PJM will perform a cost-benefit analysis before proceeding with a combined-cycle bidding model expected to cost up to $1 million.
Combined Cycle Plant Diagram (Source: General Electric Company)
PJM’s Tom Hauske told the Operating Committee that incorporating the Alstom model — chosen by the OC to ensure more consistency among offers — will be more complicated and costly than initially expected. Hauske said the changes will affect more than eMKT and scheduling and won’t be implemented until 2015 instead of June 2014.
Given the new cost estimate of between $750,000 and $1 million, Hauske said, “We have to be able to justify it” for inclusion in PJM’s budget.
All 53 combined-cycle units in PJM, which can now offer as steam units or combustion turbines, would be required to use the new model. Sellers will have to offer the new combined cycle configurations for at least three months. All units would be aggregated under one unit ID.
Maryland officials aren’t saying what their next move is in the wake of a federal court ruling that voided the state’s contract with developers of a 725 MW combined cycle plant in St. Charles.
Judge Marvin Garbis
U.S. District Judge Marvin J. Garbis ruled that the “contract for differences” the state Public Service Commission negotiated with Competitive Power Ventures unconstitutionally interfered with the Federal Energy Regulatory Commission’s jurisdiction over interstate wholesale energy sales.
“Because states have no authority, either traditional or otherwise, to set wholesale rates, the compensation received by CPV for its wholesale energy and capacity sales is exclusively subject to the regulation of FERC,” the judge wrote in a 149-page order.
The ruling invalidates the PSC’s April 2012 order directing Baltimore Gas and Electric Co., Potomac Electric Power Co., and Delmarva Power & Light Co. to enter into contracts that guaranteed CPV Maryland LLC an income stream so that it could finance construction of the Charles County facility.
Robert J. Grey, general counsel for PPL Corp., one of the companies that challenged the CPV deal, said the ruling “upholds the integrity of competitive generation markets.” PSEG Power LLC and Essential Power LLC were the other plaintiffs.
An appeal is likely, although Regina L. Davis, spokeswoman for the PSC said Friday that the agency was reviewing the ruling and had no immediate comment.
Charles County Commissioner Ken Robinson said the county remained “cautiously optimistic” that the project will proceed.
Merchant Option?
CPV officials did not respond to requests for comment. Last month, the company announced that it would build a 700-MW combined cycle plant in Woodbridge, New Jersey as a merchant facility because of uncertainties created by legal challenges to state-sponsored contracts there.
On Oct. 11, a federal court judge threw out New Jersey’s contracts, also on constitutional grounds, with CPV, Hess Corp. and NRG Energy. The three were selected through a solicitation by the New Jersey Board of Public Utilities for construction of 2,000 MW of generation.
Despite the ruling, the CPV and Hess plants are being built. Hess, which began construction late last year on its 655 MW plant in Newark, said it expects to complete the plant in 2015. CPV said it expects construction on the $842 million Woodbridge project to begin within weeks. NRG cancelled its project after failing to clear in two consecutive capacity market auctions.
CPV said in 2009 that it needed state backing to secure long-term financing to build in Maryland. In the interim, however, low natural gas prices and retirements of coal-fired plants have led to a spurt of unsubsidized generation in PJM. CPV said the debt syndication for its New Jersey plant was oversubscribed “reflecting the project’s strong fundamentals.”
Panda Power Funds in July proposed an unsubsidized 859-MW combined cycle plant in the Washington suburb of Prince George’s County, Md. LS Power Group, which had earlier sought subsidies to build in New Jersey, is building a plant in West Deptford without state backing.
Contract for Differences
Under the Maryland contract, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices are higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices are higher than the contract, CPV would make payments to the EDCs.
Boston Pacific Co., a consultant hired by the PSC, estimated the contract would save residential ratepayers $0.32 to $0.49 per month over the life of the 20-year contract. However, PSC General Counsel Robert Erwin told FERC’s technical conference Sept. 25: “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.” (See Capacity Market Attracts Praise, Criticism at FERC).
PJM Capacity Market ‘Failed’
The PSC took its action to spur new generation after concluding that the state faced “a critical shortage of electricity capacity” because it is a net importer and is subject to higher prices because of transmission congestion.
