New England power generators are joining FirstEnergy’s effort to expand a court ruling that would prevent demand response providers from participating in capacity auctions.
The New England Power Generators Association asked the Federal Energy Regulatory Commission Nov. 14 to order ISO-NE to exclude such resources from the Forward Capacity Market (EL15-21).
In May, the D.C. Circuit Court of Appeals threw out the commission’s Order 745, which required RTOs and ISOs to pay demand response providers for energy at LMPs. The Electric Power Supply Association had sued FERC, claiming the commission exceeded its jurisdiction. FirstEnergy Solutions then filed a complaint with FERC, seeking to expand the challenge.
The D.C. Circuit granted a stay until Dec. 16 on its ruling in order to give U.S. Solicitor General Donald B. Verrilli Jr. time to file a petition on FERC’s behalf to send the case to the U.S. Supreme Court. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)
NEPGA, which represents 26,000 MW of generating capacity in New England, asked FERC to issue an order by Jan. 15, two weeks before ISO-NE is set to begin its next Forward Capacity Auction on Feb. 2. An order at that time would “ensure that clearing prices are not distorted by the participation of resources that cannot lawfully participate in that auction and that will be unable to fulfill their obligations if selected,” the NEPGA complaint states.
NEPGA also argues that the reasoning of the D.C. Circuit’s jurisdictional holding in the EPSA case — that FERC was erroneously attempting to regulate a retail product — was not limited to the energy markets. Demand response capacity resources must be excluded from participating as supply in capacity auctions because they can’t fulfill their energy must-offer obligations as required by ISO-NE’s Tariff, the complaint states.
After investing in natural gas-fired generation and committing to a $2 billion pipeline investment, Duke Energy now says it might get into gas production.
Duke Chief Financial Officer Steve Young told the annual Edison Electric Institute Financial Conference Nov. 11 that the company’s increasing dependence on natural gas means wellhead investments could make sense for the company.
“Gas prices have some volatility and investments in gas reserves might make sense,” Young said, according to a Bloomberg News account of the conference.
Young didn’t make any specific references to natural gas production investments, but it was the first time a Duke executive raised such a possibility. Since then, the company has declined to make public any plans for natural gas production investments.
“Duke Energy is in the early stages of evaluating investments in shale gas production,” company spokeswoman Jennifer Zajac said. “There are no immediate plans and the company will not make any decisions on the matter any time soon.”
Zajac said Duke is carefully watching another company’s move in that direction, however.
”Duke Energy will continue to monitor Florida Power & Light’s request for a rate-base shale gas production framework from the Florida Public Service Commission,” she said.
The idea is that instead of passing on gas costs to customers as it does now, Duke could control the price at the wellhead, lock in prices for customers and earn a profit on the investment. It would need regulatory approval for such a plan.
NextEra Energy, FPL’s parent company, generates 52% of its electricity using natural gas and has invested in natural gas pipelines. It is pushing for approval of a 600-mile, $3.7 billion natural gas pipeline into Florida from a hub in Alabama. It would partner for the project with Spectra Energy Partners.
Earlier this year, FPL said it was partnering with PetroQuest Energy to develop more than three dozen natural gas wells in the Woodford Shale region in southeastern Oklahoma. It is waiting for the Florida PSC to approve the company’s plan to invest in natural gas production as a long-term program and add it into its rate-base case. Currently, the Florida PSC allows the company to engage in short-term fuel hedging agreements to smooth fuel price volatility. FPL said it expects a decision from the PSC by late this year or early next year.
Like NextEra, Duke is investing in gas-fired generation and pipeline construction. Earlier this year, Duke said it would partner with four other companies to build a 550-mile, $5 billion pipeline to bring Marcellus and Utica shale gas to Virginia and eastern North Carolina. Called the “Atlantic Coast Pipeline,” it would have a capacity of 1.5 billion cubic feet of gas per day. Duke would own 40% of the pipeline. (See Duke, Dominion Propose 550-Mile, $5 Billion Pipeline for Shale Gas.)
