WASHINGTON — Last week’s FERC technical conference focused on tensions between state clean energy policies and RTO/ISO markets in the East. Yet witness after witness cited California to make their points — often in a context unflattering to the Golden State.
Exelon cited the closing of the San Onofre nuclear plant — and the resulting increase in carbon emissions — to defend the subsidies of its nuclear plants in New York and Illinois.
Charles River Associates consultant Robert Stoddard said California’s duck curve is the result of “a pricing failure.”
“Out-of-market subsidies have been growing in the East. If not addressed, these subsidies will undermine the competitive wholesale markets, turning the Eastern markets into a command-and-control structure much like California is today — i.e., the states mandate when and where new generation will be built and the technology type that will be used for that generation,” Hill said.
“In California, essentially all investment, including investment in new conventional generation, is supported by mandate-driven long-term contracting schemes. Because the policies that bring about this substantial investment are divorced from competitive wholesale markets, it has led to the paradox that while retail rates are rising rapidly to reflect the costs of mandates, wholesale prices are so low that the economic viability of the remaining generation that is dependent on competitive wholesale markets (generally existing conventional generation resources without long-term contracts, many of which are critical for reliability) is increasingly threatened. Addressing the revenue shortfall for existing units that are needed for reliability likely will entail additional out-of-market mechanisms.”
Independent consultant Roy Shanker also called out California, saying the state Public Utilities Commission has “explicitly stated that while a transparent, open and competitive central capacity market might be more efficient in the long run, it preferred to maintain a less efficient bilateral capacity market structure because of short run cost savings.”
“Similarly it expressed concerns that a centralized market under the CAISO might open the door to undesirable FERC jurisdiction and authority,” he added.
Shanker cited California’s increase in negative energy pricing, which nearly doubled to 1,000 hours in 2016 from 588 in 2015.
“In general the state subsidized or mandated units under long-term contracts participate as price takers in both energy and/or capacity markets, driving down prices, often below zero in the energy market,” he said.
Innovation
Hogan (left) and Lawrence Makovich, IHS Markit | RTO Insider
Some witnesses, however, looked to California for innovation and leadership.
PJM officials said they are considering use of a “border adjustment” similar to that approved by FERC for CAISO to add carbon constraints for states that want to pursue climate goals.
And Harvard University’s William Hogan said the success of CAISO’s Western Energy Imbalance Market in reducing curtailments of solar and wind “is a case in point that reinforces the vibrancy and the importance of real-time markets organized around the principles of economic dispatch.”
WASHINGTON — ISO-NE presented its proposal for a two-tiered capacity auction at last week’s FERC technical conference, saying it would incorporate state-mandated renewable generation while preventing oversupply and addressing objections to a regional carbon tax.
The RTO released a 33-page description of the Competitive Auctions with Subsidized Policy Resources (CASPR) proposal a week before the conference.
The proposal, developed with Market Monitor David Patton, would provide financial incentives for existing, high-cost capacity resources to transfer their capacity obligations to subsidized new resources and permanently exit the capacity market through a two-stage, two-settlement process. The RTO said it could be in place for Forward Capacity Auction 13 in February 2019.
Although it is not the only short-term proposal being considered by policymakers in New England, it appears to be the clear front-runner. It survived the technical conference without coming under attack and is the “farthest along” among the stakeholder initiatives in the three Eastern grids, said acting FERC Chair Cheryl LaFleur at the close of the two-day conference (AD17-11).
Although the New England Power Pool has not taken a position on the proposal as a group, Participants Committee Chair Tom Kaslow in January presented a similar “paired retirement election” concept on behalf of his company, FirstLight Power Resources.
The proposal arose out of NEPOOL’s Integrating Markets and Public Policy (IMAPP) initiative, launched last August in response to state officials’ concerns that consumers could end up facing excessive costs for meeting state renewable procurement mandates and to generators’ fears that out-of-market resources will suppress capacity prices.
The CASPR proposal was designed to address the concern that consumers would end up “paying twice” for capacity — once for resources that clear in the FCA, and a second time for subsidized state-mandated renewables that could be prevented from clearing by the minimum offer price rule.
Failing to coordinate ISO-NE’s capacity market with state renewable procurements would lead to a “train wreck … [that] would probably be the end of the markets as we know them today,” said Jeffrey W. Bentz, director of analysis for the New England States Committee on Electricity.
Drivers and Goals
New England states are set to procure more than 3,600 MW of nameplate renewable generation:
Connecticut is negotiating out-of-market contracts for 375 MW of nameplate clean energy capacity.
State regulators in Massachusetts, Connecticut and Rhode Island are considering out-of-market contracts for 460 MW of nameplate clean energy capacity resulting from their three-state solicitation.
Massachusetts’ 2016 energy bill required its utilities to purchase about 1,200 MW of new renewables, including onshore wind and hydropower and 1,600 MW of offshore wind. The state issued its first solicitation March 31; a second is expected by June 30.
‘Cash for Clunkers’
ISO-NE said it developed its proposal with a goal of avoiding excessive capacity spending and cross-state cost shifts while continuing its Forward Capacity Market and minimizing the price-suppressive effect of out-of-market subsidies.
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 savings would in effect be a “severance payment” to the retiring resources, ISO-NE said. “The substitution auction might reasonably be viewed as an auction-based ‘cash for clunkers’ secondary market,” the RTO said, referring to the Obama administration’s 2009 program to encourage the retirement of older, gas-guzzling autos.
ISO-NE said it believes it can implement the proposal before March 2018, when the retirement window opens for FCA 13, which will acquire capacity for the delivery year beginning June 2022. “This timing is important given the anticipated schedule for substantial new state-sponsored resources to enter service in 2022,” the RTO said.
Questions about CASPR
CASPR attracted little opposition at the technical conference.
New Hampshire Public Utilities Commissioner Robert Scott said pointedly in his written testimony that he was taking no position on the proposal. “What I want is not to pay for Massachusetts’ and Connecticut’s policies,” he told FERC during live testimony.
CASPR was based on an idea submitted by NRG Energy last October, one of two two-tier proposals that consultant James Wilson evaluated for NESCOE. Wilson said that NRG’s proposal was an improvement on one submitted by public power representatives that he concluded would result in excessive costs and distort the incentives to submit competitive offers.
Wilson said the NRG proposal addressed the problem with public power’s handling of “tweener” resources — those that don’t clear because their offer prices fall between stage 1 and 2 clearing prices. But he said that comes at a cost: The scaling of capacity awards means all resources, including competitive and self-supply resources, receive reduced awards. Because of the reduction, “resource owners that need a certain minimum revenue may be inclined to raise their offer prices to make up for the pro rata quantity reduction,” Wilson said.
Other Proposals
NEPOOL says stakeholders have reviewed more than 17 proposals during the IMAPP sessions, many of them designed to “achieve” state policy in the wholesale market (long-term proposals), and “a few other” proposals such as CASPR to “accommodate” state-sponsored resources while addressing capacity market pricing concerns (near-term proposals).
Aside from the two-tier/paired retirement options, NEPOOL said the proposals fell into three categories:
Carbon pricing in the energy market: A carbon adder would be included in energy offers and reflected in clearing prices. The adder would be collected from carbon emitters and redistributed to ratepayers.
Carbon-Integrated Forward Capacity Market (FCM-C): A new zero-emission credit market would be integrated with the FCM to incorporate a forward signal for clean/renewable energy into the market.
Forward Clean Energy Market (FCEM): A new forward market for commitments to deliver clean energy that would support new or existing clean energy resources.