The PSC said that PJM’s capacity market “has failed to attract new generation” to the Southwest Mid-Atlantic Area Council (SWMAAC), which encompasses most of Maryland.
“Since its inception in 2007, RPM has brought no new generation to Maryland, in spite of the fact that clearing prices for capacity in the SWMAAC have averaged almost double those of the non-constrained portions of PJM,” the PSC said. Existing generators had no incentive to build more capacity, regulators said, because increasing supply would reduce prices.
Request for Proposals
Aerial map of CPV St. Charles location
CPV was selected over two other bidders that responded to the state’s request for proposals (RFP).
The contract for differences required CPV’s plant to clear in PJM’s annual Base Residual Auction. New generators participating in the auction are subject to the Minimum Offer Price Rule (MOPR), which sets a minimum offer price based on the net Cost of New Entry (net CONE), a measure to prevent buyer-side market power.
In the 2012 capacity auction, PJM approved a MOPR bid floor of $96.13/MW-day for the CPV plant. Prices in SWMAAC and MAAC cleared at $167.46/MW-day in SWMAAC and MAAC, although a PJM sensitivity analysis found prices in SWMAAC would have been almost $30 higher had the bid capacity been 750 MW lower.
MD Argument ‘Unpersuasive’
Garbis said he found “unpersuasive” Maryland’s argument that the contract price is a competitive market price because CPV initially proposed it as part of the RFP. He noted that the PSC had reserved the right to select none of the proposed contract prices. “Accordingly, although it was proposed by CPV, the contract price in the CfD is a price ‘set’ or ‘determined’ by the PSC,” the judge ruled.
Garbis also rejected the state’s contention that the contract was a “mere financing arrangement outside the jurisdiction of FERC.”
“While there exist legitimate ways in which states may secure the development of generation facilities, states may not do so by dictating the ultimate price received by the generation facility for its actual wholesale energy and capacity sales in the PJM Markets without running afoul of the Supremacy Clause,” he wrote.
‘Win’ for Consumers?
The COMPETE Coalition, an organization that represents generators and others, called the ruling “an important win for electricity consumers,” saying subsidized development would “needlessly shift the financial risk of new construction from power plant developers to consumers.”
The Maryland Office of People’s Counsel, which represents residential utility customers, was less sanguine. “If the order stands, it could restrict the state’s ability to address reliability problems within the state,” People’s Counsel Paula M. Carmody told The Baltimore Sun.
PJM officials said they are pleased with the response to their request for additional black start resources, as more than 50 generators responded with offers.
“There appears to be a large pool of viable units, both proposed and existing,” said Mike Kormos, PJM executive vice president for operations.
Officials said it will take months to select their fleet of black start resources from among current resources and the new bidders. Locational needs and costs will be the determining factors.
Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
The solicitation was one of the recommendations of the System Restoration Strategy Task Force, which also increased the pool of potential resources.
PJM expects to lose some existing black start capacity by 2015 due to coal plant retirements.
The PJM Board of Managers last week approved $1.2 billion in transmission reliability projects.
CEO Terry Boston said the projects in the 2013 Regional Transmission Expansion Plan (RTEP) will enhance grid resiliency and respond to the shift of generation from coal to natural gas.
PJM has approved more than $24.2 billion in transmission additions and upgrades since the first RTEP in 2000.
The plan includes upgrades and improvements to transformers, substations and other facilities.
The approved projects can commence as soon as the transmission developers receive required state and local regulatory approvals, said PJM Chief Financial Officer Suzanne Daugherty.
The Environmental Protection Agency’s proposal to regulate emissions from existing coal-fired power plants could result in creation of a cap-and-trade system on a regional basis.
EPA Administrator Gina McCarthy said that controls on existing plants would be imposed through something similar to the “state implementation plans” that the agency has required to regulate pollutants like sulfur dioxide and nitrogen oxides. The rules are scheduled to be issued next June.
The Supreme Court is expected to decide this week whether it will review a lower court ruling that upheld the Environmental Protection Agency’s greenhouse gas regulations.
