The owner of a Massachusetts generating plant says ISO-NE is forcing it to pay millions in unnecessary capacity costs because the RTO mistakenly underestimated the plant’s capacity.
GenOn Energy Management, a unit of NRG Energy, asked the Federal Energy Regulatory Commission last week for relief from what it called an “anomalous, illogical and patently unfair circumstance” (EL15-57).
Canal Generating Plant
GenOn said ISO-NE credited its Canal 2 oil- and gas-fired generator in Sandwich, Mass., with capacity of only 303 MW — rather than the plant’s actual 556.5-MW output — in the March annual reconfiguration auction (ARA) for the 2015-2016 capacity commitment period.
As a result, the RTO submitted a demand bid on GenOn’s behalf for the difference, forcing the company “to buy out of a capacity supply obligation that Canal 2 is fully capable of fulfilling.” Only a portion of the demand bid cleared because supply offers filled only two-thirds of the demand bids entered.
The company redacted specifics of how much it estimated the error could cost it, but based on the ARA’s clearing price of $11.466/kW-month, and the prorated apportionment of cleared bids, GenOn could be forced to spend more than $22 million.
GenOn said the plant’s output was derated after the failure of a step-up transformer in July 2013, but that it returned to full capacity in May 2014, as documented by the RTO’s capacity audits. The company noted that it offered the plant’s full capacity in Forward Capacity Auction 9 in February.
The company asked FERC to force the RTO to correct the “obvious mistake on ISO-NE’s part” or grant it a waiver to allow it to escape the capacity charges.
It asked for FERC action by May 25 so that ISO-NE can ensure that the appropriate capacity supply obligations are in place before the beginning of the 2015/16 capacity commitment period on June 1.
MISO transmission owners have told the Federal Energy Regulatory Commission it should order only a modest reduction in their base return on equity to 11.39%, not the 9.15% sought by industrial customers.
On April 6, the TOs filed an analysis contending 11.39% represented “a logical and supportable estimate of the cost of equity.” Omitting the FERC-approved ROEs for ITC Holdings — the only publicly traded transmission-only company in the U.S. — would result in an “absolute minimum” base ROE of 10.8%, the analysis said.
MISO industrial customers initiated the ROE dispute last fall, contending that transmission operators’ current base return on equity — 12.38%, except for American Transmission Co. at 12.2% — is too high (EL14-12).
The industrials contend the base ROE for TOs should not exceed 9.15%, citing changes in financial markets and other factors. They say the lower base ROE would cut transmission rates by about $327 million annually.
The dispute last year went into settlement discussions, but talks broke down in December.
After it became clear the case would not settle, the MISO Public Consumer Group sector joined in the fight, in what is its first-ever litigation in a FERC rate case.
In February the sector — which includes both non-profit groups and government agencies that represent consumers in utility cases before state regulators — asked MISO for $200,000 to help cover its legal costs in the dispute. (See MISO Advisory Committee Briefs.)
MISO spokesman Andy Schonert said last week that the RTO “continues to consider stakeholder feedback [on the request] and will be finalizing [its] decision quickly.”
On April 3, the consumer advocates asked FERC for approval to amend the group’s intervention by adding the Arkansas Attorney General’s Consumer Utility Rate Advocacy Division; the Kentucky Attorney General’s Office of Rate Intervention; the Louisiana-based Alliance for Affordable Energy; the Montana Consumer Counsel; and the Illinois Attorney General.
“As the outcome of the joint consumer advocates funding request has not yet been determined, it is even more important to broaden consumer advocate engagement in this proceeding in order to build up resources to support the Consumer Advocates’ participation in this case,” wrote Jennifer Easler, an attorney in the Iowa Office of Consumer Advocate.
The dispute follows FERC’s ruling last June that introduced a new, two-step method for calculating transmission owners’ ROEs. Ruling in a case involving New England TOs, FERC tentatively set the “zone of reasonableness” at 7.03 to 11.74%.