No to Carbon Pricing
Although New York and the New England states have been participating in the Regional Greenhouse Gas Initiative cap-and-trade carbon market since 2009, the RGGI emissions limits would have to be substantially reduced to make the resources sought by the states economic in the RTO markets, Patton said.
“We do not believe it is likely that the states will rely on the RGGI market or a carbon tax to achieve their public-policy objectives, although this would likely be the most efficient and effective approach,” Patton said.
Other New England stakeholders agreed with Patton’s prediction.
In an April 7 memo to NEPOOL, NESCOE outlined its opposition to “a FERC-jurisdictional tariff reflecting carbon pricing.”
“These concerns include risks to states’ ability to make their own determination regarding the implementation of their carbon-reduction laws. For example, as illustrated in recent years, a few market participants with an appetite and budget to litigate matters could seek to disrupt a design over which ISO-NE, NESCOE and NEPOOL find agreement. FERC could also seek to direct changes on its own initiative,” Bentz said.
“Conceptually, assessing a price for each ton of carbon emitted by an electric generator, and crediting those revenues to load that would be paying higher energy prices, seems simple to understand,” said Brian Forshaw, who appeared at the conference on behalf of public power agencies in Connecticut, New Hampshire and Vermont. “In a practical sense … there are substantial challenges associated with deciding on the initial carbon price and figuring out how to adjust the price over time to achieve desired carbon reduction levels, deciding who will get the rebates and in what form, and legal questions over whether the ISO has the authority to charge generators for carbon emissions.”
CLIPR
Charles River Associates senior consultant Robert Stoddard, who testified on behalf of the Conservation Law Foundation, briefed the commission on his proposed Carbon-Linked Incentive for Policy Resources (CLIPR). Under CLIPR, load-serving entities would pay state “policy” resources an energy price premium that would fluctuate based on the “marginal carbon intensity” (MCI) of the dispatch, “a direct analog to the LMP but computed as lbs-CO2/MWh instead of $/MWh.”
Stoddard said the proposal would address most of the problems with the carbon adder, with the clearing price determined by the market, “simultaneously removing administrative discretion and assuring that the prices paid are supporting the particular policy resources demanded.”
The incentive would likely be zero in hours with negative prices because the marginal resource is likely to be zero-emitting. CLIPR delivery rights could be traded bilaterally.
Bentz was intrigued by the idea and said he plans to discuss it in detail with Stoddard.
NextEra Energy and RENEW Northeast, a group of renewable energy companies and environmental interest groups, offered the proposal to create a FCEM.
RENEW Chair Seth Kaplan, EDP Renewables’ senior manager for regional government affairs, outlined the group’s proposal to FERC, in which he said the RTO, electric distribution companies and states would cooperatively manage resource procurements.
ISO-NE would study the network upgrades needed to connect renewable generation in the interconnection queue. When there is a competitive clean energy solicitation, EDCs and state regulators could consider competitive transmission solutions to address the network upgrades, agreeing to bear the cost under a public policy designation. The cost allocation would be identified by the opting-in EDCs and filed for FERC approval by the participating transmission owners as a participant-funded project.
In January, public power representatives presented a proposal to amend the FCM to ease bilateral contracting by LSEs with generation assets.
Next Steps
On April 7, NESCOE issued a memo saying that the states needed additional time to further study the long-term proposals presented to date.
NEPOOL said it will consider ISO-NE’s near-term proposal at its regular meetings beginning with the June Markets Committee meeting. In addition, NEPOOL said it expects discussions to continue at events over the next two months:
SPP stakeholders last week unanimously approved what could be the first MISO-SPP interregional transmission project, but hurdles still remain.
The Interregional Planning Stakeholder Advisory Committee’s May 3 endorsement of the 115-kV project in South Dakota matches a thumbs-up from MISO’s Planning Advisory Committee. (See MISO Stakeholders Give Go-Ahead on SD Interregional Project.) That leaves only approval from the SPP-MISO Joint Planning Committee — composed of representatives from the two RTOs — followed by an IPSAC review of a final report before the project can enter the regional review process.
The $5.2 million project would relieve congestion on a tie line shared by the Western Area Power Administration in SPP’s footprint and Xcel Energy in MISO. The project loops a Split Rock-Lawrence 115-kV circuit into Sioux Falls to relieve congestion on the Lawrence-Sioux Falls 115-kV line.
| MISO & SPP
The project was the only one of seven proposals to survive a coordinated system plan study conducted by the RTOs last year. Some of the projects failed to pass muster because of a $5 million threshold for interregional projects, a metric both RTOs are open to changing. (See 1 Project Recommended for MISO-SPP Coordinated Plan.)
Much of the cost (81.48%) for the South Dakota line shifted to MISO with the recent approval of projects in its generator interconnection queue. The project has a 20-year benefit-to-cost ratio of 4.42.
Adam Bell, SPP’s interregional coordinator, told the IPSAC that the project’s cost estimate is study-level, and that a few specific outstanding details could change the final figure.
Several stakeholders raised concerns that the economic project may not address reliability issues, but Bell assured them the regional review would be “very much stakeholder-driven.”
“We used the most up-to-date power-flow models we had,” Bell said. “We ran it in every season and year and didn’t detect any reliability concerns.”
Bell also expects the final regional review to be ready for board-level action in October.
MISO, SPP Agree to M2M Improvements
SPP and MISO have reached an agreement on improvements to the market-to-market coordination process across their seam, David Kelley, SPP’s director of interregional relations, told the Seams Steering Committee last week.
Pending executive signoff, a memorandum of understanding will document the agreement, which Kelley stressed is not a “wholesale redesign.”
The RTOs’ M2M process is modeled after a similar process between MISO and PJM, and is designed to economically relieve congestion and align border prices. Under the current model, which began in March 2015, MISO has paid almost $20 million to SPP for creating congestion on the other side of the seam.
“Almost immediately, we noticed there were some issues we needed to deal with,” Kelley said. “Price convergence should be a result of effective market-to-market. You do market-to-market because the other market potentially has generation it can dispatch at a lower cost than the monitoring market.”
The MOU will target “ineffective real-time congestion management” on some of the 135 permanent M2M flowgates between the two RTOs, errors in settlement data calculations and difficulties in finding a common interpretation of certain sections of the interregional coordination process of the RTOs’ joint operating agreement.
| MISO & SPP
SPP and MISO staff have developed an alternate M2M procedure in which the monitoring RTO relies on ”market flow control” (redispatching generation within its footprint to a targeted level of market flow) rather than “total flow control” (redispatching generation within its footprint to maintain total flow on the flowgate) to help address volatility and “power swings” on certain flowgates. The process is limited to instances where M2M “does not resolve, or even aggravates, reliability concerns.”
Kelley said the monitoring RTO’s control of a flowgate’s total flow works best when it has the predominant flow.
“There are situations where we experience power swings, where a renewable wind resources swings flow on a flowgate back and forth,” he said. “One way SPP has found [to mitigate power swings] is market flow control.”
Other improvements in the MOU include forming a technical committee to address issues as they arise and following a standardized process for future resettlement requests.
SPP, MISO Studying Overlapping Charges on the Seam
SPP and MISO are currently studying a year’s worth of data to analyze overlapping charges along their seam. The result, covering the period between the March 2015 open of M2M through February 2016, will be presented at a May 31 JOA meeting.
“The research could help with market-to-market,” SPP’s Gerardo Ugalde said. “We’re doing extensive analysis to ensure the interface picked is the most accurate representation of imports in and out of SPP.”
Ugalde told the seams committee that each market should charge for congestion based on the redispatch of their respective generation resources. When a host market dispatches a resource, that resource should get either a charge or a credit based on the flowgate it is affecting.
