New York state is proposing to invest $1.5 billion in large-scale renewable energy development over the next decade under a revised procurement strategy to reduce costs.
Without a federal production tax credit, NYSERDA’s current 20-year REC contracts for wind result in a $33/MWh premium to market prices. The premium could be reduced to about $18/MWh using utility-backed PPAs with a developer that has a relationship with a YieldCo. Utility-owned generation is estimated to have a premium of less than $27/MWh.
The New York State Energy Research and Development Authority made the proposal in a report released early this month. “The current approach has been good, but we can do better,” said Richard Kauffman, the state’s chairman of energy and finance.
Unlike most state renewable portfolio standard programs, which delegate renewable purchases to utilities, New York designated NYSERDA to act as a central procurement agency.
NYSERDA said the $1.5 billion investment is comparable to the state’s spending since it created its RPS in 2004. The programs have led to the construction of 1,900 MW of clean generation, although the RPS goal of 29% for this year will not be met.
A 32-MW project on Long Island is the only large-scale solar project in the state, according to the Long Island Power Authority. The American Wind Energy Association says New York had 1,749 MW of installed wind capacity at the end of 2014.
The report recommends several new strategies that it said would allow it to obtain renewable resources at lower costs, optimize siting of projects and extend benefits to customers.
It said long-term bundled power purchase agreements would provide developers predictable revenue streams, allowing them to obtain cheaper financing and reducing the levelized cost by at least $11/MWh. Securitizing debt and opening projects to financing vehicles such as “YieldCos” — publicly traded companies formed to own operating assets that produce a predictable cash flow — could reduce costs further.
It also invited comment on whether utilities should be permitted to bid against other developers for renewable projects, saying the competition could also reduce costs.
Procurements should take into account not just price, the report said, but also plant retirements, price forecasts and integration with storage and demand response to ensure projects are sited where they provide the greatest system and customer benefits.
It called for ways to address insufficient demand volumes, contract durations and credit supports that it said had crimped voluntary renewable purchases.
A 10-year budget commitment of $1.5 billion would stimulate investment and help renewables become self-sustaining without subsidies.
The report was filed in response to a Feb. 26 New York Public Service Commission order laying out the role of renewables under the Reforming the Energy Vision overhaul of the state’s energy industry. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)
The PSC will hold a technical conference to discuss the report, with initial public comments due July 22.
The Federal Energy Regulatory Commission last week denied rehearing in a challenge to PJM’s method of funding Financial Transmission Rights, closing a docket that had been in limbo for almost two years — and potentially clearing the decks for a unilateral rule change proposal by the RTO.
FirstEnergy had requested removal of real-time congestion costs from the calculation of transmission congestion charges, saying it would allow FTR holders to better hedge congestion.
“We continue to find that allocation of real-time balancing congestion to current FTRs has a reasonable basis, because FTR holders are in the best position to reflect the associated underfunding in the value of FTRs,” the commission wrote. “Allocation to other parties would not create any incentive to reduce real-time balancing congestion and would provide even less of an ability to provide any reflection of the value of the underfunding in any instrument.”
The commission gave no reason for the timing of its ruling (EL13-47-001) on the rehearing request, which was filed by FirstEnergy, J. Aron & Co., DC Energy, Vitol and Public Service Electric and Gas and its affiliates after the commission denied a complaint by FirstEnergy in June 2013.
But it came after just days after PJM suggested it may make a unilateral section 206 filing to break a deadlock among stakeholders over potential rule changes.
PJM’s June 2 filing with the commission noted that the FTR funding shortfall the companies had complained of had been resolved — at least for now, with FTRs fully funded since the current planning year began in June 2014.
PJM said it had addressed underfunding by being more conservative in its annual modelling of Auction Revenue Rights and FTRs, particularly the impact of transmission outages, market-to-market flowgates and loop flow.
“Thus, while FTR underfunding has been resolved for now, the consequence is that customers have experienced reduced ARR allocations,” PJM said. “PJM’s solution has therefore shifted revenues from ARR holders, through a reduction of the quantity of ARRs, to FTR holders, in the form of increased FTR funding … PJM believes that the resulting status quo is less equitable and desirable than it would prefer.”
“Redesigning the funding and allocation processes for FTRs and ARRs is fundamentally an issue of cost allocation among different classes of members. Therefore, it is unlikely that stakeholders will be able to come to consensus on a long-term solution to address PJM’s FTR design,” PJM said. “Indeed, PJM expects that in the future any significantly proposed market rule changes aimed for an improved, more efficient and equitable ARR and FTR design may have to be prompted by a filing made by PJM under section 206 of the Federal Power Act.”
