New York’s winter electricity prices are expected to average about 9% lower than last year’s, the staff of the New York Public Service Commission said on Thursday.
In a presentation to the commission, staffers said market conditions would benefit from better preparation and other practices refined over the past two winters, as well as from lower natural gas prices that have also influenced other eastern U.S. markets.
“We have adequate resources to meet the needs of the utilities … while we’re also looking at lower commodity prices,” said Raj Addepalli, managing director for utility rates and services at the PSC.
For example, at the New York Mercantile Exchange, futures prices for electricity in the New York City, Hudson Valley and Western New York zones range from about $11 to $23/MWh lower than they were a year ago. New York City futures prices averaged $91.06/MWh a year ago, while that same contract now averages $67.94.
The PSC said utilities and the commission have instituted a series of “lessons learned” procedures that grew out of the polar vortex two years ago. Plants have increased their capacity for on-site fuel storage, especially in eastern New York, and state officials have implemented an expedited procedure to obtain permits from the Department of Environmental Conservation to allow fuel-oil burning.
“Terry Boston’s service to PJM and stakeholders has set a high standard,” board Chairman Howard Schneider said. “The board and I are confident that Andy will continue to ensure the stakeholder collaboration and outstanding performance for which PJM is known while establishing his own visionary leadership.”
“There’s a lot of things that make Terry exceptional, not the least his humility,” said FERC Commissioner Cheryl LaFleur, a luncheon speaker at the event Monday. “He has a rare combination of technical expertise — no matter what you’re talking about: everything from transformers to transmission planning to market planning — and people leadership skills.”
Ott’s previous role was as PJM’s executive vice president of markets. An 18-year veteran with the RTO, Ott was responsible for implementing LMP, financial transmission rights, the day-ahead energy market and capacity market.
Prior to joining PJM, he worked for GPU Inc. in transmission planning and operations.
He is a board member of both PJM Technologies and PJM Environmental Information Services. He also serves on the board of directors for the Association of Power Exchanges and chairs the Study Committee on Electricity Markets and Regulation for Paris-based CIGRE (International Council on Large Electric Systems).
He received his bachelor’s degree in electrical engineering from Pennsylvania State University and his master’s in applied statistics from Villanova University. Ott is an Institute of Electrical and Electronics Engineers fellow.
FERC last week denied Champion Energy Marketing’s request for a $3.1 million refund in PJM uplift charges related to the polar vortex of January 2014 (EL15-46).
Texas-based Champion, a load-serving entity, paid about $3.8 million in real-time balancing operating reserve (BOR) charges that it said it should not have been assessed because it had covered nearly 100% of its load for that month through forward contracts. Champion requested a refund of $3.1 million plus interest. The retail energy provider, a Calpine company, operates in Illinois, Pennsylvania, Ohio, New Jersey and Maryland in PJM.
It also asked that Tariff provisions governing BOR charges and allocations be amended, saying they were unjust and unreasonable “because it allocates BOR costs for reliability to all load when these costs should be allocated to market participants that were short supply.”
The commission disagreed. “Despite the fact that Champion was long on an aggregate daily basis, as a load-serving entity with real-time load, Champion participates with other customers as part of an integrated grid and therefore relies on PJM to assure that its transactions can be delivered as scheduled,” it said.
Commissioner Philip Moeller dissented in part. “Allowing PJM’s current BOR cost allocation to continue harms market participants like Champion and decreases the efficiency of PJM’s markets. Allocating costs broadly to load-serving entities like Champion unfairly frustrates their efforts to hedge their positions; it does not ensure that the market participants who actually caused those uplift costs pay corresponding charges.
“The fact that Champion benefits from grid reliability does not indicate that their actions caused the uplift costs it was forced to bear,” he continued. “Champion and other load-serving entities should only be allocated uplift costs on the basis of those benefits when the parties who caused those costs cannot be identified.”
PJM said its operators responded appropriately to the extreme weather conditions and accompanying outages and that Champion’s charges were consistent with the Tariff and how other LSEs were assessed.
It did note that Champion was allocated $2.8 million in real-time BOR reliability charges in January 2014 incurred as a result of actions taken by PJM’s operators during the operating day that were “uneconomic but nonetheless needed to maintain the reliability of the PJM transmission system because physical, real-time load benefitted from the reliability provided by these operator decisions.”
