A New York judge ruled last week that the state’s Public Service Commission has “the very broadest of powers” to regulate energy service companies and utility rates, especially when seeking to prevent the overcharging of low-income customers.
The June 30 decision by Supreme Court Justice Henry Zwack dismissed a case filed against the commission by the National Energy Marketers Association and three energy service companies (ESCOs), as well as a similar suit by the Retail Energy Supply Association.
Nikola Tesla corner in New York City
The ruling also lifted Zwack’s own temporary injunction against the PSC’s February 2016 “reset order,” which sought to overhaul the business practices of retail energy suppliers and limit the ability of independent energy marketers to sell electricity and gas to low-income customers (15-M-0127, et al.). (See New York ESCO Order Vacated by Court.)
The commission’s order mandated that ESCOs guarantee all mass-market customers an electric rate lower than what their host utility offers, with the exception of “green” offerings, which must include a minimum of 30% renewable energy. The PSC said it intended to combat deceptive practices and boost consumer confidence.
The energy companies argued that the commission overstepped its regulatory authority and violated the privacy of participants in New York’s Home Energy Assistance Program (HEAP).
The injunction did not affect the PSC’s July 2016 moratorium on ESCOs signing up additional low-income customers, which the commission issued after the failure of a collaborative effort to develop a formula that could guarantee savings. (See NYPSC Declares Moratorium on Low-Income Sign-ups.)
No ‘Independent Rights’ for ESCOs
The notion that ESCOs “have somehow morphed into a separate energy sector with independent rights simply has no basis in law,” Zwack wrote in his opinion. “To the extent that ESCOs believe that their regulation must be minimized because of this also has no basis in law.”
The PSC moved quickly last year to address the judge’s concerns about its procedural practices, and last December it launched hearings to examine ESCO marketing practices.
‘Immediate Reform’ Needed
In weighing the privacy of low-income customers against ensuring their right not to overpay for energy services — and against the public’s right not to subsidize ESCOs — the court found the sharing of customers’ HEAP status to be “well within the authority” of the commission.
“What can also be reasonably concluded is that the ESCOs have instead focused on litigation to frustrate the plain purpose of … consumer protection through the adoption of reasonable rates, particularly for those whose utility costs are being subsidized by the public,” the court said. “The ESCO market is in need of immediate reform to protect low-income consumers and to avoid the diminution of taxpayer-funded assistance funds.”
Richard Berkley, director of consumer advocacy group Public Utility Law Project of New York, told RTO Insider that ESCO customers are being overcharged millions of dollars a month, “which pays for a lot of lawyering.”
| EIA
The PSC found that ESCOs overcharged customers by $819 million between January 2014 and June 2016, with low-income customers representing $96 million of the overcharges.
A United Way study in 2016 found that, while federal poverty benchmarks show 15% of New York households experience financial hardship, an additional 29% (2.1 million households) have income above the federal poverty level but still cannot sustain a basic household budget that covers housing, child care, food, transportation and health care.
Warren Buffett is stepping in where two other suitors have failed and will soon make a deal for Oncor, Texas’ largest transmission and distribution utility, according to The Wall Street Journal.
Citing sources “familiar with the matter,” the Journalreported that an announcement by Berkshire Hathaway Energy proposing to acquire Oncor was imminent. The acquisition’s terms have not been disclosed but are thought to be more than $17.5 billion and less than the $18.7 billion NextEra Energy put up last year, according to reports.
Buffett
NextEra’s bid was spiked by the Public Utility Commission of Texas, which ruled in April that the proposed merger was not in the public interest. The commission subsequently rejected two requests for rehearing by NextEra and Oncor. (See NextEra-Oncor Deal Meets Third Denial.)
NextEra’s failure was preceded by that of Dallas-based Hunt Consolidated, which saw its bid fall apart last year when the PUC placed conditions on the transaction that the Hunt family was unable to meet. Hunt’s motion for rehearing also was turned down by the commission. (See Texas PUC Denies Rehearing on Oncor Sale, Ends Hunt Bid.)
Oncor’s sale is instrumental to resolving the $42 billion bankruptcy of Energy Future Holdings, Oncor’s parent company. EFH declared Chapter 11 bankruptcy in April 2014, and creditors last year reached a settlement contingent on Oncor’s sale.
A regulated utility, Oncor has maintained its profitability despite EFH’s woes. The Berkshire Hathaway acquisition, like the previous two failed bids, would require PUC approval.
Berkshire Hathaway, headed by billionaire Buffett, was among those thought to be interested in the company after the Hunt deal fell apart.
Oncor would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, the company held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
Buffett has made several large purchases lately, including spending $32 billion for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, he told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
Warren Buffett’s bid for Oncor won an immediate endorsement from the head of the Texas Public Utility Commission’s staff Friday, suggesting the Oracle of Omaha may succeed where two other suitors for the state’s largest transmission and distribution utility failed. But first, Buffett may have to overcome a challenge from hedge fund Elliott Management, which is reportedly unhappy with the offering price.
Des Moines, Iowa-based Berkshire Hathaway Energy (BHE) announced Friday it had reached an agreement on an all-cash deal that will pay $9 billion for bankrupt Energy Future Holdings (EFH), Oncor’s parent. BHE said that is based on an equity value of $11.25 billion for 100% of Oncor. The Wall Street Journal, which reported Thursday that the deal was imminent, said the purchase has an enterprise value of about $18 billion including debt.
BHE said it expects the purchase to close in the fourth quarter, following approvals by federal and state regulators and the judge overseeing EFH’s bankruptcy.
The PUC rejected prior bids for Oncor by Florida-based NextEra Energy and Dallas-based Hunt Consolidated. But PUC Executive Director Brian Lloyd issued a statement praising the BHE offer, saying he looks “forward to an expeditious filing of this agreement for the commissioners to consider.”
“I applaud both Berkshire Hathaway Energy and Oncor for their productive efforts with PUC staff, the Office of Public Utility Counsel, the Steering Committee of Oncor Cities and Texas Industrial Energy Consumers,” he said. “These parties have developed a transaction that fortifies the successful ring-fence protections the commission ordered in 2007. Both BHE and Oncor are proposing additional assurances regarding Oncor’s independence, financial integrity and commitments to invest in infrastructure, cybersecurity and system reliability for the more than 10 million Texans served by Oncor.”
PUC spokesman Terry Hadley said Lloyd’s statement was based on meetings that preceded the merger announcement. “As is typical with this process, the PUC staff and other parties mentioned in the statement met informally to see what can be resolved prior to an official filing,” Hadley said. He said the first filings on the deal will likely be with the bankruptcy court.
Winning the Debtors
Winning regulators’ approval is only part of the challenge facing Berkshire, however.
Elliott Management, a $33 billion hedge fund that is the biggest holder of EFH bonds, is signaling it may make a competing bid for Oncor, the Journal and Reuters reported late Friday. Elliott added to its stake in the last several months, acquiring them from other funds tired of waiting for an Oncor sale.
Although the fund has no experience in an acquisition of this size, the Journalreported, it could threaten a higher bid to force Berkshire to improve its offer, which is insufficient to pay creditors 100 cents on the dollar. With a “blocking” position in two classes of EFH debt, Elliot has a pivotal role in whether creditors accept the Berkshire offer and complete EFH’s bankruptcy reorganization. Elliott had previously opposed NextEra’s higher bid for Oncor.