At the North Carolina CEO Forum in Raleigh on Oct. 23, Duke CEO Lynn Good noted that its generation portfolio is increasingly dependent on natural gas. “By 2013, it was 20%, and we think it is going to be more and more and more as we go forward,” Good said, according to the Charlotte Business Journal. As recently as 2008, she said, “it would have been close to 0%.”
As part of its $9 billion generation fleet modernization program, the company retired about 3,830 MW of older coal-fired units in recent years, and it says that number will grow to nearly 6,300 MW, about a quarter of its earlier coal fleet. It is building a $600 million gas-fired plant in South Carolina and a $1.5 billion plant in Citrus County, Fla.
The company generated 55% of its power with coal in 2005, a share projected to drop to 38% by 2015. Gas, which was responsible for only 5% of its 2005 output, is expected to generate 24% of its power next year. Duke owns about 50 GW of generation in the U.S.
MISO consumer advocates last week asked the Federal Energy Regulatory Commission to reconsider their request to cap the equity component of transmission owners’ capital structure at 50%. The advocates also renewed their request to eliminate transmission rate incentives for RTO participation and independence.
The commission rejected both requests Oct. 16, but it ordered an evidentiary hearing on complaints that the base rate of return on equity of MISO’s 24 transmission operators is not just and reasonable (EL14-12).
The commission said the challengers failed to demonstrate that the capital structure and incentive rules were unjust. FERC also ruled that evidence showing that certain MISO TOs have higher amounts of equity than they need to maintain good credit ratings and attract capital was insufficient grounds for investigating their capital structure.
Consumer advocates from Indiana, Iowa, Michigan, Minnesota, Missouri and Wisconsin argue in their latest filing that “the allowed ROE and the ratemaking capital structure must be considered together and both subject to reasonable standards.”
They said there’s evidence that transmission-only companies with lower operating risk can finance with greater amounts of financial risk or leverage while supporting an investment-grade bond rating. They said “today’s changed financial market” warrants a lower cap on the equity component.
ITC Holdings Cited
As an example, the advocates pointed to ITC Holdings and its utility subsidiaries. While those subsidiaries set transmission rates based on a commission-approved 60% equity ratio capital structure, ITC seeks to maintain an adjusted debt-to-total capital ratio of 70%, the advocates said.
Bond ratings of the ITC companies reflect a common equity ratio of 30%, not the 60% used to set ITC’s and Michigan Electric Transmission Co.’s FERC transmission rates, the advocates contend. ITC’s bond ratings are “only slight lower” than its FERC-regulated operating subsidiaries.
“That fact means that the FERC-regulated ITC subsidiaries could be capitalized with much lower (and much less expensive) common equity ratios, just as the parent (ITC) does and still maintain investment-grade bond ratings,” they said.
Customers who must pay for the much more expensive equity capital allowed in ITC’s subsidiaries’ 60% ratemaking capital structure “are not getting any debt cost advantage of that extreme equity ratio because the parent company leverage holds down the bond rating that could otherwise be achieved with such a high equity ratio.”
OMS Weighs In
The Organization of MISO States also requested that FERC rehear TO capital structure and continued use of incentive transmission adders for independence and RTO participation.
“If not reviewed alongside the ROE, the resulting costs in these two areas could lead to rates that will be higher than necessary to achieve investment grade utilities that build needed transmission,” OMS said. “Requiring the parties to review base ROE without looking at all the relevant factors that impact end-use rates rests on the faulty notion that these elements are discrete and disconnected from each other.”
OMS cites the ability of ITC Transmission and METC to receive a 100 basis-point adder for being an independent transmission company.
FERC opened the door to ROE fights in June, when it changed the way it sets return on equity rates for electric utilities to something akin to the process it uses for natural gas and oil pipelines. FERC ruled in a case involving a New England transmission owner, tentatively setting the “zone of reasonableness” at 7.03 to 11.74%.
The TOs’ ROE is currently 12.38%, except for American Transmission Co., which has a base rate of 12.2%.
Settlement Judge Dawn E.B. Scholz reported last week that the parties had made progress in a settlement conference Nov. 13. Another session was set for Dec. 16.
MISO industrial customers said previously they see the potential to reduce transmission rates by $327 million in year.
