As temperatures soared into the 80s outside PJM offices last week, stakeholders began debating how to avoid a repeat of the operational problems from last winter.
Operating Committee members discussed a problem statement and issue charge on gas-unit-commitment coordination, a response to PJM’s problems in scheduling gas-fired plants in January.
About one quarter of PJM’s outages on Jan. 7 were the result of gas units’ inability to obtain fuel.
Gas pipeline rules caused delays in the starting of some units and restricted PJM’s ability to dispatch units as needed. The Operating Committee’s initiative will seek methods for gas generators to communicate such operating restrictions to PJM dispatchers.
It will also respond to complaints by about 10 companies that they were left with “stranded gas” when PJM failed to dispatch their units in January. Duke Energy has filed a claim in an effort to recoup $9.8 million in gas losses, and NextEra Energy Resources said it will make a similar claim to recoup $1.3 million. (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim).
“We need to get some changes in prior to next winter, even if we need to segregate short-term [solutions] from long-term,” said Mike Bryson, executive director of system operations. The short-term solution may be a simple clarification of existing rules for RTO dispatchers and generators while PJM develops a long-term solution, he said.
The Operating Committee focused on education and interest identification in last week’s session. It will continue its work in a special meeting June 23.
States could cut their costs of complying with the Environmental Protection Agency’s carbon emission rule by more than one-quarter through 2020 by joining a regional compliance program similar to the Regional Greenhouse Gas Initiative (RGGI) cap-and-trade program.
The EPA estimates total compliance costs of $7.5 billion in 2020 (2011$) if states comply individually, versus $5.5 billion if all states take a regional approach.
Costs rise to $8.8 billion (2011$) in 2030 under state compliance, compared with $7.3 billion for the regional approach.
“States may choose to cooperate in order to achieve more cost-effective outcomes, since some states can reduce their emissions more easily relative to others,” the agency explained. It “expects this flexibility to reduce the cost of achieving the state goals and therefore expects it to be attractive to states. For example, the RGGI-participating states could choose to submit a multi-state mass-based plan that demonstrates emission performance by affected [electric generating unit (EGU)] on a multi-state basis. Additional states may also choose to join a multi-state plan.”
Individual state plans must be filed with the agency by June 30, 2017, with a one-year extension possible. Regional plans won’t be due until June 30, 2018.
The EPA’s regional analysis assumed five regions based on North American Electric Reliability Corp. (NERC) regions and RTO footprints. States that fall into more than one region were grouped in the region that comprised the majority of geography or generation. Thus, the EPA’s “East Central (PJM)” region included only seven states: Ohio, Pennsylvania, West Virginia, Maryland, Delaware, New Jersey and Virginia (see map.)
Regional Zones in EPA Proposed Carbon Rule (Source: EPA)
Mass- or Rate-Based Standards
The EPA’s default state emission limits are rate-based, setting limits measured in pounds of CO2 per MWh of generation. States have the option of converting the rate-based standards to a mass-based limit measured in tons of CO2. The regional plans also have the choice of a rate-based standard or the mass-based caps used by RGGI. (See related story, LaFleur, Bay: ‘Flexibility’ of EPA Rules Mitigates Reliability Concerns.)
The agency invited comment on suggestions that it develop a model rule for an interstate emissions credit trading program that could be easily adopted by states.
Nine states, including Maryland and Delaware in PJM, participate in RGGI. New Jersey withdrew from the program in 2011. (See related story, EPA’s Carbon Rules Attacked from Both Flanks.) California has established an economy-wide, market-based greenhouse gas emissions trading program, which requires the state to reduce its 2020 GHG emissions to 1990 levels.
Map of States Participating in RGGI
RGGI, which was created in 2009, sets an overall limit on allowable CO2 emissions from affected generators. Participating states issue carbon allowances based on their annual emission budgets.
At the end of each three-year compliance period, affected generators must submit CO2 allowances equal to their reported carbon emissions. The allowances may be traded among both regulated and non-regulated parties, creating a market and price signal for emissions. The price signal factors into the economic dispatch of affected generators.
Between 2009 and 2012, the RGGI states invested auction proceeds of more than $700 million in programs to lower energy costs and reduce emissions, such as energy-efficiency programs.
Power sector carbon emissions in the RGGI-participating states fell by more than 40% between 2005, when RGGI was announced, and 2012. The EPA acknowledges RGGI was not the primary driver for these reductions — reduced electric demand following the 2008 recession was a big factor. In January, the group lowered its 2014 CO2 emission cap by 45%.
