FERC upheld an earlier ruling that Old Dominion Electric Cooperative (ODEC) and North Carolina Electric Membership Corporation (NCEMC) shouldn’t have to help pay for $173.4 million in undergrounding for three projects in Virginia that Dominion Resources’ Virginia Electric and Power Co. included in its 2010 Annual Transmission Revenue Requirement.
Incremental ATRR costs are borne by all wholesale transmission users of the grid. ODEC and NCEMC argued in their original complaint that it was not just and reasonable for wholesale transmission customers outside Virginia to bear the cost of undergrounding when it is done for aesthetic concerns and has no impact on reliability.
The three projects were: a 230 kV line to the new Hamilton Substation in Northern Virginia, with two miles of undergrounding ($32.9 million); the DuPont Fabros project, a 0.71 mile double-circuit 230 kV underground transmission line and substation in Loudon County ($9.8 million); and the Garrisonville project, a five-mile, double-circuit 230 kV transmission line in Stafford County, Va. ($131 million).
ODEC and NCEMC said that the projects’ costs were either recoverable from Virginia ratepayers, or hadn’t been proven to be necessary for system reliability, and therefore should not have been included in Dominion’s ATRR.
ODEC serves more than 550,000 customers in Virginia, Maryland and Delaware. NCEMC serves 950,000 households and businesses in North Carolina.
“We find that wholesale transmission customers outside of the Commonwealth of Virginia should not be responsible for costs that are a direct result of legislation and VSCC pilot projects intended to benefit citizens of the Commonwealth of Virginia,” the commission wrote in an order last week (EL10-49).
The commission said a trial would be set to determine the amount of refunds due to ODEC and NCEMC, but it urged the parties to seek a settlement.
WASHINGTON — The 2013 PJM State of the Market was, to quote that noted economist Yogi Berra, mostly “déjà vu all over again.”
The 2012 report had called for substantial changes to the capacity market, demand response and the treatment of uplift. The 2013 report, which was unveiled by Market Monitor Joe Bowring during a press briefing March 13 in Washington, identifies shortcomings in the same areas.
The results of five of six markets — Energy, Capacity, Synchronized Reserve, Day-Ahead Scheduling Reserve and FTR Auctions — were judged competitive, as in 2012, along with the Regulation Market, which was judged not competitive for most of 2012.
Capacity Market
While the Capacity Market remains competitive, the 444-page report by Monitoring Analytics labeled the aggregate market structure and local market structure as not competitive, as in most prior years since 2007. (See sidebar, PJM 2013 by the Numbers.)
Bowring’s recommended changes for the market were no surprise either. Among them: requiring that all resources be physical; making all demand response a year-round product subject to must-offer rules; and requiring all imports be pseudo tied.
Alternatives to internal generation must be “full substitutes,” not the currently “inferior products” that are suppressing capacity prices, Bowring said.
“If demand response is going to be in the capacity market … it should be available every hour and it should be treated as a real product. It is a real product,” he said. The report calls for classifying all demand response as Economic and eliminating Limited and Extended Summer DR.
Bowring said DR providers can build such generation “substitutes” by aggregating resources into portfolios, a requirement he acknowledged would make DR more expensive.
Generation at Risk
Under current rules, Bowring said, DR and imports are suppressing capacity prices, particularly in western PJM. Add in low natural gas prices, which have caused LMPs to fall, and the result is 87 generators, totaling 14,597 MW of capacity, at risk of retirement. That is in addition to the 24,933 MW currently planning to close.
The 87 generating units — combustion turbines, coal, gas, oil and dual-fuel plants — were unable to cover avoidable costs in 2013 or didn’t clear the 2015/2016 or 2016/2017 base capacity auctions.
Although the report did not assess the viability of PJM’s existing nuclear fleet, Bowring said he was not surprised by reports that Exelon Corp. is threatening to close three of its nuclear generating stations in Illinois. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Bowring said although he lacked data to calculate the current nuclear fleet’s operating costs, no new nuclear plant could be profitable under current prices. “The net revenues are only covering 30% or so of costs,” he said.
At the other end of the spectrum, revenues for solar generation in the PSEG zone were double their fixed costs, due largely to state and federal subsidies.
