulting/LIPA
“We do support the NYISO’s proposal to enhance ancillary services revenues as a means of more efficiently distinguishing resources that can provide flexible resource services over and above those that cannot,” he said. “However, we do recognize that an additional missing money payment for flexible capacity attributes could signal an appropriate mix.
“I see energy as declining in price and in value generally,” Clarke said. “I also see some reliability challenges going forward — increasing ICAP requirements, net load shifting, a changing load shape and frequency of ramping, saturation of particular renewable resources in certain load pockets and continued need for firm dispatchable resources.”
Clarke showed a graph indicating that offshore wind speed — and ultimately power output — is more broadly distributed than the duration of conventional generation outages.
“If the Long Island buoy data perfectly correlated with the sites offshore New York City, then the capacity value of offshore wind would be effectively zero,” Younger said. “While this is informative to indicate that we probably are massively overvaluing the capacity value of wind, because there are so many hours with very low wind speed, it doesn’t really take us beyond that observation.”
FERC on Monday ordered a paper hearing to consider FirstEnergy Solutions’ bid to void power purchase agreements with wind generators and others as part of its bankruptcy proceeding. (EL20-35).
The commission acted days after the Sixth Circuit Court of Appeals issued a mandate on its December 2019 order overruling a U.S. bankruptcy court’s May 2018 injunction that prevented FERC from issuing any order requiring FES to continue complying with its obligations under the contracts. The appellate court also reversed the bankruptcy court’s ruling allowing FES to reject the contracts.
FES changed its name to Energy Harbor upon emerging from Chapter 11 bankruptcy on Feb. 27 with former bondholders owning 50% of the equity. (See FERC OKs FES Sale to Bondholders.)
The Sixth Circuit ruled “that the public necessity of available and functional bankruptcy relief is generally superior to the necessity of FERC’s having complete or exclusive authority to regulate energy contracts and markets.”
Kyger Creek Power Plant
But it said that, although the bankruptcy court’s jurisdiction is “superior to FERC’s position,” it is not exclusive and that the court had exceeded its authority.
“Through this rash and unnecessary overreach, the bankruptcy court has prevented FERC from timely completing an investigation into or holding a hearing about the public interest in the proposed rejection of these contracts, which … would have been appropriate and might have been valuable or beneficial to the ultimate determination,” the Sixth Circuit said.
The appeals court said the bankruptcy court must consider the impact of rejecting the contracts on the “public interest,” rather than using the “business judgment” standard that normally applies in bankruptcy cases.
The Sixth Circuit required that the bankruptcy court give the commission “a reasonable accommodation” in providing the commission’s views to the bankruptcy court with respect to whether the rejection is consistent with the public interest.
The appeals court said that when a Chapter 11 debtor asks the bankruptcy court for permission to renege on energy contracts that are FERC jurisdictional, the bankruptcy court “must consider the public interest and ensure that the equities balance in favor of rejecting the contract, and it must invite FERC to participate and provide an opinion in accordance with the ordinary FPA approach (e.g., under the Mobile–Sierra doctrine).”
Mobile-Sierra requires FERC to presume that the rate set out in a freely negotiated wholesale energy contract meets the FPA’s “just and reasonable” requirement unless the commission determines that the contract seriously harms the public interest.
The Supreme Court has ruled that the public interest can require canceling contracts that impair the financial ability of a public utility to continue its service, imposes excessive burdens on consumers or is “unduly discriminatory.”
FERC said Monday that it was initiating a hearing and investigation under Section 206 of the Federal Power Act in order to develop a record that would inform the commission’s views on the contracts’ cancellations.
The commission ordered Energy Harbor to submit a filing within 30 days, identifying each contract the company seeks to reject, the status of any negotiations with the contract counterparties and an explanation of why the rejection meets the public interest standard.
“To the extent that such explanation relies on the standard that the contract might impair Energy Harbor’s financial integrity, include a discussion of the effect of the completed bankruptcy reorganization and Energy Harbor’s emergence from Chapter 11 bankruptcy protection on the application of this standard,” FERC said.
Counterparties and intervenors will have 30 days to respond to Energy Harbor’s filing.
