The company on Wednesday reported full year 2019 earnings of $909.1 million ($2.81/share), down from just over $1 billion ($3.25/share) in the same period a year ago.
Excluding that impairment, Eversource would have earned $1.1 billion ($3.45/share) last year. In the fourth quarter, Eversource earned $250 million ($0.76/share), up slightly from $231 million ($0.73/share) in the same period a year ago.
“The credibility generated by our strong operating performance helps us achieve very tangible results, especially in areas such as structuring long-term rate deals in our regulatory jurisdictions, or entering new business ventures such as water and offshore wind,” CEO Jim Judge said in an earnings call.
All New England states are targeting at least an 80% reduction in greenhouse gas emissions by the year 2050, and in December the company announced a goal of becoming carbon-neutral by 2030. Eversource has already reduced its carbon emissions by approximately 70% over the past few years, primarily by divesting fossil generation in New Hampshire, Judge said.
Offshore Wind Advantages
Judge said Eversource’s partnership with Ørsted will result in “at least” 4,000 MW of offshore wind off Massachusetts, which is “incremental to making our operations carbon neutral by 2030.”
The companies in October signed a contract with New York for the 880-MW Sunrise Wind offshore wind project, which comes on top of their 130-MW South Fork project 30 miles off Montauk, Long Island. Their Revolution Wind project has commitments from Connecticut and Rhode Island for 600 MW of offshore wind.
Connecticut Gov. Ned Lamont earlier this month announced a public-private partnership with Eversource and Ørsted to upgrade the New London pier for offshore wind operations.
Eversource and Ørsted’s offshore wind competitiveness in New England and New York auctions benefits from their superior lease locations. | Ørsted
Planned filings with the U.S. Bureau of Ocean Energy Management (BOEM) will be consistent with the plan that Revolution will have its first full year of operation in 2024 and Sunrise in 2025, he said.
“We continue to target operation of the first and smallest of these three projects, South Fork, by the end of 2022,” Judge said. “We are currently reviewing that schedule in light of BOEM’s recent announcement that it will not complete its cumulative impact study on the six tracks of Massachusetts until mid-June. That study is part of the Vineyard Wind application but will likely encompass all of the tracks.” (See Offshore Wind Slogs Forward in Massachusetts.)
The partners did not win in the most recent awards in Massachusetts and Connecticut; while the latter price was not disclosed, Massachusetts released the record-low price submitted by Mayflower Wind: $58.47/MWh.
“Although disappointed, I was comfortable with our bid not being selected,” Judge said.
With at least 15 GW of contracts likely available to developers over the coming years, “the last thing we would want to do is lock ourselves into contracts for 20 to 25 years that would not allow us to earn our targeted returns because we bid too aggressively,” he said.
The partners control the two best ocean tracks that BOEM has auctioned off in New England, which are the closest to shore, and should be the most economic to develop and maintain, Judge said.
Eversource is the only U.S. energy utility targeting carbon neutrality by 2030. | Eversource
“We consider our sites to be a tremendous competitive advantage, and we’ll be disciplined in our bidding,” he said. “We’ll take some additional few years to reach the 4,000-MW capacity for our tracks. We are fine with being patient and preserving our potential returns.”
CFO Philip Lembo said the company expects to invest $300 million to $400 million in its offshore wind projects in 2020.
Regulatory Update
The total investment needed to switch over all electric and natural gas customers to advanced metering infrastructure (AMI) in Connecticut and Massachusetts would be approximately $1 billion, Lembo said, adding that it’s unclear whether regulators will authorize AMI.
Public Service Company of New Hampshire filed a rate case last year seeking a $70 million increase in base distribution rates. Following the settlement with the staff, the state’s Public Utilities Commission approved a $28 million temporary increase that will remain in effect until the PUC implements a final decision on the permanent rates, which he said the company expects in May with an effective date July 1.
Despite a year that saw PJM cancel its 2022/23 capacity auction and part ways with its CEO, CFO and general counsel, 89% of members who responded to the RTO’s biennial stakeholder satisfaction survey said they are satisfied with its performance, officials told the Members Committee on Thursday.
“Given the complexities we experienced last year, I personally think this is a good result,” said Jim Gluck, director of member relations.
The score was down 3 percentage points from the results in 2017 and the second-lowest score PJM has recorded in the six surveys since 2010.
Some 626 people from 372 companies responded to the survey, which ran from Sept. 30 through Oct. 11.
2019 was perhaps the most tumultuous year in recent PJM history, with the departures of three long-time executives — CEO Andy Ott, CFO Suzanne Daugherty and General Counsel Vince Duane — in the wake of the GreenHat Energy default. The RTO also parted ways with Denise Foster, its popular vice president of state and member services. (See PJM Chooses CFO, Promotes Haque.)
CEO Manu Asthana, who joined in January, said he read all 1,100 comments submitted, which he said underscored “how important it is to improve the stakeholder process.”
“There are things we could be doing better,” he acknowledged. “We don’t get it 100% right.”
Still, he said, PJM’s 89% score is “higher than Apple’s net promoter score.”
The net promoter score — an index ranging from -100 to 100 that measures the willingness of customers to recommend a company to others — is a widely cited but controversial metric.
“This was not meant to be an apples-to-Apple comparison,” PJM spokeswoman Susan Buehler explained later. “The 89% overall satisfaction rating was based on the one high-level question we asked around PJM’s performance from members only. Manu simply meant to imply that a 89% is a high level of satisfaction even when looked at in the context of a leading consumer brand, but we continue to strive for even higher results.”
About 62% of PJM members rated the RTO as very or extremely good, and another 27% rated it good with 11% calling it fair or poor.
Nonmembers were less impressed, with 17% rating it fair or poor, up from 11% in 2017. Gluck said many of the nonmembers were agents and developers concerned about the transparency of PJM’s transmission planning.
However, Gluck said PJM’s ratings improved over 2017 on each of seven individual “dimensions”: core deliverables, integrity, communication, customer relationship management, change management, project management and impact.
For the first time, the survey provided respondents the option of asking PJM to contact them for additional feedback. About 100 people said they were interested in more dialogue. “Expect PJM to contact you in next month or so,” Gluck said.
VALLEY FORGE, Pa. — Stakeholders on Thursday approved proposed changes to the RTO’s fuel-cost policy (FCP) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power.
A proposal by the PJM Industrial Customer Coalition won a sector-weighted vote of 3.57 (71%), with majority support from all sectors except End Use Customers (EUC), where it was backed by seven of 14 voters.
The Markets and Reliability Committee approved the proposal after rejecting a “joint stakeholder” package that had been the top vote getter with 87% support at the Market Implementation Committee in December. (See “Fuel-cost Policies,” PJM MIC Briefs: Dec. 11, 2019.)
The MRC rejected the joint package with a sector-weighted vote of 1.91 (38%). It won majority support from only the Generation Owners sector and no votes from the EUC and Electric Distributors sectors.
Both proposals eliminate the annual FCP review and the FCP requirement for zero-marginal-cost offer units. They also would eliminate or adjust submission and review deadlines. The ICC proposal accepted a safe harbor provision proposed by the generators but modified the terms for imposing penalties for noncompliance.
The joint proposal would impose the full penalty if the unit clears in the day-ahead market or runs in real time on a cost-based offer and is paid DA/balancing operating reserves. The joint proposal also would apply the full penalty if the unit fails the three-pivotal-supplier (TPS) test for constraints or the cost offer is above $1,000/MWh.
The ICC proposal, which had won 81% support at the MIC, built on the joint proposal and would also apply the full penalty if the unit is marginal in DA or RT on its cost-based offer. It would not apply the full penalty if the unit failed the TPS test but was running on a price-based schedule because it passed the test at the time of commitment.
The vote followed a spirited debate over last-minute changes to a new safe harbor section in both the joint stakeholder and ICC proposals, which would allow a generator to avoid penalties if it deviates from its FCP because of a force majeure event.
MIC Chair Lisa Morelli said the joint proposal used North American Energy Standards Board’s definition of force majeure and would ensure the safe harbor would only be triggered by events beyond the control of the market seller and that its affiliates could not control and could not have contemplated.