The next year will be a good one for natural gas-fired generators in PJM, according to Morningstar Commodities Research.
A new report by Morningstar analyst Jordan Grimes predicts on-peak prices at PJM’s West Hub will result in “historically high” spark spreads in delivery year 2015-16. Spark spread, a measure of gas plants’ gross profit margin, is the difference between the price received by a generator for power and the cost of the gas needed to produce it.
Grimes says physical reserve margins will tighten due to the retirement of more than 10,000 MW of older coal, gas and oil capacity before June 1.
“New combined-cycle capacity will replace some of this lost capacity, but much of the physical capacity will be replaced with demand response, renewables and expected imports from neighboring ISOs,” he wrote. “When DR replaces physical capacity, it will steepen the supply curve at the same time physical reserve margins drop this summer.”
For a gas plant with a 7,000 Btu/kWh heat rate purchasing gas at Tetco-M3 and selling power at PJM West, that could lead to spark spreads averaging $25/MWh in calendar year 2015 and $22/MWh in 2016, Grimes predicts.
But he says spreads will decline to $18 in 2017 and $16 in 2018 as more new combined-cycle plants are built in PJM and pipeline expansions allows Marcellus gas producers to obtain higher prices from more distant customers.
“There are a few scenarios … that would help keep spark spreads elevated in 2017 and 2018, but the most likely scenario is lower spark spread clears, given the new, more efficient supply stack and higher Tetco-M3 gas prices,” Grimes said.
An unexpected geomagnetic disturbance (GMD) March 17 caused brief spikes on PJM’s grid but no operational problems, RTO officials told the Operating Committee last week.
Some of PJM’s approximately 50 geomagnetically induced current (GIC) meters recorded spikes of more than 20 amps, but the jumps were short-lived and did not cause PJM to direct conservative operations.
The National Oceanic and Atmospheric Administration, which normally provides one to three days’ advance notice of such events, didn’t warn PJM and other grid operators until the morning of the 17th, said Chris Pilong, manager of dispatch.
NOAA predicted “a glancing blow” centered at 50 degrees latitude — near Winnipeg, Manitoba. As it turned out, the solar storm was a bit more intense than expected and centered a bit farther south, Pilong said.
Still, the incident did not pass PJM’s threshold for initiating conservative operations — a rise of 10 amps for more than 10 minutes. Pilong said the longest spikes lasted no more than four minutes.
“This is the highest measurement I can recall seeing in some time and we saw no impact on the system,” he said.
NOAA initially predicted a G-3 (strong) event for three hours beginning at 8 a.m. ET. It upgraded the storm to a G-4 (severe) with a lower latitude of 45 degrees — near Montreal — and a six-hour duration.
The GIC meters recorded their biggest spikes between 9 and 10 a.m. and 7 and 7:30 p.m. (See graphic.)
The incident came less than two weeks before the North American Electric Reliability Corp.’s Geomagnetic Disturbance Operations Standard (EOP-010-1) took effect on April 1. The standard requires reliability coordinators to review the GMD operating procedures or processes of transmission operators (TOPs) within their areas to mitigate the effect of GMDs on the grid.
PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs
About 20% of PJM’s combustion turbines, representing 30% of its CT capacity, would be barred from receiving lost opportunity costs under a rule change awaiting a shareholder vote, PJM officials told the OC last week.
Adam Keech, director of wholesale market operations, said PJM conducted the analysis after the Markets and Reliability Committee last month tabled voting on the proposal.
The delay came after some stakeholders complained that the changes — which would generally limit lost opportunity costs to units with start-up and notification times of no more than two hours and minimum run times of two hours or less — were too restrictive. (See PJM Tables Rule Change on CT LOCs.)
Keech said that if the minimum-run-time threshold were increased to four hours from two, only 10% of CT units and capacity would be excluded from lost opportunity costs.
PJM officials told the OC they had no operational concerns about the changes.