Uplift payments for all of 2014 totaled $964.7 million, according to the Independent Market Monitor’s State of the Market report.
PJM acknowledged there was room for improvement in reducing uplift but pointed out that it was able to capture 98.1% of all system operating costs in 2014, leaving only 1.9% for BOR charges.
The Independent Market Monitor agreed that Champion’s request should be denied but said the company did have a legitimate grievance that indicated the need for further reform of capacity market rules.
WASHINGTON — FERC last week issued a final rule to clarify and streamline its market-based rate (MBR) program, the first major update to the policy since codifying it in Order 697 in 2007 (RM14-14).
The changes are intended to increase transparency by, for example, requiring that asset appendices in MBR filings be submitted electronically so that they are searchable and sortable. MBR sellers will also be required to report all long-term firm purchases of capacity and energy that have associated long-term firm transmission.
FERC, however, eliminated some requirements in an effort to streamline the program. For example, MBR sellers will no longer be required to file quarterly land acquisition information for new generation sites. They will also no longer be required to report behind-the-meter generation in their asset appendices.
The commission issued its Notice of Proposed Rulemaking for the changes in June 2014. The final rule did not adopt the NOPR proposal to relieve MBR sellers in RTOs and ISOs of the obligation to submit horizontal market power screens, but FERC said it might reconsider this in the future. (See FERC to Revamp MBR Rules.) Commissioner Colette Honorable credited this to stakeholder feedback on the NOPR.
FERC Denies PNM MBR Authority
In a related order, FERC rejected Public Service Company of New Mexico’s (PNM’s) request for MBR authority in its balancing authority area (ER10-2302).
The company’s August 2014 request relates to its purchase of Delta Person, the owner of a 132-MW gas-fired power plant in PNM’s balancing authority. PNM sought to reinstate its MBR authority because, it said, market characteristics in its balancing authority area had changed since it relinquished its MBR authority in 2010.
FERC questioned the data with PNM’s application, including the simultaneous transmission import limit (SIL) study values included in its market power analysis. The study is performed by simulating an increase in generator output in one area, the export area, and a decrease in output in the area under study.
FERC found that PNM had improperly decreased output from plants with long-term firm transmission reservations, which are exempt from scaling in the study. As a result, the commission said that PNM’s values were invalid and that its analysis failed to rebut the presumption of horizontal market power in its balancing area.
FERC emphasized in its order that many companies used incorrect information in their market power analyses.
“We take this opportunity to remind applicants seeking initial market-based rate authority or seeking to retain such authority of the type of information and analysis that is useful and appropriate for our consideration of a delivered price test (DPT) and what is not,” the commission said in its order. “We are providing this information not only to PNM but to industry broadly with respect to several issues that arose in our review of the DPT analysis and SIL study prepared by PNM.”
“PNM was just the lucky person we chose to use their order as the vehicle to deliver this guidance,” Commissioner Cheryl LaFleur said at FERC’s open meeting Thursday. “I hope that the guidance will be helpful to applicants to make their application processes smoother and faster in the future.”
Honorable agreed. “Our intention certainly wasn’t to single out PNM,” she said.
LITTLE ROCK, Ark. — SPP and its stakeholders began trying to put their arms around the massive task of Clean Power Plan compliance last week, debating the pros and cons of mass-based versus rate-based compliance, a reliability safety valve and how best to involve themselves in the compliance process.
The goals of SPP’s Clean Power Plan Review Task Force — a name so unwieldy its chairman repeated it slowly to avoid stumbling over the words — are to develop policies and recommendations to SPP’s Strategic Planning Committee, including the development of educational materials for environmental agencies and SPP’s members and Regional State Committee. The task force will also provide comments to the Environmental Protection Agency on its Federal Implementation Plan, which the agency would apply to the states that fail to file their own plans by the 2018 deadline.
Rate vs. Mass
The task force delved into a recent staff survey of members that asked whether they preferred a rate-based or mass-based compliance approach, along with the pros and cons of each. Twelve of the 20 respondents said they preferred a mass-based approach or identified its advantages, with only one preferring a rate-based approach.