Duke Energy this month filed a plan with North Carolina environmental agencies to remove millions of tons of coal ash from four sites in the state, the beginning of a multi-year $3.4 billion remediation effort. Duke, which reported operating revenue of $26.4 billion last year, has not said how the cost will impact earnings.
Other coal-burning utilities may also be facing large cleanup bills as state and federal regulators increase their scrutiny following spills by Duke and the Tennessee Valley Authority.
So far, storage and disposal of coal ash and related materials is not federally regulated. That is expected to change on Dec. 19, when the Environmental Protection Agency is scheduled to announce a long-awaited rule.
The EPA proposed coal ash rules in 2010 but, under political pressure from industrial groups, the White House sent the rules back for rewriting. It took a court-ordered consent decree to set the Dec. 19 deadline.
Utilities are waiting to see whether the proposed rule, now at the White House for review, will classify coal ash as “hazardous,” which would require more strict remediation and disposal rules than classification as “special wastes.”
140 Million Tons Annually
Duke Energy contractors and engineers survey the site of the coal ash spill on the Dan River in North Carolina.
Earthjustice, an environmental group that successfully argued in court for the December deadline, says in a report that there are 208 documented cases of contamination caused by coal ash spills. It says that coal-fired power plants generate about 140 million tons of coal-related ash and sludge a year, all of it containing toxic materials.
Public opinion turned against Duke after a pipe at an impound pond on the Dan River near Eden, N.C., failed, dumping 39,000 tons of coal ash sludge, containing toxins such as arsenic, boron, cadmium, lead and mercury, into the river.
The result was state legislation approved in August that could be a model for other state efforts. The North Carolina law, a compromise enacted during a special session, requires elimination of leaks at coal impounds but does not require removal. It left open the question of whether the cost of coal-ash remediation could be passed on to customers while setting up a Coal Ash Commission under the state Department of Public Safety.
Under the law, all basins at four of Duke’s sites — Asheville Steam Electric Plant, Dan River, Riverbend Steam Station and the L.V. Sutton Steam Electric Plant — must close by August 2019.
Duke’s remediation plan goes further. On Nov. 13, the company said it will permanently close the sites and excavate and move more than 5 tons of ash from them. It said it has 108 million tons in basins throughout North Carolina, 30 million tons in landfills and 14 million tons at its own plant sites. The company also said it is developing plans for the next phase while awaiting approval for the work at the first four sites.
“We think these excavation plans go beyond the specific information requested by the state, demonstrating our commitment to closing ash basins in a way that continues to protect the environment, minimizes the impact to neighboring communities and complies with North Carolina’s new coal-ash management policies,” said John Elnitsky, Duke’s senior vice president of ash-basin strategy. “We are prepared to proceed as soon as we have the necessary approvals from the state.”
TVA: $3.2 Billion
Duke is not the only utility confronting the coal ash issue.
The Tennessee Valley Authority this summer agreed to pay $27 million to settle claims from property owners who said they suffered damage from a 2008 spill of 5 million cubic yards of contaminated coal ash. The settlement came after a 2012 ruling from a U.S District Court judge that TVA violated its own policies. The failure of a storage pond dike at TVA’s Kingston Fossil Plant allowed tons of coal ash sludge to flow into the Emory and Clinch rivers, contaminating properties downstream.
TVA says it has spent $1.2 billion on cleanup so far and has committed to converting its wet ash storage to dry ash, at a cost of another $2 billion. The $27 million settlement is on top of about $80 million it spent to settle about 200 other Kingston-related claims. It also gave $43 million in economic-development grants in the area. That makes about $150 million in claims and grants and $3.2 billion in cleanup costs. TVA reported $11 billion in operating revenue in 2013.
It was the Kingston spill that spurred the EPA rulemaking.
Following Duke’s spill, other companies found themselves drawn into the spotlight. Two environmental groups filed suit against Louisville Gas & Electric for what they say is illegal dumping of coal ash into the Ohio River. LG&E said the treated water it releases into the river is within the limits of its state-issued discharge permits.