One generation operator, who declined to be quoted by name, said the new rules would create “perverse incentives” for generator operators, resulting in some units running under self-schedules for an additional hour after the two-hour limit. “I will submit a schedule that meets your payment parameters, but on operations I need to do what I need to do,” he said.
“Instead of using a carrot approach, you’re using a stick approach,” he added.
Keech said that the change, which is supported by PJM and the Independent Market Monitor, was intended to eliminate incentives at odds with PJM’s needs. Under the current rules, he said, “you get paid more if you don’t run [in real-time] than if you do.”
Louis Slade, a senior policy manager for Dominion Resources, questioned whether PJM’s data would be accurate in the future, saying most new CTs are 150 MW or larger and have minimum run times of longer than two hours. “Two hours potentially puts a lot of the newer CTs outside of that range,” he said.
Director of Stakeholder Affairs Dave Anders said the Energy Market Uplift Senior Task Force, which overwhelmingly approved the proposed change in February, may consider “friendly amendments” at its April 17 meeting.
The MRC is expected to vote on the issue at its next meeting, April 23.
Too Much of a Good Thing? PJM Concerned Fast Response Regulation Crowding Out Traditional Resources
PJM operators are concerned that fast response regulation resources are taking too large a share of the RTO’s overall regulation response.
PJM’s Danielle Martini presented a proposed problem statement on the issue to the OC last week.
Fast-responding RegD are providing more than 42% of total response on average, with shares as high as 70% during some events, Martini said. That leaves less room for slower-responding RegA resources.
“Too much RegD looks like it hurts performance because it affects how much RegA we procure,” Mike Bryson, executive director of system operations, explained after the meeting.
PJM is considering whether to use a different regulation signal for energy-limited resources such as participating in the regulation market.
“This scenario is seen most frequently when the RTO experiences high or low [area control error] during periods of rapid load changes during the morning and evening periods,” the problem statement said. “During these times, the regulation signal is utilized to maintain ACE control if the load ramp briefly and instantaneously ‘slows down’ or ‘speeds up.’ During these times, larger sized units are coming on line and offline (hydro, CTs, etc.) to keep up with the load, and regulation is critical in correcting for the instantaneous changes in load and generation.
“When the regulation signal ‘times out’ for RegD resources and there is a large amount (>42%) of RegD providing the regulation service, the dispatcher is left with limited resources with which to maintain control of the system. This may lead to increased periods of ACE/BAAL excursions and increased reliance on synchronized reserves to supplement the temporarily depleted regulation reserves.”
PJM Ponders Expansion of Winter Generator Testing
PJM is considering stakeholder suggestions that it expand the winter generator testing it initiated last winter.
That testing was voluntary and limited to units that hadn’t run for the prior two months. It was credited with reducing generator outages to a peak of 10% in January 2015, compared with a high of 22% a year earlier.
Mike Bryson, executive director of system operations, told the OC that some stakeholders have suggested the testing be made mandatory.
In early November, PJM identified about 55,000 MW of generation that was eligible for testing because it had not operated for the prior two months. The number dropped to about 44,000 MW after some of the units were dispatched during an early November cold spell.
Owners of about half of the remaining units submitted them to PJM for testing, but the RTO ended up testing only about 9,000 MW because of a 1,000-MW cap on tests per day and because warm weather prevented testing on some days.
The temperature threshold “knocked most of the days out” for testing in the Dominion zone, Bryson said.
PJM officials plan to discuss the issue internally before bringing a proposal to stakeholders, Bryson said.
New Info on Planned Outages to be Shared
PJM plans to start posting additional information on scheduled transmission outages in its OASIS system in response to requests for such details.
Beginning with the third-quarter eDart release in September, the following information will be available: the queue number; the time that the outage equipment can be returned to service at PJM’s request; and a “questionable approval” indicator, which will inform market participants that the outage may not be approved by PJM.
Supporters and critics of Exelon’s proposed $6.8 billion takeover of Pepco Holdings Inc. are churning out newspaper opinion pieces, resolutions and public relations campaigns as the last holdouts to the deal approach deadlines to render decisions.