Petitioners, including the U.S. Chamber of Commerce and the American Chemistry Council are asking the court to reverse aspects of an appellate court’s June 2012 ruling that backed EPA’s first rules following the Supreme Court’s landmark Massachusetts v. EPA decision, which instructed the agency to regulate greenhouse gases as harmful pollutants under the Clean Air Act.
The Nuclear Regulatory Commission said it has enough “carryover” funding to maintain normal operations for at least a week in the event of a government shutdown.
If the shutdown exhausts the agency’s funding, it will retain about 300 of its 3,900 employees, half of them resident inspectors assigned to reactor and fuel facilities, the rest staff who would provide initial response to an emergency at licensed facilities. The NRC Commissioners and Inspector General are exempted from furloughs because they are presidential appointees.
The Nuclear Regulatory Commission has commissioned the National Academy of Sciences to conduct a pilot study of cancer risks for people living around six nuclear plants. The pilot will determine whether to extend the study to other nuclear facilities.
The plants chosen for the pilot are Dresden station in Illinois, Oyster Creek in New Jersey, Big Rock Point in Michigan, Millstone and Haddam Neck in Connecticut and San Onofre in California.
The Federal Energy Regulatory Commission will keep 48 of 1,460 employees (3.3%) at work during a government shutdown to “protect life and property.” Most of the employees work in hydroelectric and liquefied natural gas inspections (19), legal and enforcement matters (10) and commission infrastructure (10). Also to be retained are 19 contractors providing building security and information technology support. The five commissioners also are exempted from furlough as presidential appointees.
A Senate committee aide said the Obama administration is eyeing other candidates to replace Ron Binz as its nominee for chairman of the Federal Energy Regulatory Commission.
Binz’ nomination is in doubt after he failed to win support from any Republicans on the Senate Energy and Natural Resources Committee. Sen. Joe Manchin (D., W.V.) also has said he will vote against Binz.
The research arm of the National Rural Electric Cooperative Association says frequent cycling of fossil units to accommodate wind and solar power could increase forced outages in such units from about 5% a year to as high as 25%. The group said baseload coal plants will experience “thermal cycle fatigue” after 12 to 18 months of being shut down at night and restarted in the morning.
NRECA released its analysis in response to a National Renewable Energy Laboratory study that concluded frequent cycling of fossil units in the Western Interconnection could save about $7 billion a year in fuel costs.
The Public Service Commission scheduled public comment sessions for Oct. 3 and 16 in its investigation into Delmarva Power’s request to spend $397 million over five years for infrastructure and reliability projects. The PSC staff expressed concern over the request, noting that the company, which received a rate increase late last year, already exceeds its reliability requirement by 51%. (Docket No. 13-152)
Rock Island Line Map (Source: Clean Line Energy Partners)
Developers of the proposed Rock Island Clean Line heard little encouragement from hundreds of Illinoisans at a public meeting. The proposed 500-mile, 3,500-MW DC line would carry wind power to Illinois from Iowa, Nebraska and South Dakota.
The president of the Illinois Farm Bureau said the line’s proposed path doesn’t follow farm property or section lines, which would make it difficult apply pesticides and use irrigation.
Voters in the unincorporated areas of Jefferson County may get a second vote on electric aggregation if the County Board votes this month to approve the item for next March’s primary ballot. An April vote on the question failed by only 104 votes, and about 700 voters did not cast votes on the item. A consultant plans better public education on the issue.
If approved, 70 communities will band together to negotiate lower rates.
Planned Woodbridge Energy Center (Source: Competitive Power Ventures)
Competitive Power Ventures has closed financing for its $842 million Woodbridge Energy Center. GE EnergyFinancial Services is providing financing, advanced generation technology and services for the 700-MW combined cycle plant, which is owned by CPV, ArcLight Capital Partners and Toyota Tsusho.
CPV Woodbridge will sell its capacity through 15-year standard offer agreements with New Jersey utilities.
The Ohio Manufacturers Association favors the state’s energy efficiency standards but wants a cap on how much utilities can charge for efficiency riders. The group said is still studying provisions of a bill that has been introduced to make changes in the program.
Meanwhile, wind energy supporters argued against a provision in the bill that would eliminate requirements that utilities buy a certain amount of in-state renewable energy.