Nickell, SPP
SPP Vice President of Engineering Lanny Nickell said the survey identified two ideas that have a broad consensus: 1) a robust emission-trading program is “paramount” no matter which compliance approach a state chooses; and 2) states should develop their own implementation plans, rather than be subject to the FIP, which will have less flexibility.
Those who indicated they favored the mass-based approach said it was due to its flexibility in accommodating various generation technologies, its ease of monitoring and its consistency with other current emission-compliance approaches and mechanisms.
Other comments in favor of a mass-based approach said it would likely lead to a more robust allowance trading program, and that trading between mass-based states could be accomplished using established criteria from similar programs. Emission-allowance prices would be more easily reflected in wholesale energy prices than emission rate credits, they said.
“The survey was good,” Nickell said. It “at least gave us a preliminary feel.”
Nickell, who is leading the RTO’s CPP compliance efforts, said a trading-ready approach is gaining favor as a way to reach compliance.
“But if a few states go one way and the rest go the other way, those few states may have trouble trading,” he said. “It’s my understanding they’re not compatible. If you have a rate-based state, you can’t trade with a mass-based state.”
Reliability Still a Concern
SPP staff also shared a qualitative assessment of the proposed FIP, with Director of System Operations Sam Ellis pointing out that EPA will consider comments about providing for a reliability safety valve for mass-based plans. For example, he said the proposed FIP does not factor generating units’ need to run for reliability reasons when allocating allowances.
Ellis said EPA believes the need for the safety valve is “highly unlikely” but possible for states with “inflexible requirements on specific” generators.
“The EPA believes most events would be short duration and that emissions standards will not require adjustment,” Ellis said.
Xcel Energy’s Lauren Quillian questioned that assumption. “The EPA is essentially making the argument that trading will solve everything,” she said. “But why not have a reliability safety valve?”
Ellis said staff believes that while some form of a reliability backstop would be beneficial, the roles of FERC, EPA and the Energy Department should be clarified in the event of unforeseen disasters.
Regional Compliance
The qualitative assessment not only reiterated that a mass-based approach has more advantages than a rate-based approach (more liquid trading markets, better planning assumptions, easier measurements and verification, etc.). It also indicated consistent plans among SPP’s states would benefit reliability, particularly those that allowed interstate trading of allowances or credits.
Nickell said SPP continues to involve itself as the states in its footprint begin to discuss their approach to CPP compliance. The RTO introduced itself to air regulators last month with a webinar on the plan and its reliability implications, and it has participated in meetings with Missouri, Kansas and Minnesota regulators and legislators. (See SPP to Push Regional Approach in First CPP Webinar.)
“They’re really appreciating the individual nature of how we can help them,” Nickell said. “We want to ensure what the states do doesn’t disrupt the regional energy market.”
There was some disagreement, however, about whether to involve states outside of SPP’s footprint in the compliance process.
“Are there any benefits to working with regions next to ours?” Golden Spread Electric Cooperative’s Mike Wise, the task force chair, asked the group.
“We have a big enough problem already, so no, not at this time,” Richard Ross of American Electric Power replied.
“I think it’s really important to get together with MISO,” said Steve Gaw, SPP policy director for The Wind Coalition. “The states are going to do what’s best for the state. They don’t care whether [the RTOs] are part of one state or the other.”
The task force met after the SPC unanimously approved modifications to the group’s scope, expanding the group’s size from five members to seven (though open participation is welcomed).
The task force is composed of Wise, Burton Crawford (KCP&L Greater Missouri Operations), Dennis Florom (Lincoln Electric), Dale Niezwaag (Basin Electric Cooperative), Wayne Penrod (Sunflower Electric Cooperative), Quillian and Ross. Each of SPP’s 14 states is represented by a member.
LITTLE ROCK, Ark. — SPP’s Markets and Operations Policy Committee began discussions last week on how the RTO will distribute the funds it receives from MISO under the settlement in their long-running transmission dispute, announced just hours before its meeting.
MISO will pay SPP and six independent transmission owners $16 million to settle all claims of compensation from Jan. 29, 2014, to Jan. 31, 2016. SPP will receive 60% of the total, while the remaining 40% will be disbursed to the independent transmission owners. (See related story, SPP, MISO Reach Deal to End Transmission Dispute.)