In a report issued last week, a Wisconsin environmental group said utilities could be contaminating drinking water by using coal ash for structural fill without first lining the deposit sites to prevent leaching in the state.
The organization, Clean Wisconsin, said the state allows such “beneficial reuse” and that up to 85% of coal ash generated in the state is reused.
“In Wisconsin, large coal plants alone generate nearly 1.8 million tons of toxic coal ash annually, of which 85% goes to ‘beneficial use’ projects. This includes dumping under churches and schools, under or atop roads, on park paths and more,” the report states. The group called for the state to adopt rules like North Carolina’s.
DTE Energy is one step closer to getting a license to build a new reactor at its Fermi nuclear complex near Monroe, Mich., though it appears unlikely it will soon commit itself to actually starting construction.
The Nuclear Regulatory Commission staff has completed a Final Safety Evaluation Report on the Fermi 3 project. The Michigan company in 2008 began pursuing a combined construction-operation license at the complex, the site of the experimental Fermi 1 reactor and Fermi 2.
DTE has spent an estimated $30 million so far on the licensing process, though new nuclear projects have become less competitive in an age of cheap natural gas. The estimated cost to build the reactor, originally $3 billion, is now more than $10 billion.
NRG Vows to Cut CO2 Emissions by 50% by 2030, 90% by 2050
NRG Energy announced that it will cut its current overall carbon emissions in half by 2030 and by 90% by 2050.
CEO David Crane, at the groundbreaking for its new Princeton, N.J., headquarters, said NRG has already made significant moves to reduce emissions by retiring older power plants and investing in renewable energy.
Crane said NRG’s strategy is a response to its corporate customers who are striving to reduce emissions. “We are working with these companies on putting solar panels all over their facilities, and it’s helpful for them to know that we’re heading in the right direction,” he said.
NTE Energy to Build 540-MW Combined-Cycle Plant in Ohio
Middletown Energy Center Rendering (Source: NTE)
The Ohio Environmental Protection Agency gave NTE Energy a crucial air permit for its proposed 525-MW combined-cycle natural gas plant near Middletown.
The company, based in St. Augustine, Fla., said it hopes to break ground early next year. Several other permits are needed before construction can begin. The $500 million Middletown Energy Center would connect to Duke Energy Ohio’s transmission system when it is begins operations in mid-2018.
A group of Commonwealth Edison workers who call themselves the “42 Megawatts” won $1 million in the Mega Millions drawing.
The group has been collecting a pool for six years. “Over the years some members have dropped out and new ones have joined,” one of the winners, Patty Jordan, said in the statement. “We’ve always each put $2 per week into our lottery pool. I don’t think any of us really expected we would win a prize like this.”
Excepting taxes, each of the 42 members’ share is about $23,800.
FirstEnergy Gets OK from PUCO to End Most Energy-Efficiency Programs
The Public Utilities Commission of Ohio approved a FirstEnergy plan to end consumer energy-efficiency programs at the end of the year.
FirstEnergy is the only Ohio electric company that asked to end its efficiency programs under a new law enacted last spring. The programs gave rebates and discounts for Energy Star appliances and rewards for turning in old appliances. FirstEnergy’s move to end the subsidies was opposed by the Office of the Ohio Consumers’ Council, the Natural Resources Defense Council and the Environmental Law and Policy Center.
FirstEnergy will be allowed to continue to assess a surcharge on customers’ bills to finance the programs. Any over-collections will be returned to customers in a later “true-up,” the commission said.
Salem 1 Returns to Service After Month-Long Fueling Outage
Salem nuclear generating station Unit 1 returned to service early Sunday after a month-long outage for refueling and inspections.
A third of the 193 fuel assemblies in the reactor were swapped out, and several major values replaced, during the outage. The other two reactors on Artificial Island — Salem 2 and Hope Creek — continued to operate at full power.
Dominion bought a 50-MW solar project in Millard County, Utah, from juwi solar for an undisclosed price. The plant is expected to begin operations in the second half of 2015. It has a 20-year power-purchase and interconnection agreement in place.
The new project will be added to Dominion’s portfolio of 324 MW of solar facilities in California, Connecticut, Georgia, Indiana and Tennessee. Dominion Virginia Power, the company’s regulated utility, also has a number of solar projects in operation or development.