Lt. Gov. Jim Cawley thinks state Attorney General Kathleen Kane went too far in lodging criminal charges against XTO Energy for a Marcellus Shale wastewater spill. “No one should be punished more than once for the same mistake,” Cawley said at a natural gas industry conference in Philadelphia. XTO previously agreed to pay a fine for the 2010 incident and spend $20 million to upgrade its wastewater management practices.
The Public Utility Commission asked for comments on its plans to improve utilities’ response to storm outages. The PUC is proposing creation of a working group of electric distribution companies (EDCs), telephone, and water, wastewater, and natural gas distribution utilities to coordinate restoration of services where more than one party is affected in a geographic area. The agency also issued a policy statement on outage response.
The Pennsylvania Public Utility Commission will investigate Duquesne Light’s proposal to raise its electric distribution rates 17.6%. The increase would fund grid upgrades, smart grid measures and vegetation management, the company said. The Office of Consumer Advocate is challenging it.
The PUC began streaming video of its regularly scheduled public meetings. It said it also will stream video of en banc hearings and other special meetings.
The Public Utility Commission fined Great American Power $10,000 for misrepresenting its relationship with electric distribution companies and engaging in abusive telemarketing. The Commission also said the company’s ability to operate as an electric generation supplier could be revoked if it fails to meet PUC requirements for documenting customer enrollments and addressing future complaints.
Panda Power Funds acquired a majority stake in the 750-MW Stonewall combined-cycle project planned for Loudoun County. Partners include Bechtel Development and Green Energy Partners/Stonewall, the original developer.
The state approved an air permit in April, and construction is to begin once financing and all permits are in hand. Panda expects the plant to be in service in 2017.
Dominion Virginia Power is on track to finish its 1,329-MW combined-cycle Warren County Power Station by the fourth quarter of next year, having hit the 50% completion mark last month after 17 months of construction that included building a 2.5-mile gas line. Warren County Energy Partners, a partnership of Burns & McDonnell and Zachry Construction, is building the station.
Appalachian Power is moving forward with its plans to spend $337 million on a project to upgrade electrical transmission lines and related facilities. The company has filed four petitions with the Public Service Commission regarding the project, and one of them received PSC approval last week.
The company said the work is needed to replace some facilities that were built in the 1920s to 1940s and a “backbone” power line from Poca to Cabin Creek that was last reinforced four decades ago.
Thirty-eight Keyser residents filed suit against the Pinnacle Wind Farm, alleging that sound from the farm’s 23 turbines on Green Mountain has caused mental and physical problems and reduced property values. The company, owned by subsidiaries of Edison International, denies the allegations.
PJM Chief Financial Officer Suzanne Daugherty briefed the Members Committee webinar on the spending plan last week.
Daugherty said PJM plans to add five staffers to its current workforce of 665.
PJM’s composite expense rate continues to be below the 2006 stated rate settlement projections, Daugherty noted.
The operating budget is in addition to a proposed $30 million in capital spending, down $2 million from 2013. (See PJM Plans $30M Capital Spend for 2014)
The Board of Managers is expected to consider the spending plan at a meeting tomorrow.
Thursday’s FERC technical conference on capacity markets elicited sharply differing views on a variety of design concepts and technical issues. Some of the disagreements have been around since the beginning of capacity markets, others are reflecting the influence of new technologies.
Below is a summary of some of the key issues.
Forward Period & Commitment Period
Having divested virtually all of its generation, and not wanting to sign long-term purchase power agreements, Consolidated Edison Co. relies on the capacity market, said Richard Miller, director of energy markets policy. The company’s service territory straddles the New York border with New Jersey and Pennsylvania, giving it experience with both NYISO and PJM.
Miller noted that PJM, which purchases capacity three years in advance, has attracted more than 4,000 MW of new generation in each of the last two auctions (more than 3.5% of the forecast peak), while the NYISO, which has a 6-month forward, has added less than 675 MW (1.7%).
Although PJM primarily acquires capacity for a one-year commitment period, some new resources can lock-in prices for three years.
But Analyst Julien Dumoulin-Smith, of UBS Investment Research said even three years is a “mismatch” with the long life of new generation, noting that California is “trending to a 10-year market.”
Todd Snitchler, chairman of the Public Utilities Commission of Ohio, said bankers told his agency “Five to seven years [commitment] … would make it much more economical to get new generation.”