PJM Role?
The EPA also is seeking comment on how PJM and other RTOs and ISOs could help states achieve efficiencies, a role suggested by the ISO/RTO Council.
“Just as the ISO/RTO regions today share the benefits and costs of efficient EGU dispatch across state boundaries, there are significant efficiencies that could be captured by coordinating individual state plans or implementing multi-state plans within a grid region,” the agency said. “Under one variant of this approach, states would implement a multi-state plan and jointly demonstrate CO2 emission performance by affected EGUs across the entire ISO/RTO footprint.”
The Federal Energy Regulatory Commission didn’t follow environmental laws when it approved a natural gas pipeline in New Jersey, a federal appeals court ruled. FERC approved the Tennessee Gas Pipeline’s 40-mile Northeast Upgrade project, which would have followed an existing pipeline’s route, in 2012. The Delaware Riverkeeper Network, the New Jersey Highlands Commission and the New Jersey Sierra Club argued that FERC did not take into account other expansion projects under consideration at the same time.
The U.S. District Court of Appeals in the District of Columbia last week agreed, sending the matter back to FERC for another review. “In conducting its environmental review of the Northeast Project without considering the other connected, closely related and interdependent projects on the Eastern Leg, FERC impermissibly segmented the environmental review in violation of NEPA,” the three appellate judges wrote in their decision. Kinder Morgan, the company that built and maintains the pipeline, says it will reapply for the necessary permits.
Maya van Rossum, head of the Delaware Riverkeeper Network, said FERC has been allowing “illegal segmentation” by pipeline companies for years. “It is rewarding that a federal court has finally held FERC to account,” van Rossum said.
Nuclear Regulatory Commission Chairwoman Allison M. Macfarlane toured two Michigan nuclear plants last week to view safety upgrades put in place after the Fukushima crisis in Japan. Macfarlane was accompanied by Michigan Rep. Fred Upton (R), chair of the House Energy and Commerce Committee. “A lot has changed since Fukushima,” Upton said. “It’s important that we learn from that.” They were shown additional safety equipment and other improvements taken in the wake of the nuclear incident in Japan.
A recent internal Nuclear Regulatory Commission survey found that 75% of respondents said they were punished with poor performance reviews after objecting to agency decisions. The NRC Office of Enforcement conducted the survey last year.
In it, three-quarters of the employees who responded say they registered “non-concurrence” in certain situations and were later slapped with the poor performance reviews. Additionally, 63% said they felt they were excluded from certain tasks as a result of disagreeing with commission rulings, and 25% said they thought their criticisms had cost them a promotion. A quarter of respondents said they had been verbally abused by supervisors after objecting to certain decisions.
The report was released after Sen. Edward Markey (D-Mass.) cited it during a hearing last Wednesday. Markey said he was concerned that NRC staffers may be afraid to question established rules. “Especially post-Fukushima, it’s very important that we get this culture to change,” he said. He added that his staff has heard from other whistleblowers as well. “They feel that when they step forward to report safety, security or other problems, they are systematically retaliated against.”
Nuclear Regulatory Commission and Indian Point officials are searching for the source of a spike in tritium found in monitoring wells near the nuclear plant. The spike was found near Indian Point Unit 2 in March. Subsequent testing last month found that the levels had decreased 92%, but officials are still concerned.
NRC officials said the contamination exceeds Environmental Protection Agency standards but is not a public health concern because it was located in bedrock and not in water used for drinking. “The levels that we’re talking about here are very much on the low side,” NRC spokesman Neil Sheehan said. Tritium, a byproduct of nuclear power production, is a radioactive form of hydrogen.
An Associated Press review of NRC records in 2011 found 48 of 65 reactor sites had tritium leaks.
The National Academy of Sciences is studying rates of cancer and other illnesses in the communities surrounding Exelon’s Oyster Creek nuclear plant and six other nuclear generators. The academy is conducting the study at the request of the Nuclear Regulatory Commission to see if a broader analysis of all plants is needed.
Earlier studies failed to find a link between commercial nuclear plants and higher cancer rates, but some think that study was flawed because it only examined cancer deaths among men and didn’t include women and children.
