PJM’s Capacity Performance plan approved by the Federal Energy Regulatory Commission borrows elements from ISO-NE’s Pay-for-Performance program. Below is a summary of some key differences between the two plans followed by the relevant paragraph numbers from the order.
ISO-NE’s ninth Forward Capacity Auction in February saw prices increase by about one-third as 1,400 MW of new resources cleared to replace retiring coal plants. ISO-NE officials credited its new Pay-for-Performance incentive — used for the first time in FCA 9 — a sloped demand curve and a seven-year price lock-in for new resources for the results.
Annual Stop-Loss Limit: PJM’s annual non-performance charge stop-loss limit is equal to 1.5 times the annual net cost of new entry (CONE) rather than the auction clearing price as in ISO-NE. The commission acknowledged that PJM’s stop-loss limit will likely be higher than ISO-NE’s but said it was reasonable. “An important element of PJM’s overall proposal is to put at risk full capacity auction revenues if a resource completely fails to perform during performance assessment hours. Because the proposed annual stop-loss limit is equal to the maximum clearing price allowed by PJM’s Variable Resource Requirement curve, it meets this criterion,” FERC said. “In addition, basing the limit on net CONE ensures that market participants will know their maximum risk exposure in assuming a Capacity Performance commitment and be in a position to formulate their sell offers accordingly.” (¶164)
Trigger for Performance Assessment Hours: PJM will use the declaration of Emergency Actions as the trigger for performance assessment hours. In contrast, ISO-NE’s trigger is a shortage of system 30-minute reserves, system 10-minute reserves or zonal 30-minute reserves. “While PJM’s proposed trigger is more expansive, to include certain warnings and pre-Emergency Actions, we find that PJM’s approach would accurately correspond with conditions and events during which the system is experiencing, or may reasonably expect to experience, a shortage of capacity,” the commission said. “We find that this approach will appropriately trigger performance assessment hours when performance is most critical to the PJM system.” (¶186)
Transition Mechanism: FERC said PJM’s transition mechanisms strike an appropriate balance between procuring too much or too little capacity able to qualify as a Capacity Performance resource. Although the commission approved ISO-NE’s proposal to acquire only its performance product in its next auction, “PJM has demonstrated that a phased-in approach is also just and reasonable,” FERC said. (¶256)
Withholding: The commission rejected the Market Monitor’s suggestion that PJM adopt ISO-NE’s use of resources’ installed capacity values to define required performance. The Monitor said PJM’s reliance on unforced capacity could result in withholding by allowing a supplier with a large portfolio to reduce its available capacity from some of its resources to result in a higher clearing price for the entire portfolio. Such suppliers also could reduce unforced capacity available from some of its resources as a hedge against unexpected outages on other units. The commission said “the likelihood of such a strategy is mitigated by a resource deliberately forgoing considerable energy revenue in the hopes that the withholding strategy and any additional performance payments during Emergency Actions would outweigh the forgone energy revenue.” It said the Monitor should work with PJM to devise an alternative mitigation mechanism if it finds evidence of such strategies. (¶358)
Application of Non-Performance Charges: The commission approved PJM’s proposed application of non-performance charges, although it said it was “more lenient” than that applied by ISO-NE. It noted that the “more significant” of PJM’s proposed revisions regards generator maintenance outages as opposed to planned outages. “We agree with PJM that a generator on a planned outage should not be expected to return to service within a time interval of less than 72 hours. We also find reasonable PJM’s proposal requiring a generator on a planned outage to provide PJM with an estimate of the amount of time it will require to return to service. This requirement presents no significant burden to the resource but will assist PJM in operating its system during tight conditions,” FERC said. (¶496)
SPP has expanded its electric grid management from eight to 14 states, adding more than 5,000 MW of peak demand and 9,500 miles of transmission lines in the Great Plains.
The move, effective June 1, brings into SPP the Integrated System: the Western Area Power Administration’s Upper Great Plains Region (Western-UGP), based in Billings, Mont.; Basin Electric Power Cooperative in Bismarck, N.D. and the Heartland Consumers Power District in Madison, S.D.
Western-UGP becomes the first federal power agency to join an RTO under the Federal Energy Regulatory Commission’s Order 2000, which encouraged the voluntary formation of independent grid operators.