PJM would determine if the generator provided sufficient evidence to avoid penalties following a review by the RTO and the Independent Market Monitor.
Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned that the proposed Operating Agreement language lists pipeline interruptions as an “unforeseen event.” Carmean said state regulators care about FCPs when the system is strained, wanting a way to verify the high prices that result.
But Morelli said natural gas pipeline declarations of force majeure would not qualify for the safe harbor because generators can expect such actions. “It doesn’t mean that just because this condition exists that the exemption is automatically triggered,” she said.
The IMM’s Catherine Tyler said FCPs are a core part of market power mitigation and that the proposal would weaken protections.
Tyler said generators have exercised market power through weak FCPs in the past. “This makes it all quite a bit worse,” she said. It would “make legal market power abuses currently prohibited by the Tariff.”
Monitor Joe Bowring said flexible FCPs can address all of the force majeure events cited by generation owners. “PJM proposed and FERC adopted language requiring fuel-cost policies to be verifiable. With this loophole, fuel-cost policies are not and cannot be verifiable. There is simply no good reason to make this change.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he shared OPSI’s and the Monitor’s concerns.
Bob O’Connell, of Panda Power Funds, one of the companies that negotiated the joint proposal, said the Monitor “may not fully understand the challenge our gas traders face.” He cited an instance in which flooding in Houston disrupted the operations of pipelines on which his company had firm transportation.
The joint proposal “balances all the issues that need to be balanced,” he said.
Susan Bruce, representing the ICC, said the joint proposal has “very large hole in it. The marginal unit, by definition, is impactful.”
After the joint motion failed, O’Connell offered a friendly amendment to the ICC proposal requiring generators to file force majeure claims to PJM at least one hour prior to the deadline for submitting offers. They would be subject to the same verification process that applies to offers above $1,000/MWh.
But Calpine’s David “Scarp” Scarpignato objected to use of the verification process.
“I cannot vote for … that kind of material change [at the] last minute,” he said. “I’d have to work through it [with other Calpine officials]. … I’m not saying I’m against the idea, but I’m against putting it up on the fly.”
The approved ICC proposal, which will require changes to the Tariff and Manual 15, will go to a final vote by the Members Committee in March.
American Electric Power CEO Nick Akins, a Louisiana native, says he roots for the Ohio State Buckeyes “if they’re not playing” Louisiana State University.
Makes sense, given that AEP shares its Columbus, Ohio, headquarters city with the Buckeyes. However, LSU’s ride to a 15-0 season and this year’s national championship gives him reason to celebrate his home state.
“I have to use an LSU analogy given their victory in the college football national championship,” Akins said during AEP’s fourth-quarter earnings call Thursday. “The way in which the LSU office executed during the season is the way I feel about our AEP team. … The results of 2019 indicate that.”
AEP reported fourth-quarter earnings of $153.5 million ($0.31/share), down from $363.4 million ($0.74/share) the year before. When adjusted for $98 million in charges linked to the retirement of three coal plants in Virginia and the planned shutdown of another coal plant in Ohio, adjusted earnings per share met analysts’ expectations of 60 cents/share.
Year-end results of $1.921 billion ($3.89/share) were virtually unchanged from 2018’s final numbers of $1.923 billion ($3.90/share).
Operating earnings for 2019 came in at $4.24/share, which was at the top end of AEP’s revised guidance range of $4.14 to $4.24/share.
“AEP has a habit of hitting the upper half of the guidance range, if not exceeding it, and this year has been no exception,” Akins said. “As we have said repeatedly, we would be disappointed in not achieving the same track record in the future.”
AEP set its 2020 guidance at $4.25 to $4.45/share and reaffirmed its 5 to 7% operating earnings growth rate.
Renewable energy will continue to play a major role as AEP continues to shed its coal resources. The company acquired Sempra Energy’s renewables business last year and is making progress on its North Central Wind initiative, a proposed $2 billion project involving Invenergy’s construction of three wind farms in Oklahoma with 1,485 MW of nameplate capacity.
AEP’s North Central Wind initiative | AEP
Shortly after AEP’s earnings call, Oklahoma regulators signed off on a deal that allows Public Service Company of Oklahoma, an AEP subsidiary, to recover costs for 675 MW of wind energy. Should Arkansas approve the project, AEP would have a “critical mass” of 846 MW and a $1.1 billion investment to move forward.
AEP still needs approval from the Louisiana and Texas commissions which, along with Arkansas, have the ability to “flex up” and take any wind capacity other jurisdictions turn down.
Should Arkansas approve a settlement as well, Akins said, “the project is moving forward; that’s a given. Then the question becomes, ‘OK, what scale?’ And that’ll be determined by the other two jurisdictions and the amount of flex up that’s enabled in those settlements.”
AEP shares, which hit an all-time high of $104.97 on Feb. 18, fell to $101.70 on Friday, losing $1.75 following its close before the earnings announcement.
The New England Power Pool Reliability Committee on Wednesday voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs totaling $236.6 million for Eversource Energy projects to replace wood 115-KV structures in Connecticut ($200.3 million) and Massachusetts ($36.3 million).
Eversource maintains more than 20,000 115-kV structures in New England, and the work to replace aging wood structures with tubular steel pole structures is composed of 21 projects in Connecticut, three in Massachusetts and one cross-border project.
Inspections have indicated significant degradation and decreased load-carrying capacity of the wood structures. Eversource said that replacing the structures resolves multiple structural and hardware issues and supports safe and reliable operation.
Inspections have indicated significant degradation and decreased load carrying capacity of wood 115-kV structures. Eversource estimates cost for the 115-kV structure replacements in Connecticut and Massachusetts at $236.6 million. | Eversource Energy
Projects with additional scope, such as replacement of conductor and lattice tower lines, are generally presented individually.
In addition, the committee recommended RTO approval of approximately $18 million in PTF costs for Eversource to build a new control house for the Canal 345/115-kV substation in Sandwich, Mass., and elevate it above hurricane-level flooding. The station serves a large portion of Cape Cod load.
The RC also approved $7.5 million in PTF costs for Eversource to rebuild the 115-kV line from the Colony substation to Schwab Junction in Connecticut.
Attleboro Upgrade
The RC recommended the RTO approve $10.3 million in PTF costs for National Grid to replace worn-out assets at the Robinson Avenue 115-kV Substation in Attleboro, Mass., which dates from the 1960s.
National Grid said it will replace 115-kV components, including two oil circuit breakers, eight sets of disconnect switches and nine capacitor-coupled voltage transformers.
Two breakers were previously upgraded to support the new Highland Park distribution substation and were not included in the current project.
The new control house with modern protection and control systems should be completed by June 2021.
Operating Procedure Revisions
The RC voted to recommend that the Participants Committee support revision of ISO-NE Operating Procedure No. 3 (OP3) to extend the maximum duration for opportunity transmission outages from 96 hours to 108 hours.
Opportunity outages represent those that fail to meet the minimum advance notice required for planned short-term outage processing and are submitted for RTO “approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time,” the RTO says.
The extra 12 hours will allow these non-impactful outages to be evaluated using the seven-day load forecast, which assumes a maximum continuous outage of five days, the RTO said.
The RC also supported revisions to OP18 to add a requirement to telemeter station frequency, identify equipment requirements, specify which requirements apply to existing and new equipment, and revise Section I to reflect current practice.
The committee also approved revisions to OP23 to provide audit requirement compliance measures for resources for which the RTO has not provided an asset ID number.
Planning Procedure Revisions
Dominion Energy is replacing the Unit 3 generator and feedwater measurement equipment at the Millstone nuclear power plant in Connecticut and in April will seek a committee vote on expanding the RTO’s interconnection limits.
Dominion representatives who wished to remain unidentified told the RC how the new equipment would allow the reactor unit to increase its output to 1,262 MW year-round, up from the current 1,225 MW in summer and 1,245 MW in winter.
The increase in output will bump the unit’s output just over ISO-NE’s interconnection limit for such resources, as defined in Planning Procedure 5-6 (PP5-6), which limits interconnection to 1,200 MW for new resources and elective transmission upgrades.