TVA Awards Employee Bonuses Averaging $11,400 Each
The Tennessee Valley Authority is awarding “winning performance” bonuses to each of its 11,500 employees for meeting major goals in the past year. The company is shelling out $131 million, which comes to an average award of about $11,400.
CEO Bill Johnson, who was paid $4.6 million in fiscal year 2014, said the company met its goals for plant performance improvements, reductions in operating costs and lowered accident rates. The company earned $469 million on $11.1 billion in revenue for 2014, the best in four years. TVA cut nearly 2,000 positions in the past year.
PPL’s Sale of Montana Hydro to NorthWestern Energy Final
PPL completed the sale of 11 hydroelectric plants in Montana to NorthWestern Energy for $890 million. NorthWestern also bought the Hebgen Lake reservoir. PPL retained its interests in the Colstrip and J.E. Corette coal-fired power stations and a Butte-based energy marketing operation.
PPL paid $1.6 billion for the Montana hydro and fossil units in 1999. The hydro units were problematic for PPL, which successfully countered a move by the state to pay it $50 million in back and future rent for the riverbeds under the plants. PPL appealed the case to the U.S. Supreme Court and won.
The National Security Agency director said China and “one or two” other countries have the ability to shut down the U.S. electric grid through cyberattacks. It was the first confirmation by Adm. Michael Rogers that the national grid was vulnerable to such an extent.
Rogers told the U.S. House Intelligence Committee that China and other foreign powers are regularly making electronic “reconnaissance” missions to better prepare themselves for possible disruptive attacks on U.S. control systems. “All of that leads me to believe it is only a matter of when, not if, we are going to see something dramatic,” he said.
Rogers said that cyberattacks are more difficult to counter than nuclear attacks, in part because while there are only a few nuclear powers, any country with a computer system and the required hacking skills could be an online threat. “You can literally do almost anything you want, and there is not a price to pay for it,” he said.
Study: EPA Emissions Rule Will Cause Energy Prices to Soar
A study commissioned by the world’s largest coal company, Peabody Energy, predicts that the Environmental Protection Agency’s emissions rule, along with other regulations and natural gas prices, will increase U.S. energy prices by nearly $300 billion by 2020.
The study, by Energy Ventures Analysis, concluded that the regulations and resulting market forces will increase a typical household’s yearly electricity and natural gas bills by $680, or 35%, between 2012 and 2020.
The consulting firm said its analysis is the first to fully examine the combined economic impacts of the EPA’s proposed and finalized regulations on the electric power industry, including the Mercury and Air Toxics Standards, regional haze regulations and the Clean Power Plan.
NRC Finds 3 Security Violations at NextEra’s Seabrook Nuke Plant
An October inspection at NextEra Energy’s Seabrook nuclear generating station in New Hampshire turned up three security violations, and the Nuclear Regulatory Commission has ordered the company to fix the errors.
The NRC did not disclose the nature of the violations, in keeping with post-9/11 security requirements, but NRC Spokesman Neil Sheehan said they were not serious enough to result in increased oversight at the plant.
“Nevertheless, we are requiring the company to take actions to permanently address the issues and then notify us in writing that those steps have been completed,” Sheehan said. “We will follow up in future security inspections to ensure the fixes have been thorough and satisfactory.”
Washington State Pol Calls on NRC to Complete Yucca Mountain Review
Sen. Patty Murray, a Democrat from Washington state, called on Nuclear Regulatory Commission Chairwoman Allison Macfarlane to complete the agency’s review of the stalled Yucca Mountain nuclear waste repository in Nevada.
Murray, whose state is home to the Hanford Nuclear Reservation, a major source of nuclear waste, praised the NRC for restarting the safety review of the Yucca Mountain project and called for the commission to complete the review.
“With countless work hours to date spent by the NRC on the licensing application and billions of dollars spent at the Hanford Nuclear Reservation and at nuclear waste sites across the country in efforts to treat and package nuclear waste that would be sent to Yucca Mountain, it is imperative … [the] licensing application is thoroughly considered by the NRC,” Murray said in her letter to Macfarlane.