FERC approved SPP’s incorporation of the Integrated System in November (ER14-2850). While its grid is now under SPP’s control, the region won’t take part in SPP’s markets until October.
SPP COO Carl Monroe said Monday that the integration — which represents an increase of about 10 to 12% increase in peak load — has been seamless so far.
“The way we measure the success of the transition is if we hear no noise about it,” he said. He said it’s been quiet, and SPP is working on the next step of integrating the new organizations into the SPP tariff. He said Western-UGP, Basin Electric and Heartland Consumers are already participating in SPP’s transmission planning process.
Basin Electric has 2.8 million customers and 2,100 miles of transmission lines. Heartland serves 28 municipalities, including Sioux Falls, S.D. Western-UGP covers 378,000 square miles of prairie and farmland. The Integrated System evolved from a 1962 agreement between the Bureau of Reclamation, Basin Electric and 103 cooperative and municipal preference customers in the region. The SPP Board of Directors approved the system’s membership in June 2014.
It marks a significant increase in authority for SPP, which had shrunk after Entergy defected to MISO. The shifting of companies from one RTO to another spurred the need for settlement conferences overseen by FERC. Some issues are still in dispute, including MISO-directed transactions that flow across SPP territory.
The expansion will “enhance our ability to deliver value through transmission,” SPP CEO Nick Brown said. “The Integrated System’s footprint is well connected to SPP’s existing service territory and provides a logical expansion from a network configuration standpoint.”
SPP says the expansion will result in stakeholder net benefits of about $334 million. These include the increased ability to commit and dispatch generation into and out of Nebraska, and the availability of low-priced hydro generation out of Western-UGP.
Monroe thanked the Integrated System’s efforts in easing the transition. “Coordinating the flow of power requires hard work and collaborative planning,” he said. “We look forward to completing the Integrated System’s full membership in SPP this fall, which will provide increased options for buying and selling power.”
VALLEY FORGE, Pa. — PJM staff introduced a problem statement at last week’s Operating Committee meeting to address concerns that the RTO is purchasing too much fast-responding “RegD” resources, which is negatively affecting regulation and reliability.
The problem statement calls for a reevaluation of the marginal benefits factor used in the regulation market optimization solution, which appears to over-value the contribution of RegD resources as a substitute for traditional RegA.
“In order for the regulation market to arrange the optimal, least-cost combination of RegA and RegD to meet [area control error] control requirements, the marginal benefits factor function needs to be accurately defined,” according to the problem statement. (See PJM Market Monitor: Faulty Marginal Benefit Factor Harming Regulation.)
Generators’ Non-Compliance Continues
PJM staff continues to struggle with generators’ non-compliance with training and certification requirements.
While transmission owners generally are in compliance, 10 generators (12%) were non-compliant for certification, and two (3%) were non-compliant for training as of May, PJM’s Glen Boyle told the Operating Committee. Four demand response companies (17%) were non-compliant for training. In addition, four small generation companies (20%) were non-compliant for training.
While non-compliant companies are supposed to submit mitigation plans, many have not, and there are no financial penalties for failing to do so.
Stakeholders suggested PJM identify a compliance officer at each organization with whom to follow up. (See PJM Operating Committee Briefs,“Sought: Ways to Incent Training, Certification Compliance.”)
Susquehanna Loss of Outlet Scheme: The SPS would trip Susquehanna Unit 2 when two 500-kV outlets were open at the same time. The SPS is no longer needed with the May addition of the Susquehanna-Roseland 500-kV line.
Wescosville T3 SPS: The Wescosville 500/138-kV Transformer T3 would trip when the Alburtis end of the Susquehanna–Wescosville-Alburtis 500-kV line was open. The SPS is no longer needed with the May installation of the Breinigsville 500/138/69-kV substation.
Montour Runback SPS: During construction of the 230-kV line between Lackawanna and Bushkill and on one of the two Susquehanna-Harwood 230-kV lines, certain contingencies could overload the remaining second line. This SPS either reduced the output of Montour Units 1 and 2 or tripped the units to alleviate the overload. The SPS is no longer needed with the rebuilt line between Lackawanna and Bushkill and the Susquehanna-Harwood lines being back in service. It is blocked and will be removed in September.