MILWAUKEE — The final session of the Mid-America Regulatory Conference last week brought together top officials from MISO, SPP and PJM to discuss balancing short-term expectations with long-term planning.
“We did not know how fast the wind would develop [in the Midwest] under state [renewable portfolio standards],” said PJM CEO Terry Boston, who will be retiring later this year. “If I reflect back, a plan to build HVDC from this area of the country into the Mid-Atlantic would have been an excellent plan.”
Sam Loudenslager, principal regulatory analyst for SPP, said his region was surprised by oil shale development.
He recalled a recent tour of the Bakken region in North Dakota. “I came back telling our planners, ‘You’re not going to get it. You’re going to miss this big time because it’s growing like nobody’s business,’” he recounted.
“They’ll continue to pump as long as oil’s $35 a barrel. And if you get to the heart of the Bakken, they’re pumping at $22. And these are areas that have no transmission whatsoever.”
Richard Doying, MISO’s executive vice president of operations and corporate services, lamented that officials had not anticipated the Environmental Protection Agency’s Clean Power Plan a decade ago. “When we were doing our initial transmission planning, 111(d) was not a significant focus,” he said.
MISO asked the Federal Energy Regulatory Commission to dismiss a complaint filed last month alleging it billed more than $21 million in excessive transmission rates, saying Southern Co. and three Missouri utilities have misinterpreted its Tariff (EL15-66).
MISO transmission owners, which joined the RTO last week in asking for dismissal, were blunter, saying the utilities’ claims amount to “misrepresentations” of the Tariff.
Both maintain the utilities’ complaint is duplicative to a proceeding already underway before FERC that involves similar issues (EL14-19).
In their complaint filed last month, the utilities alleged that MISO improperly shifted and reallocated sunk costs and network upgrade costs from its legacy region in the Midwest to Entergy export customers in the South following Entergy’s integration into MISO in 2013. (See Utilities Accuse MISO of ‘Massive’ Overcharges.)
Bringing the case were Kansas City Power & Light’s Greater Missouri Operations Co., The Empire District Electric Co., Associated Electric Cooperative Inc. (AECI) and five Southern Co. affiliates: Alabama Power, Georgia Power, Gulf Power, Mississippi Power and Southern Power.
Entergy Integration
The utilities were receiving transmission service from Entergy before it joined MISO under the terms of the Entergy Tariff. When MISO succeeded Entergy as the transmission provider, they became subject to MISO’s Tariff.
Long-term, firm point-to-point transmission service rates under the Entergy OATT vs. MISO OATT.
The utilities contend that MISO’s drive-out and drive-through charges are not applicable to their transmission service reservations and that if they were applicable they should be declared unjust and unreasonable. They claim that Attachment FF-6 of the MISO Tariff provides a broad exemption for their through-and-out transaction charges. They say the allocations violate MISO’s Tariff and FERC findings that — with the exception of certain multi-value projects — point-to-point export services are provided under a no-cost-sharing rule.
Exemption Argument
In its response, MISO counters that the Tariff is clear that the utilities are not entitled to an exemption. The RTO maintains that FERC “has confirmed on several occasions” that through-and-out rates in question are applicable to transactions in the MISO South region.
“Over the past several years, the complainants have created an extensive paper trail in various proceedings, which casts doubt on their current Tariff violation claims. While the complainants have filed numerous pleadings to block and devalue the MISO South integration, those pleadings did not argue, until the instant complaint was filed, that MISO is violating the Tariff,” MISO said. “On the contrary, the complainants sought FERC action precisely because these rates were applicable.”
The RTO also said any dispute over its through-and-out rate should be resolved in the section 206 proceeding FERC initiated in February 2014 (EL14-19).
Increased Scope
MISO also said the fact that the charges may have increased does not render them unjust and unreasonable. Prior to the MISO South integration, service was limited to the Entergy transmission system. But now the utilities may redirect points of receipt or delivery on a region-wide basis, MISO counters.
“Not surprisingly, the complainants’ new charges reflect these benefits of scope, as well as many other unique benefits that a Day 2 RTO provides to its customers,” MISO said.
Finally, MISO contends that the utilities are seeking a preferential rate at the expense of other market players.
The Organization of MISO States voted last week to convene discussions on ways to improve the RTO’s stakeholder process and address friction between the RTO and some of its members.