Delaware regulators last week agreed on a final settlement but will wait to sign it until deals have been finalized with Maryland and D.C.
Pepco Holdings Inc. CEO Joseph Rigby testifies before D.C. Public Service Commission.
Evidentiary hearings were scheduled to end last week in D.C., but two more days of testimony were added for April 20-21. The Public Service Commission will close the record on May 13. (See CEO Crane to DC PSC: Exelon Committed to Jobs, Ratepayers.)
In Maryland, hearings are set for Wednesday, Thursday and, if necessary, Friday. The PSC has a deadline of May 8 to reach a decision.
The acquisition already has been approved by the Federal Energy Regulatory Commission, the New Jersey Board of Public Utilities and the Virginia State Corporation Commission.
Exelon has promised all jurisdictions equivalent concessions, the bulk of which address customer benefits, workforce retention and commitments to energy efficiency. It also conceded items of particular interest to some jurisdictions, such as recreational trails in Maryland and a feasibility study of wind generation in Delaware’s southern counties.
Delaware PSC on Board
Under the terms of the settlement outlined before the Delaware Public Service Commission last week, electricity users will share a one-time credit this summer totaling $40 million instead of a larger payout that would have been distributed over 10 years. Exelon also committed to spend $2 million for a low-income energy efficiency plan for PHI’s Delmarva Power & Light customers.
One intervener initially skeptical of the deal, University of Delaware professor Jeremy Firestone, withdrew his opposition at last week’s hearing, saying he was pleased to have helped negotiate the lump sum credit and the study of wind generation in Kent and Sussex counties.
PJM’s Independent Market Monitor, represented at the hearing by General Counsel Jeffrey Mayes, said the merger should be conditioned on several measures designed to ensure competition, including a promise to remain in the RTO indefinitely and to make property paid for by ratepayers available to competitive transmission developers. The suggestions, however, gained no traction among the commissioners.
Although the commission did not vote on the agreement, none of the commissioners expressed opposition.
State Rep. John Kowalko, who did not act in time to become an intervener, was the lone voice of dissent during public comments at the hearing, saying the interests of Delaware’s 250,000 residential ratepayers will be lost among the total of 9.6 million customers affected by the acquisition. “We will be the proverbial flea on the elephant’s back,” he said.
Opposition Grows in DC
The deal is facing stiff opposition in D.C., where nearly half of the District’s Advisory Neighborhood Commissions last week passed measures against the takeover, including every ANC in Ward 4, home to Mayor Muriel Bowser. None of the groups has come out in support of the deal.
“Some of D.C.’s electricity consumers have long suffered from poor reliability, and allowing our power decisions to be made by an out-of-state energy conglomerate with a sizeable roster of high-priced nuclear power plants would not be in our community’s best interest,” Douglass Sloan, commissioner of ANC 4B09, said in a statement released by Power DC, a coalition of electricity customers concerned about rates, reliability, renewable energy and local control.
Three of the 12 members of the D.C. Council — Mary Cheh, Elissa Silverman and Charles Allen — filed a letter with the PSC opposing the merger. The Office of People’s Counsel is also advising against approval.
Exelon has fared better in Maryland, where two key counties — Montgomery and Prince George’s — agreed to support the acquisition in return for promises to fund customer bill credits, grid reliability improvements, renewable energy projects, energy efficiency programs and help for low-income consumers. (See Exelon, Pepco Ink Deal with Md. Counties, but Critics Stand Firm.)
However, the Montgomery County Council split from County Executive Ike Leggett and unanimously passed a resolution saying that the settlement “does not adequately address the overarching issues that have led the state, the Office of People’s Counsel, the environmental community and other public interest organizations to maintain that the merger is contrary to the public interest.”
The acquisition also is opposed by state Attorney General Brian Frosh.
If the deal is approved, it will create the Mid-Atlantic’s largest electric and gas utility.
SPP’s Market Monitoring Unit asked the Federal Energy Regulatory Commission last week to reject a proposal that would bar the RTO from canceling commitments of gas-fired generators if they are not needed.