David Kelley, SPP’s director of interregional relations, said that because the funds are not being collected under the Tariff, SPP will have to make a filing with FERC setting rules for its portion’s distribution to its members. Kelley said staff and parties to the settlement have determined that the payments should flow through to the benefit of SPP load.
“The money could start flowing in March 2016,” Kelley said. “We’ve had some conversations with members as a part of the settlement process, but we don’t have any provisions set up yet.”
Kelley said the majority of SPP transmission-owning members that were part of the settlement negotiations favor a 100% flow-based approach. Some stakeholders disagreed, suggesting a 100% load-ratio share approach or a 50-50 annual transmission revenue requirement/flow-based approach.
“We’re all in this together when it comes time to build transmission, but we seem to lose sight of that when it comes time to distribute the revenue,” said Dennis Florom of Lincoln Electric System.
Kelley said the general consensus is to develop a new settlement-specific Tariff schedule addressing revenue distribution. It would include a requirement that revenue be credited to benefit all customers taking SPP transmission service in the same manner in which point-to-point revenue is credited.
“We thought the revenues should be distributed on the same basis the service was granted,” Kelley said. “But this is a conversation we needed to have.”
He added, “I would not want to diminish what I think is a very significant victory.”
South Central MCN’s Noman Williams, chair of the MOPC, agreed.
“Let’s not lose sight of this victory by squabbling over who gets the dollars,” he said. “It all goes to the customers.”
FERC declined last week to rehear a 2013 order approving PJM’s revisions to a rule designed to mitigate buyer-side market power in the capacity market.
PJM in 2013 proposed narrowing the list of resource types to which MOPR would apply, eliminating the unit-specific review process and establishing categorical exemptions for competitive entry and self-supply resources.
That, PJM said, would create a better defined and transparent process for granting MOPR exceptions, while addressing concerns from market participants about competitiveness in the 2012 capacity market auction.
FERC accepted the exemptions but ordered that PJM retain its unit-specific review process.
The order was challenged by stakeholders including NRG Energy, state consumer advocates, the PJM Power Providers Group (P3), the Illinois Commerce Commission, Calpine and FirstEnergy.
‘Flawed’ Process
Calpine said FERC was mistaken in requiring PJM to retain the unit-specific review because the commission had acknowledged in the 2013 order that it was “flawed.” FERC said it had acknowledged that the process “warranted additional stakeholder review and the consideration of certain enhancements.”
Nevertheless, it said “we cannot conclude, based on the record before us, that review of individual units’ costs and revenues is an unjust and unreasonable method of determining rates. To the contrary, the commission noted in the May 2013 order that, based on PJM’s assessment, the clearing prices in PJM’s capacity auctions held during the period in which the unit-specific review process has been in effect have been just and reasonable.”
Exemption for IGCC Units?
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The ICC said FERC erred in allowing PJM to subject integrated gasification combined-cycle generators to the MOPR because they require long development times and thus incur significant sunk costs prior to their participation in capacity auctions, making them unlikely to suppress capacity prices.
The commission responded by citing PJM’s “concerns regarding the ability to eliminate the gasification component of an IGCC plant such that the project originally planned as an IGCC plant could become a combined-cycle plant.”
“Based on these concerns, we continue to find the relevant characteristics of an IGCC resource justify their inclusion in the MOPR, consistent with PJM’s treatment of other natural gas-fired units,” FERC said.
Discrimination Against Competitive States Alleged
The commission also rejected a complaint by consumer advocates that the MOPR is discriminatory because generation in restructured states is not eligible for the self-supply exemption and because the competitive entry exemption qualification requirements are more stringent than those for self-supply in traditionally regulated states.
The commission accepted PJM’s proposal to exempt new entry projects developed through a state-sponsored or mandated procurement process as long as that process was competitive and non-discriminatory. FERC gave no ground in its new order, saying the differences between the eligibility requirements for the competitive entry and self-supply exemptions were not discriminatory.
“Both the competitive entry and self-supply exemptions are tailored to ensure that merchant resources that have no incentive to artificially suppress capacity prices are able to offer into the capacity auction at prices that are not subject to mitigation,” it said.
Self-Supply Concerns
FirstEnergy worried that the self-supply exemption could be gamed. NRG argued that the self-supply exemption “will result in a large number of new power plants being built by vertically integrated utilities and public power entities, the effects of which will suppress market clearing prices.”