Reuters noted that Elliott filed a lawsuit in May asking EFH to consider a debt reorganization that could convert the hedge fund’s debt to equity, which could give it control of Oncor. EFH owns 80% of Oncor.
Prior Deals Rejected
The PUC rejected NextEra’s $18.7 billion bid for Oncor in April, ruling that the proposed merger was not in the public interest. (See NextEra-Oncor Deal Meets Third Denial.)
The commission said it believed the risks posed by NextEra’s acquisition outweighed the benefits, fearing that it would dilute Oncor’s credit profile and eliminate local control. The PUC insisted on strong ring-fencing provisions, including “a truly independent” Oncor board with control over decisions on capital expenditures and operating expenses — a requirement NextEra rejected as a “deal-killer.”
The DallasMorning News reported that BHE has agreed to 44 commitments to the PUC, including an independent board that would have complete control over how to use Oncor’s dividends. Only two of the 12 board members would be appointed by BHE, the paper said.
BHE says that it does not pay dividends “and can invest our profits back into our businesses to provide additional value for our customers. This relationship to our parent uniquely positions us to take a long-term view and to take on ambitious energy projects that other companies may not be able to afford.”
The company also reportedly committed to returning 90% of interest rate savings to customers in rate cuts until the next rate case after one currently pending is final. There would also be no involuntary layoffs or wage and benefit cuts for at least two years for Oncor’s 3,700 workers, the Morning News said.
“The bankruptcy court has to bless it, and it ultimately has to come to commission,” Geoffrey Gay, who represents the Oncor cities steering committee, told the paper. “If they follow the path of failures by Hunt and NextEra, they ought to be able to safely navigate through these obstacles.”
BHE contributed almost 10% of the earnings last year to Buffett’s Berkshire Hathaway conglomerate, whose holdings include GEICO, Kraft Heinz, Fruit of the Loom, Benjamin Moore and BNSF Railway. The company earned $24.07 billion last year, and its $223.6 billion in revenue last year ranked it No. 2 on the Fortune 500 list, behind only Walmart.
Texas Connections
In an apparent bid to curry favor with state regulators, the second paragraph of the press release announcing the deal noted the conglomerate’s other holdings with headquarters in Texas, listing 10 of them.
“Oncor is an excellent fit for Berkshire Hathaway, and we are pleased to make another long-term investment in Texas — when we invest in Texas, we invest big!” Buffett said in a statement. “Oncor is a great company with similar values and outstanding assets.”
| Buffett
Oncor CEO Bob Shapard said the merger would give his company “access to additional operational and financial resources as we continue to position Oncor to support the evolving energy needs of our state.”
“Being part of Berkshire Hathaway Energy is a great outcome for Oncor,” he added in a statement. “Oncor will remain a locally managed Texas company headquartered in Dallas, committed to the communities we serve, and our customers will continue to receive the safe and reliable service they have come to expect from our dedicated team of employees.”
Shapard, who announced plans to retire last October, will become executive chairman of the Oncor board. Senior Vice President and General Counsel Allen Nye will replace him as CEO, as previously announced, Oncor said.
Nye said he was “excited to begin the regulatory approval process,” adding “this transaction has significant support across our key stakeholders.”
Resolving Bankruptcy
Oncor has been ring-fenced since 2007, when EFH, a collaboration of several private-equity firms, acquired TXU Corp. in a leveraged buyout. EFH, saddled by nearly $50 billion in debt when it bet wrong on high gas prices, declared Chapter 11 bankruptcy in 2014.
Creditors last year reached a settlement of the bankruptcy contingent on Oncor’s sale. EFH has already spun off generator Luminant and retailer TXU Energy into a new publicly traded company, Vistra Energy. (See TXU Energy, Luminant Rebrand as Vistra Energy.)
With about 121,000 miles of transmission and distribution, Oncor owns and operates the grid for most of North Texas.
It would join BHE’s NV Energy, MidAmerican Energy and PacifiCorp, which collectively serve 11.6 million electric customers. As of 2016, BHE held $85 billion in assets, including almost 236,000 miles of transmission and ownership or control of more than 35 GW of generating capacity. The companies employ about 21,000.
| Berkshire Hathaway Energy
BHE earned $2.29 billion last year, 9.5% of the conglomerate’s total. Had Oncor’s $431 million in profits been part of BHE in 2016, the energy unit would have generated 11.1% of the conglomerate’s earnings.
BHE is headed by CEO Greg Abel, who has been mentioned as a possible successor to the 86-year-old Buffett as chairman of Berkshire.
The Oncor purchase would be Berkshire’s largest acquisition since its $32 billion deal for Precision Castparts Corp. last year, according to the Journal. With more than $95 billion in cash and cash equivalents, Buffett told investors during Berkshire’s annual meeting in May, the time may come when the company has more cash than it can profitably use.
“Even at $9 billion, the takeover of Oncor … is tens of billions of dollars shy of the mega-deal Berkshire Hathaway Inc. shareholders have anticipated for more than a year,” Tara Lachapelle and Liam Denning wrote in a Bloomberg Gadfly column Friday. “Costco Wholesale Corp., 3M Co. and Hershey Co. are closer to the kinds of names investors had in mind for Berkshire’s next big transaction, as its cash pile grows uncomfortably high.”
MISO’s Independent Market Monitor still sees room for significant improvement after giving the RTO’s markets a passing grade for last year.
“Although the energy markets generally set efficient prices in 2016, we recommend improvements to MISO’s price formation through improved shortage pricing and price-setting by peaking resources,” Monitor David Patton said in his annual State of the Market report released last week, which included nine new recommendations.
The Monitor concluded that — based on the “output gap” measure of economic withholding (the difference between potential and actual energy output) — “potential” withholding of generation represented just 0.11% of load and scarcity mitigation was “infrequently implied.”
The report also showed that modest declines in fuel prices contributed to slightly lower energy prices, make-whole payments and congestion costs than in 2015. MISO’s peak load of 121 GW was slightly higher than the previous year but well below the forecasted peak of 125.9 GW because of mild weather and lower loads. Real-time congestion, however, rose 4.3% from 2015, totaling about $1.4 billion, “amongst the highest in the U.S.,” according to Patton, which he in part attributed to high outage rates in MISO South.
| Potomac Economics
The Monitor’s new market recommendations — many of them already familiar to MISO staff and stakeholders — join a rolling list of unimplemented recommendations dating back to 2010:
Improve shortage pricing by adopting an improved contingency reserve demand curve that reflects the expected value of lost load (VoLL). Patton recommended earlier this year that the RTO immediately up its $3,500/MWh VoLL limit to $9,000/MWh and change its operating reserve demand curve calculation to a sloped curve that he contends would better price shortages. (See MISO, IMM Differ over Scarcity Pricing Changes.)
Transfer control of market-to-market flowgates to improve procedures for M2M activation and coordination. The Monitor would like to see MISO, PJM and SPP become more active in transferring monitoring of constraints when the non-monitoring RTO has all of the transmission loading relief on a flowgate. Last month, MISO and SPP announced plans to begin swapping flowgate control. (See MISO Interregional Plans with SPP Echo PJM Efforts.)