SPP’s proposal would result in “an inefficient transfer of gas market risks to SPP’s load,” wrote Catherine Tyler Mooney, the MMU’s manager of market analytics (ER15-1293). “… This commitment may impose uneconomic production on the market, impacting market prices, uplift, congestion, transmission congestion rights payments or market-to-market settlements.”
At issue is SPP’s March 16 proposal to codify its historical practice of not de-committing generators committed out of its multi-day reliability assessment during emergency operations. The Tariff change would bar SPP from decommitting such units unless they presented a reliability risk.
SPP proposed the change after some gas-fired generators in PJM complained that they suffered “stranded gas” losses in 2014 when they bought fuel at high prices in response to transmission operators’ directions that were not needed by the market later. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
SPP said it filed the Tariff revisions in response to “stakeholders’ request for clarity on whether and how resources may be committed” under its multi-day reliability assessment if SPP has implemented conservative operations under its emergency operating plan. The proposal was approved by the RTO’s Members Committee and Board of Directors in January.
The MMU said the proposed change was problematic for several reasons. “First, it may be difficult for SPP to verify the legitimacy of unused fuel cost claims. Second, generator operators are in the best position to effectively minimize fuel costs.”
The MMU said that SPP should have the ability to reevaluate its need for generation during emergencies — if, for example, weather forecasts change.
“Avoidable adverse consequences should not be imposed on the market to lessen the predetermined cost exposure of individual generators,” the MMU said. “It is not a cost-minimizing market outcome. If SPP staff, its members and the commission believe that an uplift payment for unused fuel is necessary to preserve system reliability during emergencies, SPP should pursue that particular issue.”
VALLEY FORGE, Pa. — PJM planners said last week they will announce their revised recommendation to address stability problems at the Artificial Island nuclear complex at a special Transmission Expansion Advisory Committee meeting April 28.
Planners recommended Public Service Electric & Gas for the project last June, but the Board of Managers reopened the bidding to finalists Transource Energy, Dominion Resources and LS Power after criticism from environmentalists, New Jersey officials and spurned bidders.
All of the potential solutions involve new transmission lines connecting Artificial Island to Delaware. LS Power and Transource have proposed a southern crossing of the Delaware River. Dominion and PSE&G offered a northern route with an overhead crossing.
Planners had hoped to announce their revised selection in January but delayed their decision to allow consultants to investigate concerns that Dominion’s proposed use of thyristor controlled series compensation (TCSC) could threaten reliability at the island, home to the Salem-Hope Creek nuclear complex. (See Further Study Delays PJM’s Artificial Island Decision.)
PSEG Nuclear, which operates the nuclear plants, contends Dominion’s proposal would use unproven technology that could result in damage to turbine generator shafts.
Planners told TEAC members last week Siemens Power Technology International had completed its sub-synchronous resonance analysis of Dominion’s proposal and found that the TCSC could result in “negative damping” for several resonant frequencies.
However, Exponent, an engineering and science consulting firm that reviewed the Siemens study at PJM’s request, said it was “inconclusive” because of limits in the data available.
Exponent expressed its own concerns with the Dominion proposal. It said Dominion is proposing a 90% post-contingency TCSC compensation — well above the 70 to 80% compensation used by others in the industry.
Responding to questions from stakeholders who suggested more study might be needed to verify the feasibility of the Dominion proposal, Steve Herling, vice president of planning, said Siemens had identified the “potential for an issue.”
“It’s not a fatal flaw,” he said.
“[I]t’s an issue going forward,” said Thomas Leeming, director of transmission operations and planning for Exelon’s Commonwealth Edison. Not “having wrestled this to the ground could be an issue.”
“We understand what needs to be done if we go that way,” Herling responded. “We recognize that if we go with this solution there’s more work to be done. We’ve already talked to a number of manufacturers about all these issues.”
Planners said their current schedule would result in a recommendation to the Board of Managers’ Reliability Committee on May 19.