OMS President Libby Jacobs noted that MISO has several efforts under way already, including a white paper that MISO’s Steering Committee will discuss Thursday on concerns that the stakeholder process has become “cumbersome and inefficient.” The MISO Advisory Committee has made stakeholder process improvement the “hot topic” for its October meeting.
“We certainly applaud MISO for their efforts,” Jacobs, of the Iowa Utilities Board, told OMS board members on June 11.
Richard Doying, EVP of MISO (L) and Elizabeth (Libby) Jacobs, IUB Commissioner and OMS President at MARC 2015 Annual Meeting
But she said, “We had some concerns that it didn’t appear there was a formal outreach to all the stakeholder groups to really weigh in on the process.”
OMS would convene the dialog but will likely hire an outside facilitator to moderate the discussions, she said.
The effort could help better document how the stakeholder and governance process works, look at best practices at other RTOs and help stakeholders identify priorities.
MISO’s white paper cites overlapping responsibilities among committees and insufficient focus on the most important issues as weaknesses in the current process.
Tensions
Tensions between some MISO stakeholders and the RTO have flared in recent months.
Transmission developers objected earlier this year to MISO’s approval of Entergy’s request for $217 million in out-of-cycle transmission projects in Louisiana. As out-of-cycle projects, they were excluded from competition.
The Consumer Advocates sector complained it was being disenfranchised after MISO denied its request for $200,000 in funding to help cover legal costs in a case before the Federal Energy Regulatory Commission on MISO transmission owners’ return on equity rates.
ISO-NE’s power prices dropped by more than 40% in the first quarter of 2015 thanks to lower natural gas costs, the Internal Market Monitor reported last week.
In a filing with the Federal Energy Regulatory Commission, the Monitor said a 43% decrease in the cost of natural gas from the previous year was largely responsible for the power price decline (ZZ15-4). Natural gas prices averaged $11.37/MMBtu, a drop from $19.95.
Day-ahead energy market prices averaged $84.84/MWh at the Massachusetts hub, down 41% from a year ago, while real-time prices averaged $81.97/MWh, a drop of 43%.
Also lower were real-time reserve payments (-80%), regulation payments (-56%) and net commitment period compensation payments (-67%).
Total wholesale market costs of $3.14 billion were down 41%. “Overall, market prices reflected the cost of providing energy, and energy market outcomes were competitive,” the Monitor said.
Pricing Flexibility
The IMM said generators are taking advantage of the flexibility resulting from the RTO’s Dec. 3 rule change allowing market offers to be made hourly and changed during the operating day. The energy market offer flexibility (EMOF) rule, which allows resources to respond to changes in production and opportunity costs, has been used primarily by natural gas generators.
“There has been a reduction in the volume of self-scheduling, in which generators assume a price-taking role, and to the extent to which generators vary economic minimum parameters to reach desired levels of output,” the Monitor said.
Some generators also took advantage of EMOF rules allowing them to offer negative prices to signal their desire to maintain minimum output levels.
Only hydro and wind resources offered negative prices in the day-ahead market. They were joined by some natural gas, biomass and coal resources in offering negative prices in the real-time market.
“On average, the amount of capacity offered in the real-time market at negative prices was equal to roughly 3% to 4% of load,” the Monitor said.
VALLEY FORGE, Pa. — This winter bumped aside last year’s peak load record, but PJM’s system experienced a fraction of the stress brought on by the January 2014 polar vortex. Generator outage rates, which exceeded 20% in 2014, were generally less than 15% in 2015.
Peak loads grew more gradually in Feb. 2015 than in Jan. 2014.
To figure out why, PJM researchers “did a deeper dive in different areas so we could understand the differences from last winter, and while we hit a new winter peak, why we did so much better,” Chantal Hendrzak, executive director for operations support, told the Operating Committee in presenting the 2015 Cold Weather Report.
Last year, recommendations for follow-up on winter preparedness filled pages. This year, there were five recommendations, all contained on one page.
A lot of the conversation, she said, revolved around whether this winter was colder, noting that it was most relevant to compare this past February with January 2014.
“We poked at weather in all sorts of different ways to understand what some of the differences were,” she said.
One of the findings was that while temperatures were colder this winter, the wind chill factors weren’t as severe in some areas. Including the wind chill factor, the low temperatures for Cleveland, Chicago and Columbus, Ohio, all were at least 14 degrees warmer this year.
Generator outage rates, which exceeded 20% in 2014, were generally less than 15% in 2015.
Wind chill can have more of an impact — and more quickly — on generators than temperature alone, depending on how insulated they are and if the units are not enclosed in structures, she said.