File changes with FERC to give MISO increased authority to approve generation and transmission planned outages and the ability to coordinate outage schedules in order to lower costs. The Monitor said the move would reduce both outage-related congestion during peak outage season and capacity-related emergency events during the shoulder months. Currently, the RTO can only recommend outage schedules and work with operators to reschedule planned outages when reliability is at risk. Last month, both MISO and the Monitor expressed concern over higher-than-usual planned outages in MISO South during the spring. (See MISO South Outages Worry RTO, Monitor.) The Monitor reported that from January 2016 to May 2017, 25% of all real-time congestion ($457 million) could be traced to concurrent generation outages.
Establish regional reserve requirements, creating a local, 30-minute reserve product and developing procurement requirements in areas with voltage and local reliability needs. The Monitor said the reserve product will align the market with reliability needs, allow MISO to accurately price subregional shortages and “lower costs by allowing the markets to satisfy MISO’s reliability needs and reducing out-of-market actions by MISO operators.” Like several other 2016 State of the Market recommendations, this recommendation appeared earlier this year when the Monitor submitted it for consideration in the RTO’s Market Roadmap list of market changes. (See MISO Steering Committee OKs IMM Proposals for Market Roadmap.)
Change MISO’s Day-Ahead Margin Assistance Payment (DAMAP) and Real-Time Offer Revenue Sufficiency Guarantee Payment (RTORSGP) rules to compensate wind operators whose output more closely matches their day-ahead forecasts and reduce gaming opportunities and unjustified costs. Patton warned the RTO late last year that wind generators appeared to be deliberately over-forecasting their output to inflate payments made through revenue sufficiency guarantees. (See MISO IMM Sees Deliberate Over-Forecasting by Wind Operators.)
Increase the accuracy of MISO’s Look-Ahead Commitment recommendation, which was developed in 2012, and seek to improve resource commitment by modeling system conditions for a three-hour future time frame.
Improve forecasting incentives for wind resources by creating a method to validate wind supplier forecasts and use the results to alter dispatch instructions if needed, while improving forecasting incentives by modifying deviation thresholds and settlement rules.
Disqualify from the Planning Resource Auction any resources expected to be unavailable during peak conditions. MISO is currently shopping its own proposal to prohibit resources on extended outages from participating in future auctions or making changes to capture the risk of such outages in loss-of-load-expectation analyses. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
The Monitor also warned that the $1.50/MW-day footprint-wide clearing price in MISO’s spring capacity auction was too low to be sustainable.
“This is essentially zero. This is not an efficient price under current capacity levels and will motivate poor retirement and export decisions by MISO’s competitive suppliers,” Patton said.
Despite FERC’s rejection of a three-year forward market design for MISO’s retail-choice areas, the RTO should pursue “more reasonable and efficient alternatives,” he added.
In a decision that could boost prospects for controversial state policies favoring select types of electricity generation, the Second Circuit Court of Appeals last week rejected a suit claiming that a Connecticut renewable energy procurement law intruded on FERC’s authority.
A wind turbine installation on I-95 in Fair Haven, CT.
The June 28 ruling affirmed a lower court decision in favor of a Connecticut law that requires the state to solicit proposals for renewable energy projects and utilities to enter into bilateral contracts with the winners. Renewable energy developer Allco Finance challenged the law’s implementation as discriminatory (16-2946, 16-2949).
The court also lifted an injunction it issued last November that blocked the awarding of clean energy contracts by Connecticut, Massachusetts and Rhode Island. (See Court Halts New England Clean Energy Contracts.)
The court’s opinion — which reviewed the Connecticut program based on the Supreme Court’s 2016 decision in Hughes vs. Talen — could influence district courts that are considering motions related to New York and Illinois policies providing zero-emission credits (ZECs) to nuclear plants. (See Federal Suit Challenges NY Nuclear Subsidies.)
FERC Authority
Hughes vs. Talen found that a Maryland plan to spur construction of new natural gas-fired generation encroached on FERC’s authority over wholesale prices under the Federal Power Act. But the Second Circuit ruling identified a key distinction between the Maryland and Connecticut programs.
“While Maryland sought essentially to override the terms set by the FERC-approved PJM auction, and required transfer of ownership through the FERC-approved auction, Connecticut’s program does not condition capacity transfers on any such auction,” the appeals court said. “Connecticut, instead, transfers ownership of electricity from one party to another by contract, independent of the auction.”
Furthermore, the contracts stemming from the requests for proposals are just the kind of bilateral agreements already subject to FERC oversight, the court said.
And while the appeals court affirmed that “states may not regulate interstate wholesale sales of electricity unless Congress creates an exception to the FPA,” it also determined that the Public Utility Regulatory Policies Act “contains such an exception, permitting states to foster electric generation by certain power production facilities … that have no more than 80 MW of capacity and use renewable generation technology.”
“The decision comes out on the right side legally, clearly on the better side for the states who want to set up programs to encourage renewable energy,” said Seth Jaffe of the law firm Foley Hoag, who wrote a blog post on the case. “The court properly noted that the state really wasn’t getting in the way of FERC setting wholesale prices.”
In a June 30 blog post, John Moore of the Natural Resources Defense Council wrote that “contrary to the claims of some generators who would like to see state energy laws invalidated per Hughes, the 2nd Circuit made clear that Hughes applies only to a narrow class of state schemes that, like Maryland’s, seek to ‘override’ the rate set by the FERC-approved auction and instead guarantee a generator a wholly different rate — not policies like the Connecticut clean energy programs.”
Dormant Commerce Clause Claims Rejected
The Second Circuit also rejected Allco’s claims that Connecticut violated the dormant Commerce Clause of the U.S. Constitution: the idea that states may not pass laws discriminating against interstate commerce to protect intrastate commerce. Allco argued Connecticut’s law violated the clause by making the state’s acceptance of renewable energy credits (RECs) contingent on the ability of a generator to deliver its electricity to the New England grid.
SunPower “Intelegant” award-winning installation in Westport, CT.
Allco claimed that Connecticut’s rules discriminated against the company’s solar facility in Georgia by not letting its RECs count toward Connecticut utilities’ renewable portfolio standard requirements. The company also argued that Connecticut discriminated against Allco’s New York facility in requiring producers of RECs in adjacent control areas to pay transmission fees in order to sell their credits to Connecticut utilities.
The Second Circuit first considered “whether the allegedly competing entities — Allco’s Georgia generator, on the one hand, and generators located in ISO-NE and adjacent control areas, on the other — provide different products, i.e., different RECs. We find that they do.” (See NYISO Sees Carbon Adder as Way to Link ZECs to Markets.)
The opinion gave “greater weight” to the market for RECs produced by generators able to connect to Connecticut’s grid and noted that “Connecticut’s RPS program makes geographic distinctions between RECs only insofar as it piggybacks on top of geographic lines drawn by ISO-NE and the [New England Power Pool], both of which are supervised by FERC — not the state of Connecticut.”
Regarding the court’s dormant Commerce Clause finding, Jaffe said, “I think they got it right; the reasoning is pretty sound, but I can certainly imagine people continuing to litigate this.”
The decision said it recognized “the importance of Connecticut’s interest in protecting the market for RECs produced within the ISO-NE or in adjacent areas. Connecticut’s RPS program serves its legitimate interest in promoting increased production of renewable power generation in the region.”
The court’s arguments in favor of the Connecticut program “are not that different from arguments that we’ve sometimes seen rejected by the courts, in saying, ‘Well, we understand the policy preference, but you’re not allowed to essentially discriminate,’” Jaffe said.