Uplift
Energy uplift increased by $231 million, or 36%, in 2013. The two main culprits were reactive services, with an increase of $263.5 million, and black starts, which were up $78.2 million. Balancing and day-ahead charges dropped.
The report says PJM should increase its transparency by having operators record the reasons for dispatching out-of-merit generators and identifying the units that are receiving uplift payments.
Ten generating units — less than 1% of all units — received 38% of all uplift in 2013, but PJM confidentiality rules prohibit these units from being identified.
“All uplift payments should be public information. They are [currently] totally non-transparent,” Bowring said. “No one in the market really understands what’s going on.”
Identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs, he said.
In addition, the report says up-to congestion trades should be required to pay uplift charges like other virtual transactions.
Interchange Ramp
Bowring was adamant in his opposition to a proposal floated by PJM officials earlier this month that would allow operators to reduce interchange ramp limits to reduce price volatility. (See Ramp Limits Cause Stir at MIC.)
“In our view, we see nothing wrong with [price] swings. It’s what happens in markets. [PJM] operators should not be concerned with price volatility,” Bowring said.
Competitive Concerns
Joe Bowring presenting the 2013 State of the Market Report
While the Monitor found all market results were competitive, it expressed concern over the potential for anticompetitive behavior by generators, particularly those owned by holding companies that are also transmission owners.
The report recommends that PJM consider rules to ensure that incumbent generation owners cannot use Capacity Injection Rights (CIRs) to hamper entry by competitors.
Under current rules, companies that retire generation retain CIRs for one year and have the ability to sell them.
The Monitor said stakeholders should decide whether CIRs are considered property rights of generation owners or should revert to the system upon a plant’s retirement. Companies lacking CIRs face higher interconnection costs than those possessing them.
The Monitor also recommended that interconnection studies, currently performed by incumbent transmission owners, be outsourced to an independent party. The current practice “could result in a conflict of interest when transmission owners have generation interests,” the Monitor said.
State of the Market Report 2013 High Priority Recommendations (Source: Monitoring Analytics LLC)
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
The committee will be asked to endorse revisions to PJM’s Tariff and Operating Agreement to clarify agreements and transactions to which PJM Settlement, Inc. is not a party.
4. ESUITE APPLICATION NAME CHANGES (9:35-9:50)
The committee will be asked to endorse Tariff and OA revisions to effectuate the eSuite application name changes (i.e., changing eSchedules and EES to InSchedule and ExSchedule, respectively), as well as updates to the Regional Transmission and Energy Scheduling Practices for the deployment of ExSchedule. These changes are being requested in part due to the new Coordinated Transaction Scheduling (CTS) between PJM and NYISO. (See NYISO Scheduling Product Wins FERC OK.)
5. CONE REVIEW TIMING (9:50-10:05)
The committee will be asked to endorse Tariff and OA revisions related to the timing of the CONE (Cost of New Entry) periodic review. This would move the dates for the various stages of the triennial review up by two months. The Members Committee will also be asked to endorse these revisions (agenda item #5).
The committee will be asked to endorse proposed Tariff revisions associated with Coordinated Transaction Schedules and export transactions. Among other things, the revisions clarify that transactions established directly by and between PJM and a neighboring balancing authority for the purpose of maintaining reliability are not subject to export transaction screening. (See NYISO Scheduling Product Wins FERC OK.)
The committee will be asked to endorse proposed Tariff revisions to add a near-term transition mechanism to address changes to Manual 21: Rules and Procedures for Determination of Generating Capability. This transition mechanism allows certain generation owners to provide revised summer capability test results for the last three summers by April 1, in exchange for forgiveness of potential ICAP shortfalls for the 2014/15 delivery year. (See Transition Period OKd for Seasonal Verification Rules.)
Environmentalists’ efforts to dampen the Obama administration’s support for natural gas are not meeting a warm reception. White House adviser John Podesta, former president of the liberal and environmentalist think tank Center for American Progress, told reporters that opposing all fossil fuels “is a completely impractical way of moving toward a clean-energy future.”
His remarks came a day after the Sierra Club and others urged President Obama to reject calls to speed up permits to export liquefied natural gas, because gas production and export works against the administration’s climate change plan — an agenda Podesta said he spends about half his time working on.