Staff also looked at the days leading up to peak loads. This year, she said, “we kind of baby-stepped into the peak load” as opposed to the large incline seen before last year’s peak.
In addition, she said, wind capability increased over the previous winter.
This winter, she said, pipelines were more proactive in making sure pressure was maintained for their firm customers, generation owners took a number of precautions to ensure their availability and more units were running on alternate fuel.
In addition to PJM’s initiatives to introduce the Capacity Performance product and improve gas-electric coordination, the new report recommended continuing efforts to improve the ability of generators to communicate their operational parameters to grid operators; building on the testing program for seldom-run units and winter preparation checklist; and continuing efforts to reduce energy market uplift.
This winter’s success led a number of stakeholders to question the need for PJM’s new Capacity Performance product, which aims to strengthen reliability by penalizing underperforming units and rewarding overperforming participants. (See FERC OKs PJM Capacity Performance Proposal; Bay Dissents.)
Hendrzak said the changes the RTO saw this winter were voluntary. “PJM believes we need a more sustainable approach, so we are continuing to move forward with CP,” she said.
Talen Energy, the merchant generation company formed by spinning off much of PPL’s generating assets and combining it with those of Riverstone Holdings, began trading on the New York Stock Exchange on June 2. The company issued shares at $20 but ended its first day at the $18.50 mark.
Trading under the symbol TLN, Talen has only hovered around $19/share through its first two weeks of trading and experienced a dip on Thursday and Friday to close out last week, finishing at $18.13/share. The company is now one of the country’s largest merchant generators, with about 15,000 MW in its fleet. Most of the assets are in PJM, along with some in ERCOT. To allay concerns from competitors, the company agreed to divest about 1,300 MW in PJM in a settlement with the Federal Energy Regulatory Commission.
Amazon.com announced that it is partnering with Community Energy Inc. to build an 80-MW solar farm in Virginia to help power its data centers in the state.
The $200 million solar farm, to be built on the Eastern Shore’s Accomack County, will be called Amazon Solar Farm U.S. East and should be operating by October 2016. When completed, the 250,000-panel solar farm will increase the state’s solar capacity by a factor of five. Virginia currently ranks 30th in the U.S. for solar capacity.
Amazon says it eventually wants to use renewable energy to power all its data centers.
DTE to Drop Renewable Energy Surcharge, Reducing Rates $15M Annually
DTE Electric has proposed dropping a 43-cent/month customer surcharge that pays for renewable energy.
Under changes in the utility’s renewable energy plan filed early this month with the Michigan Public Service Commission, DTE said the request would reduce electric rates by a total of $15 million a year. DTE also said it will be in compliance with Michigan’s renewable portfolio standard requiring electric utilities to supply 10% of their power from renewable sources.
Parent DTE Energy has a 1,000-MW renewable portfolio that it acquired from Michigan developers. DTE began assessing the renewable surcharge in 2009. Last year it reduced the charge to 43 cents from $3.
Meanwhile, DTE said it will explore the potential of a voluntary pilot program for customers who want to pay for more than 10% of their electricity from renewables.
Xcel Energy’s Southwestern Public Service last week scaled back its rate-increase request in Texas by nearly $23 million.
SPS last year filed for an annual revenue increase of $64.8 million, or 6.7%. On June 10, SPS revised its request to $42 million, or 4.4%. A number of interveners have been pressuring regulators for a rate decrease and in May the Public Utility Commission of Texas staff recommended a decrease of $2.6 million.
SPS is also seeking a waiver of PUCT’s post-test year adjustment rule, which would allow the company to include $392 million additional capital investment for the July-December 2014 period.
Duke Ordered to Stop Groundwater Contamination from Coal Ash Site
North Carolina environmental regulators ordered Duke Energy to stop one of its retired coal-fired power plant sites from polluting groundwater after tests showed heavy metals in nearby drinking water wells. The contamination, including boron, was found in three wells near the retired Sutton Steam Plant near Wilmington, N.C. Boron is an indicator of coal ash contamination.
The state gave Duke until July 9 to stop the spread of the contamination at the Sutton site. If it can’t, it could face further fines than the $25 million the state has already assessed the company in relation to leaching from the plant’s coal ash basin. Duke is appealing the fine. The company also recently reached a $102 million settlement with federal regulators concerning coal ash spills relating to the January 2014 spill at the Dan River.