SPP could meet the Environmental Protection Agency’s 30% carbon dioxide reduction target by 2030 through a $45/ton carbon adder and 7.8 GW of additional generation, most of it wind, according to a report issued last week by the RTO.
The analysis, the RTO’s second on the potential impacts of EPA’s Clean Power Plan, estimates the cost of those measures at $2.9 billion per year, not including additional transmission or gas pipelines that will be needed.
SPP’s first study, released in October, concluded that EPA’s implementation timeline — particularly its 2020 interim goals — did not allow enough time to build needed generation and transmission to replace coal plant retirements and deliver wind power to population centers. It predicted SPP’s transmission system could face severe overloads, increasing the potential for cascading outages.
“This second analysis does not alter our earlier conclusion that additional infrastructure — and time — is needed to meet the CPP’s proposed CO2 emission goals,” Lanny Nickell, vice president of engineering, said in a statement.
During a series of technical conferences convened by the Federal Energy Regulatory Commission, and at meetings with state regulators, EPA officials suggested the final rule due this summer may relax the 2020 goals, which have been widely criticized as unworkable. (See EPA on Carbon Rule: We’re Listening.)
Methodology
SPP said its analysis found that the region could meet the EPA goal with a carbon adder — essentially a tax on a unit’s carbon emissions — of $60/ton of carbon emissions. But it said an adder cost of $30-$45 per ton would be most cost-effective.
The report’s conclusions are based on a $45/ton adder and the addition of 5.6 GW of wind and 1.2 GW of natural gas generation above that currently planned.
The $2.9 billion in annual costs is the result of $600 million in increased annual energy costs and $13.3 billion in capital spending. The study did not evaluate infrastructure needs and thus did not include costs of transmission or gas pipeline that would be needed.
The study assumed a 70% capacity factor for combined-cycle gas generators and 47% for new wind. The added wind generation would allow that resource to meet 25% of the non-coincident peak-load obligations in the region. SPP’s minimum 12% capacity margin was preserved in each load zone.
Unduly Pessimistic
The tone of SPP’s second analysis is less gloomy than that of the first, which warned of the possibility of rolling blackouts. But critics said the new report is still unduly pessimistic.
The American Wind Energy Association said SPP’s analysis overestimates compliance costs because it “arbitrarily” limited the region’s options.
Michael Goggin, AWEA’s senior director of research, said SPP’s assumption for the cost of new wind generation is about 40% higher than current wind in the region, a nearly $1 billion difference. “Those costs would be even lower if SPP accounted for how wind energy costs continue to fall drastically, dropping by more than 50% over the last five years,” he wrote in a blog post.
Goggin said SPP’s analysis also did not include energy efficiency as a compliance option and assumed almost no new gas generation would be built.
“SPP’s study essentially examines what would happen if the region tried to comply with one arm tied behind its back,” he said. “If the region had been allowed to fully utilize its abundant and low-cost resources of wind, natural gas, and energy efficiency, the cost of achieving the Clean Power Plan would have been far lower.”
SPP acknowledged it did not analyze each of the EPA’s proposed “building blocks.” Unlike the RTO’s Integrated Transmission Plan, the study also did not consider economic interchange with other regions. The RTO said it made this choice to minimize “the uncertainty associated with trying to determine how SPP’s neighbors will operate under their own compliance with the CPP.”
In an interview, Nickell said the AWEA critique failed to “recognize that the study was meant to be indicative as opposed to definitive.” Nickell said some potential compliance options were excluded to provide an apples-to-apples comparison for a third, state-by-state analysis, which is expected in early June.
“This isn’t the only way to solve the problem,” he acknowledged. “Clearly [energy efficiency] could reduce costs. It’s a matter of what could be done.”
While the study assumes only 1.2 GW of incremental gas-fired generation, that is in addition to 22 GW of new gas capacity already planned, he added.