When the host market pseudo-ties out a resource, the host market will charge or credit for the congestion from the source to the interface, covering any congestion charges to export the power out of the market. The attaining balancing authority will dispatch the resource, and the resource will get either a charge or a credit based on the flowgate it is affecting.
Ugalde said MISO and PJM have proposed a solution in which the attaining market refunds the marginal congestion component (MCC) between the interface and the resource. Under that plan, the host charges the transmission customer from the resource to the host border, the attaining market charges the MCC from the resource to the attaining market load, and the attaining market then rebates the MCC from the resource to the host border.
“If you have a resource, the interface is the border,” Ugalde explained. “If you go resource-to-border, and border-to-load, you’ve minimized the amount of overlap.”
March’s M2M Bill: $3.98 Million for MISO
SPP recorded its second highest month of M2M payments from MISO, collecting $3.98 million for congested flowgates between the two RTOs in March. The month accounts for slightly more than 20% of the $19.3 million MISO has paid SPP since the two began the M2M process in March 2015.
Most of the March payment ($3.2 million) came from a congested SPP flowgate in southeastern Kansas, caused by high winds and several line outages in the area, including a 345-kV line from Neosho County, Kan., into Oklahoma. The permanent flowgate was binding for 365 hours, representing almost half the 741 hours for all binding temporary and permanent flowgates between the two RTOs.
SPP Director Wins Illinois Volunteerism Award
SPP Director Larry Altenbaumer was honored recently with a Governor’s Volunteer Service Award for his community efforts in his hometown of Decatur, Ill. The ceremony took place April 25 at Illinois’ Old State Capitol with Gov. Bruce Rauner.
Altenbaumer was honored for his leadership of Grow Decatur, a collaborative growth and development effort transforming the city through improved economic and quality of life. Through the initiative, the community identified 10 areas as imperative to the city’s resurgence and has since formed community teams to address the issues.
“I accept this award on behalf of the dozens of other Decatur community volunteers who I have had the privilege of working with over these past several years on the Grow Decatur initiative,” he said.
Altenbaumer is vice chair of SPP’s Board of Directors, on which he has served since 2005, and chairs the Finance Committee. He retired in 2004 as president of Illinois Power.
Exelon is encouraged by Energy Secretary Rick Perry’s order to study if government regulations and policies are forcing baseload power plants into early retirement and thinks courts will uphold the programs that provide zero-emission credits benefiting its nuclear power plants, executives said during the company’s first-quarter earnings call Wednesday.
The executives also said Exelon’s bids in PJM’s upcoming capacity auctions will reflect the economic needs of its plants, even if that leads to some of its plants not clearing the auction.
Exelon CEO Christopher Crane said Pepco Holdings Inc., which the company acquired a year ago, has only rate cases in D.C. left from its first planned cycle of rate filings under Exelon and has started the second cycle at its Maryland and Atlantic City Electric subsidiaries.
Crane also said Exelon is not concerned that the bankruptcy of Westinghouse, which is one of the suppliers of fuel for its nuclear plants, will impact its ability to get fuel for the plants.
“We continue to competitively bid our reactor fuel suppliers … and we move that around based off of pricing,” Crane said.
Exelon’s first-quarter results exceeded earnings and revenue estimates. Its adjusted operating earnings of 65 cents/share beat the Zacks consensus estimate of 61 cents but were down from 68 cents the year prior. Its net income was $1.07/share, up from 19 cents/share in 2016. The company’s revenue was $8.76 billion, beating the Zacks consensus estimate of $8.48 billion, and up 16.5% from $7.48 billion a year ago.
“We’re off to a great start in 2017,” Crane said.
Crane and Joseph Dominguez, Exelon’s executive vice president of governmental and regulatory affairs and public policy, made positive comments about Perry’s recent memo directing department staff to conduct a 60-day inquiry into “the extent to which continued regulatory burdens, as well as mandates and tax and subsidy policies, are responsible for forcing the premature retirement of baseload power plants.”
The memo has been interpreted by foes of coal-fired and nuclear power plants as an attempt to find reasons for the department to support both.
Exelon has the nation’s largest nuclear generation fleet and its plants have faced pricing pressure from cheap natural gas and the plunging costs of utility-scale solar arrays and wind farms.
“Energy Secretary Perry’s recent directive to look at the importance of preserving baseload generation is early but encouraging,” Crane said. “We appreciate the secretary’s focus to promote needed market reforms to compensate these assets.”
Exelon has argued that its nuclear plants need to be compensated for their ability to provide emissions-free power, and New York and Illinois have established zero-emissions credits to do that. The programs have been challenged by other power providers and some environmental groups, although other environmental groups have backed them.
On March 31, Exelon assumed ownership and management of operations of the James A. FitzPatrick Nuclear Power Plant in Scriba, New York, which is eligible for zero-emission credits. | Entergy
Crane said a New York federal judge heard oral arguments March 29 on Exelon’s motion to dismiss a lawsuit challenging ZECs. “We made strong arguments at this hearing and believe the law is clearly on our side,” Crane said. (See Federal Suit Challenges NY Nuclear Subsidies.)
The judge has not said when he would rule on the motion, Crane said, and that if Exelon prevails, it expects its opponents to appeal the judge’s decision. If it doesn’t prevail, he said, it will proceed with the case.
In Illinois, two groups of plaintiffs have challenged the ZECs in federal court. The cases have been combined before one judge, who has delayed action on a motion for a preliminary injunction against the ZECs while he receives a full briefing on Exelon’s motion to dismiss the cases. (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Crane said the briefing will be completed by May 15 and the judge is scheduled to let the parties know his intention concerning the cases on May 22.
Exelon began recognizing ZEC revenues in New York on April 1, Crane said. In Illinois, he said, it has filed tariffs to begin collecting the ZEC payments on June 1 but doesn’t expect the actual procurement process to conclude until fall.
The earnings call came the day after the conclusion of a two-day technical conference at which independent power producers asked FERC to take action to prevent the ZECs from undermining the NYISO and PJM markets. (See related story, NYISO See Carbon Adder as Way to Link ZECs to Markets.)
Crane said he expects clearing prices in the upcoming PJM capacity auction to “come down to bidding behavior.”
“You have seen us bid our assets in recent auctions to reflect the underlying economic needs of the individual plants, which in turn has led to some of our plants not clear[ing]. You should expect us to bid our assets in the same responsible fashion in this next upcoming auction.”
Exelon expects a ruling on Pepco’s D.C. rate case in July, CFO Jonathan Thayer said. It expects rulings in the Maryland and Atlantic City Electric cases in the fourth quarter of 2017 and the first quarter of 2018, respectively, Thayer said.
WASHINGTON — More than 50 stakeholders from PJM, NYISO and ISO-NE made their cases to FERC last week on how to resolve the increasing conflicts between state energy policies and wholesale markets.
Many of those who testified also had appeared at the commission’s September 2013 technical conference, which was billed by then-Commissioner Tony Clark as a “check-up” on the capacity markets six years after the inception of PJM’s Reliability Pricing Model. Participants at that time differed on the health of the markets and whether major changes were needed. (See Capacity Market Attracts Praise, Criticism at FERC and Old Issues, New Technologies in Capacity Debate.)
Last week, however, virtually everyone was calling for change — the disagreements being over how much, how fast, what kind and whether it should be directed by FERC or come from stakeholders.
The diagnosis: The patient is running a fever and will only get worse without treatment.
“The challenge before the commission, the states and all other stakeholders is no less than the question of whether the power industry will continue to use competitive markets as the basis for investment decision-making,” Peter Fuller, vice president of market and regulatory affairs for NRG Energy, said in his written testimony.