North Carolina has hired a private law firm to assist it in its ongoing cases against Duke. “It is evident that Duke Energy is choosing to spend its virtually limitless legal resources to fight fines for clearly documented groundwater contamination stemming from its coal ash impoundments near the Sutton plant,” said Sam Hayes, general counsel for the state environmental department.
Fallout Grows Following Accusations Dynegy Manipulated MISO Auction
At least 16 stakeholders have filed notices at the Federal Energy Regulatory Commission to intervene in a request by a consumer group and the Illinois Attorney General for an investigation into whether Dynegy illegally manipulated MISO’s Planning Resource Auction last April.
The Illinois AG and the group Public Citizen Inc. point to a nine-fold price increase resulted in Zone 4, which includes much of downstate Illinois. (See Public Citizen to FERC: Investigate Dynegy Role.) Among those filing to intervene at FERC is the Illinois Citizens Utility Board, a public advocacy group that this week claimed that electric bills for downstate Illinois customers rose more than 10%.
Dynegy says it followed all the auction rules and the results were verified by an independent monitor.
Opponents to Exelon’s Medway Generating Plant Air Concerns at Meeting
Exelon Generation’s plan to build a two-unit, 195-MW generating station in the Boston suburb of West Medway drew opponents last week at a public information meeting.
Exelon plans to build the natural gas-fired units on the existing 94-acre site of the West Medway Generating Station, a three-unit, oil-fired 117-MW peaking station built by Boston Edison following the 1965 East Coast blackout. The oil-fired units only run about 100 hours a year, but the new gas-fired generators would operate about 14 hours a day.
Several residents said they were concerned about the plant’s needs for cooling water. According to the company, the units would need 97,000 to 197,000 gallons of cooling water each day. This would come at a time, said resident Brian Adams, when he and his neighbors “are told every day that we can’t water our lawns.”
Invenergy’s Proposed Jessup Plant Opponents Meet with Gov. Wolf
Pennsylvania Gov. Tom Wolf listened to the concerns of a small group of residents who are worried about Invenergy’s plans to build a 1,500-MW combined-cycle natural-gas plant in the Northeastern town of Jessup.
Four members of Citizens for a Healthy Jessup said the plant is being pushed through the siting and permitting process too quickly. They also expressed concerns that the plans for the plant seem to change. Wolf didn’t offer his own position on the plant.
Invenergy announced the project last November and said the site’s proximity to both the new Susquehanna-Roseland transmission line and shale gas supplies made it an attractive location. It was originally proposed to be a 1,300-MW facility. If built, it would be the state’s second-largest natural gas-fired plant, after PPL’s 1,722-MW Martins Creek plant in Northampton County.
Dominion Questions Zoning Ordinance’s Effect on Proposed Virginia Wind Energy Facility
Dominion Virginia Power is concerned that a proposed local zoning ordinance would create roadblocks to its proposed wind energy facility near Bluefield, Va. Dominion wants to build an industrial-sized wind farm on 2,600 acres it purchased near East River Mountain in 2009.
Opponents say the wind-turbine towers would ruin the view. Dominion, in a letter to Tazewell County officials, said that a recent proposed zoning ordinance change that would limit industrial expansion in the area, coupled with an existing tall structure ordinance, “significantly deters wind development” in the area.
County officials think the zoning issue could spell the end of the project. “This ordinance in my opinion is a death blow to that project,” said Charles Stacy, a member of the board of supervisors in Tazewell County’s Eastern District.
Options Limited for County Opposed to Dominion Tx Line Proposal
Orange County, Va., is considering making an attempt to block a proposed 230-kV transmission line between two rural areas near Culpeper, but the county attorney says little can be done to stop it.
Dominion Virginia Power has proposed running the line between Remington and Pratt, but local opponents fear the line would detract from the area’s scenic beauty. The alliance asked Orange County officials to see if there was a way to block the project.
County Attorney Tom Lacheney said last week that a review of existing laws and ordinances seems to indicate that Dominion will probably be successful in its attempts to build the line.
Duke Energy to Introduce ‘Swine Waste’ Gas into Plants’ Fuel Stream
Duke Energy has applied to the North Carolina Utilities Commission to buy gas produced from Midwestern swine farms for two of its North Carolina plants in order to comply with a state biofuel mandate.
Duke and other power producers say there are insufficient in-state supplies of gas produced from swine waste to comply with a state law, which mandates that 0.07% of energy be derived from pig manure. The mandate steps up to 0.2% by 2020.
The fuel would come from hog farms in Missouri and Oklahoma, where manure and other waste is deposited in a digester, which then collects the gas. The fuel would be used at Duke’s Dan River combined-cycle plant near Eden and its Buck combined-cycle plant near Salisbury.