[Editor’s Note: An earlier version of this story said the ruling was by the D.C. Circuit Court of Appeals.]
Massachusetts officials said Friday the state’s electric distribution utilities must procure a combined 200 MWh of energy storage by Jan. 1, 2020 — an unambitious goal to some observers.
Although the Department of Energy Resources’ (DOER) announcement called the 200 MWh “an aspirational” target, some industry stakeholders expected more from Gov. Charlie Baker’s Energy Storage Initiative. The department’s State of Charge report, released in September, presented recommendations for generating 600 MW of advanced energy storage by 2025, saying it would capture $800 million in system benefits. (See Mass. Considering Storage Mandate.)
| DOE Global Energy Storage database and Massachusetts Department of Energy Resources
“Based on lessons learned from this initial target, DOER may determine whether to set additional procurement targets beyond Jan. 1, 2020,” DOER Commissioner Judith Judson said in announcing the target. The state also agreed to spend $10 million on energy storage demonstration projects in addition to the $10 million that accompanied the ESI announcement in May 2015.
Judson said the state also had begun implementing other recommendations from the State of Charge report, allowing storage to be paired with the state’s plans to procure 9.45 million MWh of clean energy and 1,600 MW of offshore wind.
She also said the state was “incentivizing” storage through the Solar Massachusetts Renewable Target (SMART) program and that storage would be funded by alternative compliance payments under the ACES Grant Program, the Peak Demand Reduction Grant Program and the Community Clean Energy Resiliency Initiative, and that storage would be eligible for future Green Communities grants.
| Massachusetts Department of Energy Resources, Massachusetts Clean Energy Center
It also is considering allowing utilities to use energy-efficiency funds for storage that provides sustainable peak load reductions and expanding energy storage in the Alternative Energy Portfolio Standard.
“It’s less of an aspirational target, something the state’s going to strive for, and more a description of what the state is already doing,” said Ted Ko, director of policy at Stem, a provider of commercial-scale energy storage. “It’s entirely possible they would have met [the target] anyway. For example, Eversource [Energy] has already proposed over 180 MWh of storage projects in a recent rate case.”
Ko said the SMART program, whose regulations were released last month, “by itself conceivably could come up with 100 MWh.”
“Essentially, by setting a low, voluntary target number, you’re not inspiring any new programs or new initiatives as outlined in the State of the Charge report,” he added.
The announcement drew similar, if more temperate, comments from others, including Chris Rauscher, director of public policy at residential solar company Sunrun.
“The decision by DOER to set a soft energy storage target of 200 MWh is a moderate first step in providing long-term market surety,” Rauscher said. “Growing the storage market in Massachusetts has the potential to support local job creation and lower costs for Massachusetts ratepayers, all while providing critical resiliency through backup power.”
Rauscher said the company would work with legislators to expand storage’s potential “by encouraging private investment in Massachusetts through programs like the Alternative Energy Portfolio Standard.”
The Energy Storage Association noted that Massachusetts utilities previously proposed “specific, albeit voluntary, procurement targets of a combination of up to 200 MW/500 MWh of energy storage. Today’s announcement is a more conservative step in that direction.
“Massachusetts is also competing for industry jobs with California, Oregon, New York and other states moving forward on their own storage procurement targets,” ESA added.
Massachusetts becomes the second state in the U.S. to mandate storage. The California Public Utilities Commission in 2013 ordered the state’s three large investor-owned utilities to add 1.3 GW of energy storage by 2020.
New York lawmakers last month passed a measure requiring the state’s Public Service Commission to set targets to increase the adoption of energy storage in the state through 2030. If signed by Gov. Andrew Cuomo, the new law would require the commission to work with the New York State Energy and Research Development Agency and the Long Island Power Authority to set up a storage deployment program. (See NY Bill Sets Stage for Storage Targets.)
HERSHEY, Pa. — Near the end of the final panel at last week’s Mid-Atlantic Conference of Regulatory Utilities Commissioners conference, PJM’s Stu Bresler was asked what it would take for the RTO to take the lead on developing a large-scale, regional transmission line from Virginia to New York City to help take advantage of offshore wind capabilities in the Atlantic Ocean.
“My knee-jerk, flippant answer is a whole lot of money,” said Bresler, PJM’s senior vice president of markets and operations. “It’s difficult at this point to build a reliability case for that kind of infrastructure investment. I think what’s required is more a business case for the generation to say that level of investment is rational.”
PJM would know. Every month, a heated debate flares up at its Transmission Expansion Advisory Committee meetings to examine the details, costs and necessity of proposed transmission projects. American Municipal Power’s Ed Tatum often leads the discussion.
As a member of a panel on transmission replacement earlier at the conference, Tatum revealed that when he was brought on at AMP, he was given a mission to reduce its members’ transmission costs. He responded that controlling their costs would be a more reasonable goal.
That could be because much of the transmission grid needs replacement, and transmission owners are often sensitive to any implication they’re overbuilding the system. Tatum’s fellow panel participant, Jodi Moskowitz of Public Service Electric and Gas, took exception to that suggestion in her opening remarks.
“We don’t look at the issue quite that way, in terms of if the transmission system is overbuilt,” Moskowitz said. “We think that the appropriate focus is to make sure that we have a safe, reliable grid for many years to come, but make sure we are planning and building in a cost-effective way.”
And even that might be more expensive than customers want to pay. Speaking on the fuel mix panel with Bresler, Rich Sedano of the Regulatory Assistance Project said the one-day-in-10-years loss-of-load expectation that PJM and other grid operators use is a handy standard, but not necessarily indicative of what the market will bear.
That clash over cost versus demand would be cleared up through increased competition and cost-containment measures in transmission construction, LS Power’s Sharon Segner said. “If you read the [court] orders on why competition was upheld, it’s because of the argument for the consumer benefits of competition.”
While Segner said that cost containment offers price assurance, Moskowitz cautioned that there will always be “uncontrollable issues” that occur during construction.
Expressing the states’ perspective, West Virginia Public Service Commissioner Brooks McCabe called for restraint on all sides. During the transmission panel, he urged slowing down the decisions to construct large-scale projects and to revisit the “fundamental ground rules” to “tweak” when and how projects should be addressed.
On the fuel mix panel, he urged everyone to “lighten up” because the “hard work” would not be solved immediately. Retaining baseload units is important, he said, because “that’s our security blanket.”
Matt Crozat of the Nuclear Energy Institute had a mixed reaction to that message. He said he can’t be relaxed like McCabe because “I know that if I lose nuclear plants, I can’t get them back.”
By Michael Kuser, Amanda Durish Cook and Rich Heidorn Jr.
Following FERC’s two-day technical conference on tensions between wholesale electric markets and state energy policy initiatives in early May, the commission invited comments on five potential paths forward (AD17-11).
The paths include a continuation of the status quo (Path 3), with the courts sorting out whether state initiatives — such as the zero-emission credits for Exelon nuclear plants in New York and Illinois — violate federal jurisdiction; changes to the minimum offer price rule (MOPR) (Paths 1 and 5); and market rule changes to accommodate state policies (Path 2) or incorporate them into RTO and ISO pricing (Path 4).
The commission also asked commenters to rate the urgency of the issue and solicited suggestions on how FERC should go forward procedurally.