“Is there a role for the markets? Absolutely,” said Scott Weiner, deputy for markets and innovation at the New York State Department of Public Service. “The energy markets will always be there. The capacity market may not be.”
FERC scheduled the conference out of concern that the RTO/ISO energy and capacity markets could lose relevance — or have their pricing signals undermined — because of state plans to procure out-of-market renewable power and prop up nuclear generators (AD17-11).
“There are three ways this could go,” acting FERC Chair Cheryl LaFleur said at the opening of the two-day conference May 1. “A designed market solution, a litigated outcome or a planned change in the regulatory construct of how we handle resource adequacy. The fourth outcome — an unplanned change in the regulatory construct — or unplanned and piecemeal regulation, is one that I think we should avoid because I think it would be a bad outcome for customers and market participants in terms of cost, reliability and regulatory certainty.”
“All options, in my mind, are on the table,” added Commissioner Colette Honorable.
Factions
The witnesses fell into several camps.
Public power representatives said they should be relieved of participation in the capacity markets, which they say are too expensive and inflexible. Unlike in 2013, they had lots of company in calling for change.
Independent power producers called for FERC to act decisively to protect markets from out-of-market contracts and subsidies.
The grid operators differed on their preferred role for FERC, with PJM and NYISO urging the commission to set deadlines and provide direction.
Officials from New England said they will continue to pursue their states’ clean energy mandates with or without cooperation from the wholesale markets.
Carbon Adder
Economists have been telling FERC and others for years that the simplest way to reconcile the markets with environmental policies is to incorporate the cost of carbon into LMPs and generation dispatch. While New York and PJM are exploring ways to do so, New England policymakers said differences in state policy goals make it politically unpalatable despite its economic elegance.
IPPS: FERC Should Act Decisively Against Subsidies
Independent power producers NRG, Calpine, Dynegy and Eastern Generation, and their trade group, the Electric Power Supply Association, called for FERC to act quickly and firmly.
“A policy approach that lets any given action prevail at all costs in the name of a ‘state preference’ regardless of the detrimental impact on federally regulated wholesale markets would be the exception that swallows the rule of law in the” Federal Power Act, EPSA CEO John Shelk said. “If the commission wishes to continue delivering the benefits of wholesale markets, it needs to direct steps be taken by the Eastern ISOs/RTOs by specific deadlines to ensure that wholesale markets are protected and not undermined.”
FERC’s “hands-off approach” to date “rightly allowed states to experiment on the edges of the wholesale market with a variety of new programs and to avoid over-burdening these fledgling initiatives with federal intervention,” said Abe Silverman, vice president and deputy general counsel at NRG.
Now, however, the commission must develop “rule-of-reason” tests “to delineate how state programs are harmonized with competitive markets,” he said. “Wherever the line is eventually drawn, there clearly must be a line if the Federal Power Act is to have meaning.”
Calpine CEO Thad Hill also called for swift action.
“The legal process is lengthy, and it will take the courts considerable time to work through these issues. The commission should not wait for the courts to act, but instead the commission should be prepared to act quickly and decisively when viable proposals are brought before it,” he said.
Joining the IPPs in calling for action was Seth Kaplan, EDP Renewables’ senior manager for regional government affairs, who cited the D.C. Circuit Court of Appeals’ April ruling in Emera Maine v. FERC. That ruling upheld FERC’s Order 1000 finding that FERC-regulated transmission planning must accommodate state public-policy requirements. (See Court Rebuffs New England TOs, Upholds FERC ROFR Order.)
“The Emera decision reaffirms once again that FERC and the entities it regulates have the ability — and I would argue obligation — to recognize state policies, like renewable portfolio standards and procurements, as cost drivers that must be recognized in the transmission planning and cost-allocation process,” Kaplan said.
Aleksandar Mitreski, senior director of regulatory affairs for Brookfield Renewable, agreed, saying “the time is ripe for public-policy objectives to be incorporated into the wholesale markets.”
Independent consultant Roy Shanker said FERC must take a leadership role because stakeholder negotiations will not prevent litigation. “The fundamental differences among parties … make any cooperative solutions unlikely,” he said. “In the presence of such fundamental differences, any path forward requires the commission to exercise its full authority over wholesale markets in order to find a resolution that does not cannibalize markets.”
New England: Butt Out, FERC
State officials from New England were equally forceful in saying they don’t want FERC interfering with ongoing stakeholder processes.
“Our work with the National Council [on Electricity Policy] supports the idea that states are well suited to collaboratively working out answers to the policy questions addressed by this technical conference,” said Vermont Public Service Board Commissioner Sarah Hofmann, a member of the NCEP’s executive committee.
“The New England states have shown the ability to work collaboratively to address climate change through [the Regional Greenhouse Gas Initiative], which is a program under state control,” New Hampshire Public Utilities Commissioner Robert Scott said. “Addressing carbon emissions through a federally controlled tariff based on state policies raises significant concerns not only about the potential for unreasonable allocation of costs but also states’ rights. If the federal government wishes to regulate carbon emissions in the wholesale electric sector, Congress should pass a law giving the appropriate agency such authority.”
The Beginning of the End of RPM?
Public power representatives reiterated their longstanding complaints about mandatory capacity markets, saying they could provide resource adequacy more cheaply through bilateral contracting and self-supply.
Lisa McAlister, general counsel for regulatory affairs at American Municipal Power, said FERC should eliminate the mandatory participation requirement in PJM’s capacity market. “RPM is a ‘market’ in name only, and, as time has gone on, fewer and fewer PJM market participants use that term to describe it,” she said.
“With respect to meeting adequacy needs, the markets have been a success,” said Cliff Hamal, managing director at Navigant Economics, who has consulted for AMP in PJM’s new capacity initiative. (See PJM Capacity Task Force Debates the Value of Price Transparency.) “With respect to doing so at a reasonable cost to consumers and consistent with meeting other legitimate policy goals, I think we can do better.”
Hamal said the capacity market’s cost of capital is increased by a “volatile, fickle and frail price mechanism that relies more on regulatory nurturing than the fundamentals of supply and demand.”
While RTOs should continue to set capacity obligations for load-serving entities, Hamal said, the LSEs should be allowed to meet their obligations independently.
“I believe the most promising option would be to allow state policies to be implemented through a formal commitment to bilateral markets. States would withdraw from the RTO centralized auctions and meet their capacity objectives bilaterally,” he said. “Energy markets will continue to function and capacity markets will return to providing the ‘missing money’ in the sense of a supplemental payment needed to ensure supply adequacy after consideration of all other revenue streams.”
Deadlines for Stakeholder Processes
Silverman said the commission should “direct each of its ISO/RTO markets to set forth a comprehensive plan to integrate state goals into its wholesale market outcomes in a sustainable manner. Unless the commission mandates such a process — by a date certain — I fear that states will continue to pursue carbon mandates outside of the organized markets, and society will be deprived of the benefits of competitive markets.”
PJM and NYISO officials said they would welcome FERC deadlines to pressure stakeholders to compromise on rules for incorporating state initiatives into the markets.
“We don’t want to run a 50% market. … We want to be the market that all resources depend on … for entry decisions, and we will work with the state to achieve those goals,” said Rana Mukerji, senior vice president of market structure for NYISO. “The stakeholder process … is long and contentious. Having deadlines works miracles.”
“Yes, there are compromises that come out [of the stakeholder process]. Yes, they can lead to maybe suboptimal … approaches,” said PJM Senior Vice President for Operations and Markets Stu Bresler. “But I can say without reservation [that] almost universally what comes out of a detailed stakeholder vetting of an issue is better than what went into it.