Florida Atlantic University lease area (Source: Bureau of Ocean Energy Management)
The federal Bureau of Ocean Energy Management last week awarded a lease to Florida Atlantic University to test hydrokinetic energy equipment off the coast of Fort Lauderdale, the first time a lease has been awarded for such technology. The university’s Southeast National Marine Renewable Energy Center applied for the lease to test various demonstration devices in an area about 10 miles offshore.
The project involves anchoring several “test berths” to test ocean current turbine designs. The university will next submit a project plan for review. “This project is a potentially paradigm-shifting development in the global quest for clean energy,” FAU President John Kelley said.
The Demand Response Subcommittee will seek ways to improve measurement and verification of emergency demand response under an issue charge approved last week by the Market Implementation Committee.
Existing procedures, which use the hour before an event as the default customer baseline (CBL), may be inaccurate for dispatches in the early morning and on days with multiple dispatches, PJM says. PJM’s Pete Langbein said the current process can also require a cumbersome administrative process requiring an electric distribution company review.
PJM estimates the work will take six months if only manual changes are needed and nine months if Tariff changes are required. The goal is to have all changes in place prior to start of the 2015/16 delivery year.
Sea turtles, sturgeon, wetlands and shipping accidents — transmission developers seeking the contract to fix the Artificial Island stability problem invoked all of them and more last week in arguments against their competitors.
All five of the development teams identified as finalists filed comments with PJM, the last chance for contestants to make their case before PJM planners announce their selection next Monday.
State regulators also weighed in, as did PSEG Nuclear LLC, the operator of the Salem and Hope Creek nuclear plants at Artificial Island.
North or South
Each of the finalists has proposed a 500-kV line paralleling an existing 500-kV line to Red Lion, Del., including Delmarva Power’s Delaware River crossing north of Artificial Island.
Supporters say using an existing path could result in less public opposition than a new southern overhead crossing envisioned in 230-kV proposals by LS Power and Dominion. The two companies and Transource Energy, a joint venture of American Electric Power and Great Plains Energy, have also proposed southern routes with submarine crossings.
Environmental Concerns
Wetlands in New Jersey would be impacted by the northern 500-kV route. (Source: PSEG)
But the New Jersey Board of Public Utilities said the developers of the 500-kV proposals might have difficulty winning regulatory approvals because the path would cross the Supawna Meadows National Wildlife Refuge, the Alloway Creek Watershed Wetland Restoration Site and the Abbotts Meadow and Mad Horse Creek Wildlife Management Areas.
The BPU noted that the Susquehanna to Roseland 500-kV transmission line was delayed for three years because of problems obtaining approvals to cross federal lands even though it had been designated for “rapid response” by the Interior Department. The project “resulted in protests, delays and costs well above initial estimates for mitigation,” BPU said.
“PJM’s analysis of the five projects in the Red Lion 500-kV option group recognizes negative impacts for all as to wetlands and land permitting but only `some impacts’ as to public opposition,” the BPU continued. “In our experience, that is an optimistic view of the likely public response to these projects.”
LS Power agreed, citing an opinion from its outside counsel concluding that permitting of the northern route “is likely not obtainable,” due in part to the existence of the southern crossing options.
Sunken Ship Cove (Source: PSEG)
Transource argued that its submarine crossing proposal was preferable to an overhead line, noting the potential for shipping accidents, such as a 1987 crash that resulted in a nine-month outage to the Delmarva Power crossing. Transource also said an overhead crossing would require towers about 100 feet tall, which could increase the likelihood of public opposition.
PSE&G, which proposed a northern route, countered that the submarine crossing proposed for the southern route could impact a submerged dike “normally considered historic in nature,” an artificial reef created from sunken World War I ships (Sunken Ship Cove) or habitats for protected species, “including the shortnose sturgeon, the Atlantic sturgeon, the hawksbill sea turtle, the loggerhead sea turtle, Kemp’s ridley sea turtle and the leatherback sea turtle.”
Order 1000 Implications
Even before making a selection decision that is certain to disappoint all but one of the finalists, PJM is already receiving criticism for how it has managed the competition — the first in PJM under the Federal Energy Regulatory Commission’s Order 1000.
The Delaware Public Service Commission complained that the proposed cost allocation for the 230-kV solutions “displayed neither logic nor fairness” in assigning all of the cost to the Delmarva Power zone. In contrast, the cost of the 500-kV proposals would be spread among two dozen transmission zones and merchants. (See Delaware Unhappy with Artificial Island Cost Allocation.)