More than 80 commenters responded, although many repeated their past positions and did not provide feedback on the paths the commission outlined. Based on RTO Insider’s review of the comments, below is a summary of the supporters and detractors of each path.
Paths 2 and 4 appeared to be the most popular, although there were supporters and detractors for all of the proposals.
The range of challenges to the capacity market constructs in PJM, ISO-NE and NYISO — the Eastern markets that were the focus of the technical conference — raises the prospect that FERC could relax the markets’ participation requirements. Public power advocates, who have been seeking relief for years, peppered their comments with repeated demands to let them acquire capacity via bilateral contracts, with capacity auctions playing a much smaller, “residual” role.
Path 1: Limited or No Minimum Offer Price Rule
FERC Description
“An approach that would either not apply the minimum offer price rule to state-supported resources, or limit application of the minimum offer price rule to only state-supported resources where federal law pre-empts the state action providing that support.”
Background
If FERC were to abandon the MOPR altogether, it would likely invite court challenges alleging it was allowing states to usurp its authority under the Federal Power Act. Thus any relaxation of MOPR is likely to be constrained by the Supreme Court’s 2016 rulings in Hughes v. Talen and Electric Power Supply Association v. FERC. (See Court’s Reticence Frustrates Energy Bar.)
Supporters
Load-serving entities are the biggest fans of this approach, which also is supported by the Nuclear Energy Institute (NEI) and some commenters in the renewables camp.
The National Rural Electric Cooperative Association (NRECA), American Municipal Power and Old Dominion Electric Cooperative support Path 1 or 2 or a combination of the two.
The American Public Power Association (APPA) called for “a greatly limited MOPR that provides full exemptions for self-supply and state-sponsored resources, or the ability to remove such resources from the capacity market clearing process altogether.”
The Transmission Access Policy Study Group (TAPS), which represents transmission-dependent utilities in 35 states, considers it “potentially viable.”
NEI, the Sierra Club and the Natural Resources Defense Council’s Sustainable FERC Project all expressed support, with NRDC calling it the solution “most likely to support proper price formation.”
Opposed
Groups representing consumers led the opposition, with the Electricity Consumers Resource Council (ELCON) rejecting it as “too extreme.”
A group of 60 large industrial, commercial and institutional energy consumers in New York who filed as “Multiple Intervenors” also opposed it, saying “it presumes that state public policies that unduly impact or interfere with competitive wholesale electricity markets must be accommodated in most circumstances, and that the preferred ‘solution’ in cases where federal law pre-empts state action is the application of a minimum offer price rule.”
“While MOPRs may be appropriate in certain circumstances, Multiple Intervenors disagrees that they represent the only — or even the best — response to all state public policies that trespass into the commission’s jurisdiction,” the group said.
NRG Energy also opposed Path 1, saying it would exacerbate price suppression in wholesale markets by allowing subsidized resources to enter the markets at prices below actual cost. It has proposed a “Forward Clean Attribute Market” in the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative.
NRG, Dynegy, Eastern Generation and the Electric Power Supply Association (EPSA) filed a federal court suit in October claiming the New York ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The same companies filed suit in February challenging Illinois’ ZECs for Exelon’s Quad Cities and Clinton nuclear plants and have also asked FERC to reject the subsidies.
Path 2: Accommodation of State Actions
FERC Description
“An approach that would accommodate state policies that provide out-of-market support with the operation of the wholesale markets by allowing state-supported resources to participate in those markets and, when relevant, obtain capacity supply obligations, subject to adjustments necessary to maintain certain wholesale market prices consistent with the market results that would have been produced had those resources not been state-supported.”
Background
Proposals for two-tiered capacity auctions that would clear subsidized resources separately fall into this path.
LSEs are the biggest supporters, with the NRECA, AMP, ODEC and Eastern Massachusetts Consumer-Owned Systems backing the concept. The American Forest and Paper Association also favored a Path 2 solution, saying “each of the other four pathways are likely to prove impractical and more expensive for consumers.”
APPA said it supports efforts to accommodate state actions, “assuming such accommodation also covers resources procured by public power and cooperative utilities. Such an accommodation should be designed broadly so that there is no determination by the RTO of what constitutes ‘legitimate’ state policies.”
The New England States Committee on Electricity (NESCOE) noted that NEPOOL’s IMAPP initiative “has focused on developing approaches that align with Paths 2 and 4.” At the conference, ISO-NE presented its proposal for a two-tiered auction that it said would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
The Advanced Energy Management Alliance (AEMA) said FERC should direct ISO-NE, NYISO and PJM to file Path 2-type changes in capacity market rules to support “the rights of states to control their own energy policy and to procure carbon-free resources that wholesale markets can integrate cost-effectively” while ensuring they do not distort wholesale prices.
New York City said Paths 2 and 4 provide the “best opportunities to correct current market constraints” on renewable resources and new technologies procured under public policy goals.
“The appropriate future is clearly a combination of Paths 2, 4 and 5,” NRG said, adding that they are consistent with a “pro-markets approach [that] appears to have wide support from across the stakeholder community.”
Independent power producers Calpine and Dynegy also expressed support for Path 2, with Calpine calling it a “mid-term solution.” Dynegy says Path 2 “is the next step: a robust stakeholder process to fully develop and refine the proposed solutions that have recently been presented by the ISOs/RTOs (ISO-NE’s Competitive Auctions with Subsidized Policy Resources (‘CASPR’) proposal and PJM’s capacity market repricing proposal).”
Brookfield Renewable, the Conservation Law Foundation and NextEra Energy, which are promoting their Carbon-Linked Incentive for Policy Resources (CLIPR) proposal as a long-term Path 4 solution, say Path 2 may be needed in the interim.
“Feasible Path 4 solutions — like the CLIPR proposal — must be identified simultaneously with the formulation of any interim short-term proposal, as doing so will avoid the risk that the interim Path 2 solution outlives its useful life to the detriment of the market and more robust and comprehensive long-term solutions,” the “CLIPR Coalition” said.
Avangrid said a combination of Paths 2 and 3 is best for multi-state regions, “while Path 4 is better suited to single-state wholesale markets.”
Opposed
ELCON and New York’s Multiple Intervenors opposed, with ELCON rejecting it as a “kluge.”
PJM’s Independent Market Monitor, which opposed all but Paths 4 and 5, said “it would be a mistake for ISO/RTOs to explicitly accommodate state-level subsidies” in their capacity market design.
The American Wind Energy Association said any Path 2 solution should be “technology-neutral.” It questioned “the feasibility of any Path 2 solution that proposes to differentiate … ‘subsidized’ resources from ‘unsubsidized’ resources and calculate the competitive offer price of the ‘subsidized’ resources.”
The New York Public Service Commission, which is backing a plan to integrate carbon pricing into the NYISO market, said Path 2 “illustrates the limitations of the five paths.”
Path 3: Status Quo
FERC Description
“An approach that would rely on existing tariff provisions applying the minimum offer price rule to some state-supported resources, and continuing case-by-case litigation over the specific line to be drawn between categories of state actions that may, or may not, result in a state-supported resource being subject to the minimum offer price rule.”
Background
At the hearing, acting FERC Chair Cheryl LaFleur urged stakeholders to avoid “unplanned and piecemeal regulation,” saying “it would be a bad outcome for customers and market participants in terms of cost, reliability and regulatory certainty.”