Dominion is replacing the Millstone Unit 3 generator and feedwater measurement equipment, which will bump the unit’s year-round output to 1,262 MW, just over ISO-NE’s interconnection limit for such resources. | NRC
Regardless of the results of a system impact study, the RTO indicated it likely could not approve the increase in interconnection rights because of this “pretty straightforward” language, one Dominion representative said. Revising PP5-6 would allow ISO-NE to approve the uprate if no issues were found on their review of the system impact study.
Dominion proposes allowing existing capacity resources above 1,200 MW, which are “increasing output as a result of good stewardship of their resources,” to “increase their interconnection rights accordingly.”
“The new generator and new equipment we’re putting into it allows to provide some extra benefits to the grid. … You’re going from a hollow core to a solid-core rotor, so you’re going up roughly an additional 50,000 pounds on that rotor, and all that’s online and provides additional inertia, so during a voltage transient, it’s like a flywheel on your car to keep providing energy for a while,” the representatives said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
In a separate matter, the RC also approved recommending that the Participants Committee approve revisions to Planning Procedure 3 (PP3) to conform to defined terms. As part of the changes being made, the term “governance participant” was replaced with “market participant” and/or “transmission owner” to conform to Section I.3.9 of the ISO-NE Tariff.
FERC last week denied multiple requests for rehearing and clarification of Order 860, its 2019 rulemaking lessening the reporting requirements of electricity sellers with market-based rate authority (MBRA) (RM16-17-001).
Currently, sellers are required to describe the activities of all their upstream owners, often requiring them to submit multiple amendments to their filings. Once the new rule goes into effect on Oct. 1, sellers will only need to identify their “ultimate” upstream affiliate — the furthest upstream owner. (See FERC Reduces MBRA Data Requirements.)
The commission denied requests to clarify several aspects of the order, including:
NRG Energy and Vistra Energy’s request to clarify that an investor will not be considered a seller’s ultimate upstream affiliate based solely on holdings of publicly traded securities;
the Edison Electric Institute’s request to extend the implementation timeline of the order’s requirements; and
the Transmission Access Policy Study Group’s (TAPS) request for safeguards from being penalized for reporting errors. (“We expect that most inadvertently erroneous or incomplete submissions will be promptly corrected by reporting entities without the imposition of any penalty.”)
FERC did clarify in response to a request by TAPS that the public will have access to the relational database it will establish to collect all the required information. It also noted in response to EEI that this Thursday it will hold a technical conference, announced last month, to discuss the implementation and use of the database.
Types of market-based rate authority filings | FERC
The commission also denied a request for rehearing by several state consumer advocate agencies, which argued that it erred in not adopting its original proposal to require submission of connected entity information (CEI) and that traders of financial transmission rights and virtual products also submit affiliate information. The agencies “assert that the final rule deprives the commission of important tools to address and combat market manipulation and fraud,” FERC summarized.
In the alternative, the agencies requested that their arguments be filed in the docket that FERC created when it dropped the CEI proposal in order to leave it open for consideration (AD19-17), a request the commission granted.
The agencies also requested “that the commission expediently implement the connected entity proposal and any additional reforms offered in [AD19-17] given the clear potential for future market manipulation, fraud and default.” But in his partial dissent of last week’s order, Commissioner Richard Glick said that was unlikely to happen.
“The commission has relegated even those common-sense reforms to a hollow administrative docket that has not seen any action and likely never will under the commission’s current construct,” he said. “As I explained in my earlier dissent, the commission’s retreat from the … proposal is part of a troubling pattern in which the majority seems indifferent to detecting and deterring market manipulation.”
Order 861
FERC also upheld Order 861 — issued at the same time as 860 — which eliminated the requirement for sellers with MBRA to submit pivotal supplier and wholesale market share screens in PJM, ISO-NE, MISO and NYISO (RM19-2-001).
Sellers of capacity in SPP and CAISO, which do not have capacity markets, will still need to submit the screens. In explaining the reason for this in its original order — and in response to requests for CAISO to receive the same treatment as the RTOs — FERC said the soft offer cap in the ISO’s capacity procurement mechanism “is an estimate of the cost of new entry and does not necessarily reflect a mitigated, ‘going forward’ cost of any existing generator and does not address concerns regarding local market power.”
CAISO took issue with that description, requesting clarification that the “soft offer cap represents an estimate of going-forward costs plus a 20% adder, as opposed to an estimate of the cost of entry.” Pacific Gas and Electric went further and requested rehearing of the order based on FERC’s erroneous description of the offer cap, arguing that the commission should remove the requirement to submit indicative screens.
FERC granted CAISO’s request but said its error does not affect its determinations in Order 861, denying PG&E’s request.
“The commission declined to extend Order No. 861’s relief to capacity sellers located in CAISO for several reasons, including the lack of a transparent market price for capacity in CAISO and the fact that capacity sales are not reviewed, approved or monitored by CAISO,” FERC said. We find that these reasons continue to apply and, therefore, deny PG&E’s request.”
New York Gov. Andrew Cuomo last week announced a push to amend this year’s state budget to speed up the permitting and construction of renewable energy projects.
If the legislature passes the amendment, a new Office of Renewable Energy Permitting will be set up to streamline the siting process for large-scale renewable energy projects.
“This legislation will help achieve a more sustainable future … with a revamped process for building and delivering renewable energy projects faster,” Cuomo said.
The state’s existing energy generation siting process was designed for permitting coal-, oil- and natural gas-fired power plants, dating from prior to the growth of clean energy.
New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.
The 100.5-MW Bliss Wind Farm near Eagle, N.Y.
“The renewable energy industry is ready to invest in New York, and a more sensible permitting process that still retains all the environmental protections is sorely needed,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “The proposal also includes transmission planning, which is so critical to moving clean power to where it is needed.”
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 law’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.
The executive branch proposes that the New York State Energy Research and Development Authority collaborate with the Department of Environmental Conservation and Department of Public Service to develop build-ready sites for renewable energy projects.
“Permitting is a process that involves basically anyone who wants to be involved, which is a good thing, but a challenge for the state,” Sarah Osgood, director of policy implementation at the Department of Public Service, told a conference in 2018. (See New York Plans for Wind Energy, Related Jobs.)
The proposal includes a bulk transmission investment program and streamlined siting process for transmission infrastructure built within existing rights of way, and foresees NYSERDA working with the New York Power Authority, the Long Island Power Authority, NYISO and the state’s utilities to identify cost-effective bulk electric system upgrades and file such evaluations with the Public Service Commission.
The PSC in turn would establish a distribution and local transmission system capital program, with benchmarks and reviews, for each relevant utility.
Consolidated Edison on Thursday reported 2019 net income of $1.34 billion ($4.09/share), down slightly from $1.38 billion ($4.43/share) the previous year.
Net income for the fourth quarter was $295 million ($0.89/share), compared to $331 million ($1.06/share) in 2018.
The company attributed the decline in income to depreciation and amortization expenses increasing 14.6% year-on-year, and taxes other than income taxes going up 8.4% in the same period.
“While meeting many challenges in 2019, Con Edison delivered solid financial results and remained focused on leading the way towards a cleaner energy future for our customers and the planet,” CEO John McAvoy said. “Our recently approved three-year rate plans are essential to helping New York state achieve its clean energy goals, as well as to continue providing safe and reliable service to our customers.”
The state’s Public Service Commission last month approved electric and gas rate plans for January 2020 through December 2022 reflecting an 8.8% return on equity, and the New Jersey Board of Public Utilities approved an electric rate increase, effective Feb. 1., of $12 million for Rockland Electric, reflecting a 9.5% ROE.
The PSC last month also issued an order directing energy efficiency targets and budgets for New York utilities, approving $2 billion statewide for EE programs, heat pump budgets and associated targets through 2025 to meet the goal of reducing electric use by 3% and gas use by 1.3% annually by 2025 (19-E-0065).
Con Ed’s DER meter, ConnectDER | Con Edison
In December, Con Ed completed a study of climate change vulnerability. Considering the increased risk of sea level rise, coastal storm surge, inland flooding from intense rainfall, hurricane-strength winds and extreme heat, the company estimates it might need to invest between $1.8 billion and $5.2 billion by 2050 on programs to adapt to impacts from climate change.