Retirements
SPP’s scenario assumed about 2.2 GW of coal retirements “incremental to those retirements already planned,” based on those generators running below a 30% capacity factor after adding a $45/ton adder.
As much as 13.9 GW of generation could be at risk of retirement in addition to what is included in SPP’s current transmission planning models, SPP said.
“This assumption may be conservative considering that SPP’s analysis indicates nearly all existing coal-fired generation in the region would operate above 80% capacity factor without a carbon cost adder but approximately 12,200 MW of coal-fired generation would operate below 80% capacity factor with a $45/ton cost adder.”
The analysis does not take into account transmission constraints or interchange with adjacent pools, SPP said.
AWEA also criticized the report’s claim that 13.9 GW of coal is “at risk” of retirement.
“SPP gets to the extremely unrealistic 13.9 GW number by considering coal plants ‘at risk’ for retirement if they fall below an 80% capacity factor. An 80% capacity factor is an extremely high and unrealistic threshold for considering a plant at risk of retirement; in fact, the national average coal plant capacity factor is currently 60%. Almost all of SPP’s ‘at risk’ coal plants would actually just be operating at average capacity factors.”
From Crisis to Inevitability
Late last year, SPP and MISO warned of a reliability crisis if the Clean Power Plan isn’t eased to account for up to 134 GW of generation retirements by 2020, most of them coal-fired units. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability.)
SPP’s first study assumed new generation was added without additional transmission infrastructure. The model showed that portions of the system in the Texas panhandle, western Kansas and northern Arkansas “were so severely overloaded that cascading outages and voltage collapse would occur and would result in violations of [North American Electric Reliability Corp.] reliability standards,” SPP CEO Nick Brown said in his comments to EPA.
But the initial alarm about the Clean Power Plan has given way to compliance strategy contemplation. In addition to the third study that will analyze the cost of state-by-state compliance, the RTO is beginning work on a transmission planning study. That analysis is targeted for January 2017, Nickell said.
FERC issued the order in February, accusing the company of billing ISO-NE for oil at its 181-MW plant in Pittsfield, Mass., while actually burning cheaper natural gas during a July 2010 heat wave. In dispute are a series of emails between Maxim employee Kyle Mitton and the Internal Market Monitor.
“Staff’s reply contains no credible evidence that Maxim or Mr. Mitton omitted any material fact in any of their communications with the IMM which left the IMM with any false impressions about what fuel actually was burned at Pittsfield,” Maxim said.
In its reply, Enforcement said Maxim “made a series of carefully managed statements about pipeline restrictions and the theoretical possibility of losses from offering gas and burning oil, and said nothing about what was actually happening at Pittsfield.”
In addition to the Pittsfield plant, Maxim operates two other plants in ISO-NE: CDECCA, a 62-MW cogeneration plant in Hartford, Conn., and Pawtucket Power, a 63.5-MW cogeneration plant in Pawtucket, R.I.
Transmission planners are considering additional changes to their light-load studies based on a reevaluation of three years of data that showed coal- and natural gas-fired generation are operating at higher capacity factors than previously assumed. Planners already had concluded that maximum wind capacity factors should be increased in the studies.
The analysis showed that capacity factors for coal generators during light-load periods — 1 to 5 a.m. from Nov. 1 through April 30 — have been trending up, in large part because retiring units are leaving more electricity to be generated by those remaining.
Planners are considering increasing the maximum ramping of coal plants 500 MW and larger above the current 60% and boosting the assumptions for coal plants below 500 MW above the current 45% maximum. PJM also is weighing an increase in assumptions for natural gas plants; planners currently assume they are not dispatched at all during light-load periods.
The analysis found large plants operated above the 60% capacity factor in about two-thirds of light-load hours RTO-wide during delivery year 2013-14, with the APS and AEP zones above that level about 80% of the time. Smaller coal units operated above their assumed capacity factor in about half of the hours RTO-wide. In APS, small coal ramped above the assumption in all light-load hours for the year, Mark Sims, manager of transmission planning, told the Planning Committee last week.