Robert Erwin, general counsel of the Maryland Public Service Commission, said the short commitment period exacerbates’ bankers concern over the volatility of capacity prices. Bankers have told the PSC: “There’s no way I’m going to lend money on that kind of price signal – and certainly not for one year [of guaranteed revenue].”
Demand Response vs. ‘Steel in the Ground’
The role of demand response was another issue that sparked much discussion.
“It is simply not the case that 1 MW of Demand Response provides the same reliability contribution to the grid as 1 MW of steel in the ground,” said Shahid Malik, president of PSEG Energy Resources and Trade.
James Holodak, vice president of regulatory strategy and integrated analytics for National Grid USA, agreed, bemoaning demand response, which is not subject to must-offer rules, “jumping in and out of the market.”
Andy Ott, PJM executive vice president for markets, said PJM is seeking to treat demand response more as an operational resource reflecting differences in physical characteristics, as is the case with generators. He noted that most of the 14,000 MW of demand response that cleared in the most recent base auction gets two-hour notice and an identical price. “We can’t sustain that,” he said. “We really need to have more diversity.”
“Iron in the ground is worthless,” said Peter Cramton, professor of economics at the University of Maryland. “What consumers should be buying is energy in shortage situations.” He called for an ex-post grading of resources — a “second settlement” — with good performers receiving bonuses and penalties for poor performers.
Dan Curran, market strategist with demand response aggregator EnerNOC, said the “downstream” focus on demand response “is treating the symptom and not the cause.” He said it was more appropriate to set qualifications for participation in DR, as PJM is considering.
Tranches
The commission asked the panelists for their opinion on creating “tranches” of capacity products based on operational characteristics such as fast-ramping or load-following ability given the increase in variable and intermittent resources.
Michael Hogan, of the Regulatory Assistance Project, is a supporter, saying tranches would create a fairer and more efficient market. “We’ve had ObamaCare in energy for years…,” he said. “People are paying for insurance they don’t need for a service they don’t really consume.”
But Cramton called the idea “a nightmare” that would lead to “rent-seeking.”
Sue Kelly, general counsel of the American Public Power Association, also said she feared that tranches would lead to gaming. “There’s always an extremely enterprising financial player who will find a way to arbitrage,” she said.
Consultant James Wilson urged a “purist” view: “Stay focused on the peak day… rather than [making] it more complicated through ramping … or tranches.”
The Markets and Reliability Committee heard first reading last week on the following manual changes. Members will be asked to endorse the changes at the MRC’s next meeting.
WASHINGTON — Some came to praise PJM’s Reliability Pricing Model. Others said they’d like to bury it.
Six years after RPM’s inception, the Federal Energy Regulatory Commission convened a technical conference last week to ask the question: How’s the capacity market working for you?
The commission said it was time for a broad look at the strengths and weaknesses of PJM’s model and those launched later in ISO New England and NYISO and how the markets should evolve in the future. Commissioner Tony Clark likened the session to a “checkup.”
The day-long session, which featured 26 panelists and attracted an overflow crowd of hundreds, was the prelude for a potential FERC rulemaking. (The speakers’ written testimony is available in FERC’s eLibrary under Docket # AD13-7.)
PJM Represents `Best Practices’
Capacity Clearing Prices – Delivery Years 2006-2017 (Source: FERC)
The consensus among the speakers was that PJM’s market deserved the highest marks. “PJM does represent the vast majority of best practices here,” said securities analyst Julien Dumoulin-Smith of UBS Investment Research. Lee Davis, who heads NRG Energy’s operations in the three eastern regions, said his company is investing “hundreds of millions” to upgrade 600 MW of generation in PJM because of its confidence in the RTO. In contrast, he said, the company is retiring capacity in New England because of the instability in the region’s market rules. “We look at risk just as highly as we look at revenues,” he said.
Changes Needed
That’s not to say PJM’s model couldn’t use improvement, even its supporters acknowledged.
Andy Ott, PJM executive vice president for markets, cited concerns about the volume of imports that cleared in this year’s auction (see PJM Seeks to Curb Capacity Auction Speculation). He also cited price volatility in western PJM due to MISO’s “inadequate construct.”