Eight Utilities Joining Together to Form Emergency Equipment Stockpile
Eight U.S. utility companies are forming a consortium called Grid Assurance to stockpile large transformers, circuit breakers and other special equipment so they are available for emergencies. The venture will help the companies to more economically meet a Federal Energy Regulatory Commission mandate to have vital backup equipment available.
“Restoration of the transmission grid can be hampered by long lead times required to design, build and deliver” such equipment, one of the companies, American Electric Power, said in a statement. “Subscribers can call on equipment when they experience … physical attacks, electromagnetic pulses, solar storms, cyberattacks, earthquakes and severe weather events,” it said. The equipment would be stored at warehouses throughout the country.
In addition to AEP, the other companies in the program are Berkshire Hathaway Energy, Duke Energy, Edison International, Eversource Energy, Exelon, Great Plains Energy and Southern Co.
The Federal Energy Regulatory Commission on Tuesday approved PJM’s dramatic restructuring of its capacity market, saying the changes were justified by “the combination of deteriorating resource performance and the ongoing change in the resource mix in the PJM region.”
The proposal, a response to the poor generator performance during the January 2014 polar vortex, increases reliability expectations of capacity resources with a new Capacity Performance product. It is intended to result in larger capacity payments for the most reliable resources (including performance bonus payments for overperforming participants) and higher penalties for non-performers (non-performance charges).
The changes will be phased in beginning with the 2018/19 and 2019/20 delivery years, when PJM hopes to make at least 80% of capacity procured Capacity Performance, with the remainder “Base Capacity” subject to lower performance expectations. The transition will be complete for 2020/21, when PJM expects 100% of capacity to be Capacity Performance resources. PJM also is changing energy market rules regarding operating parameters, force majeure and generator outages under a “no excuses” policy.
PJM’s Board of Managers filed the proposal Dec. 12 following its first-ever “enhanced liaison process,” under which it accepted comments on the proposal but made no attempt to reach stakeholder consensus.
Although it rejected some of PJM’s related proposals for changes to the energy market, the commission otherwise approved the RTO’s changes with only limited modifications (EL15-29, ER15-623). (See related story, What is Changing in PJM’s Proposal?)
The commission cited evidence of increased generator forced outage rates since 2007, saying that capacity resources “are not being properly incented to make the investments required to perform reliably, including during extreme weather conditions.”
(Click to zoom.)
It accepted PJM’s prediction that resource performance will continue to worsen without changes as the RTO sees much of its coal fleet retire, replaced largely by natural gas-fired generation.
The commission rejected the arguments of opponents who said the changes were not necessary because generator performance improved last winter following more modest changes, including testing of seldom-used units.
“While encouraging, this does not assuage the long-term reliability concerns raised by historical unit performance,” the commission said. “Moreover, it is not uncommon for performance to improve after an event, only to trail off later. PJM has shown that, although its capacity market construct has been successful in procuring commitments three years in the future, it has not been successful in ensuring that resources actually perform when called upon.”
Stocks for PJM’s largest generators traded higher Wednesday following news of the ruling. Dynegy’s share prices jumped almost 9%, while NRG Energy and Exelon prices rose about 4%. As of Monday morning, NRG Energy had given back most of its gain, up 1% from before the order.
Bay Dissents
Chairman Norman Bay issued a stinging dissent, raising objections that are likely to be cited in any court challenges. Bay said the proposal will continue to allow generators to profit from poor performance while potentially saddling ratepayers with billions in excessive capacity costs annually.
“The majority today accepts a flawed, complex, highly technical market construct in which there is a potential mismatch between incentives and penalties [and] in which mitigation has largely been eliminated in a market characterized by structural non-competitiveness,” he wrote. (See related story, Bay’s Dissent: ‘Two Carrots and a Partial Stick.’)
PJM CEO Terry Boston, attending the Mid-America Regulatory Conference in Milwaukee, said he was “very pleased” by the ruling.
Exelon also applauded the ruling, saying it “will result in hundreds of millions of dollars in investments across the PJM fleet to harden power plants to operate — and reduce outages — during extreme weather.”
America’s Natural Gas Alliance, which represents independent exploration and production companies, said it was happy that the order provides way for combined-cycle generators to recover costs for securing fuel and investing in infrastructure.
Ruth Price, deputy Delaware Public Advocate, said the changes are unnecessary. “Last winter shows that we can get by without CP,” she said. “Clearly it’s going to be a cost burden on” ratepayers.