Murray’s move is regarded as a sign of the waning power of Senate Majority Leader Harry Reid of Nevada, who will become minority leader when Senate control shifts to the Republicans. Reid has been a fierce opponent of the Yucca Mountain project.
GOP Calls for FERC Conference on Reliability Impact of EPA Rules
Sen. Lisa Murkowski (R-Alaska), incoming chairman of the Senate Energy and Natural Resources Committee, and Rep. Fred Upton (R-MI), chairman of the House Energy and Commerce Committee, yesterday asked the Federal Energy Regulatory Commission to hold a technical conference with federal agencies and stakeholders to discuss the reliability impacts of new federal environmental regulations.
The request follows a November report by the North American Electric Reliability Corp. that raised reliability concerns over the Environmental Protection Agency’s proposed carbon emission rule. NERC said the power industry will need to replace 103 GW of retired coal resources by 2020, including more than 50 GW of retirements already announced in response to the EPA’s Mercury and Air Toxics Standard.
The Republicans said congressional testimony by FERC commissioners “suggests EPA did not properly consult with the commission when writing its proposed rule and ignored recommendations from the Government Accountability Office (GAO) that a formal, documented process be established among relevant federal agencies to monitor reliability challenges.” (See FERC Split on Reliability Analysis of EPA Rule.)
A repeat of last winter’s polar vortex should not imperil the nation’s power system, the North American Electric Reliability Corp. said last week. Lessons learned from last year’s extreme weather and subsequent operational reviews have left the U.S. better prepared compared to early 2014, NERC said in its 2014-2015 Winter Reliability Assessment.
“Last year, the system bent, it twisted, but it didn’t break,” John Moura, NERC’s director of reliability assessments, said in a press briefing Friday. He said various scenario analyses of weather, and fuel resource and plant availability, were run to recreate January’s polar vortex under current operational conditions.
NERC concluded that “all areas appear to have sufficient resources,” he said. Moura noted familiar themes: an increased reliance on natural gas could cause fuel constraints and limit the availability of some plants during cold snaps.
While New England is “at the forefront of concern” for areas with heavy reliance on gas, he said significant progress has been made in addressing that need through ISO-NE’s winter reliability program. (See ISO-NE in Precarious Position for Winter.)
Moura said that coal delivery and supplies have become concerns in the Midwest and elsewhere that require monitoring, but he characterized it as isolated to relatively few plants and a low risk to grid reliability.
New PJM Demand Record
Hints of the coming winter hit PJM Nov. 18 when unseasonably low temperatures pushed the RTO beyond its previous November demand record. The preliminary peak demand was 121,987 MW at 7 p.m. Real-time prices topped $200/MWh throughout much of PJM at 6 p.m., with the Dayton Power and Light zone highest at $287. The previous November record, set in 2013, was 114,699 MW.
(Click to zoom)
New England got some good news last week from the latest National Oceanic and Atmospheric Administration 90-day forecast, which said that slightly higher temperatures than previously forecasted are expected in the region. Chances for slightly drier weather have increased along the Great Lakes and in the Ohio Valley. However, the probability of above-normal levels of precipitation along the eastern seaboard up to southern New England has increased.
FERC Query on RTO Fuel Assurance
Meanwhile, the Federal Energy Regulatory Commission on Nov. 20 ordered RTOs and ISOs to file reports within 90 days on their efforts to ensure generators have adequate fuel (AD13-7, AD14-8).
This topic has been on FERC’s radar since at least 2013 but became more acute after last winter, as natural gas generators faced price spikes and an inability to obtain fuel. The high prices meant dual-fuel capable plants in New York and New England burned unexpectedly large amounts of oil.
The following items were approved by members Thursday with little discussion or opposition:
Markets and Reliability Committee
Interchange Limits Approved
The MRC approved PJM’s proposal to limit interchange during emergency conditions by acclamation, with five objections. An MRC sector-weighted vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
To address concerns raised by PJM’s Independent Market Monitor, the proposal was revised to include language to address hoarding and manipulation of interchange “room.” The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.