He added: “Deadlines and guidance from the commission are always helpful with respect to the efficiency of how that stakeholder process works.”
ISO-NE and the New England Power Pool, however, urged FERC to give them breathing room. Matt White, chief economist for ISO-NE, said the RTO will file a proposal with FERC by late this year or early 2018.
“The house is not burning down so fast that we must make an exigent circumstances filing with you within a week,” he said. “Coming up with something we can do and you will not be tweaking it again and again and again and again is probably worth six to nine months of our time.
“We have a very active stakeholder process that is deeply engaged on these issues,” he continued. “A deadline would not be terribly helpful.”
Not everyone saw the value of stakeholders’ participation, however.
“FERC should immediately begin a formal inquiry to rationalize the capacity and energy market constructs with the long-term financial needs of different operational categories of electric generation,” said John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents large U.S. manufacturers. “We strongly oppose any attempt to solve this problem via negotiated settlements in ISO or RTO stakeholder processes.”
Now What?
The “crossroads” for the markets, as multiple speakers called it, comes at a time when FERC has never been less prepared to act. With three empty seats, it has been without a quorum since February; Honorable announced last month that she won’t seek a new term when hers expires in June.
So, as the participants wheeled their suitcases to cabs outside FERC headquarters at the end of the two-day hearing, the commission’s policy direction could hardly be more uncertain.
With President Trump — who has moved to dismantle his predecessor’s climate change policies — in a position to fill four of the five seats, at least some of the new members could be hostile to Northeast states’ climate policies. At press time, there were numerous reports that Trump will nominate Pennsylvania regulator Robert Powelson and Neil Chatterjee, senior energy policy adviser to Senate Majority Leader Mitch McConnell (R-Ky.) to fill two Republican vacancies on FERC. Chatterjee was described in a Bloomberg profile as “the McConnell adviser determined to stop the Clean Power Plan.” (See related story, Trump Nominates Republicans Powelson, Chatterjee to FERC.)
Even if the commission did support an RTO-administered carbon adder, would it have the authority to do so?
Certainly someone will ask the courts that question.
VALLEY FORGE, Pa. — PJM’s proposed problem statement and issue charge on whether states can control energy-efficiency participation in the capacity market drew heated debate on two issues — one expected and the other not — at last week’s Market Implementation Committee meeting.
Because of the ongoing debate, a vote on endorsing the proposal was delayed until next month with one objection and one abstention.
The proposal was developed in response to a current proceeding before the Kentucky Public Service Commission on energy-efficiency requirements, said Denise Foster, PJM’s vice president of state and member services. PJM’s rules on load-modifying resources offering into the market, such as demand response, don’t address whether energy efficiency should be treated the same as DR, so the RTO is considering how and whether to add it.
However, PJM is specifically limiting the scope to avoid discussing whether state jurisdiction factors into the discussion, despite stakeholder suggestions to include it. The issue charge would establish requirements for energy efficiency entering the market, rules around those requirements and how to handle energy-efficiency resources that have already cleared past capacity auctions.
Tom Rutigliano, representing Electric Market Connection, expressed concern that the proposal would ostensibly grant state regulators new power to restrict energy efficiency participation in wholesale markets. He pointed to the Supreme Court case EPSA v. FERC as confirming that FERC has jurisdiction over retail customer participation in the wholesale markets.
“We appreciate that Kentucky may have claims, but we feel at this point, it’s not really appropriate to put PJM and its stakeholders in the position of deciding if those jurisdictional claims are correct or not,” he said. “This is really not at this point a stakeholder issue.”
His concerns were echoed by Rick Drom, an attorney with Eckert Seamans Cherin & Mellott, who offered a presentation titled “A Flawed Solution Seeking a Problem.” He said any discussion on PJM deferring to state regulatory authorities is premature and that the proposal risks balkanization of the energy market.
Drom’s arguments, however, were overshadowed by his unwillingness to name whom he represented at the meeting. He said his client, whom he said is one of the largest energy efficiency providers in the PJM footprint and operates in Kentucky, fears reprisal from opponents. Drom said he met with senior PJM staff to explain the situation, and they agreed to let him speak without naming his client.
Bruce Campbell of CPower noted that Eastern Kentucky Power Cooperative is seeking a declaration from the Kentucky PSC that the utility has the authority to “terminate electric service to any energy-efficient resource provider who violates Kentucky law, a commission order, rule or regulation or commission-approved tariff.” Drom acknowledged that was part of his client’s desire to keep its name hidden.
When Drom refused to identify whom he represented, Calpine’s David “Scarp” Scarpignato requested a point of order, citing Manual 34 rules that require speakers to identify whom they represent. Other stakeholders supported the request, noting that it would create a bad precedent.
Chantal Hendrzak, the chair of the MIC, called a short recess for Drom to explain the situation to Scarp. Scarp maintained his request, which led Hendrzak to acknowledge that PJM would take greater care considering similar requests in the future.
DR Open Registration Under Consideration
PJM is considering changes to when DR can be registered. Currently, all registration must be completed prior to the beginning of the delivery year, so new customers who wish to enter after June 1 are barred from participating and those who leave can’t find new customers to take over their responsibility.
The RTO is offering three options. The first would move the deadline to Dec. 1. The second would have no registration deadline. The third would also have no deadline but would require registered DR to test prior to the delivery year and new registrations to test on the first active day. All three would allow for the daily deficiency penalty to change daily, and the test commitment would change from the daily average during summer period to daily average for delivery year. The third solution, proposed by the Independent Market Monitor, would instead use the peak commitment day for the delivery year.
Stakeholders who don’t handle DR asked if there was a strong preference among stakeholders who do regarding which option they supported. Bruce Campbell of CPower said he generally supported the second option. A stakeholder poll produced identical support of 51% for the first and second options and minimal support for the third one. However, there was greater support (69%) for the status quo.
WASHINGTON — If the economists who testified at FERC’s technical conference last week agreed on nothing else, it is that a carbon adder is the simplest way for the power markets to value emission-free generation.
New York is going to try and translate the theory into practice as a way of addressing the impact of the state’s zero-emission credits (ZECs) for its upstate nuclear plants, officials told FERC.
On the first day of the two-day conference (AD17-11), state and NYISO officials asked FERC for time to develop their plan even as merchant generators called for immediate action to block the subsidies or respond to their effects on the wholesale markets.
The ZECs are part of New York’s Clean Energy Standard, which mandates reducing greenhouse gas emissions by 40% by 2030, from a 1990 baseline, and by 80% by 2050. The CES also calls for renewables to meet 50% of the state’s energy needs by 2030.
The subsidies will support Exelon’s two-unit Nine Mile Point, and the single-unit R.E. Ginna and James A. FitzPatrick plants for more than 12 years at a cost estimated as high as $7.6 billion. (See NY Legislators Frustrated by Lack of Answers at ZEC Hearing.) At a legislative hearing into the ZEC program in Albany on May 1, however, New York Public Service Commission interim Chair Gregg Sayre said he expects the actual cost may be much less, perhaps as low as $2.86 billion.
NYISO CEO Brad Jones told FERC that while the ISO supports the ZEC program, it wants to find a way to incorporate the payments into the wholesale market.
The ISO has hired the Brattle Group to develop a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Generating units that emit carbon would incur a penalty based on their level of carbon emissions; the penalties collected by the ISO would be “returned to customers in some equitable manner.”
Jones said the project was in its “initial stages” and that implementation could take three years.
That is too long for other stakeholders.