The commission requested PJM planners provide details on the distribution factor (DFAX) analyses for the 230-kV and 500-kV solutions and “explain how a transmission project to alleviate an operational issue in one transmission zone could be solely the cost responsibility of a different transmission zone.”
The Exelon-Pepco team criticized PJM planners’ modifications to developers’ plans, which included the addition of static VAR compensators (SVCs) to all projects and the removal from the Dominion and PSEG proposals of a second Hope Creek-to-Salem tie line. (See Dominion, PSE&G Proposals Gain in Artificial Island Race.) “The tweaking of proposals eliminates the competitive nature intended by the FERC Order 1000 process,” said Exelon-Pepco.
Transource said PJM should make its decision based on the merits of the projects as proposed rather than comparing them after PJM’s modifications.
“This will send a strong signal to developers that the relative quality of their work will be rewarded in the PJM process and that the burden is on the developers, not PJM, to get the details right,” Transource said. “It would set a concerning precedent if PJM decided that none of the proponents `sponsored the selected project,’ based on the modifications made by PJM, and designated the project to the incumbent transmission owner(s).”
Nuclear Operator’s Concerns
PSEG Nuclear also criticized PJM planners’ decision to use SVCs, saying they have never been used to correct “transient angular stability” and would pose “unknown and potentially challenging regulatory risks.”
The company noted that Artificial Island is the “second-largest nuclear installation in the country with well-known stability challenges.”
“The worst case consequences that will result from a contingency-induced stability event coincident with an SVC failure include loss of all offsite power to the three co-located nuclear units at AI as well as potential collateral impacts to the offsite sources at neighboring regional nuclear plants,” the company said. “These consequences will influence the [Nuclear Regulatory Commission] to require an in-depth review.”
PJM planners will recommend almost $150 million in transmission upgrades in the Atlantic City Electric transmission zone to address reliability problems anticipated from the retirement of the B.L. England coal-fired generator.
Greenpeace demonstrators protest B.L. England coal generator (Source: Greenpeace)
B.L. England Unit 2 is under a consent order to shut down in June 2015 due to emissions rules, and Unit 3 and a diesel unit may shut down at the same time, PJM’s Paul McGlynn told the Transmission Expansion Advisory Committee during a presentation last week. The at-risk units total about 300 MW. England’s 129-MW Unit 1 retired May 1.
Rockland Capital’s plans to repower the units have been stymied by the New Jersey Pinelands Commission’s rejection of a proposed 15-mile natural gas pipeline through the protected region. (See Plant Retirement Could Spur $148 Million in Tx Upgrades.)
“We think it’s prudent to recommend to move forward with the upgrades,” McGlynn said. If the pipeline were approved and the units remain active, some or all of the proposed upgrades would be cancelled, McGlynn said.
The RTO will recommend the Board of Managers include the upgrades in the Regional Transmission Expansion Plan (RTEP), but the projects aren’t expected to be complete until 2016, leaving the area at risk for multiple N-1-1 violations.
The proposed upgrades include:
Removal and reconfiguring of the New Orchard-Cardiff 230-kV line ($57 million).
Addition of new Upper Pittsgrove-Lewis 138-kV line ($28 million).
Cardiff substation work to accommodate new Orchard-Cardiff 230-kV line and new Cardiff-Lewis 138-kV line ($16.4 million).
Conversion of the Landis substation to a ring bus and connection of three lines to it ($13.4 million).
The Environmental Protection Agency’s proposed carbon emission rule took fire last week from both Republicans and coal-state Democrats — who said it would cause economic woes — as well as environmentalists, who said it was an inadequate response to climate change.
Senate Minority Leader Mitch McConnell (R-Ky.) called the rule a “dagger in the heart of the American middle class and to representative democracy itself.”
“The president’s plan is nuts,” said House Speaker John Boehner (R-Ohio).
“President Obama promised to make electricity rates skyrocket,” tweeted Rep. Marsha Blackburn (R-Tenn.), vice chair of the House Energy and Commerce Committee. “Unfortunately, this is one pledge he intends to keep.”
“There is no doubt that 7 billion people have had an impact on our world’s climate,” said Sen. Joe Manchin (D-W.Va.). “However, the proposed EPA rule does little to address the global problem with global solutions.”
Too Little
Some environmentalists were equally dismissive. “This is like fighting a wildfire with a garden hose — we’re glad the president has finally turned the water on, but it’s just not enough to get the job done,” said Kevin Bundy of the Center for Biological Diversity’s Climate Law Institute in a statement.