Dan Griffiths, executive director for the Consumer Advocates of PJM States, said the group was reviewing the order and had no immediate reaction.
Two Dockets
PJM made its proposal Dec. 11 in filings that totaled nearly 1,300 pages in two dockets.
One, EL15-29, filed under sections 205 and 206 of the Federal Power Act, contained proposed changes to PJM’s Operating Agreement and Tariff to correct “deficiencies” regarding resource performance in PJM markets.
FERC responded with a deficiency notice March 31 questioning 10 areas of the proposal. PJM’s answers largely satisfied the majority, although FERC’s order required the RTO to make a compliance filing within 30 days incorporating changes on some details.
Base Residual Auction
The new rules, which will be phased in over five years, will be reflected in the Base Residual Auction for the 2018/19 delivery year, which will begin Aug. 10.
“We are obviously still digesting the order,” senior vice president for operations Mike Kormos told the Market Implementation Committee on Wednesday. But he said he saw nothing in the ruling that would keep PJM from going ahead with the BRA as planned on Aug. 10.
“We fully expect to make the compliance filings as we were directed,” he said. “We will do that within 30 days, sooner if we can.”
Manual changes to accommodate the new product will be discussed at a special meeting of the Markets and Reliability Committee being planned for June 18, time and location to be announced.
Training will be held June 24, and the MRC will be asked to endorse the manual changes June 25.
PJM also released a schedule for deadlines leading up to the BRA.
Need for Change
FERC agreed with PJM that current capacity rules subject poorly performing resources to minimal penalties, placing most of the risk of under-performance on load. During the 2013/14 delivery year such penalties totaled less than $39 million, 0.6% of total capacity revenues. “Without more stringent penalties, PJM has shown there is little incentive for a seller to make capital improvements or increase its operating maintenance for the purpose of enhancing the availability of its unit during emergency conditions,” FERC said.
PJM’s rules also limited capacity resources’ ability to recover costs needed to improve performance, allowing recovery of capital costs for dual-fuel capability but denying expenses for natural gas firm transportation contracts.
“PJM has shown that its existing payment features not only inadequately incent resource performance, but may perversely select less reliable resources over more reliable resources because a capacity seller’s decision to forego investments that would improve resource performance allows it to offer in PJM’s capacity market at a lower price and be paid the clearing price while providing less reliable service,” FERC said.
The commission was not persuaded by opponents who argued that PJM could provide incentives for improved performance through changes to energy and ancillary services rules. “For example, although better alignment of electric market and natural gas pipeline scheduling deadlines would improve operations, it would not provide capacity market sellers the incentive to perform,” it said.
Fixed Resource Requirements
Although some intervenors argued that Fixed Resource Requirement entities are already subject to strong performance incentives from state regulators, the commission approved PJM’s decision not to exempt them from Capacity Performance penalties. “While Fixed Resource Requirement entities do not procure their capacity commitments through PJM’s capacity auctions, the ability of these resources to perform is equally critical to system reliability,” the commission said. It rejected an argument by the Organization of PJM States Inc. (OPSI) that PJM’s proposal infringed on state authority by effectively eliminating states’ choice to opt out of the capacity auction process.
The commission did, however, require PJM to modify how it calculates penalties for FRR entities.
Eliminating 2.5% Holdback
FERC approved PJM’s controversial proposal to eliminate its 2.5% capacity holdback effective with the Base Residual Auction for delivery year 2018/19. PJM said the change, which the Market Monitor has long urged, will ensure that it has obtained committed capacity and is not reliant on short-term procurement.
The commission rejected consumer groups’ contention that the holdback should be retained as a counter to PJM’s consistently overstated load forecasts. “We are not persuaded that a holdback requirement is necessary to address load forecast errors, or that the historical overstatements experienced to date are unavoidable or likely to recur at a level that requires mitigation,” the commission said.
It also rejected the Pennsylvania Public Utility Commission’s argument that the holdback is necessary to incent demand resources’ participation, saying it was “not convinced that the benefit of any incremental demand resource participation resulting from retaining the holdback requirement will necessarily outweigh the economic efficiency benefit of no longer withholding demand from the Base Residual Auction, an action that can suppress market clearing prices.”
Force Majeure
FERC approved PJM’s changes to its force majeure rule, under which a resource will be excused for non-performance only “in the event that all, or substantially all, of the electric transmission or fuel delivery infrastructure in the PJM region is incapacitated.”