“I was shocked to hear [Jones] say yesterday that he doesn’t think the rates are just and reasonable but we have three years to work out a solution,” said Abe Silverman, vice president and deputy general counsel for NRG Energy. “No, this is something that needs to happen almost immediately.”
John Reese, senior vice president of Eastern Generation, said the issue is particularly acute in New York, which has a one-year forward capacity auction, unlike the three-year auctions in PJM and ISO-NE. Eastern Generation operates almost 5,000 MW of generation in NYISO and PJM, including 18% of New York City’s capacity.
“I can’t wait for seven years or eight years for this to work out,” he said. “Regardless of which model we end up with, we need to be sending investment signals now!”
The Independent Power Producers of New York argued that the state’s goals and its energy markets have reached a crossroads, saying that out-of-market solutions threaten the ability of the wholesale market to meet system needs at the least cost.
“Retail electricity customers are required to pay for renewable energy credits to support new large-scale renewable resources, as well as zero-emissions credits to support nuclear facilities which might otherwise retire from the market — both of which are out-of-market valuations for environmental attributes,” IPPNY CEO Gavin J. Donohue said. “The implementation strategies used to meet those [CES] goals conflict with the competitive market principles that have produced unparalleled reliability and record-low electricity prices.”
The NYISO discussion focused on several questions, some of which will also be central to challenges to the ZECs in court and before FERC: state vs. federal jurisdiction; the price suppressive impact of ZECs; and the efficacy of saving at-risk nuclear plants versus replacing them with renewables.
Dynegy, Eastern Generation, NRG and the Electric Power Supply Association filed a federal court suit in October claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order them withdrawn from the CES. (See Federal Suit Challenges NY Nuclear Subsidies.)
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 (EL16-49). (See IPPs File Challenge to Illinois Nuclear Subsidies.)
Do ZECs Interfere with the Wholesale Markets?
The Supreme Court has attempted to draw the lines between state and federal jurisdiction over the power industry in a series of rulings, most recently the January 2016 ruling in EPSA v. FERC, in which the court upheld FERC’s jurisdiction over demand response, and the April 2016 order in Hughes v. Talen, which rejected Maryland’s subsidy of a generator that could have undermined PJM’s capacity auction.
New York regulators took pains to ensure the ZEC program complied with the court’s advice in the latter case. “Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation,’” the court said.
Scott A. Weiner, deputy for markets and innovation at the New York State Department of Public Service, made an impassioned defense of the ZEC program, saying it was permitted by states’ “settled jurisdiction over environmental policy, resource adequacy, fuel diversity and reliability.”
“Rather than opening this discussion with the question of how state policies can be implemented through federally regulated wholesale markets, we should ask, ‘should they?’ An attempt to select resources through the federally regulated wholesale markets to achieve individual state policies may undermine, even if unintentionally, those very state programs,” he said. “By incorporating state policy into the wholesale markets, the state would have to seek a tariff change to reform its own policy.
“This changing role of the state’s utilities must be harmonized by federal and state regulators acting in respectful collaboration without one seeking to subsume the other.”
Rather than attempting to “absorb” state policies into the federal wholesale markets, Weiner said, FERC should consider removing barriers to new entry by state-supported resources by eliminating buyer-side mitigation.
“It is essential to recognize that policies addressing legitimate state interests may have incidental impacts on wholesale market prices without raising the specter of price suppression or undermining markets.”
NY, Exelon: ZECs not Intended to Suppress Prices
“New York, like other states, does not seek to suppress wholesale market prices. Ending application of this false assumption eliminates the need for market rules based on that presumption,” Weiner said.
Exelon also insisted that ZECs are not vehicles for price suppression, comparing them to the renewable energy credits (RECs) issued in support of state renewable portfolio standards.
“Buyer-side mitigation rules are aimed at large buyers seeking to suppress market prices by introducing new, uneconomic supply. But environmental programs like ZEC programs do not fit that description,” Exelon said. “First, in ZEC and REC programs, the state is purchasing a separate environmental attribute, so ZECs and RECs are not tied to energy or capacity sales.”
Impact, not Intent, is What Matters
Others counter, however, that it is the impact of state policies on prices — not policymakers’ intent — that is at issue.
David Patton, president of Potomac Economics, which provides market monitoring in NYISO and ISO-NE, said nuclear subsidies can be much more damaging to wholesale price formation than renewable subsidies because solar and land-based wind have low capacity values.
Former FERC Commissioner Tony Clark, now a senior adviser at Wilkinson Barker Knauer, said at a conference in March that while FERC hasn’t seen harm to the markets from state REC programs, the scale of the nuclear generation covered by subsidies — 20% or more of the market in some regions — may make them more vulnerable. (See Ott Seeks ‘Resilience’; Clark Handicaps ZECs.)
And even renewables are having a significant impact on prices, Lawrence Makovich, chief power strategist for IHS Markit, told FERC.
He presented analysis that he said demonstrated that wind output suppressed PJM prices by about 24% during the top net load hours in 2015, when peaking units were setting the price. Wind suppressed prices by 4% when net loads were average and by about 9% during minimum load, he said.
“On the cost side, compensating for the impact of wind … [caused] load-following generators to increase output ramping and starts and stops, causing less production efficiency and higher [operating and maintenance] costs,” he said.
Is Preserving Nukes the Best Policy Choice?
Exelon says ZECs are justified because it would take too long and be too costly to replace the zero-emission capacity of at-risk nuclear plants versus renewables. “When a nuclear facility retires, it cannot feasibly be replaced by renewable generation in the time necessary to avoid a spike in emissions. Instead, it will be replaced predominantly by fossil fuel-fired plants emitting significant carbon and other air pollution,” Exelon said.
The company cited Germany’s retirement of its nuclear fleet following the 2011 Fukushima nuclear accident, which resulted in “a massive increase in emissions despite investing in new renewable generation to such a degree that its electricity rates are now among the world’s highest.”
Similarly, the closure of the San Onofre nuclear plant in early 2012 “resulted in an increase in emissions that more than offset all of California’s investment to date in wind, solar and biomass generation,” Exelon said.
New York concluded replacing its nuclear fleet would require that it triple its energy-efficiency targets or construct 9,000 MW of onshore wind or 22,000 MW of solar.
NRG’s Silverman, however, said New York chose an expensive path.
“For $3.5 billion — or approximately half the price of the bailout in New York — the state could have purchased enough renewables to replace the output of all of its at-risk nuclear fleet with 100% new renewable power. Additionally, New York’s Independent Market Monitor found that a new combined cycle on Long Island is a far cheaper means of reducing carbon in New York than the nuclear bailout.”
The impact of state mandates on load-serving entities was the key concern of James Holodak Jr., vice president of regulatory strategy and integrated analytics for National Grid, which owns LSEs in New York and New England.
Holodak said National Grid’s Niagara Mohawk Power subsidiary was forced to absorb $2 billion in stranded costs as a result of New York legislation that required utilities to buy electricity from independent power producers for at least 6 cents/kWh, a price higher than utilities’ production cost.
Holodak said the law forced Niagara Mohawk to sign contracts for output in excess of its actual demand and helped increase the utility’s rates by 25% between 1990 and 1995, causing many industrial and commercial customers to seek alternative suppliers or lower-cost locations.
Holodak said New England states with mandates should adopt a structure similar to that in New York in which each LSE is required to purchase the ZECs from the New York State Energy Research and Development Authority while recovering the costs from its customers. “In this instance, NYSERDA acts as the middleman, which advances the state’s policy goals and presents less risk for utilities than under a mandatory contracting model between the generator and the utility,” Holodak said.
He also made a case for allowing utilities to own renewables rather than being required to purchase them.