Bill McKibben
“I think it’s properly ambitious — for the first term of the Bill Clinton administration,” Bill McKibben, president of environmental group 350.org, told The New York Times. “Given the melting Antarctic, we obviously should be doing far, far more, but at least we’re finally started, and that’s to Obama’s credit.”
The U.S. Chamber of Commerce straddled the issue, both criticizing its cost and dismissing it as ineffectual. CEO Thomas J. Donohue said in a statement that the rule will “add immense cost and regulatory burdens on America’s job creators.”
Meanwhile, Stephen Eule, a vice president at the Chamber’s Institute for 21st Century Energy, said the rule would have little impact.
“No matter what your view of climate change, these [U.S.] reductions will be dwarfed by increased emissions in other parts of the world,” Eule told The Wall Street Journal. “For every ton of carbon dioxide that’s reduced in the administration’s proposal, there will be at least six to seven tons of increase [elsewhere]. Unless the rest of the world gets on board, this won’t have an impact on the climate.”
State Response
Politico reported that lawmakers in at least eight states have approved symbolic anti-EPA resolutions based on a model from the American Legislative Exchange Council, a conservative group.
Kentucky enacted a law this spring that goes beyond symbolism, seeking to bar the state from complying with the rule. The EPA has said it will develop compliance plans for states that fail to produce their own.
Not all Republicans and coal-state officials reacted negatively, however.
New Jersey Gov. Chris Christie made no public comment on the rule last week and did not sign a GOP-backed letter calling for the rules to be blocked. A spokesman for the state’s Department of Environmental Protection said the Christie administration supports the rule.
Christie, a potential 2016 Republican presidential hopeful, pulled New Jersey out of the Regional Greenhouse Gas Initiative cap-and-trade program in 2011, the same year he reduced the state’s renewable power goal from 30% to 22%.
Illinois Gov. Pat Quinn, a Democrat facing re-election this year, heads a state that depends heavily on both coal and nuclear power. It is the fifth-largest coal producer in the nation. Regardless, he came down firmly on the side of the new rule.
Teresa Marks
“I commend President Obama for confronting this critical issue,” Quinn said in a statement. “Illinois has seen the devastating impacts of severe weather first-hand with 11 natural disasters over the past five years. Moving toward a cleaner, more reliable and resilient energy system will bring significant benefits to our communities and our state.”
Teresa Marks, director of the Arkansas Department of Environmental Quality, told the Times the plan was reasonable. “This is not going to be the Armageddon that some people think,” she said
Federal Energy Regulatory Commission officials said last week that the Environmental Protection Agency’s proposed carbon emission rule appears to provide enough flexibility and time for compliance to address potential reliability concerns.
Acting FERC Chair Cheryl LaFleur and nominee Norman Bay gave their preliminary assessments in written comments to the Senate Energy and Natural Resources Committee, which is considering their nominations to the commission.
“My understanding is that EPA’s proposal offers broad flexibilities that will empower states to design state implementation plans that ensure resource adequacy and reliability,” said Bay, thedirector of FERC’s Office of Enforcement. “In addition, the proposal does not require any compliance until 2020, and it gives states flexibility over a 10-year period through 2029 to reach their overall emission rate targets.”
LaFleur said the proposed rule “gives significant flexibility to states and permits regional approaches to compliance.”
She said that FERC provided input to the EPA “from a reliability perspective” as part of the Office of Management and Budget (OMB) interagency review process.
“FERC has a role in ensuring that the energy infrastructure and markets adapt to new environmental requirements through its authority over transmission ratemaking and natural gas permitting and ratemaking,” she said. “For example, if additional gas generating capacity is needed and more gas pipelines need to be built, FERC has a role in certificating those pipelines. FERC also has a role in ensuring that the regulations under its jurisdiction are sufficient to attract needed investment in electric transmission and gas pipelines.”
Their responses didn’t satisfy Sen. Lisa Murkowski (R-Alaska), the ranking Republican on the Energy Committee. “I am even more troubled that EPA, which has conceded that a single rule may have `localized’ effects, has not sought from our grid regulators, FERC and NERC [the North American Electric Reliability Corp.], an analysis of the cumulative impact its rules may have,” Murkowski said in a statement. “Instead, EPA appears to be morphing into an industrial planning agency for the energy sector.”