Few commenters embraced the status quo, although ELCON called it the only path that is “tenable.” Duke endorsed it, saying that stakeholder discussions occurring in the RTOs/ISOs “should run their course” and that it is not necessary for the commission to take “prescriptive” action. “Threshold legal issues are pending before the courts, and the resolution of these issues should be allowed to play out before any further action is taken at the federal level,” ELCON said.
The large New York customers group said that while it is “not optimal,” it “may be the most realistic among the choices identified” by FERC.
AWEA said it would support Path 3 only if FERC continues to exempt renewable resources from the MOPR.
Opposed
TAPS called it “unsustainable and unworkable,” and NRECA and APPA also opposed, with the latter saying, “No participants expressed support for this option at the technical conference.
“The lack of support for the status quo has persisted throughout the history of the capacity markets and must be recognized in determining future paths,” APPA said.
Dynegy’s Illinois Generation Assets | Dynegy
NRDC said Paths 3 and 5, “as well as some approaches to implementing Path 2,” would violate the Federal Power Act by improperly discriminating between resources. “The act of defining what is or is not a ‘subsidy’ will inevitably entail arbitrary and discriminatory line-drawing efforts, as has become increasingly clear through FERC’s decisions regarding the application of the MOPR to resources supported by state policies,” it said.
Dynegy said Path 3 is “unsustainable.”
“Dynegy has already been negatively impacted by the ZEC subsidy programs and will continue to be negatively impacted absent relief from the courts or commission action. In a ‘status quo’ scenario, Dynegy will be unable to proceed with capital improvements [and] hiring, and will need to evaluate shutdowns of generating plants that are more cost efficient than the subsidized nuclear units.”
Path 4: Pricing State Policy Choices
FERC Description
“An approach in which state policies, to the extent possible, would value the attributes (e.g., resilience) or externalities (e.g., carbon emissions) that states are targeting in a manner that can be readily integrated into the wholesale markets in a resource-neutral way. For those state policies that cannot be readily valued and integrated into the wholesale markets, Path 4 would also require consideration of what, if anything, the commission should do to address the market impacts of these state policies. For instance, other approaches for these state policies may include accommodation, application of the minimum offer price rule or an exemption from the minimum offer price rule.”
Background
A carbon price adder is one potential Path 4 solution, but it has been rejected by the New England states.
Supporters
The NYPSC said its work with NYISO to incorporate carbon into the wholesale electricity markets “might be viewed as an endorsement of Path 4.”
Path 4 also won support from Dominion Energy, Calpine, Dynegy, Exelon, NEI, Vitol and the Solar Energy Industries Association (SEIA).
EPSA gave Path 4 conditional support. “The challenge will be to define those resource attributes (e.g., flexibility) or externalities (e.g., carbon emissions) that should be integrated into the wholesale market, and then to develop a mechanism to value those qualities in a resource-neutral manner,” EPSA said, adding that it “is confident that, if these objectives can be identified, the ISOs/RTOs and market stakeholders can establish workable and efficient means to integrate these objectives into competitive market structures.”
APPA also gave a qualified endorsement, saying it could result in “an efficient means of achieving environmental or other policy goals if it were limited to a single price adjustment, such as a carbon tax or adder.” The group said it would only support this “achieve” approach “if it were done along with and not as a replacement to an accommodation of state policies or a move to a voluntary residual capacity market.”
AWEA said Path 4 is its first choice and would allow the markets to “better value the benefits and externalities of renewable energy that are not being currently captured.”
It also expressed concern that the five paths could tread on state sovereignty, asking FERC to consider carbon pricing. “Since there is currently no real conflict between state-supported renewable energy resources and wholesale markets, nor has there been one over the decades for which these policies have been in place, there is no basis for the commission to suddenly upset this balance by infringing upon state sovereignty and undoing the intent of state laws that seek to promote renewable energy.”
The Brookfield “CLPR Coalition” said Path 4 is preferable to Path 2. It asked FERC to issue a policy statement directing the RTOs to submit “achieve” solutions to the commission in the near term and requiring them to file quarterly reports on their progress.
Opposed
Opponents include the Natural Gas Supply Association, NRECA, TAPS and the large New York customers, the last of which said they were skeptical that it could be implemented effectively and benefit customers.
ELCON said the proposal would be the “most prone to abuse” of the alternatives. “It would fail in real-world conditions because some states would not respect market-based solutions. They would concoct attributes that are not realistically fungible or tradable for the purpose of selectively internalizing externalities or for socializing the costs of command-and-control mandates.”
AEMA said FERC should allow RTOs and stakeholders to develop solutions but not force them to file proposals. “Pricing state policy into energy and ancillary markets, through mechanisms such as carbon adders, raises several controversial issues. Capacity market solutions are not plagued with such controversial questions, and if the commission were to direct ISOs to pursue both capacity and energy market solutions simultaneously, it would slow the progress of the capacity market solution,” AEMA wrote.
Economist James F. Wilson said the commission should set a long-term goal “of seeing more revenues from the energy and ancillary services markets, and eventually phasing out the capacity constructs, or converting them to voluntary mechanisms, recognizing the changing nature of `resource adequacy.’
“The energy and ancillary services markets hold the potential to efficiently guide the changing resource mix over time, including incorporating public policy objectives such as decarbonization that presently are not reflected in the markets; the capacity constructs cannot do this,” Wilson continued. “Reducing the role of the capacity constructs will require resisting the frequent pressures to change them in ways that raise capacity prices and/or lead to clearing substantial excess capacity.”
Cliff Hamal, managing director of Navigant Economics, said “the most fundamental assumption” underlying capacity markets — setting capacity prices based on the cost of building new gas-fired generation — may no longer be valid. “What if policy options, such as those that promote low-carbon resources and demand reductions have eliminated the need for regular additions of gas-fired generation? A case could be made that we have already reached that point, or might do so in the near future. If so, the fundamental basis for setting capacity prices through the net-[cost of new entry]-based demand curve auction is no longer valid.”
Path 5: Expanded Minimum Offer Price Rule
FERC Description
“An approach that would minimize the impact of state-supported resources on wholesale market prices by expanding the existing scope of the minimum offer price rule to apply to both new and existing capacity resources that participate in the capacity market and receive state support.”
Background
The MOPR came up frequently at the technical conference with some witnesses calling for its expansion and others seeking its relaxation or abolition. (See Uncertain Future for MOPR.)
Supporters
EPSA and EPSA members Dynegy and Calpine would like to see this path pursued immediately, while the NGSA says it is fine as a short-term fix but not as a long-term solution. Calpine also sees it as a “near-term” fix.
Competitive Power Ventures called for expansion of the MOPR to reserve price signals, the implementation of a “universal” carbon price into the energy markets and RTO dispatch decisions and improvements to price formation.
Opposed
NRDC, which said it would not be just and reasonable, was joined in opposition by Hydro-Quebec, the New York Power Authority, NEI, Dominion, FirstEnergy, East Kentucky Power Authority, the New York Multiple Intervenors, the PJM Industrial Customer Coalition, ELCON, TAPS, NRECA and APPA.
APPA called it “the worst possible outcome,” which would result in “an overly administered noncompetitive market that would frustrate resource development pursuant to policy decisions.”
“This would greatly benefit the pure merchant facilities, leading to a significant decline in resource diversity, a higher cost of capital and a lack of any type of planning or optimization of resources. Because the states will likely continue to seek to procure or retain resources based on policy preferences, an expanded MOPR also increases the risk of overbuilding and double-payment for capacity.”