“We disagree,” the commission responded. “With properly calibrated [net short and net long] thresholds, PJM’s self-supply exemption will not operate in a manner that encourages uneconomic entry and thus will not artificially suppress market clearing prices.”
FERC last week issued two orders reaffirming earlier rulings on MISO’s disputed system support resource agreement with Illinois Power’s Edwards Unit 1 generator in Peoria, Ill.
The SSR agreement took effect in January 2013 to keep the Edwards unit operating to address thermal and voltage problems until transmission upgrades can be completed in December 2016. Dynegy’s Illinois Power unit acquired the plant from Ameren in December 2013.
In the first order, the commission affirmed its July 2014 finding that a generator should be allowed to recover its fixed costs through a full cost-of-service rate when it is forced to continue operating for reliability reasons (EL13-76-001, et al.).
MISO industrial customers and the PJM Market Monitor challenged the 2014 order, arguing that uneconomic generators targeted for retirement are not recovering their fixed costs from the market and should not receive a “windfall” because they are needed for reliability. (See PJM IMM Questions MISO Cost Recovery Ruling.)
The commission saw it differently. “Although a retiring generator may view undepreciated costs as being sunk and may write-off any loss at the time of retirement, the fact remains that MISO has the ability to unilaterally delay this decision,” FERC said. “During this delay, an SSR unit owner is providing utility service, and … when a generator is required to provide utility service, it should be permitted to recover costs beyond going-forward costs.”
Last week’s order also affirmed the commission’s earlier ruling that the Federal Power Act prevents the commission from providing retroactive cost-of-service recovery. The order left the commission’s previous rulings regarding Edwards’ 2013 and 2014 costs unchanged.
In the second order, FERC denied requests for rehearing of the commission’s March 31 order that renewed Edwards’ SSR agreement for one year through 2015 (ER15-943-002, et al.).
Hoosier Energy Rural Electric Cooperative, Illinois Municipal Electric Agency, Prairie Power, Southern Illinois Power Cooperative and Wabash Valley Power Association sought rehearing on the basis that MISO needed to conduct a new reliability analysis to re-evaluate the need for Edwards as an SSR unit. The companies contended MISO’s 2013 analysis may be out-of-date. FERC agreed with MISO that there were “no significant changes” that would necessitate a new analysis.
BALTIMORE — Former Environmental Protection Agency official Jeff Holmstead says he hasn’t made predictions on how the courts will rule on previous environmental rules affecting the electric industry.
But Holmstead, former EPA assistant administrator for air and radiation, says he’s very confident that the agency’s new carbon emission rule, the Clean Power Plan, will not live long enough to be implemented.
“I have not been out there predicting any of the other rules would be struck down,” said Holmstead, now a lobbyist for utilities and the coal industry, during a panel discussion that opened the Organization of PJM States Inc. annual meeting last week.
“I had my concerns about [the Mercury and Air Toxics Standards]; I had concerns about [the Cross-State Air Pollution Rule]; but I was pretty confident they would be upheld in court. … But this rule is completely different from anything that EPA’s ever done before. … If this gets to the Supreme Court, there are right now almost certainly five justices that would vote to overturn it.”
Although the court has said EPA can regulate CO2 emissions, Holmstead said, the agency must do so by setting an emission rate based on the best technology available. “It cannot require an existing source to go out and pay another entity to do something else that has nothing to do with the particular plant,” he said.
“The only program I think that would clearly withstand judicial scrutiny would be an inside-the-fence line, efficiency-based approach. The reason EPA didn’t do that is because it doesn’t get you very much,” he said. “The reason they’ve taken this big, legally vulnerable step is because that’s the only way they thought they could get meaningful reductions.”
Holmstead — who served in both Bush administrations and now lobbies for Arch Coal, Southern Co. and Duke Energy as head of the environmental strategies group at Bracewell & Giuliani — is hardly a neutral observer. He is loathed by environmentalists, with Greenpeace labeling him “King Coal’s Mercury Pollution Lobbyist.”
But none of the other members of the panel — which included PJM’s Mike Kormos and officials from Exelon, American Electric Power, the American Wind Energy Association and the Southern Environmental Law Center — challenged Holmstead’s legal analysis, although some questioned his prediction that a Supreme Court ruling could come by the end of 2017.