The senator criticized LaFleur and Bay for not being more involved in the rule-making process.
“The current chairwoman of FERC, while not calling for a formal official role for the commission as many of us would like, is certainly up to that task, in my view,” Murkowski said. “Unfortunately, the White House does not want her in charge. Its nominee to serve as chairman [Bay] is both short on energy experience and largely unaware of the electric reliability implications of EPA’s rules. In response to a hearing question about grid reliability from Sen. [Joe] Manchin [D-W.Va.], the nominee conceded that he ‘has not been following the decisional process at EPA closely enough to know.’
“That response is not only disturbing, it raises the question of whether anyone in the administration is actually following EPA’s process ‘closely enough to know’ what will happen to our electric grid,” she said.
Load representatives concerned by reports of generators’ bidding strategies in May’s capacity auction reacted Wednesday by threatening to block an Exelon Corp. initiative to provide more informative supply curves.
The measure — which would change the smoothing method used in the supply curves published after capacity auctions — was approved by the Market Implementation Committee with 54% support, short of the two-thirds sector-weighted vote it will need to clear the Markets and Reliability Committee June 26.
No Opposition Early
Stakeholders had approved a problem statement by Exelon’s Jason Barker on the issue without opposition last June. The proposals considered last week were developed by an MIC working group that included Barker and economist Jim Wilson, a consultant to consumer advocates in New Jersey, Pennsylvania, Delaware, Maryland and the District of Columbia.
But support for the change eroded after Market Monitor Joe Bowring signaled his opposition to the new curve. At the MRC meeting May 29, Bowring said it could reveal sensitive data about price-quantity offers and cause collusion among generators. (See Bowring: Reject Revised Supply Curves.)
In announcing Old Dominion Electric Cooperative’s opposition to the change, ODEC’s Steve Lieberman cited Bowring’s concerns and news reports indicating Exelon had helped boost clearing prices in the May auction by offering 4,255 MW of nuclear capacity at the maximum price allowed. Although the units did not clear, UBS Securities analysts estimated Exelon boosted its 2017/18 capacity revenue by about $150 million more than what it would have received had the units cleared. (See How Exelon Won by Losing.)
‘Craftier’ Bidding Behavior
“I can understand from the supply side why they want the information published,” Lieberman said. “If we give generators more information, they’re going to be craftier with their bidding behaviors. If a more transparent supply curve was to be published and supplied to suppliers with large portfolios, they could make strategic decisions to benefit themselves.
“It’s completely a one-sided discussion,” Lieberman continued. “Load has to offer in and we’re purely at the mercy of the results of the market — what [price] suppliers decide to offer in at.” He said he sees no need for the supply curve to be published.
[Correction: A previous version of this article stated that Old Dominion Electric Cooperative decided to oppose the new supply curve “based on” Market Monitor Joe Bowring’s opposition and news reports regarding Exelon’s bidding strategy. Although ODEC’s Steve Lieberman mentioned them in announcing his opposition to the change, ODEC says it made its decision to oppose the change “a few days after the problem statement was approved” in June 2013.]
Carl Johnson of the PJM Public Power Coalition agreed. “We don’t see a benefit to the market or to customers of making that information more specific,” he said. “We think there are companies that could use that info in a non-competitive way. It could be used inappropriately and for an unfair advantage.”
Moving Average
The proposal that narrowly cleared the MIC Wednesday would use a seven-segment moving average as a smoothing method for supply curves for the RTO and MAAC. (See chart.)
Barker said Wednesday opponents of the new curve had no evidence to back their “vague assertions of market power.”
He said he did not believe market participants could use the revised curve to “back into unit-specific information.
The MIC rejected a proposal that would allow publishing curves for locational deliverability areas (LDAs) in addition to the RTO and MAAC. An LDA’s curve would be published only if it passed tests that ensured they had sufficiently diverse market concentration so that individual generators could not be identified.
Following each Base Residual Auction, the Market Monitor posts supply curves that mask individual price-quantity offers.
The current smoothing method was a compromise resulting from a Federal Energy Regulatory Commission order (ER09-1063-003) resulting from a dispute over PJM’s proposal to publish price-quantity pairs after the 2010 BRA. Due to the concentration of generation ownership in the SWMAAC LDA, Constellation Energy and the Monitor said that the data could be used to reconstruct market participants’ offers.