Con Ed is still extremely exposed to Pacific Gas and Electric’s bankruptcy through a large volume of power purchase agreements sold to the California utility. At year-end, Con Ed’s balance sheet included $819 million of net non-utility plant relating to PG&E projects, approximately $1 billion of intangible assets relating to PG&E PPAs, $282 million of additional projects that secure the related debt and approximately $1 billion of non-recourse related project debt. (See PG&E Reports $3.6 Billion Q4 Loss.)
Pursuant to the related project debt agreements, Con Ed reported distributions from the related projects to the Clean Energy Businesses have been suspended.
“Unless the lenders for the related project debt otherwise agree, the lenders may, upon written notice, declare principal and interest on the related project debt to be due and payable immediately and, if such amounts are not timely paid, foreclose on the related projects,” the company said.
FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) prompted outrage among some officials in the RTO’s 13-state footprint and shoulder shrugs from others (EL16-49, EL18-178).
Filings by officials in Delaware, Virginia, West Virginia and D.C. show they share some of the concerns that regulators from Illinois, Maryland, Pennsylvania, Ohio and New Jersey expressed last week in a webinar with RTO Insider. (See related story, PJM’s MOPR Quandary: Should States Stay or Should they Go?)
But regulators in Indiana, Tennessee, Kentucky, Michigan and North Carolina — which are only partly within the PJM footprint — say they expect little impact from the ruling. Here’s a summary of where regulators in the nine jurisdictions not represented in the webinar stand.
D.C.
The D.C. Public Service Commission sought rehearing or clarification on the MOPR’s impact on new renewables, new demand response and the district’s default service procurement program, which provides 28% of the district’s electricity, including 85% of residential customers’ usage.
It noted that Maryland and Delaware have similar procurement processes for their default customers.
The PSC said it is unclear if the commission intended the MOPR to apply to the default service procurements. Commissioner Richard Glick said in his dissent that the MOPR could apply to New Jersey’s similar default program, but the PSC noted that the order suggested such programs could be protected under the competitive market exemption or unit-specific exemption.
D.C. also is concerned that the order could make it more expensive for it to comply with district law requiring a 50% cut in greenhouse gas emissions by 2032 and reaching carbon neutrality by 2050.
PJM transmission zones | PJM
It said only 7% of PJM’s power comes from renewables, below the national average (17%) and the shares in MISO (15%), ISO-NE (18.8%) and ERCOT (21.5%).
Using the net cost of new entry (CONE) to set the price floor for renewables could leave PJM further behind, the PSC said. “Thus, we request that FERC consider exempting new renewable resources from the MOPR or treat such resources as an exception — using the net ACR [avoided-cost rate] as opposed to the net CONE for the price floor for new renewables.”
The district also raised concerns about the order’s directive that PJM average the last three years’ DR offers to determine the default offer price floor value for DR that has not previously cleared a capacity auction. A new DR program targeting water heating would have no history, it noted.
It said new and existing DR should have a zero floor price “due to the fact that demand response programs are producing negawatts, not kilowatts.”
“Inasmuch as customer participation in demand response programs is ‘voluntary’ and the programs produce benefits greater than their costs, we do not fully understand why demand response is considered as a subsidized resource. Furthermore, the demand response programs from [electric distribution companies], due to their proximity to load, offer significant reliability values and lead to reduced market power and reduced final price to consumers especially during scarcity hours.”
Delaware
The Delaware Division of the Public Advocate’s rehearing request sought a declaration that the MOPR does not apply to the Regional Greenhouse Gas Initiative, which includes Delaware, Maryland and New Jersey in PJM. Pennsylvania Gov. Tom Wolf is attempting to join also but is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
The advocate expressed concern that the order appeared to limit the MOPR exemption for existing renewable resources based on the PJM Tariff’s definition of “intermittent resources,” which it said does not cover all renewable resources that have generated or received renewable energy credits (RECs) and solar RECs (SRECs).
“For example, Delaware’s [renewable portfolio standard] statute includes geothermal energy technologies, biomass generators, landfill gas generators and fuel cells as electricity generators that are eligible to produce RECs, SRECs or their equivalencies,” it said. “These resources are not intermittent.”
Virginia
The Virginia State Corporation Commission filed a brief rehearing request that referred back to its October 2018 comments in the docket, in which it called for continuing the self-supply exemption for vertically integrated utilities in regulated states. The order exempted existing self-supply resources but indicated new self-supply would be subject to MOPR. (See Is Self-supply Suppressing Prices?)
“Customers in vertically integrated states should not bear the risk of paying twice for capacity, because the states in which such customers reside have made no out-of-market payments to generators,” it said. “What the commission concluded [in 2013] remains true today: Utilities in regulated states have no incentive to attempt to artificially suppress capacity prices, and a properly configured self-supply exemption would fully address the intent of an expanded MOPR.”
West Virginia
West Virginia, which remains fully regulated, has one load-serving entity that meets its capacity obligation through PJM’s fixed resource requirement (FRR): American Electric Power’s Appalachian Power and Wheeling Power, which together serve a little over half of the state’s load. Appalachian also serves significant retail load in Virginia.
The remainder of the state’s load is served by FirstEnergy’s Monongahela Power, which owns or controls 3,580 MW of generation, and Potomac Edison, which owns no generation but is supplied by Mon Power.
Mon Power’s load is almost entirely in West Virginia, while three-quarters of Potomac Edison’s load is in Maryland. Mon Power bids its capacity into PJM and buys its requirements, and those for Potomac Edison’s West Virginia operations, from the PJM market.
“The commission is still reviewing the order, but it appears that the decision to grandfather existing regulated plants that have been selling capacity into the PJM capacity market means that there is no immediate MOPR-related effect on our RPM [Reliability Pricing Model] LSE,” said Susan Small, communications director for the Public Service Commission of West Virginia.
The ruling would not impact the current operating decisions of the AEP companies, but their “option to elect to switch to RPM is now compromised,” Small said.
“We are concerned that new or existing regulated power plants that have not been selling into the PJM capacity market in the past will be subject to the MOPR, a treatment that we believe is unreasonable and discriminatory. This will mean that future options for West Virginia capacity additions and existing FRR regulated plants may be limited.
“By regulating the bid price of only certain unfavored power supply, including regulated power supply, not only will our options regarding how to serve West Virginia load be limited, but the cost of RPM capacity will grow over time because of the discriminatory treatment of resources that are bidding at a price that is considered by some to be too low.”
Indiana
Indiana Michigan Power (I&M), a subsidiary of AEP, is the only investor-owned utility in Indiana operating in PJM and meets its capacity obligation through the FRR, said Stephanie Hodgin, deputy director of communications and media for the Indiana Utility Regulatory Commission.
“Indiana also has rural electric membership cooperatives and municipal electric utilities that may participate in PJM; however, the IURC does not have information on how FERC’s MOPR order may or may not affect them,” she added.
Tennessee
Only a small portion of the northeast corner of Tennessee is within PJM. It is served by AEP’s Appalachian and its affiliate Kingsport Power, according to Tim Schwarz, chief of the communications and external affairs division for the Tennessee Public Utility Commission.
AEP, which serves about 47,000 customers and does not generate any power in the state, is exempt from the MOPR because it uses FRR.
Kentucky
Four Kentucky utilities participate in PJM, including AEP’s Kentucky Power and Duke Energy Kentucky, which use the FRR, and Big Rivers Electric, which is an “other supplier” in PJM but participates in the market through MISO.
Only East Kentucky Electric Cooperative participates in PJM’s capacity market, according to Andrew Melnykovych, director of communications for the state’s Public Service Commission. In its request for rehearing, EKPC called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.
EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.” (See MOPR Ruling Threatens to Upend Self-supply Model.)
Michigan
The only Michigan utility in PJM is AEP’s I&M, which uses FRR.
“It’s a very minimal impact, if anything,” said Matt Helms, spokesman for the Michigan Public Service Commission.
North Carolina
Dominion North Carolina is the only FERC-jurisdictional utility regulated by the North Carolina Utilities Commission. Dominion, which serves about 120,000 customers in the state, uses FRR. Only about 5% of North Carolina’s load is in PJM.