“A significant amount of coal has retired. What’s left is running more often because it’s more efficient and competitive,” Sims said.
Capacity factors also have been increasing during light-load hours for natural gas combined-cycle units as the fuel has become cheaper. RTO-wide, they operated in about one-quarter of light-load hours, with units in the AEP zone running in 86% of hours. When they are operating, they are generally doing so at capacity factors of 80% or higher.
No changes in assumptions are proposed for oil (assumed at 0%) and nuclear units (assumed at 100%).
PJM last month announced its intention to increase the maximum wind capacity factor from 80% to 100%, consistent with the modeling in MISO. (See Changes Proposed for Light Load, Wind Modeling.)
Sims said staff will conduct sensitivity analyses after finalizing their recommended changes and report back to the PC.
PJM Looks to Tweak Peak Load Forecast
PJM plans to recommend changes to improve its peak load forecasts by the end of June, officials told the PC. The revised model is an effort to better reflect customer usage, energy efficiency, weather and the impacts of “behind the meter” solar generation. (See PJM Seeking Improved Load Forecasts.)
PJM’s John Reynolds said efficiency in heating is continuing to climb, though not as dramatically in recent years. Meanwhile, cooling efficiency has leveled off and overall energy usage for cooling is expected to begin increasing by 2020.
PJM also is investigating the impact of distributed solar energy on demand. More than 1,700 MW of photovoltaic solar generation not registered as capacity resources is now receiving solar renewable energy credits in the PJM region, up from zero in 2005. Reynolds said most of the generation is in New Jersey, which has generous solar subsidies.
Planners expect to identify improvements to the model by the end of the second quarter, with revised manual language brought to stakeholders for endorsement by the end of the third quarter. Any changes would be implemented in the 2016 load forecast.
Long-Term Firm Transmission Study Endorsed
Members unanimously endorsed creating a Planning Committee sub-group to consider changes in how it studies long-term firm transmission service requests. The effort, initiated with a problem statement approved in March, is intended to ensure that individual requesters share in the cost of transmission upgrades required to serve them. (See Change Would Shift Baseline Upgrades to Network Customers.)
“PJM’s process, tools and thresholds have been established based around a local generation or transmission injection projects’ impacts and not around remote origination of energy,” according to the issue charge approved by members.
The group is expected to complete its deliberations by the end of the third quarter.
Committee Endorses Reserve Requirement Study
The PC approved revised assumptions for the 2015 PJM reserve requirement study that are expected to have a minor impact.
The study will determine the installed reserve margin, forecast pool requirement and demand resource factor for future delivery years and will look at the period from June 1, 2015, through May 31, 2026.
The two changes of note regard the computation of demand response and PJM’s proposed Capacity Performance product.
The study will use PJM’s new method of modeling demand response, which takes the average of the final amount of committed DR for the most recent three years. Previously, forecasters used the amount that cleared the last Base Residual Auction. (See Members Endorse Change to Demand Response Modeling.)
And, because the RTO’s Capacity Performance plan is in limbo as it awaits a ruling from the Federal Energy Regulatory Commission, the study will report using two sets of parameters — one with the CP product and one under the status quo. The forecast pool requirement values that ultimately will be applied will depend on whether FERC approves PJM’s plan. (See related story, PJM Responds to FERC Queries on Capacity Performance, Requests Approval.)
Order 1000 Problem Statement Approved
The PC approved a problem statement formalizing its work on process improvements as a result of Order 1000 “lessons learned.”
Although PJM already has begun incorporating the lessons — for example, introducing an improved method for receiving document submissions from transmission developers — officials said they decided a problem statement was needed because the issue would be a “standing agenda item” for the committee in the future.
PJM’s first project under the order, soliciting a fix for stability issues at New Jersey’s Artificial Island nuclear complex, has been beset by numerous delays and controversy. Planners expect to recommend a proposal to the Board of Managers next month — more than two years after the competitive window opened. (See related story, Planners Set April 28 for Artificial Island Recommendation.)