“Any counterparty that does not submit such a response shall be deemed to acquiesce in the rejection of its contract for the purpose of the commission’s public interest determination,” FERC said.
The commission said it plans to issue an order within 180 days. The refund effective date will be the date of the publication of Monday’s order in the Federal Register.
The contracts FES sought to renege were with Allegheny Ridge Wind Farm (Phase 1 and Phase 2), Blue Creek Wind Farm, Casselman Windpower, High Trail Wind Farm, Krayn Wind, Meyersdale Windpower, North Allegheny Wind (Phase 3 and Phase 4), Maryland Solar and Forked River Power.
FES also sought to escape and the multi-party intercompany power agreement with Ohio Valley Electric Corp., 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.”
FERC on Thursday approved settlements of two complaints over PJM’s regulation market design despite opposition from Dominion Energy and the Independent Market Monitor (ER19-1651).
Regulation service is the injection or withdrawal of real power by facilities that respond to PJM’s automatic generation control (AGC) signal to maintain system frequency.
The settlements resolve complaints filed in 2017 by the Energy Storage Association (EL17-64) and Invenergy and Renewable Energy Systems Americas (RESA) (EL17-65), which alleged PJM’s January 2017 regulation market redesign violated commission precedent and discriminates against faster, dynamic “RegD” resources such as battery storage.
The complaints alleged that the January 2017 signal redesign directed RegD resources to operate outside of their design parameters, resulting in performance and efficiency issues, reduced compensation and damaged equipment.
FERC partially granted the complaints, finding that PJM implemented the redesign improperly through its manuals and not its Tariff. After initially ordering a technical conference on the issue, the commission initiated settlement proceedings in June 2018. (See FERC Postpones Tech Conference on PJM Regulation Market.)
AES’ 32-MW Laurel Mountain battery storage project in Elkins, W.Va., is one of the resources covered by the regulation market settlement approved by FERC. | AES
The commission said the “overall effect of the settlement is just and reasonable” because the compromise between PJM and the battery owners “outweigh the expense and uncertainties of further litigation, which could result in a very different regulation market design. The settlement supports grid reliability by facilitating the continued operation of short-duration resources on the PJM system, which reduces the potential for sharp market disruptions.”
Invenergy said it supported the settlement, despite its continued exposure to the “30-minute conditionally neutral signal” implemented in 2017 “because it believes that the limited window of market and operational stability the settlement provides is preferable to continued litigation,” the commission said.
PJM estimated the settlement will cost about $8 million over its three-and-a-half-year term.
The commission said the settlement “is no worse for Dominion and the IMM than the likely result of continued litigation.”
“Load-serving entities like Dominion will benefit from the settlement’s contribution to controlling ACE [area control error] while the cost of the settlement to load is minimal.”
FERC said the Monitor failed to provide evidence to back its contention that the compensation under the settlement exceeds that which was available to batteries before 2017. “Further, the commission need not find that the settlement rate is exactly the same as the rate the commission would establish on the merits after litigation. Settlements by nature are compromises, and the commission typically does not require settling parties to justify individual elements of a settlement package.”
The commission on Thursday also denied rehearing of its March 2018 order rejecting PJM’s proposed revisions to build on the January 2017 redesign (ER18-87).
The March 2018 order rejected PJM’s regulation changes, saying they were inconsistent with commission regulations and Order 755 because it did not compensate for actual mileage — the absolute amount of regulation up and down a resource provides in response to the system operator’s dispatch signal — and did not compensate all regulation resources based on the quantity of regulation service provided.
Monitor Joe Bowring criticized the rehearing ruling Thursday during a Markets Committee briefing on his recently released State of the Market Report, which found that the regulation market design is “flawed.”
FERC “said the regulation market was just fine,” Bowring said. “It’s actually not just fine. Its horrifically bad.”
The Monitor’s report said the design fails “to correctly incorporate a consistent implementation of the marginal benefit factor in optimization, pricing and settlement” and uses an incorrect definition of opportunity cost. The IMM also said the market structure is “not competitive” because it failed the three-pivotal-supplier (TPS) test in almost 91% of the hours in 2019.