“Long-term bilateral [power purchase agreements] with developers equate to ‘virtual ownership’ with utilities and their customers absorbing project risks without the benefits of ownership,” he said, acknowledging that support for utility ownership will depend on utilities’ ability to “produce demonstrable customer savings.”
“We further recognize that this position may seem inconsistent with our broader support for market-based solutions where circumstances permit. However, today’s RTO/ISO markets do not adequately incentivize new entry from zero-emitting resources and it is not clear how or when they will evolve to do so.”
FERC’s agenda said the technical conference “may address matters at issue” in the following pending dockets:
ER16-1404 Power Producers of N.Y. v. NYISO re. buyer-side capacity market power mitigation
WASHINGTON — The minimum offer price rule came up frequently at last week’s FERC technical conference exploring tensions between state clean energy policies and RTO/ISO markets in the East, with some witnesses calling for its expansion and others seeking its relaxation or abolition.
Robert Erwin, general counsel of the Maryland Public Service Commission, called on FERC to help states achieve their energy policy goals by simplifying the “unduly complex” capacity market rules and reducing “the chilling effects” of the MOPR on state innovation.
He was one of several MOPR critics who invoked the words of former FERC Chairman Norman Bay to buttress their case. (See Bay Blasts MOPR on Way Out the Door.)
MOPR ‘Cudgel’
“State policy decisions over new generation — previously exempted under the [PJM Reliability Pricing Model] settlement — have become subject to the cudgel of the minimum offer price rule,” Erwin complained. “We believe that the putative threat of state initiatives that the MOPR was devised to counter is overblown. Accordingly, the Maryland commission agrees with former Chairman Bay that the MOPR, as currently utilized, ‘places [FERC] in constant tension with the states’ and inhibits valuable state policies.”
The Sierra Club also quoted Bay’s comments in calling for “curtail[ing]” the use of the MOPR, citing his criticism that “‘MOPR not only frustrates state policy initiatives, but also likely requires load to pay twice — once through the cost of enacting the state policy itself and then through the capacity market.’”
“We agree that it is essential to mitigate actual buyer-side market power, but encourage the commission to undertake a more careful examination of the evidence as to whether buyer-side market power is exercised in capacity or energy markets and develop appropriate screens to be applied whenever a mitigation mechanism is premised upon the existence of such power,” said Mark Kresowik, deputy director of the eastern region of the Sierra Club’s Beyond Coal Campaign. “As former Chairman Bay observed, ‘the commission simply assumes [buyer-side market power] exists. The commission has not explored or tested these assumptions in its orders, and it does not know whether they are true.’”
Angela M. O’Connor, chairman of the Massachusetts Department of Public Utilities, said that in addition to the short- and long-term policies being discussed by stakeholders in the New England Power Pool’s Integrating Markets and Public Policy (IMAPP) initiative, “we hope to explore other potential solutions, including a further examination of the minimum offer price rule, which presents a significant challenge to the participation of state-supported resources in the Forward Capacity Market.”
O’Connor (left) and Scott | RTO Insider
“Any IMAPP proposal that substantially increases the amount of clean energy resources entering the FCM will likely involve either the elimination of or modification of the minimum offer price rule,” said New Hampshire Public Utilities Commissioner Robert Scott, who added that his state has not taken a position on any potential changes to the rule. “Such a change in market design should be accomplished in a thoughtful manner and certainly not without a full understanding of the likely long-term implications for electric rates.”
Harvard University’s William Hogan also quoted Bay in urging FERC to minimize the role of the capacity markets.
“In his last comments about the minimum offer price rule, Commissioner Bay summarized: ‘The premise of the MOPR appears to be based on an idealized vision of markets free from the influence of public policies. But such a world does not exist, and it is impossible to mitigate our way to its creation. The fact of the matter is that all energy resources receive federal subsidies, and some resources have received subsidies for decades.’
“The factual premise is well founded. They are myriad subsidies, many beyond the commission’s jurisdiction,” Hogan continued. “It is also true that the commission cannot, by itself, unwind all these subsidies to create the idealized vision of pure markets.”
While the capacity markets exist, however, Hogan said FERC should “strengthen anti-manipulation efforts such as the MOPR.”
“The avowed purpose of capacity markets is to correct for defects in energy pricing. If this is the case, the commission should have no obligation to accommodate subsidized resources that, in effect, make the problem worse. The commission can and should limit access and discriminate against those subsidized resources that are adding to the problem of inadequate pricing in energy markets.”
PJM Independent Market Monitor Joe Bowring and Dynegy CEO Robert Flexon both told FERC it should expand the rule to include existing generation as well as new resources. PJM officials also have called for such an expansion. (See PJM: MOPR Could be Improved, but not by BRA.)
Flexon said FERC should require “adequate minimum bids for all existing and new resources that receive revenue or revenue certainty (e.g. long-term multiyear contracts, ZEC payments) from sources other than the competitive marketplace. All resources, new and existing, should be required to bid at least the level they would have bid if they were being supported solely by the competitive market.”
“The MOPR should be expanded to address subsidies for all existing and proposed units, and this should be done expeditiously,” Bowring said. “An inclusive MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”
VALLEY FORGE, Pa. — Even as PJM moves into a heavy outage season, its balancing authority area control error limit (BAAL) remains lower than usual, PJM’s Ken Seiler said at last week’s Operating Committee meeting.
PJM’s excursion minutes dropped to 177 in April, from 257 in March and 224 in April 2016. PJM posted a 99.6% BAAL score for April, improving 0.1 percentage point from a year ago and 0.2 percentage points from March. (See “Inconsistent Weather Contributes to Operational Inaccuracies,” PJM Operating Committee Briefs.)
Seiler said generators beyond PJM’s control but that tied into the RTO’s grid are still overgenerating, which is unbalancing the system. The excursions are mostly happening in “the valley period” between 1 and 3:30 a.m., he said, during light-load conditions when generation is mostly baseload units and wind turbines. He said PJM is working with neighboring grid operators to identify the causes of the issues, beyond large temperature swings.
“Our actual numbers are very good, actually,” Seiler said. “But when we look outside, we’re starting to see some excursions outside that are starting to have more of an impact on us.”
With new transient-shortage pricing set to go into effect on May 11, PJM’s Chris Pilong said system operators are being trained in how to best maintain lowest-cost generation, but that operations will largely remain the same.
“It’s an awareness issue,” Pilong said. “We need operators to understand these changes, which they do. They’re prepared for them.”
Calpine’s David “Scarp” Scarpignato, who raised the issue, said he agrees with the way PJM is handling the transition.
PJM Considering Compensation in Frequency Response Study
Stakeholders endorsed by acclamation PJM’s plan to address FERC’s recent Notice of Proposed Rulemaking on frequency response. PJM’s problem statement and issue charge suggest that the RTO might consider compensating units for maintaining primary frequency response, even though the NOPR is silent on the topic. (See “Stakeholders Push Back on Paying for Frequency Response,” PJM Markets and Reliability and Members Committees Briefs.)
John Farber of the Delaware Public Service Commission acknowledged it might be “reaching for belt and suspenders,” but he requested that the compensation issue be separated into another phase of the study from the main discussion.
This was received coolly by both stakeholders and PJM staff. “I think separating it too much may complicate the solution space that we come up with,” PJM Vice President of Operations Mike Bryson said. “I think separating it too much may predetermine the solution probably more than we’re willing to.”