VALLEY FORGE, Pa. — Maryland and Delaware officials are protesting PJM’s proposal to allocate most of the cost of the stability fix at Artificial Island to Delmarva Power & Light ratepayers.
PJM planners expect to present their recommended fix to the Board of Managers on July 27, after a meeting with the board’s Reliability Committee, which is made up of four of the board’s 10 members.
The project has been mired in controversy since planners last summer recommended Public Service Electric & Gas for the job, only to have the Board of Managers reopen the bidding following an outcry from finalists, environmentalists and New Jersey officials. On April 28, planners completed a second review, recommending selection of a proposal by LS Power. Including upgrades by PSE&G and Transource, the project is expected to total more than $200 million. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.)
Steve Herling, vice president of planning, told the Transmission Expansion Advisory Committee that the allocation is based on the location of the solution, not the problem. In this case, while the stability fix affects nuclear generators located in New Jersey, the project would entail transmission terminating in Red Lion, Del.
In its letter to the board, the Delaware PSC estimates that the AI fix could boost Delmarva’s annual transmission revenue requirements by $30 million over the current $121 million, an increase of almost 25%. Ratepayers of ODEC and the Delaware Municipal Electric Corp. also would be affected.
The Maryland PSC echoed its neighboring state’s concern, saying, “We do not view such a cost allocation as reasonably comparable to the benefits received from the project, which we believe would flow equally to at least New Jersey and Pennsylvania residents. Thus, such an allocation of costs, we believe, is in violation of FERC’s Order 1000 cost allocation principles and directives.”
PJM Holds Firm on its Pratts Decision
PJM planners reaffirmed their recommendation to select Dominion Resources and FirstEnergy to resolve reliability problems near Pratts, Va., despite feedback from several stakeholders questioning their decision. (See Tx Developers Challenge PJM Choice on Pratts Project.)
“We’ve been pretty consistent in the way we’ve been evaluating all the proposals submitted in a proposal window,” said Paul McGlynn, PJM general manager of system planning, noting that the key factors in PJM’s decision were performance, cost and risk associated with siting, feasibility and cost commitment.
PJM will continue to accept comments regarding the decision until July 13. It plans to make its recommendation to the Board of Managers at its meeting July 27.
VALLEY FORGE, Pa. — A months-long debate over whether to create “historic” capacity rights for some load-serving entities took a twist last week when PJM staff returned with a different proposal angled to achieve the same result.
“This has very little similarity, if any, to the previous approach,” PJM’s Jeff Bastian told the Market Implementation Committee on Wednesday.
PJM has been wrestling with how to help the Illinois Municipal Electric Agency meet its internal resource capacity requirements when it needed to use resources located outside of the Commonwealth Edison locational deliverability area to serve its Naperville, Ill., load. (See PJM Debate over ‘Historic’ Capacity Rights Gets a Face: IMEA.)
After failing to gain traction with skeptical stakeholders, staff veered from the notion of “historic” capacity to recommend a proposal that would apply only to Fixed Resource Requirement (FRR) entities — LSEs permitted to avoid direct participation in the Reliability Pricing Model auctions by meeting their capacity requirements using internally owned resources.
Under a proposal approved by PJM, the Independent Market Monitor and IMEA, the internal capacity requirement would not have an effect unless there was price separation for the relevant LDA.
IMEA will put in its offer after PJM defines the auction parameters. If its LDA has price separation when PJM clears the auction, it will be required to meet the internal requirement for the next auction, avoiding the internal capacity rule for only one auction, Market Monitor Joe Bowring explained.
The changes put IMEA where it was before PJM changed the rules regarding the trigger for the internal capacity requirement.
“Within an LDA that is being modeled separately, for reasons other than [Capacity Emergency Transmission Objective or Capacity Emergency Transmission Limit] threshold test or non-zero locational price adder in past three auctions, the FRR entity would not be subject to an internal minimum requirement until the first year after the LDA actually in an auction — or they could resort back to RPM the following year,” Bastian said.
Stakeholders, however, asked for more information regarding the thought process behind the changes before they considered approval.
Committee members were presented with the first read of three competing proposals addressing the issue of how to compensate Tier 1 synchronized reserves.