Compromises Weaken Model
Consultant Roy Shanker said “FERC got it right” in setting capacity market rules but that compromises have eroded the construct. He cited PJM’s short-term resource procurement — which removes 2.5% of the reliability requirement from the demand curve — as “blatant price discrimination.”
There also was debate about the optimal forward and commitment periods, the role of demand response, the wisdom of creating “tranches” to reflect differences in resource capabilities and how capacity can accommodate the growing role of variable resources and new technologies such as storage. (See sidebar, Old Issues, New Technologies in Capacity Debate)
States, Public Power Bash MOPR
The central debate, however, was a crossfire between those who contend capacity prices are too high and those who say they are too low.
State and public power representatives said the markets interfere with state policies and have failed to attract competitively-priced new generation.
“A capacity market that does not recognize new capacity developed pursuant to the requirements of state statutes and regulations … cannot endure,” said Jeffrey Bentz, of the New England States Committee on Electricity.
Reality on the Ground
James Jablonski, representing the Public Power Association of New Jersey, said PJM’s capacity market rules don’t recognize “the reality on the ground.”
Despite capacity prices of $245 per MW Day in PSEG North, Jablonski said, no generation is being built because of the difficulty siting in the densely-populated state. “There’s no point in having … customers paying for something that doesn’t have a way of getting built.”
Ed Tatum, vice president of RTO and regulatory affairs for Old Dominion Electric Cooperative, said PJM’s rules to curb buyer-side market power are unnecessary. “I would like us to stop looking behind every tree for the boogeyman of monopsony power,” he said. “You have to think about intent [to exercise market power]. You have to think about incentives. You have to think about ability.”
He noted that PJM’s minimum price floor for generation sponsored by public power — the net Cost of New Entry (CONE) — has almost doubled since it was instituted.
Jablonski urged a return to the self-supply provisions in the 2006 RPM settlement. “We don’t bother you, you don’t bother us…We know we can build for less than [net CONE] so it makes no sense to buy from the capacity market.”
Generation Owners Cry Foul
Representatives of generation owners, however, said capacity prices are too low, due in part to state-subsidized generation projects in Maryland and New Jersey. Shahid Malik, president of PSEG Energy Resources and Trade, said his company decided against building a merchant generator because of concerns it would be undercut by a subsidized competitor.
William Massey, now counsel to COMPETE, a coalition of generators and others, said Maryland’s “contract for differences” with Competitive Power Ventures’ 725 MW St. Charles generating plant “skews the capacity market in a way that this commission should not allow.”
“That’s just not true,” Robert Erwin, general counsel of the Maryland Public Service Commission, shot back. He said Maryland’s initiative “irons out” volatility. “No one knows whether at the end of 20 years Maryland ratepayers will pay CPV or if CPV will have paid Maryland ratepayers.”
Commissioner LaFleur asked if the impact of state programs such as Maryland isn’t the same in reducing prices, even if it is not the state’s intent.
Erwin conceded its new generation could depress prices. “But it’s no different than a state that says we’re going to have emission limits on power plants,” which would have the opposite effect, he said.
Capacity Market Not Voluntary
Susan Kelly, general counsel of the American Public Power Association, parried with Commission Chairman Jon Wellinghoff, who said APPA’s members were not required to join RTOs and thus participate in capacity markets. “It’s not a legal requirement,” Wellinghoff said.
Kelly responded: “If you have to take transmission service from the organization it’s kind of silly not to be a member… no system can be an island.”
FERC’s Next Step
Some panelists said they hoped the conference would be a prelude to a future rulemaking.
Consultant Susan Tierney called for a policy statement — “a visioning thing” — on the role of capacity markets in the future.
Richard Miller, director of the energy markets policy at Consolidated Edison Co. called on the commission to impose “some minimum level of standardization.”
Others said the role of the capacity market should shrink to its initial concept — a “residual” role that supplements bilateral contracts and self-supply.
“The mother of all rulemakings – Standard Capacity Market Design – scares me,” said Kelly.
“I guarantee that’s not what it would be called,” responded LaFleur, prompting laughter from the audience.
LaFleur added: “There is not a `thing’ to be named. We have to distill what we learned.”