“Without a replacement provision narrowing the reach of a force majeure event to excuse performance only in the most unforeseen and catastrophic circumstances, a market participant would be able to escape its obligations under circumstances not contemplated by the design of PJM’s markets,” the commission said.
FERC rejected arguments that the new definition was too narrow. “The risk of capacity resource non-performance must be borne by either capacity suppliers or consumers, and capacity suppliers are in the best position to assess and price the performance risk associated with their resources, including performance risks beyond a resource owner’s control, such as weather-related outages,” it said.
Accommodations to Demand Response
FERC approved PJM’s proposal to replace its current demand response products with an annual product that meets Capacity Performance requirements. Most of PJM’s current DR is available only in summer, including limited DR, which is available for only six hours daily up to for 10 days.
The commission required PJM to modify its proposal consistent with its response to the deficiency notice, which clarified that storage, intermittent resources, energy efficiency and DR may submit capacity offers based on their average expected output during peak hours.
FERC said it was permissible for PJM to allow such resources to make offers based on aggregate capacity while limiting traditional resources to unit-specific offers.
“The aggregated offer allowance is designed to provide an avenue to Capacity Performance participation by resources that otherwise may be unable or unwilling to participate on a stand-alone basis because no reasonable amount of investment in the resource can mitigate non-performance risk to an acceptable level,” the commission said. “Generally speaking, other resource types do not face this same limitation.”
The commission rejected the Market Monitor’s complaint that PJM’s proposal discriminated in favor of DR.
The Monitor contended that DR resources should have their output metered in five-minute intervals rather than estimated and be dispatched nodally to ensure that all capacity is performing as required. The commission said PJM’s concessions are “minor but reasonable accommodations” that allow DR to participate in the capacity market.
FERC also rejected the Monitor’s contention that DR should be subject to a must-offer requirement in the day-ahead energy market. The commission said PJM’s plan to exempt intermittent resources, storage, energy efficiency and DR from the must-offer requirement was reasonable because “they do not raise the same physical withholding concerns as do existing generation resources because their ownership is not concentrated.”
Increased use of renewable energy will depress energy prices, increase capacity prices and lead to early retirement of some baseload plants, according to a discussion paper by ISO-NE.
Conceptual illustration of potential transmission for 12,000 MW wind scenario. (Click to zoom)
The RTO said renewables’ low operating costs, combined with state and federal subsidies, reduce the energy market clearing prices, requiring competing traditional resources to make up that shortfall in the capacity market.
“State subsidies for renewable resources will put downward pressure on energy market prices, but this action is not without consequences: it will put upward pressure on prices in the capacity market. The capacity market will help balance the revenue needs for resources as the energy market provides fewer opportunities for resources to recover their fixed costs,” the paper says.
In 2014, the region’s 800 MW of wind power produced nearly 1% of its electricity. Solar penetration had reached 900 MW at that time, with projections of nearly 2,500 MW by 2024.
Developers have proposed 4,000 MW of additional wind power, with studies suggesting 12,000 MW of onshore and offshore wind could supply a quarter of the six states’ electricity needs.
Increased renewables are expected to impact technology choices, even as the region continues its inexorable march to natural gas, which accounts for about half of New England’s power generation. “That might mean a shift from gas-fired combined cycles toward gas-fired peaking resources,” the report said.
A decrease in energy revenues may cause combined-cycle generators — which expect to earn double the energy and ancillary market revenue of a combustion turbine — to become less competitive. At the same time, more gas peakers will be needed to provide additional reserves as the penetration of intermittent renewables grows.
Baseload Coal and Nuclear
The report said renewables will put the most pressure on baseload coal and nuclear units, noting that Entergy cited low energy market revenues in closing Vermont Yankee.
“With the expected increased penetration of renewable resources, more such retirements should be expected in the future. For example, at current energy and capacity prices, nuclear units might earn almost 10 times more revenue from the energy market than they earn from the capacity market. Modest changes in energy market revenues could have large impacts on the bottom line of a nuclear unit or baseload coal unit. This may be especially true for nuclear units, which have very high fixed operating costs and typically operate at very high capacity factors.”
No Changes Recommended
Nevertheless, ISO-NE said it does not believe its market rules need to be changed to accommodate these developments. It previously noted that higher capacity prices in recent auctions attracted new generation resources into the region. (See Prices up One-Third in ISO-NE Capacity Auction.)
“In the medium- to long-term, the capacity market will enable the region to achieve necessary levels of resource adequacy and resource performance while transitioning toward a system with greater levels of renewable resources,” the report concludes.