Since October 2012, Tier 1 reserves have been compensated at the synch reserve market clearing price (SRMCP) when the non-synch reserve market clearing price (NSRMCP) is greater than $0. While Tier 1 reserves are paid the same as Tier 2, only the latter is subject to penalties for non-performance.
The problem statement the proposals seek to solve asks whether it’s appropriate for such reserves to be credited when they are not responding to a synch reserve event, and if so, how much? (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
Tier 1 reserves are made up of on-line resources that are able to ramp up from their current output within 10 minutes in response to a synchronized reserve event.
The proposals come from PJM, the Independent Market Monitor and PJM’s Industrial Customer Coalition.
The PJM proposal would retain the status quo of paying Tier 1 reserves the SRMCP when the NSRMCP is greater than zero. The ICC recommends paying the non-synch reserve price in that scenario. The Monitor says Tier 1 resources should not be paid except during a synch reserve event.
PJM’s proposal alone would impose an obligation on Tier 1 resources to respond, with a refund owed for nonperformance.
Independent Market Monitor Joe Bowring said the payments to Tier 1 resources are an unnecessary “windfall” that have totaled up to $15 million in the first quarter of this year alone.
“There’s no reason to pay Tier 1 anything additional than what they’re being paid now,” Bowring said. “That’s fully compensatory for what they’re doing.”
Changes Would Allow Earlier Replacement Transactions
The committee will be asked to vote at its next meeting on manual changes that would allow replacement capacity transactions earlier than Nov. 30 prior to the start of the delivery year.
Such replacements would be permitted when the owner of the replaced resource could show the expected final physical position of the resource at the time of the request.
Existing generators could engage in such transactions if they are being deactivated, while new generators could replace themselves if their project is cancelled or delayed. Demand response or energy efficiency resources could be replaced due to the permanent departure of their loads.
Resources replaced would not be able to be recommitted for the delivery year.
VALLEY FORGE, Pa. — PJM will propose a two-tiered fee schedule for proposed transmission projects, officials told the Planning Committee last week.
Instead of asking for $30,000 to study any project costing at least $20 million, it will request that amount only for projects of at least $100 million.
For projects between $20 million and $100 million, PJM will recommend collecting a fee of $5,000.
The $30,000 fee proposal was approved Feb. 26 by the Markets and Reliability and Members committees after the Federal Energy Regulatory Commission rejected as discriminatory a previous plan to apply the charge to all greenfield projects but not upgrades of less than $20 million. (See FERC Rejects Fee on Greenfield Transmission Projects.)
“Because we put this threshold in place, we were going to be collecting for a larger number of projects,” PJM’s Fran Barrett told the committee. “Staff said that we could find ourselves over-collecting.”
The Planning Committee will be asked to approve the proposal, which would be tested over a two-year period, at its next meeting on July 9.
The fee schedule would be applied based on the cost estimates presented by those proposing the projects.
“If it turns out that a lot of people are trying to get around that with [estimates of] $99,999,000 we’ll have to revisit it,” said Steve Herling, vice president of planning.
Task Force Would Create Standards for Order 1000 Projects
A problem statement and issue charge introduced on first read Thursday would create a task force to develop minimum design standards for competitively solicited greenfield projects under FERC Order 1000.
The idea arose from concern that the designated entities for such projects would not be required to follow the design standards of the zonal transmission owner.
“We don’t want this new product to fix one problem but introduce a weak point in the system,” PJM’s Suzanne Glatz said, reflecting stakeholder feedback.
The design standards would apply to transmission lines, substations, and system protection and control design and coordination. They would take into consideration geography and physical and local needs of the project.
The task force would be open to all PJM stakeholders and would report to the Planning Committee.
Still Searching for Ways to Incent Early Project Submissions
The committee endorsed a problem statement and issue charge to find ways to incent customers to submit transmission projects earlier in the queue window.
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The issue will be assigned to the Planning Committee, which will have three to six months to identify better incentives to encourage earlier participation. (See PJM to Try Again to Speed Interconnection Filings.)
The imposition of non-refundable fees that escalate later in the queue window have had little effect on changing participants’ behavior, said Dave Egan, manager of interconnection projects.
Meanwhile, those who have done their due diligence in their submittals are being held up by late, deficient entrants, PJM says.
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.”
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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.”