VALLEY FORGE, Pa. — PJM will discuss its updated capacity emergency transfer limits at next month’s meetings of the Market Implementation and Planning committees, staff said at last week’s PC meeting. The announcement came just days after Jorge Cardenas, vice president of asset management and centralized services for Public Service Electric and Gas, sent a letter to PJM’s Board of Managers voicing concern about the CETL values calculated for PJM’s eastern region.
Cardenas said the values were overstated, exposing PSE&G customers “to the risk of failing to meet the applicable generation adequacy standard under which PJM plans its system.” CETL values represent the amount of power that can be reliably imported to a locational deliverability area to meet its loss-of-load-expectation threshold. They also impact the Base Residual Auction, which begins tomorrow, so the RTO published the updated values on April 13.
PJM’s Mark Sims said the RTO has received substantial feedback on the CETL calculation methodology since the original numbers were posted in February, so the discussions will explain the RTO’s assumptions and how to “memorialize” them for future use.
Steve Herling, PJM vice president of planning, noted that some stakeholders have suggested using “slightly different” CETL values in the BRA versus the Regional Transmission Expansion Plan, which is why the RTO plans to discuss it at both the MIC and PC next month. He said he “expects” PSE&G’s concerns will be covered during the discussion.
John Farber of the Delaware Public Service Commission noted that PSE&G’s letter is substantially redacted and hard to understand.
“I think the philosophical elements need to be discussed regardless,” Herling said. “Some of the details that were redacted I don’t know will be necessary to everyone’s understanding of the issues.”
PSE&G’s letter suggests that PJM made “invalid assumptions regarding the operation of the controllable lines between PJM and NYISO,” specifically the phase angle regulators on the J/K lines at the Waldwick substation and the 5018 line at Ramapo. PSE&G said PJM’s assumption is “unreasonable” because it would prevent fulfillment of the RTO’s supply obligation to Rockland Electric on the 5018 line, which is part of PJM’s joint operating agreement with NYISO, and because the PARs must be changed individually. Since it would require adjusting PARs on the Waldwick, Ramapo, Goethals and Farragut lines, it couldn’t happen fast enough to address emergency situations, PSE&G said.
The letter also points out that the values assume NYISO will be able to produce certain results on its system, but that assumption might be unwarranted because the ISO will likely also be experiencing any weather-related emergencies that cause PJM to implement emergency actions.
Competitive Planning Process Manual Won’t Address Cost Containment
For PJM to codify its competitive planning processes in time for an upcoming RTEP window, as it hopes to accomplish with its proposed Manual 14F, the RTO won’t have time to address cost-containment provisions that stakeholders have repeatedly brought up. (See PJM Making Cost Consciousness a Focus for RTEP Redesign.)
Herling PJM
“The discussion of cost capping is not going to be completed before we are asking for this endorsement of the manual,” Herling said. “Obviously, this is going to take a little bit longer. We have engaged two different consultants to help us, and we expect that there will be a lot of input from stakeholders, so for now, the coverage of the cost containment in the manual is going to be somewhat high-level. … We’ll amend the manuals as necessary, but we think it’s important to have the rest of the structure of the manuals and the process documented.”
Herling said PJM is “hoping” to have a two-month RTEP window running in the June-July timeframe.
PJM is holding an initial special session of the PC on cost capping and containment on May 24. It’s likely to cover education on types of cost containment that have been used in the industry, along with some financial analysis on how they could potentially be compared, PJM’s Sue Glatz said. Further meetings will be scheduled after that, she said.
The results of those discussions will have to be added into the manual later as amendments. PJM’s Mike Herman brought the manual for a first read last week and will be seeking endorsements at the PC and the Markets and Reliability Committee next month.
DEDS Task Force Ends at PC
Along with Manual 14F, PJM also hopes to secure approval for three designated entity design standard (DEDS) documents in time for the RTEP window. That process will likely be easier because, as Herman explained, the standards only require PC endorsement to become effective.
That unusual situation created concern for American Municipal Power representatives, who have previously questioned why PJM won’t require endorsement at the MRC.
Farber expressed concern about a designated entity agreement he had found filed at FERC that included a 3% rate escalation, which he felt went beyond the standards the Designated Entity Design Standards Task Force was developed to create.
“The designated entity agreement contains all terms and conditions, the requirements and obligations of a party who has been designed to construct a project, not just design standards,” Herling explained. “It’s far more reaching than that.”
The escalation was not pro forma and was unique to that specific project, PJM staff confirmed. The financial agreements were included, Herling said, as protection of the agreement.
“Our feeling was that those terms needed to be memorialized somewhere so that they would be to some degree at least enforceable,” he said. “People are bidding on a project with some form of cost containment. Obviously, we hope that they will then stand by that and we figured by putting it in an agreement that gets filed at FERC that there would be some teeth in it.”
Related to that topic are updates to Manual 14C that PJM is also presenting for endorsement, which focus coordination among entities constructing interconnection facilities. The negotiations could be long and laborious, but it could always be worse: AMP’s Ed Tatum asked what happens when the stakeholders can’t agree.
“We beat them with a stick,” Herling responded.
“But after that, Steve?” Tatum continued.
“We keep beating them with a stick.”
“What are the next steps?”
“It’s a bigger stick,” Herling said. “We’re confident of our ability to find a solution.”
Glatz reassured stakeholders that such measures are a last resort. “We have a long track record of coordinating with entities on both the transmission and on the generation interconnection side, and to my knowledge, we haven’t actually had to beat anybody with a stick yet.”
Tatum thanked them for the explanation and told Glatz he would relay a story about stick beating to her at another time.
“We appreciate you holding that one for later,” Herling said.
ISO-NE out of this ‘World,’ According to PJM Reserve Requirement Study
PJM has released for approval its assumptions for its 2017 reserve requirement study, and one thing PJM staff wanted to make clear is that ISO-NE has been completely removed from its calculations of the “World,” which consists of the four external systems with direct ties to PJM: NYISO, MISO, Tennessee Valley Authority and SERC Reliability’s VACAR region in Virginia and the Carolinas.
“Last year … we had New England inside of the World,” PJM’s Patricio Rocha-Garrido said. “Later on, when we ran load model selection analysis, we realized that if we keep New England in the World, then PJM and the World would be peaking on the same week, which was not consistent with what we were seeing from the historical perspective. Based on this, we introduced a change to the World load model, which switched the peaking week of the World load model.”
“I hope RTO Insider reports that PJM kicked ISO New England out of the World,” said Carl Johnson, who represents the PJM Industrial Customer Coalition.
Johnson then asked for PJM to perform a sensitivity study on what the results would be if it continued to use the commercial probability in its study. PJM doesn’t plan to adjust the megawatt rating of future generation by the commercial probability, as it has done in the past.
The assumptions will also correct what PJM sees as incorrect accounting in the past of behind-the-meter generation. No longer can BTM owners choose to be capacity resources. PJM’s Tom Falin said BTM will be reflected based on how it has impacted the metered load history over the past eight or nine years. That will be specified later this summer when the PC is asked to endorse a historical time period, he said.
“This language is just catching up to our current practice,” Falin said. “I would say the original language was wrong.”
Ramapo PAR Cost Allocation Forging New Territory
PJM’s current cost allocation construct is not applicable to the replacement of the Ramapo PARs because PJM’s JOA with NYISO points to the Northeast Protocol for most planning issues, and the protocol is an agreement that includes ISO-NE, PJM’s Chuck Liebold told the Transmission Expansion Advisory Committee last week. (See NYISO, PJM Discuss PARs’ Benefits, Cost Allocation.)
PJM is considering broadening the planning included in the JOA to include transmission facilities eligible for interregional and regional cost allocation. The current process uses an avoided-cost method, but PJM could use a solution-based distribution factor. Several other options are under consideration as well.