On Feb. 19, RTO Insider held an hourlong webinar with regulators from five of PJM’s biggest states to find out how they plan to respond to FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) to new state-subsidized resources (EL16-49, EL18-178).
Illinois Commerce Commission Chair Carrie K. Zalewski; Maryland Public Service Commission Chair Jason Stanek; Pennsylvania Public Utility Commissioner Andrew G. Place; Ohio Public Utilities Commissioner Beth Trombold; and New Jersey Board of Public Utilities President Joseph L. Fiordaliso joined RTO Insider Editor Rich Heidorn Jr. for the conversation.
The regulators were all highly critical of FERC’s ruling — and confident that parts of it will be overturned in the appellate courts — although not all states find it as disruptive as others. (See sidebar: MOPR a Non-Issue for Some PJM States.)
The expansion of the MOPR to existing subsidized nuclear plants is creating major headaches for regulators in New Jersey and Illinois, where nuclear plants are receiving zero-emission credits (ZECs). New Jersey and Maryland, which are planning large offshore wind farms, are upset by the order’s expansion of MOPR to new state-subsidized renewables.
Pennsylvania regulators are concerned that the order will lead to even more over-procurement of capacity. The PUC also said in its rehearing request that the order is arbitrary and capricious because it rejected the competitive exemption to natural gas-fired units not receiving a state subsidy.
The PUC of Ohio said it feared “increasingly complicated MOPR slicing-and-dicing administrative routines” that will disregard the preferences of willing buyers and sellers.
The regulators also expressed a diversity of opinion on how quickly PJM should hold its next Base Residual Auction under the new rules.
The webinar included questions from, and polling of, the audience. It was held the day after FERC issued a tolling order giving it more time to respond to the requests filed last month for rehearing and clarification.
Here’s what we heard. (The transcript has been lightly edited for length and clarity.)
Reaction to Dec. 19 Order
RTO Insider: Let’s go to our first poll question to our audience. We asked what their reaction was to the MOPR order. Were you very happy, very unhappy? Somewhere in the middle?
[Reading results] Not a lot of fans of the order thus far. We’ll let this go just a couple more seconds. At this point, it looks like, the majority of people are on the unhappy side of the coin. And I suspect that may also be the case here amongst our panelists, but let me open it up. So, Chair Zalewsky, tell us about your initial reaction to the order, and did anything in it surprise you?
Carrie K. Zalewski, Illinois Commerce Commission: I’m probably falling on the pretty unhappy spectrum. I don’t want to call the order [a] disaster. … But I think our surprise and disappointment is off the heels of the June 2018 order [in which FERC declared PJM’s existing MOPR unjust and unreasonable but offered a resource-specific fixed resource requirement as a possible option for subsidized resources].
We saw a little bit of hope and some chance in the 2018 order. As you recall, it says it does not take lightly the concerns that states might need to pay twice [for capacity]. This 2018 order [acknowledged] that that was a possibility [and] acknowledged states’ rights to propose valid policy. I think what was most surprising to the Illinois Commerce Commission is that [FERC] noted that it may be reasonable to allow for the resource specific FRR [in the June 2018 order]. And we find out on Dec. 19, that’s no longer the case.
RTO Insider: Who wants to jump in next? Joe?
Joseph L. Fiordaliso, New Jersey Board of Public Utilities: I’d be happy to. And I agree with the chairwoman in her remarks. [My] initial reaction, after they got me off the floor, was devastating. And I’m not going to be as polite as the chairwoman. I’m not going to insult anybody but, wow, were they [FERC] off track. And off track as far as New Jersey is concerned with our initiatives in the renewable energy area can be devastating.
Illinois has same problem as far as ZECs are concerned that we have, but we’re [also] going to have offshore wind pretty soon and this can be expensive; more expensive than we had anticipated if this is not rectified. And New Jersey is willing to go the [extra] mile to try to get some justice here, because it’s that important to our ratepayers.
I think the FERC commissioners who voted for it, as I said, were totally off track. And they did not take into consideration the impact on ratepayers. They did not take into consideration states’ rights. And we have to stand up, I believe, as a region, as an RTO, to get them to reconsider. And I’ve said this before, we’re ready for full frontal assault here against them.
RTO Insider: Thank you, Joe. Chairman Stanek?
Jason Stanek, Maryland Public Service Commission: Similar to both chairs, we were surprised and not in a good way. That decision obviously retreated from its earlier position, where we thought we were all working towards some alternative carve-out mechanism in the FRR market. So, we invested a lot of time and resources only to be surprised with an order that had a very expansive determination in terms of making that [MOPR] floor go as wide as possible with little to [no] exemptions. So, we’ve obviously filed for rehearing; we made note of the fact that FERC failed to consider our alternative proposal called the competitive carve-out auction. We made that a point in our rehearing request, but similar to the other chairs, we’re looking at all of our options right now. We have a work group in the state capitol, taking a look at how we would implement an FRR if we elect to go that route. But we also need time. This is very complicated. We’re working closely with the Market Monitor [in] PJM and our fellow PJM states to figure out what to do next.
RTO Insider: OK, thanks. Commissioner Trombold?
Beth Trombold, Public Utilities Commission of Ohio: Thanks. Ohio has some similar [reactions] to what was just spoken. I guess we never anticipated that FERC would take such a broad action to displace the state’s decisions made through what we believe were lawful exercises of power, or that FERC would fail to demonstrate that the current [capacity] market at PJM … was unjust or unreasonable. So, the order kind of sets in motion this period of uncertainty, which is very concerning to us, and the auctions that we hold here in Ohio [to set default retail generation rates]. And I don’t see how the order improves reliability in the interim or the future necessarily. So those are some of our concerns.
RTO Insider: And Commissioner Place?
Andrew G. Place, Pennsylvania Public Utility Commission: I wholeheartedly agree with what has been said so far. Particularly the breadth of what was defined as a subsidy got our attention. The rejection of the resource carve-out was a significant surprise. The bright line between state and federal jurisdiction authority really to us is eye-catching — that obviating or neglecting the ability of states to make their own choices. And then the disparate treatment between new and existing [resources]. I see no rational basis for the bright line that they drew between new and existing [resources].
Supreme Court or Bust
RTO Insider: Thank you. Chairman Stanek, you said that you’ve got a working group in the capital examining the FRR option. I wanted to ask the rest of you: If this is not overturned on appeal, or scaled back on rehearing, what are the alternatives that you are looking at? Are you considering the FRR option or even something more drastic than that?
Fiordaliso: I agree with Jason: This is a very complicated issue, and one that we are examining very, very closely. And it is one that is going to take us some time, along with our fellow states within the PJM footprint. And I might add, you know, the Organization of PJM States [Inc.] [OPSI] has also settled solidly behind this. And so, I think you have a lot of states and organizations [working to ensure] that something is done to alleviate this injustice, whether that is going to an FRR, whether that’s seeking … the legal avenue. I mean, we’re dealing here with not only the effect on the ratepayers, but we’re also dealing with a states’ rights issue. And the Supreme Court of the United States always likes to get involved in states’ rights issues. So, I wouldn’t be surprised to see this entire order go up to the Supreme Court for final determination. … FERC has stepped over the line, and somebody’s got to bring them back to the other side of that line. And as states, if we can continue to agree, we do have the ability, I believe, to bring [the commission] back to the other side of the line.
RTO Insider: Commissioner Place, let me ask you to follow up with that. And also give us some sense of the timeline. Are you guys willing to wait for the legal process to play out? It could be years before the D.C. Circuit [Court of Appeals], let alone the Supreme Court, rules on this.
Place: Yeah, from our perspective, we would rather see the [Base Residual] Auction take place sooner rather than later. We have implications in our own state for DSP [default service plan] filings that we will see immediate impact on. So, we clearly opined for reconsideration as well as clarification. But in the interim, we say the best course to minimize the damage is to have the auction sooner rather than later. I suspect we are somewhat divergent from our neighboring states on that issue, but it’s the short-term impact that’s got our attention in Pennsylvania. We are well along with compliance with the Alternative Energy Portfolio Standard. So, the impacts for us are on the out years, and they’re significant. So, I’m not minimizing that the rule is deeply flawed. But we have to judge what’s the bigger near-term impact. And for us, the near-term impact is largely if we delay the auction any further than necessary, and 2020 would be ideal for us. [Pennsylvania’s Alternative Energy Portfolio Standard requires that by 2021, 8% of electricity come from Tier I energy sources — including solar, wind, low-impact hydro, geothermal, biomass, coal-mine methane and fuel cells — and 10% from Tier II energy sources, including waste coal, distributed generation, demand-side management, large-scale hydro, municipal solid waste, wood pulping byproducts and integrated gasification combined cycle coal.]