Current Curve Too Inaccurate
In winning support for the problem statement a year ago, Barker said the method used by the Monitor was not accurate enough for any LDA to be useful in analysis. Improving the supply curve would give stakeholders a greater ability to analyze the RPM auction process by helping market participants analyze supply and regulators ensure auction results are just and reasonable, he said.
ODEC’s Lieberman agreed that the current curve wasn’t very useful. “It’s obvious almost any formula would be more accurate” than the current one, he said in voicing his support for the problem statement. (See MIC Seeks Better Way to Draw Capacity Supply Curve.) Lieberman noted yesterday that it’s rare for stakeholders to oppose problem statements, though that doesn’t commit them to supporting changes that may result from them.
Auction Strategy
Fears that the curves could disadvantage load grew after results of the 2017/18 BRA were posted last month.
With new PJM rules limiting offers by imports and demand response, and economics and the Environmental Protection Agency’s Mercury and Air Toxics Rules forcing as much as 14 GW of PJM coal capacity into retirement, Exelon felt confident in offering its nuclear plants at the maximum price it was allowed — the Avoided Cost Rate (ACR) minus net energy revenue. Exelon confirmed afterward that its Oyster Creek plant in New Jersey, as well as Byron Units 1 and 2 and Quad Cities Units 1 and 2 in Illinois, had failed to clear the auction.
Bowring said that all generation offers were screened by his staff to ensure market power was mitigated by offer caps. That included a determination that no generator with market power could offer at a price higher than ACR minus net energy revenue.
But Wilson said the way the Monitor calculates the price caps leaves generators leeway to exercise market power without violating market rules. “There is now, and has always been, an awful lot of flex within the market power mitigation,” he said in an interview last week.
Wilson pointed to the energy and ancillary services offset, which he said is “much lower than market participants’ expectations.”
He also cited the avoidable project investment recovery rate (APIR), an adder to the offer cap, which he said “unmitigates a lot of capacity” because it is amortized over a short time period. Wilson noted that The Brattle Group’s 2008 review of the capacity market had recommended changes to the application of APIRs.
Dan Griffiths, executive director of the Consumer Advocates of the PJM States (CAPS), said his organization has not taken a formal position on the revised curve, although individual members have discussed it. He said CAPS will meet to decide whether to oppose the change or abstain when it comes up for a vote at the MRC.
“We’re not making any market power [allegations],” he said in an interview. “But if folks are successfully strategically bidding we don’t want to enhance their ability to do that.”
A subsidiary of NRG Energy announced late last week that it will buy the largest wind farm in North America for $870 million. The deal is seen as another move by NRG to bulk up its portfolio of renewable energy, especially important now that the Environmental Protection Agency has issued its carbon emission reduction rules.
NRG Yield Inc. is buying California’s 947-MW Alta Wind Energy Center. NRG formed NRG Yield in December 2012 to own and operate its “clean energy” fleet. The project is located in Tehachapi Pass in California’s Kern County and sells its power under long-term power contracts with Edison International.
The Nuclear Regulatory Commission began a surprise inspection last week at Dominion’s Millstone nuclear generating station in Waterford, Conn., after both units shut down unexpectedly May 25. Millstone Units 2 and 3 shut down safely after a problem at one of three off-site high-voltage lines that feed power to the plant.
Unit 2 shut down without complications. At Unit 3, however, several problems arose during the shutdown, including a problem with a reactor coolant system drain. The inspection of both units started last week. There is no word on how long the inspection will take. The NRC said it will issue a report 45 days after the end of the inspection.
PPL Corp and Riverstone Holdings LLC said yesterday they would combine their generation businesses into a new publicly traded independent power producer.
The new company will be called Talen Energy Corp. and will own and operate 15,320 MW of capacity. Talen will be listed on the New York Stock Exchange, with PPL shareholders owning 65% of the company and Riverstone owning 35%. Financial terms of the deal were not disclosed.
The Wall Street Journal reported last week that Dynegy is among those bidding for Duke Energy’s 11 fossil fuel-fired plants in the Midwest, going up against Blackstone Group and Riverstone Holdings. Citing unnamed sources, the Journal said that Dynegy, less than two years from emerging from bankruptcy, is looking increase its customer base. The plants, in Ohio, Illinois and Pennsylvania, are expected to sell for about $2.5 billion.
About one quarter of PJM’s outages on Jan. 7 were the result of gas units’ inability to obtain fuel.