In a related matter, the Members Committee approved revisions to Manual 11, Manual 28 and the Tariff concerning energy and reserve pricing.
Gas Unit Commitment Rules OK’d
Members approved changes to gas unit commitment rules, including a provision allowing generators to change their offers to reflect fluctuating fuel prices. Generators will be able to lock in their fuel prices three hours in advance of the operating hour. Officials said the increased flexibility will require software changes that should be complete in January.
The option will be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)
PJM conducted training for system dispatchers yesterday on the changes.
Sampling to be used for Measuring Residential DR
Members approved a proposal allowing PJM to measure the demand response performance of some residential customers through sampling of interval-meter data. The new measurement method will replace outdated studies dating back to 2001.
The change won support of almost 81% of members on a sector-weighted vote. It was approved over opposition by Market Monitor Joe Bowring, who said sampling would not be as accurate as metered data. “We know when generators fail to respond because they are metered,” Bowring said. “The same will not be true here.”
PJM officials said sampling will improve accuracy without the cost of installing one-minute meters on every participating household. PJM’s Shira Horowitz said the new method builds on an “extremely successful” pilot program.
FirstEnergy’s Jim Benchek also opposed the change, saying it was a “carve out” for DR. He also said it was “inappropriate” to continue incorporating DR in the wholesale market in light of the D.C. Circuit Court of Appeals’ EPSA ruling, which concluded that DR in the energy market fell under the jurisdiction of the states and not under the Federal Energy Regulatory Commission’s authority over wholesale markets. (See New Measurement Rules for Residential DR OK’d; FirstEnergy Opposes.)
Seller Credit Eliminated
Members agreed to eliminate the “seller credit” provision from its credit policy, which RTO officials said was no longer needed. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.
Manual Changes
Manual 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The change will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts. In cases of shortages those parties due payments would be “short paid” on a pro-rata basis. Shortages will not be socialized among all members.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).
Members Committee
The committee approved:
Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.
PJM stakeholders deadlocked for the third time Thursday on changes to the $1,000/MWh energy offer cap, leaving it to the Board of Managers to decide whether to seek Federal Energy Regulatory Commission approval of any changes.
Old Dominion Electric Cooperative’s Ed Tatum withdrew a compromise proposal to raise the cost-based offer cap to $1,800 in the face of opposition from load representatives following a lively Members Committee debate.
Members’ inability to reach consensus means the board would have to make a unilateral Section 206 filing to win FERC approval for any change.
PJM CEO Terry Boston expressed disappointment. “I was hopelessly optimistic that we could get to a [Section] 205 filing,” he said.
“There will be other times” when the cap is exceeded, Boston said. “I really don’t like the idea that we hold in abeyance until we have an emergency. … We don’t want to be in the position that we have to run to FERC and ask for a 24-hour decision.”
In January, FERC granted the RTO’s request for a waiver, allowing make-whole payments for generators with operating costs exceeding $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover costs above the cap, as spot gas prices spiked as high as $140/MMBtu.
Earlier this month, Calpine Energy Services requested that FERC allow it to recover about $3.3 million it said it spent on expensive gas for two generating units at PJM’s direction and was unable to burn when the RTO cancelled their plants’ dispatches (ER15-376). Calpine’s claim is similar to those filed earlier by Duke Energy, which is seeking $9.8 million for “stranded” gas (EL14-45) and Old Dominion, which is seeking $2.7 million (ER14-2242). (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)
In April, PJM members agreed to form a task force to consider changing the cap. The group was unable to reach consensus after nine meetings and has since disbanded.
The proposal presented Thursday resulted from negotiations led by Tatum and Mike Borgatti, of Gabel Associates, who represented generators. It would have allowed cost-based offers between $1,000/MWh and $1,800/MWh to set LMPs. Generation costs above that cap would be recovered through uplift.
Maximum market-based offers would be capped at $1,000 or the cost-based offer.
The majority of members who spoke Thursday strongly opposed the changes. Even those who encouraged the proposal’s passage conceded they supported it only as a better alternative to losing control over the matter to FERC. A 205 filing also would show a cohesiveness among the group, they said.