RTO Insider: Just to follow up, commissioner, when you say the out years, is there a threshold? Is it three years, five years?
Place: There is no good, bright line. It’s this continuum, the drip, drip, drip, that will see continuing oversupply, which will damage particularly energy market prices. So, the damage [is] to generators, [who are] going to be dropping out because, for example, the nuclear units get much of their revenue from [the capacity market]. They will start to be bitten more and more. And you’ll get this greater and greater overhang of capacity that’s being built outside of the market. So, it’s a continuum. I’m not sure whether there is an inflection point out there. It’ll just worse year to year. So, it’s difficult to answer, but I’m thinking five years out, and certainly no more than 10 years out, you will see substantial damage from this rule if it if it remains in place. Although I agree with President Fiordaliso [about] the certainty that this will go through the courts.
RTO Insider: Thank you, commissioner. Commissioner Trombold, I’m sorry, you were trying to get in there.
Trombold: I just wanted to piggyback on Commissioner Place’s comment about the auctions occurring sooner rather than later. We were the only two OPSI states that both agreed to have the auction sooner rather than later. And in terms of the FRR in Ohio, no decisions have been made on that yet. But the companies would be the ones to elect the FRR in Ohio. So that’s just something I wanted to point out.
RTO Insider: You raise a very good point. When we talk about states [potentially] pulling out of the capacity auction, that does oversimplify it. If you wanted to direct your utilities to either go that route or not, what kind of control do you have to be able to do that?
Trombold: I’d have to double check with our legal eagles. But I believe that we do not have specific control over the FRR election. I don’t think that would be something that commission has powers to order.
RTO Insider: Thank you. Chair Zalewski, want to weigh in on this one?
Zalewski: Yeah, sure. In Illinois, we’re in our spring legislative session, which started in January and ends May 31. There have been bills previously filed that are circulating that do speak to FRR. This was before the order came down. It was in anticipation. So, these were, bills that were filed in previous spring sessions. Our governor did say in his State of the State [address] that his energy bill is at the top of his list. Now whether that includes an FRR is to be determined. He’s not taken an official stance on that. And I think he’s wise because his office as well as our office is waiting for some of these [MOPR] values to come down to really have an understanding of the impact. And obviously we’re hoping for more clarity. In our request for rehearing we asked for clarity, which I’m sure everyone — all other chairs and commissioners did as well. So hopefully that will shed light on it. With regard to the timing, we matched up with the letter that was filed on behalf of OPSI, which was a kind of a balanced approach where [the auction would be held] at least 12 months from the PJM compliance filing order, but not more than May 31, 2021. The idea being that’s enough time for the states to react — and maybe that’s not enough time, but some time for the states to react, whether that be a change in the renewable portfolio standard and how we address that or we go a different route — but not too much time. And I think this point was raised as well. These [generating] plants need to have an understanding of their revenue stream. So, the closer the auction is to the delivery year, I think it gets more and more complicated for them to make business decisions. So that’s how we landed on that timeline. It’s not perfect, but we had to pick something.
Impact on Renewables
RTO Insider: Thank you for those answers. I should update you. This morning the Market Implementation Committee had a special session on the MOPR ruling and much of the discussion was on potentially compressing the auction schedule from nine months to six months. There are three deliverables that happen in the nine-month time frame that they’re discussing compressing into six months, and that generally seemed to be fairly well received [by stakeholders]. I can say that the suggestion by Maryland that the auction not be held until [May] 2021 was deemed, quote, “crazy” by one generator, who said, you know, ‘We’re making investment decisions here. We need to move on.’ [See related story, PJM May Compress BRA Schedule over MOPR.] So, this is certainly an issue that we will be tracking going forward.
I’m going to pause for another poll here. This has to do with the impact of the MOPR on new renewable generation: Assuming it’s not overturned on appeal or rehearing, will it have a big impact, a small impact or medium impact? Of course, I didn’t really qualify over what time frame I was saying. So, some people may be wondering about that. But maybe you all can comment on that once we complete the poll.
[Reading results] OK, about half say it’ll have a big impact. About a third say a medium impact, and about the fifth say a small impact. So, what say you panelists?
Fiordaliso: I would say big impact. … Any renewable [that] comes online is going to face this situation. And we have 7,500 MW of offshore wind scheduled by 2035. We have ZECs that are going to be on the chopping block. Any new renewable that we’re not even thinking about probably today that comes online will be severely affected in my mind. This is the federal government’s way of saying that, ‘You want to do clean energy? Fine, but we really don’t support it. So, we’re going to throw obstacles. We’re going to throw barriers in front of you to make it more challenging.’ Instead of making it less challenging, so that we can proceed in a prudent, logical fashion to mitigate the effects of climate change. We don’t need these roadblocks. What we need is cooperation.
Stanek: I agree with Joe. We know that FERC crossed the line under Section 201 of the Federal Power Act, which delineates the wholesale markets from the retail markets. To your question, I think you picked up on the area where we could have had more clarity. Where are we going to see this [impact]? In the near term? Years further out? If we look back at the last auction that was conducted in May of 2018, only about 1%, a little over 1% of the cleared capacity was renewables. And I suspect that that will continue on for the next couple of years. But this problem will magnify as we go further out, and then perhaps the rate impacts will be several billion dollars. Commissioner [Richard] Glick, I believe he estimated $2.4 billion annually. So, whether it happens next year or 2022, we’re going to see the effects begin to ramp up within the next, I would estimate, two to three years.
Fiordaliso: I would agree with that, Jason. And the major effect on New Jersey will probably be the next year and a half to two years. I would expect the generators to say that Maryland’s stand on this is crazy. However, I don’t think it’s necessarily crazy.
RTO Insider: Joe, let me follow up on something you said. [FERC] Chairman [Neil] Chatterjee has said this is all about protecting the markets. You suggested that this is really a manifestation of the Trump administration’s hostility to clean energy policy. Do you not buy what Chairman Chatterjee is saying? Do you really think this is just a naked political move?
Fiordaliso: Honestly, yes, I do. Why present these kind of challenges if the states are trying to do programs that hopefully will mitigate the effects of climate change? Why throw obstacles in our way? The federal government is doing nothing regarding climate change. It’s up to the states to do it. We’re willing to do it. And we’re willing to prudently move down this path of a carbon-neutral environment by 2050. If the federal government doesn’t want to join us, fine, just get out of our way.
RTO Insider: Commissioner Place, would you like to weigh in on that?
Place: Yeah, happy to. From a parochial perspective, our Alternative Energy Portfolio Standard is essentially flatlined where it is. It’ll hit its peak in 2021. So, our parochial impact for our renewable portfolio is marginal. Plus, we have [an] overbuild, except perhaps in some in-state solar, to meet the requirements through 2021. … But the question was PJM-wide and very clearly, I would agree that this would have draconian impact on states’ desires to build renewable power. And I think the problem I have with the ruling is that it, it doesn’t tackle the problem. As I noted earlier, you’re going to see states are going to build regardless. New Jersey is going to build offshore wind; Maryland’s going to build offshore wind. Those are going to happen. So, you’re going to have more states potentially doing FRR. You’re going to have this great overhang of excess capacity being built outside the market. You’re going to see that deleterious impact on energy market prices, all of which is going to make the current impact from state-supported resources in the market pale in comparison to what you will see five, 10 years from now. It’s a moment where you really do need to go back to square one and think about how this mechanism should be done. If you care about the integrity of the market, you’re just simply not tackling the problem or the issue that you’ve identified. I wholeheartedly agree, the state’s ability to choose their own path forward should be in this way sacrosanct, other than not distorting the market. But you can clearly develop mechanisms that accomplish both the state’s desires to have the portfolio of their choice, but also ensure that capacity markets — or if it’s a totally new construct — [obtain] capacity. Or do we go back to essentially an energy[-only] market formulation? Those solutions are all achievable versus what was put on the table here, which does look like a very pointed, very one-dimensional attack, on renewable choices by states.