However, it concluded that participant behavior and market performance are competitive because market power mitigation requires competitive offers when the TPS test is failed “and there was no evidence of generation owners engaging in noncompetitive behavior.”
“We had a hard time deciding whether we wanted to call the regulation market results competitive because the regulation market design is so bad,” Bowring told the MC. “It’s not compensating people correctly. It’s not calculating the economic value of regulation.”
The tamest winter in recent memory brought no emergencies for MISO, though the RTO’s South region was the subject of three weather-related alerts.
Speaking during a teleconference of the Board of Directors’ Markets Committee on March 24, Executive Director of Market Operations Shawn McFarlane said the winter resulted in “minimal drama” over the three months.
He said MISO’s “lowest winter peak in recent years” was driven by relatively high temperatures. Winter load peaked early at 96 GW on Dec. 19, far short of the forecasted 104 GW. While Midwest region temperatures were higher than average, the South region experienced temperatures about 4 degrees lower on average than in early 2019.
McFarlane said low gas prices and smaller load brought a 28% decrease in prices from last winter. Real-time LMPs averaged $21/MWh, down 28% from last year’s $29/MWh winter average.
“This is about as low as we’ve seen gas prices since they were deregulated in the ’80s,” Independent Market Monitor David Patton said. “It’s fundamentally changing MISO’s dispatch.”
MISO declared just one maximum generation alert for its South region, on Feb. 21, when cold weather in the Southeastern U.S. caused tight conditions.
McFarlane said in addition to the cold that morning, three major long-lead generation units failed to come online, dropping the operating margin to 500 MW, which triggers a maximum generation alert. The no-shows led MISO to call up all area short-lead units. He said two of the three long-lead units eventually started.
“The alert was only in effect for 90 minutes to cover the morning peak from 7:30 to 9 a.m. We weren’t at risk of not being able to serve load,” McFarlane explained.
MISO winter wind production | MISO
MISO South was also the subject of two separate severe weather alerts as tornados and heavy rain hit the region Dec. 16-17 and again Jan. 10-11.
MISO also set a new all-time wind generation peak of 18 GW on Feb. 22.
“It seems like it occurs every season other than summer,” McFarlane said of wind peaks.
However, McFarlane said MISO also experienced a “nearly zero” wind output from Jan. 28-30, illustrating the need to continue the resource availability and need projects to better manage the intermittent nature of renewable resources. (See MISO Forward Report Stresses Near-term Change.) Altogether, the three days brought 39 hours of wind production below 200 MW.
Lake Erie Loop Flows Re-emerge
MISO’s winter prices were impacted by loop flows on lines around Lake Erie that are not being controlled through phase angle regulators, Patton said.
According to the Monitor, Ontario’s Independent Electricity System Operator (IESO) throughout January and February requested transmission loading relief (TLR) on the Michigan-Ontario interface related to the loop flows. IESO’s requests resulted in PJM curtailing about 162 GW worth of exports to MISO across 80 hours in the winter, Patton said.
“Now that’s a really big deal. That’s like losing two nuclear units. MISO doesn’t plan for this,” Patton said. “This is hugely costly to MISO when IESO takes these actions.”
As a result, Patton said hourly market-wide energy prices exceeded $370/MWh, and market participants that had scheduled imports from PJM in the day-ahead market lost about $3.5 million collectively.
Patton said he’s concerned that it appears IESO is calling for relief not because the Michigan-Ontario interface is overloaded, but because the PARs aren’t enough to control the loop flows.
“It’s important for IESO to tighten down and only take these actions when they’re warranted,” Patton said.
He said MISO is in discussion with IESO, PJM and NYISO about the appropriate criteria to call for TLR.
“This is an ongoing issue that we’ve been struggling with for years,” MISO President Clair Moeller told board members. Unscheduled loop flows around the Lake Erie region have been a problem since the late 1990s. (See MISO not Allowed to Allocate Lake Erie PARs Costs to PJM and NYISO.)
MISO management said it plans to examine IESO’s TLR requests to see if there may be a means to mitigate their frequency.