(At a conference in Washington Tuesday, EPA Associate Assistant Administrator Joseph Goffman said the rule’s building blocks – which include increased dispatch of natural gas plants and renewables – “reflect what states and utilities told us was the ‘Best System of Emission Reduction.’”)
Holmstead pointed to four dates that will determine the rule’s fate:
In the first quarter of 2016, he said, a decision is likely by the D.C. Circuit Court of Appeals on requests for a stay (highly unlikely, he acknowledges).
The next milepost will be the 2016 presidential election. “The [EPA] administrator and the administration have been telling people around the world that once this regulation is finalized it will be very hard for anyone to change it. It becomes a part of the law and what’s done is done,” he said.
“There are some rules that are very difficult for a new administration to change, for legal reasons or practical reasons. But this is not one of those regulations. So I can say with some confidence that if there is a Republican administration … the rule will fairly quickly be revoked.”
Holmstead sees a D.C. Circuit court ruling on the merits of the rule by the end of 2016 because the Obama administration has said it wants to defend it before the president leaves office.
Because of the expedited schedule, a Supreme Court ruling could come by the end of 2017, he said, though others say 2019 is a more realistic timeline.
And if the rule is thrown out?
“At that point we’re probably all back on Capitol Hill talking about legislation,” he said. “And the good thing about legislation of course is that it really does provide you much more certainty.
“The fact that EPA will ultimately likely regulate [carbon] regardless of how this rule comes out doesn’t tell you very much about your future investment decisions. Because you just don’t know if EPA can do anything that’s at all aggressive.”
ERCOT last week released an updated analysis of the Clean Power Plan’s impacts on the Texas grid’s reliability, saying the Environmental Protection Agency’s final rule could result in the retirement of at least 4,000 MW of coal-fired generation, beginning as soon as 2022.
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Warren Lasher, ERCOT’s director of system planning, said while the 4,000 MW represents only 6 to 7% of the grid’s total generation reserves, losing that capacity in too short of a timeframe would threaten the target reserve margin (13.75%).
“Coal retirements may happen sooner if owners have to make capital investments to comply with other plans,” Lasher said, noting the current reserve margin is 16%. “One of our concerns is the potential for all the units to retire in too short period of time.”
ERCOT said the changes could also increase retail power prices by up to 16% by 2030, based on an increase in the marginal price indicator. That doesn’t include the costs of new transmission projects or other investments that could be needed to support compliance.
“Unit retirements may lead to reduced reliability of the system in localized areas, as new transmission lines will be needed to connect customers to new generating,” Lasher said, noting it takes about five years to build transmission lines in Texas.
ERCOT’s analysis considers the CPP’s effects based on mass-based approaches to achieve the region’s emissions targets by modeling four scenarios:
Baseline: reflects current trends in the ERCOT region and market while considering announced retirements and current regulatory requirements;
CO2 limit: considers a system limit on emissions that allows the model to select the lowest-cost resource option without regard to market design or other considerations associated with implementation;
CO2 price: estimates a price for CO2 emissions that would cause the ERCOT region to achieve the compliance targets; and
CO2 price/regional haze: also estimates a CO2 price, but models the combined impacts of the CPP and the proposed Regional Haze Federal Implementation Plan within the ERCOT region as well.
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ERCOT’s 4,000 MW of coal retirements would increase to about 4,700 when regional-haze requirements are taken into consideration.
“ERCOT focused on high-level reliability concerns, consistent with our reliability role in Texas,” Lasher said.
The scenarios that take into consideration a CO2 price indicate more than 14,000 MW of utility-scale solar, 9,000 MW of wind capacity and nearly 3,000 MW of new gas-fired combustion turbines would have to be added to achieve compliance.
“Integrating intermittent renewables can be a challenge,” Lasher said. “Increased storage capabilities on the system would increase its ability to integrate renewables … that would be an additional tool.”
The ERCOT study only looks at the 85% of the state it is responsible for, leaving out East Texas, the Panhandle and El Paso areas.
In a presentation to the commission, staffers said market conditions would benefit from better preparation and other practices refined over the past two winters, as well as from lower natural gas prices that have also influenced other eastern U.S. markets.