Impact on Coal, Gas
RTO Insider: Let me go to a related question that was posed by one of our listeners, Michelle Bloodworth [CEO of coal trade group America’s Power]. She asked: ‘What impact will the MOPR have on the coal fleet?’
Stanek: I would suspect in the near term, this would be a net positive for any of the fossil resources, whether it be gas or coal. So, I suspect that those sectors viewed the December order rather favorably.
Fiordaliso: Yeah, I would concur.
RTO Insider: Commissioner Place, do you have any perspective on that, given the Pennsylvania’s spot in the fossil generation?
Place: I agree. Certainly in the near term, it’s advantageous. But … there are probably greater economic forces driving us away from coal consumption. So, they’ve got substantial headwinds. But this is, in isolation, sort of a short-term net benefit to the coal generators, and as Chairman Stanek pointed out, to all fossil generation.
Carbon Pricing
RTO Insider: A couple weeks ago, PJM appeared on a forum and suggested that really the answer to this dilemma — this constant conflict between state and federal policy over environmental policy and emissions — is a carbon price. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.) And clearly, that is a very complicated and potentially divisive issue. But I wanted to ask you, what do you think your state’s appetite is for a carbon price? Is it a realistic idea? We know that the New England states, while they have RGGI [the Regional Greenhouse Gas Initiative], the bigger states and more aggressive states were unable to persuade some of their smaller more conservative states to up the carbon emission targets as part of their approach to the capacity market. So, do you see this as either feasible or acceptable to your state?
Stanek: Well, as a RGGI state … we see the benefits of having a carbon cap-and-trade program here. I think what was laid bare in the Dec. 19 order was the fact that we don’t have any value on carbon, whether at the federal level or at the PJM level. And if we did, we’d be able to [put a] value on our preferred resources and we’d be out of this mess entirely. But as a RGGI state along with New Jersey … we see some benefits. But we do have issues with leakage regarding some of our neighboring states. And that’s a problem with having voluntary constructs such as RGGI.
Zalewski: Illinois — we’re not a RGGI state — does not have a broad carbon price. However, the state has employed carbon prices for legislation. For example, customers pay on their utility bills for ZECs — they pay $16.50/MWh — and also through a renewable portfolio standard. And so, through policies like this clean energy is given a priority over dirty generation. I’m not aware of any additional legislation as I sit here right now of potentially going to moving towards RGGI. I think everyone right now is reassessing and seeing if it makes sense. It’s not clear obviously how RGGI would be MOPR’d. … I think that there are people thinking through all options. But as I sit here today, that’s going towards a RGGI in Illinois, to my understanding, has not been put on the table for legislation.
Place: And if I may jump in, as most everyone I presume on this call is aware, Pennsylvania, under an order by our governor late last year, will be linking to RGGI. The rule is expected to be before the Environmental Quality Board in July of this year. And so that’s the extent of our conversation within the commonwealth on pricing carbon. We did have the conversation last year — the nuclear debate [over ZEC-type subsidies]. I can’t comment on whether that will resurface and whether that is another piece of this.
RTO Insider: I should mention in Pennsylvania, for context, there was a hearing last week in the legislature, the Republican-controlled legislature, which is not in favor of joining RGGI. And they made sure that not a single pro-RGGI witness apparently testified. (See Critics: Pa. RGGI Hearing Stacked with Detractors.) The legislature believes that the governor does not have the authority to enter RGGI. Does the PUC have an opinion on that at this point?
Place: The PUC does not have an opinion on that. But I would steer it towards the governor’s belief that he has the authority to do so. And when I did watch the legislative hearing last week, [I] agree with you that … there was no balance.
Fiordaliso: New Jersey, Rich, just recently rejoined RGGI after many years of absence. And we’re very happy to be back in RGGI. And generally speaking, I think the concept of carbon pricing is very much in line with our clean energy goals.
RTO Insider: Commissioner Trombold, did you want to weigh in on this, or is this a hot potato?
Trombold: [laughs] Well, yeah, we’ve talked about carbon pricing probably for the last 30 years, and it hasn’t really happened yet. I think there’s many coal states in PJM, and we’d have to get all the PJM states on board in order to do something like this. I think at the end of the day, every state has to do what’s in their best interest. So that’s why the PUCO hasn’t really weighed in on any kind of carbon pricing at this point.
RTO Insider: I do note that the PJM has actually said that they wouldn’t need all of the states to join. But it certainly would be a lot more complicated if you’ve got some states in, some states out, referring to leakages as Chair Stanek mentioned.
Place: I should jump in. The governor’s executive order on RGGI did contemplate leakage and border adjustments. So that that’s yet to be determined on what that might look like — emissions leakage or economic leakage. That’s clearly on the menu here in Pennsylvania.
Economic Impact
RTO Insider: I’ve got another question here from Nancy Bagot, [senior vice president] from EPSA [the Electric Power Supply Association]. She says: ‘Many clean energy resources have become increasingly cost competitive, if not more competitive than existing resources. Therefore, most may clear [the capacity auction] using the unit-specific exemption. How are states making the assessment that this will have a great impact? Also, offshore wind is so expensive comparatively, it could never clear a regional auction. So how is it disadvantaged? As states follow their own paths, how is reliability being ensured on a system that is physically regional?’
I’ll let you guys jump in on to any or all of that.
Fiordaliso: I’d like to jump in, Rich. I think renewables in general, initially are expensive. But I can build a solar installation today for half the price of what it would have cost me back in 2008. I think we’re seeing prices, price per kilowatt-hour, decreasing as renewables become more prevalent. I think the offshore wind is going to follow the same pattern.
And I think one of the things we don’t really put a lot of emphasis on, and we should, [is] the economic impact of renewable energy. As an example, in the state of New Jersey, we have over 7,000 people working just in the solar industry. We expect thousands more to be working in the wind industry. And all of the ancillary businesses that feed into you know, along the East Coast here. States like Maryland and New Jersey can be supply chains for offshore wind throughout the Northeast. So, we rarely look at the economic advantages. All we do is look at the economic disadvantages with offshore wind. I submit the advantages certainly outweigh the disadvantages when we take into consideration not only the supply chains and things of that sort and the ancillary businesses that will grow around wind and solar, etc. But also, can we afford not to spend the money to mitigate what 98% of all scientists tell us can be a catastrophe in years to come?
Zalewski: [In] Illinois, I think the immediate answer is we’re just collecting as much data as we can and trying to keep current with the information coming at us with things like the MOPR [pricing] data. In fact, our General Assembly just called a subject matter hearing this Friday to discuss this, the impacts of the MOPR. And we’re having the Market Monitor coming to speak to our legislators. … The Market Monitor has put out a report, they indicate that … the MOPR may not be so high that some of these resources can’t clear [in the auction]. We also know, capacity revenues for renewables are not as much of an impact on revenues in total as compared to nuclear.
… And I agree with the economic impact. In Illinois, we have a preference for in-state renewables. The legislation we’re under is the Future Energy Jobs Act. The ‘J’ stands for ‘jobs.’ All renewables must be in-state. … I agree, it will be a big hit to the state if we do see renewables taking a backslide.
Stanek: I don’t think the question that was asked is an unreasonable one: Can we use the unit-specific exemption for some of these clean technologies that are more cost competitive? But there is recognition — and I think the questioner was right — offshore wind is terribly expensive. But states such as Maryland have passed laws to provide these subsidies, these RECs [renewable energy credits] to the wind developers. And we recognize that it’s going to cost more than, let’s say, a gas plant or a coal plant to operate. But that’s the state’s decision. And under Section 201 of the Federal Power Act, states determine their resource portfolio, including the type of generation that they want to see in their mix. So, I would I push back gently on Nancy’s question. I think there will be some use of the unit-specific exemption, but I don’t think it’s going to be all that great.
Impact on Demand Response, Energy Efficiency
RTO Insider: Let me move over to another question from the audience. And this is a question that is actually being discussed right now, by the Demand Response Subcommittee at PJM. That is: What is the effect of the order on the EE [energy efficiency] and DR [demand response] programs of your utilities?