The Multiple Intervenors was also opposed, saying that MOPRs “have the effect of sheltering incumbent generation owners from competition and impeding market entry.”
AWEA said it could open “the door to widespread mitigation of legitimate state policies and, in turn, uncertainty for renewable energy investors.”
“If the commission approves a MOPR based on factors other than limiting the application of the MOPR to only state-supported resources where federal law pre-empts the state action, then it becomes difficult to draw a clear boundary limiting commission interventions,” AWEA said. “As this path has no discernable limit to what types of public policies would be exposed to a MOPR, it could lead to an environment where legitimate state renewable energy policies could be impeded by the risk of being mitigated.”
In a joint filing, AWEA, Advanced Energy Economy, Alliance for Clean Energy New York, American Council on Renewable Energy, Mid-Atlantic Renewable Energy Coalition, RENEW Northeast, and Wind on the Wires also opposed expanding MOPR.
“All energy resources benefit from subsidies and/or favorable policies and, therefore, a singular focus on incentives for certain resources such as renewables, would be discriminatory,” they said. “Contrary to the claims of some of the panelists at the technical conference, Northeast power systems are performing better as a result of the availability and integration of renewable energy into the resource mix. Negative pricing is rare and, more importantly, not responsible for negative economic impacts on other generation sources. Gas prices, not renewables, are the primary factor reducing revenues for nuclear, coal, and other supply sources.”
Economist James F. Wilson also opposed Path 5. “The markets are not nearly as fragile, and the impacts of public policy resources not nearly as substantial, as some stakeholders suggest,” he said.
Rob Gramlich of Grid Strategies said FERC should continue to treat public policies as “exogenous, as a factor that may affect market participants’ behavior and willingness to pay or accept money for a transaction, but not something for the commission to mitigate or undo. One can disagree with some of the laws state and federal legislatures pass, and FERC can offer its input into legislative processes, but it would be a major shift in the regulatory paradigm for the federal electricity market regulator to go beyond intervening to remedy market power and manipulation and enter the realm of mitigating public policy.”
“A wide range of state and federal policies have affected quantities and prices in power markets since the inception of U.S. electricity markets,” Gramlich continued. “For example, there might not be any nuclear generation in operation were it not for the Price-Anderson Act limiting liability for unit owners. We might not have as much natural gas generation if intangible drilling costs were not allowed to be deductible as a current business expense under federal tax law.”
NEI and IPPs — though on opposite sides of the nuclear subsidy debate — agreed on the need for a speedy resolution. NEI said RTO markets are not just and reasonable if they don’t provide sufficient revenues to retain nuclear generation threatened by low-cost natural gas.
EPSA said immediate action is needed to “insulate” wholesale markets “from current distortive state actions while all stakeholders collaborate on identifying market structures that help address defined public policy goals.” Also calling for urgency were Calpine, Eastern Generation, the Independent Power Producers of New York, the New England Power Generators Association, LS Power and NRG, which said that competitive markets are “under siege.”
NRG said FERC should actively participate in suits challenging the ZECs and act on pending complaints before the commission on the subject of the MOPR.
The R Street Institute, a free-market think tank, said FERC should have “an extremely high sense of urgency.”
Dynegy also called for swift action, criticizing Exelon Senior Vice President of Competitive Market Policy Kathleen Barron, who told FERC on May 1 that “we have some time to talk about where we go.”
No
Exelon responded that FERC should implement energy market fixes to eliminate the need for ZECs before considering any of the paths identified.
The PJM ICC said there was “no need for rush to judgment” and ELCON said the “problem at hand is too important to be rushed.”
NRDC said there is no evidence of a “crisis,” pointing out that reserve margins in PJM, ISO-NE and NYISO are all currently higher than their targets.
The Union of Concerned Scientists said the “proposed solutions are premature due to lack of [a] coherent argument” for action. “The calls for urgent action by stakeholders have presumed that there is clarity regarding the nature and size of the alleged problem with the capacity markets,” it said. “As far as the renewable portfolio standards, there is neither urgency, nor a clear statement sorting the issue.”
Procedural Steps
NRECA and Exelon said FERC should convene technical conferences in each region and require the grid operators to file progress reports on their stakeholder processes.
ELCON said any action should be a common solution across all RTOs to avoid exacerbating seams issues. Xcel Energy — which doesn’t operate in the three Eastern RTOs — said FERC should reiterate that the docket is limited to RTO/ISO markets, urging it to “do no harm” to unbundled states.
EPSA said energy price formation should be a priority, calling for completion of Notices of Proposed Rulemaking on the pricing of fast-start resources (RM17-3) and addressing uplift allocation and transparency (RM17-2). (See FERC Seeks More Transparency, Cost Causation on Uplift.)
The R Street Institute called for FERC to issue a new NOPR setting a “bright line” on state policies that would be subject to the MOPR or legal challenges. “This would offer a more proactive approach than retroactive litigation, deter egregious interventions and perhaps disarm state-federal tensions.”
Public Citizen said the paths outlined by FERC are too narrow to solve the problems and that competitive markets may not always be the best solution. It said the commission should start by conducting an evidentiary hearing on whether RTO markets are resulting in just and reasonable outcomes. It also called for governance changes to allow non-governmental organizations voting rights in the RTO/ISO stakeholder process.
New England’s public power utilities aren’t convinced that ISO-NE’s proposed two-tiered capacity auction is the best way to incorporate state clean energy procurements into the wholesale markets.
At FERC’s May 1-2 technical conference on state policies and wholesale markets, ISO-NE presented its Competitive Auctions with Subsidized Policy Resources (CASPR) proposal, which it said would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
In post-conference comments filed with the commission, several major New England stakeholders indicated they were willing to consider the RTO’s plan.
The Massachusetts Department of Public Utilities said it “generally agrees” with the four objectives of the ISO-NE proposal: “(1) competitive capacity pricing; (2) accommodating the entry of state policy resources into the [Forward Capacity Market] over time; (3) avoiding cost shifts; and (4) a sustainable, market-based approach.”
The New England States Committee on Electricity (NESCOE) said it will provide analysis later this year “on a variety of mechanisms through which states could execute policy objectives,” including Path 4 long-term “achieve” proposals and near-term Path 2 “accommodate” proposals such as CASPR. “NESCOE will continue to work with ISO-NE, market participants and others to explore potential solutions that could improve upon the status quo,” NESCOE told FERC.
However, the RTO’s plan got a wary response from the Eastern New England Consumer-Owned Systems (ENECOS). “The history of New England’s Forward Capacity Market (FCM) has not been a happy one from the perspective of small, vertically integrated utilities,” the group wrote. “To suggest — as some have in the technical conference — that the answer to the ‘threat’ posed by the prospect of large-scale entry of variable-energy, renewable resources into the current centralized auction construct is to create yet another centralized auction construct [invites] extreme skepticism.”
The group said any solution “should be coupled with restoration of the right of self-supply for load-serving entities as a means of satisfying their share of regional capacity obligations.”
ENECOS said both Paths 1 and 3 are “preferable to the more structurally profound proposals — such as carbon ‘adders,’ or creation of yet another centralized capacity auction construct for ‘clean’ energy.”