“This is not a proposal that Old Dominion would have come up with,” Tatum said in making his presentation. But, he said, “I think we’ve gone as far as we can go with this.”
Susan Bruce of the PJM Industrial Customer Coalition said her group opposed the proposal. “There is a lack of evidence of a systemic problem,” she said.
Market Monitor Joe Bowring said fewer than 25 offers breached $1,000 in January. While some of the proposed offers were in the $1,700/MWh range, Bowring said there were no legitimate offers greater than $1,400/ MWh.
Walter Hall, representing the Maryland Public Service Commission, said Tatum’s proposal represented not a “compromise” but a concession to generators’ attempts to profiteer.
“We fear this is a profit-making opportunity [for generators], not a cost-recovery opportunity,” he said. “Why should everyone profit from something of that nature?”
Jim Jablonski of the Public Power Association of New Jersey referred to the Market Monitor’s March 26 report to FERC, which concluded that only $9,118 of $583,774 in additional compensation sought by seven units in three PJM control zones when gas prices peaked in January was legitimate.
And, he said, “that was at the worst of times. I certainly don’t see the justification for above $1,000.”
Carl Johnson, representing the PJM Public Power Coalition, said approving the Tatum-Borgatti proposal would have been preferable to “throwing a jump ball at FERC.”
“It’s not perfect, but it is way better than that outcome,” he said.
J.P. Morgan Ventures Energy’s Bob O’Connell, who had debated Tatum over the issue at the October MC meeting, said he came into Thursday’s forum opposed to the newest proposal. (See Load, Supply Trade Blame over Offer Cap Impasse.)
But, he said, “the deal you see on the table is a deal that can get done. This is not about getting what you want — it’s about not getting what you don’t want.”
State-by-state compliance with the Environmental Protection Agency’s (EPA’s) proposed carbon emission rule would be almost 30% more expensive than a regional approach, according to preliminary results of PJM analyses.
The analyses included eight scenarios requested by the Organization of PJM States (OPSI) and seven proposed by PJM.
One analysis (PJM scenario 4), which included existing fossil resources and planned resources with interconnection service agreements (ISAs) and facility study agreements (FSAs), estimated a 2020 carbon price of $11/ton under state compliance, compared with $2/ton under a regional approach.
PJM determined the CO2 emissions prices based on the price differential needed to ensure the RTO’s economic dispatch displaced enough high-emitting generators with lower-emitting generation to reach the emissions targets.
The regional approach sets a single carbon price for all fossil fuel generators in PJM. Under state compliance, each state would have a different carbon price. Indiana and West Virginia would face the highest carbon prices under a state-by-state approach, with prices exceeding $14/ton, while it would cost Maryland and Virginia only about $5/ton.
Under a regional plan, “states have the ability to trade reductions among each other to achieve lower costs of compliance,” explained Chief Economist Paul Sotkiewicz. Sotkiewicz and PJM engineer Muhsin Abdur-Rahman presented the preliminary results of the analyses at the Members Committee webinar last week.
Total compliance costs would near $45 billion in 2020 under the state approach, versus $35 billion using regional compliance.
Mass-to-Rate Conversion
PJM initially did the analyses based on the implied mass-to-rate conversion in the EPA’s June 2 proposed rule. It redid the calculations based on revised guidance the agency provided Nov. 6, which sets a declining mass target over the interim compliance period (2020-2029) and does not credit new renewables and incremental energy efficiency.
Under the revised conversion, most of the scenarios estimated carbon prices of about $5 to $10 per ton in 2020, rising to $20 to $30 per ton in 2029.
One scenario (PJM #8) saw carbon prices starting at about $40/ton in 2020 and rising to almost $60/ton by 2029. The scenario adjusted planned natural gas capacity based on historic commercial probabilities (greater than 70% for projects with ISAs, greater than 50% for those with FSAs), reduced new combined-cycle capacity to not exceed the installed reserve margin target and assumed a 50% increase in gas prices.
The analyses found that a rate-based approach would result in lower LMPs than a mass-based measurement, meaning generators will need to collect more in capacity revenues. There were little or no increases in LMPs for many scenarios.