Stanek: At this early stage, it seems like EE and DR would not be exempted under the Dec. 19 decision. So, we’re still waiting to see the effects. We haven’t spent as much time on those two areas of generation [as] some of the others, but it’s obviously going to have an impact on both.
Place: That was one of our [requests for] clarification. I wouldn’t bet the house that DR and EE are not going to be caught up in this. So, for our Act 129 [energy efficiency] programs, we are very much looking forward to a clarification and to ensure they are not going to be MOPR’d.
Fiordaliso: All I would say is that it’s too early and there have not been clarifications regarding certain areas. And so, we’re looking at a wide variety of alternatives, us here in New Jersey, and waiting for some of these clarifications — if we ever get them.
Zalewski: We have the same concerns, and we made note of that in our in our request for rehearing and request for clarification. It’s also unclear the distinction between new and existing demand response programs too. So just adding on to the questions waiting for answers from FERC.
Stanek: I think the point that Joe just made is, if and when we ever get [answers]. We still have a rehearing request outstanding from the June 2018 order. Now we have rehearing [requests] from the December 2019 order. And we found out just yesterday that rehearing, not surprisingly, is going to be tolled, but until when? 2021? It could be a while.
FRR Option
RTO Insider: Hopefully, we’ll get some clarity on that from the D.C. Circuit; I believe next month they’ve got oral arguments in a case that deals with the tolling orders in Natural Gas Act proceedings. A lot of people seem to think that will also have some application on FPA cases also. I have a question here from Kyle Vanderhelm [director of fundamental analysis at Tenaska]: ‘Most panelists seem to be have been OK with a resource-specific carve-out FRR. Why is that workable and FRR as it stands not workable? It seems that FRR for an entire region maybe more straightforward than one-off carve-outs.’
Anybody have any insights on that?
Fiordaliso: I don’t have any insights. I would only say that we’re still exploring. It’s early yet. … We’re still exploring: Is that the right way to go? Is it the most efficient way to go? And so, we have not in New Jersey come to that determination.
Stanek: In Maryland, I would say that we’re trying to evaluate the pros and cons right now. And there are cons. We will need some authority to provide some oversight of any FRR, whether it be one utility or all of our utilities in the state. And I have to ask myself the question: Will it be PJM subcontracting? Will the PSC be able to handle that in-house? What do we do with retail supply that’s about a fifth of the book in the state of Maryland? Will [they] be able to contract with their own resources? So, there’s more questions than answers. We’ve been an early advocate of moving the auctions out by a year, and one of the reasons is because the Dec. 19 order made clear that FERC is not likely going to rerun any auctions. So, we’ll have to live with the next auction results. That’s the reason for our [request for] delay, whether it be crazy or not.
Legal Vulnerabilities
RTO Insider: Alright, let me go to our next poll question: ‘How will the MOPR ruling fare in the appellate courts? Very well: It will be upheld in its entirety. So, so: There will be moderate changes to the ruling. Poorly: The court will largely reject FERC’s order.’
Stanek: I would just jump in quickly and say that the courts have consistently recognized state authority over generation matters. And we’ve seen a recent line of cases — whether it be EPSA, ONEOK or Talen v. Hughes, which we, Maryland, did not win, but it provided a precedent that defines the line between the feds and the retail regulators and the sense of cooperative federalism that we did not see into December order. So, I would be rather bullish here and choose option [three] ‘poorly.’
RTO Insider: Alright, well, there aren’t too many people [responding to the poll] who think it’s going to survive unscathed. Did anybody else want to weigh in on that subject?
Fiordaliso: And ultimately, it’s gonna wind up where? The Supreme Court.
Place: Yeah, and, and to me, just looking at it sort of piece by piece, particularly the disparate treatment of new versus existing [resources]. I think there’s chunks in here that I just don’t see doing well [on appeal] and being shown to be just and reasonable.
Zalewski: And there’s another layer: … not only the disparity between new and existing [resources] but the disparity between vertically integrated and deregulated states and how their resources are. And again, that leads back to a state’s decision to be become deregulated. So, we’re just circling back to where we started — the overstepping of the federal government [on] states’ rights. There’s lots of layers to it.
Place: Also, thinking about the disparate treatment between state subsidy and federal subsidy — I don’t see how a court will look at that and think that that’s a rational outcome.
RTO Insider: We have another question here from Rob Gramlich. You may recall a few months ago, Rob made some headlines with a study that found that an expanded MOPR could greatly increase [capacity] costs. He asks: ‘In other regions such as SPP, the Regional State Committee makes the high-level policy calls on resource adequacy, which FERC put in place at its start-up, recognizing the states’ authority. The idea was raised at last fall’s OPSI meeting. What do you think of that as an additional option for states to make sure wholesale markets and state policy fit together?’
Stanek: [laughs] Leave it to Rob Gramlich to come up with a question like that. Let me think about that.
RTO Insider: [pause] OK, I think Rob stumped the panel. I should mention also that on tomorrow’s agenda for FERC there is an order in FERC Narrows NYISO Mitigation Exemptions.]
Let me ask: Illinois in its rehearing request said that state policies are not subsidies but compensation for clean energy resource attributes to address PJM’s failure to account for negative environmental externality. State policy initiatives ‘improve the efficiency and price signaling aspects of PJM’s capacity auction process by accounting for the social cost of carbon.’ Can you elaborate on that Chair Zalewski?
Zalewski: Our first concern is with the term ‘subsidy.’ It’s a pejorative term, suggesting that subsidies move away from economically efficient solutions. However, we talked a little bit about this previously. This is a classic example of market failure when pollution costs are not addressed. FERC and PJM have repeatedly failed to address this market failure. And so, I think that our point is that when these pollution costs are not accounted for, markets don’t produce economically efficient solutions.
RTO Insider: We have a one more question here. Again, Kyle VanderHelm asks: ‘Do you see value in having a competitive capacity market? If so, are you supportive of alternative approaches to avoid price suppression from subsidized capacity?’
Stanek: Absolutely.
Fiordaliso: Yeah.
Place: The challenge I’ve long had is that the capacity price is a contrived mechanism. It’s a construct, versus the energy [price], which is market driven. So, although we’ve seen value in the capacity market, PJM is historically over-procuring, and it is flawed in that it’s an artificial mathematical construct. So yes, there’s some value there. But are there better ways to do it? I would argue yes.
Zalewski: I take umbrage with the second part of that question about market suppression. That was one of our points in our request for rehearing — that there’s no evidence of price suppression. … But yeah, I echo that [there] could be a good alternative.
Trombold: Ohio agrees with what the chair just said. You know, there’s lots of things that cause price suppression in the market, not just some kind of state support. I mean, there’s things like bidding behavior, forced outages, capacity imports. And we put that all into our rehearing requests as well.
Place: And if you look currently, if you go down that track of price suppression, the impacts currently in the market are small. You’re chasing a solution in search of a problem. And yes, you can see over time that the price suppression may become an issue with state resources. But I’m not buying that it’s a house-on-fire problem today or even tomorrow.
And I did also not want to let the Illinois carry the full burden on the points about subsidy versus internalizing big external costs of pollution. I’ve not taken a shot at fossil — I used to work in natural gas business. But clearly, if you’re a resource that’s able to emit without monetizing the cost to society of those emissions, then that is an inverse subsidy. So, I think it’s disingenuous to simply go down this route that says that states are doing something untoward by trying to internalize the price of those emissions.
RTO Insider: Well, thank you. I really want to thank all of you for participating today. This was a really, really good conversation. We’re about out of time. We have one more [poll question]. OK. You guys have already weighed in on this: ‘What is the biggest legal vulnerability in the MOPR ruling? Exempting future resources?’ All of you cited these examples. ‘Exempting future federal subsidies but not future state subsidies? Eliminating the exemption for future supply-side resources and FERC’s jurisdiction over state resource choices?’
[Reading results] The jurisdictional issue is very, very popular. This one’s a landslide.
Well, thank you very much. And I also want to thank the audience for its participation. We had some great questions and some great feedback on these questions. We of course will be following this on a daily basis up at PJM.