The Northeast Public Power Association (NEPPA) also had doubts, saying “the capacity market construct is ill-equipped to achieve the policy outcomes FERC, states and consumers desire.”
“When ISO-New England announced the settlement creating the FCM, NEPPA members worked to ensure not-for-profit load-serving entities (LSEs) retained the right to use their own existing resources to meet their capacity obligations,” NEPPA said. “That negotiated benefit was lost when FERC approved the minimum offer price rule (MOPR), which suddenly made the FCM a mandatory construct. ISO-New England is now effectively the single buyer and single seller of wholesale electricity in the region.”
NEPPA also criticized the MOPR as a “flawed construct.” It attached to its comments a concurring opinion by former FERC Chair Norman Bay, a parting shot before his resignation in February in which he called MOPR “unsound in principle and unworkable in practice.” (See Bay Blasts MOPR on Way Out the Door.)
The MOPR would be applied only in the first of the auctions under CASPR. In the first stage, ISO-NE would clear the auction as it does today, applying the MOPR to new capacity offers to prevent price suppression. In the new second “substitution” auction, generators with retirement bids that cleared in the primary auction would transfer their obligations to subsidized new resources that did not clear because of the MOPR. Because the substitution auction will not use the MOPR, it will clear at lower prices than the primary auction, enabling existing resources to buy out their obligations at a lower cost in return for retiring, the RTO says.
CASPR arose out of the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative — a response to state officials’ concerns that consumers could face excessive costs if state renewable procurements were not incorporated into the capacity market and generators’ fears that out-of-market resources will suppress capacity prices. New England states are set to procure more than 3,600 MW of nameplate renewable generation.
Another proposal that arose from IMAPP is the Carbon-Linked Incentive for Policy Resources (CLIPR), proposed by Brookfield Renewable, the Conservation Law Foundation and NextEra Energy.
The “CLIPR Coalition” said long-term Path 4 proposals are preferable to interim Path 2 plans. It asked FERC to issue a policy statement directing the RTOs to submit “achieve” solutions to the commission in the near term and requiring them to file quarterly reports on their progress.
Under the CLIPR proposal, LSEs would pay state “policy” resources an energy price premium that would fluctuate based on the “marginal carbon intensity” of the dispatch, “a direct analog to the LMP but computed as lbs-CO2/MWh instead of $/MWh.”
Urgency
The New England stakeholders also disagreed over how quickly the region must act and how involved FERC should be in the process.
State officials generally downplayed the urgency. NESCOE said “the overall level of state-sponsored clean energy procurements that have taken place or are expected in the near-term comprises a small percentage of installed resources on the system.” It also defended state sovereignty and urged the commission not to take “prescriptive action.”
The Massachusetts DPU noted that the states’ procurement of clean energy resources “will extend over many years.”
“There is no evidence to suggest the current market construct is causing any decrease in merchant investment,” said a joint filing by the Connecticut Department of Energy and Environmental Protection, Public Utilities Regulatory Authority and Office of Consumer Counsel. “On the contrary, New England has attracted a large amount of new investment over the last several years, including renewable generation.”
The New England Power Generators Association (NEPGA) sees it differently. “NEPGA believes that the wave of out-of-market resources beginning to crest in New England threatens the very viability of a competitive wholesale electricity market,” it said. “The need is urgent, with a necessary direct and swift response from FERC and the wholesale markets.”
Efforts to incorporate New York’s aggressive climate change policies into NYISO markets are focused on the introduction of a carbon price adder.
The ISO told FERC it has “engaged in a productive dialogue” with state regulators since the May 1-2 technical conference on state policies and wholesale markets.
NYISO is working with The Brattle Group, stakeholders and regulators to determine the feasibility of “Path 4” market design changes in response to the state’s Clean Energy Standard (CES) and its zero-emission credits for Exelon’s Nine Mile Point, R.E. Ginna and James A. FitzPatrick nuclear plants. The CES mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. It also calls for renewables to meet 50% of the state’s energy needs by 2030. (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
Nine Mile Point | Constellation Energy
About 80 parties filed post-conference comments. Among those who expressed support for a Path 4 approach, in addition to the ISO and the Public Service Commission, are New York City, the New York Power Authority and the Independent Power Producers of New York (IPPNY).
The city said Paths 2 and 4 provide the “best opportunities to correct current market constraints” on renewable resources and new technologies procured under public policy goals.
The single-state ISO can “craft a wholesale market structure that wholly integrates the state’s renewable energy objectives and provides renewable generation with better access to the marketplace,” the city said. “Market entry and exit should take into account whether the public good is being served, and whether principles related to resiliency and the improvement of air quality and public health are being advanced or hindered.”
NYPA expressed interest in exploring Paths 1, 2 and 4, and called for the elimination or a scaling back of the minimum offer price rule (MOPR). “The commission should accept state actions which do not interfere with FERC’s responsibilities,” it said.
But a group of about 60 large industrial, commercial and institutional energy consumers in New York who filed as “Multiple Intervenors” said it is not convinced of the wisdom of the Path 4 approach. The group said a status quo Path 3, while “not optimal … may be the most realistic among the choices identified” by FERC.
While the New York Public Service Commission said its work with NYISO to incorporate carbon into the wholesale markets “might be viewed as an endorsement of Path 4,” it said Path 2 “illustrates the limitations of the five paths.”
“While Path 2 may appear to represent a ‘compromise’ position, it hampers the ability of states to carry out legitimate public policies. Further, Path 2’s explicit goal to ‘maintain certain wholesale market prices,’ rather than the original, narrower purpose of mitigating for market power, shows how far afield MOPRs have strayed,” the commission said. “It asserts the right ‘to maintain certain wholesale market prices consistent with the market results that would have been produced had those resources not been state-supported.’ No true market operates in this manner.”
The ISO told FERC it has “engaged in a productive dialogue” with the state Department of Public Service, which includes the PSC, since the May conference and expects to release Brattle’s preliminary findings “in the near future.”
The report can’t come too soon for IPPNY, which said that FERC should require the ISO to file its carbon adder proposal and the Brattle analysis of it as soon as it regains its quorum.
“If the NYISO decides not to file such a proposal, the commission should require the NYISO to explain the basis for its decision,” IPPNY said. “In addition, if the commission decides that capacity markets should be modified to accommodate state public policies, it should direct the NYISO to adopt a forward capacity auction similar to the markets in PJM and ISO-NE.”
Noble Environmental Power, which claims to be the largest wind generator in New York, said its six projects totaling 612 MW will stop receiving state renewable incentives within the next two years. “As more new wind facilities enter the already bottled market in Upstate New York with discriminatory out-of-market incentives to meet state policy goals, energy prices will be substantially reduced — with a significant likelihood that the projects’ output will be curtailed under market dispatch rules.” It called for a Path 4 solution, saying FERC should order the ISO to integrate emissions-free electricity as an attribute in its markets to ensure “a level playing field” for renewables and nuclear generators.
Urgency
IPPNY, Eastern Generation, New York City and the Multiple Intervenors said the need for action is urgent. “Conflicts between state public policies and federally regulated wholesale electricity markets almost certainly will continue to get worse, thereby harming customers and other market participants irreparably,” the large customer group said.
The PSC agreed “the need to address these issues is urgent.”
But it added, “proper time must be given to explore possible solutions. … This is not the time to rush into a quick fix without thought of the impacts on the market and legitimate public policy goals.”