“I think we remain committed to developing the resource and using” natural gas, he said, “and we think there’s an advantage, particularly in the electricity generation sector, to move it forward.”
The White House launched an effort to leverage the government’s data resources to stimulate innovation and private-sector entrepreneurship to support climate-change preparedness.
The Climate Data Initiative will include launch of a website to make federal data more accessible and useful. It will focus initially on coastal flooding and sea level rise, and already includes more than 100 high-quality datasets and tools to be used to help communities prepare for the future. The site will be expanded to include other information, including energy infrastructure data. The National Aeronautics and Space Administration and the National Oceanic and Atmospheric Administration launched an “innovation challenge” to encourage deployment of visualizations and simulations to help the understanding of, and solutions to, coastal vulnerability.
In addition, the White House identified numerous private-sector initiatives being undertaken to create resources and events aimed at enabling responses to climate change impacts.
A federal appeals court upheld the Environmental Protection Agency’s 2009 and 2012 particulate matter new source performance standards (NSPS) for fossil fuel-fired boilers, rejecting most of industry’s challenges. It affirmed the EPA’s requirement for periodic visual opacity inspections for power plants that do not use continuous monitoring systems and the agency’s decision not to approve state law-based defenses to civil penalties for violations. Only unavoidable malfunctions will constitute a defense to alleged violations.
The court deferred ruling on all challenges to the regulation because some are still pending in reconsideration requests at EPA. These include requirements for testing condensable particulate matter and provisions for frequency of testing.
Nearly all of the participants in November’s GridEx II reliability preparedness exercise found it useful for identifying opportunities to improve their readiness, which they deemed insufficient, the North American Electric Reliability Corp. said in a report. NERC’s two-day readiness exercise included 2,000 companies and organizations faced with challenges to both physical security and cybersecurity. A third exercise is planned for next year.
Among things NERC recommended to improve preparedness is a review of the Defense Production Act and other laws to determine if there is a need for legislation that would facilitate recovery following a severe event. The report also said some industry regulations “would constrain the operation of certain generators, and specific relief provisions should be considered before a severe event.”
NERC also recommended continued enhancement of information sharing; expansion of the Electricity Sector Information Sharing Analysis Center conference call capabilities; clarification of ES-ISAC subject matter experts’ functions; and clarification of reporting roles. It also recommended evaluating an expansion of recovery programs such as the Spare Transformer Equipment Program.
The House Natural Resources Committee plans to question the chief of the U.S. Fish and Wildlife Service March 26 about what some members contend is selective enforcement of bird protection laws that shows wind farms more lenience than on other kinds of facilities. The committee earlier subpoenaed numerous internal agency documents on the subject.
Only one wind power company, Duke Energy, has been prosecuted for killing eagles and other birds. Duke pleaded guilty in December and will pay a $1 million penalty for bird deaths at two Wyoming wind farms.
House Panel Targets EPA’s Choice of CCS Technology
The House Energy and Commerce Committee launched an investigation into the Environmental Protection Agency’s rule limiting carbon emissions from new coal-fired plants. The committee’s Republican leadership, longtime opponents of the agency’s drive against coal plant emissions, demanded documents and names involved in EPA’s decision to set standards that require use of carbon capture and storage (CCS) technology.
Provisions of the Energy Policy Act of 2005 bar the agency from setting standards based on technology used in government-funded projects, the committee members say. Coal defenders say CCS technology has not been proven in real-world use. The EPA says its rule does not violate EPAct because the technology is proved elsewhere and its standards are achievable.
The Federal Energy Regulatory Commission issued a 10-year pilot license to Public Utility District No. 1 of Snohomish County, Washington, for the proposed 600 kW Admiralty Inlet Pilot Tidal Project to be located in the Puget Sound. In issuing the license, FERC determined the project would not adversely affect an undersea Trans-Pacific fiber optic communication cable nearby.
FERC’s action authorizes the PUD to evaluate the environmental, economic and cultural effects of hydrokinetic energy. The pilot license contains measures to protect fish, wildlife and other features and infrastructure.
Acting FERC Chairman Cheryl LaFleur called the project “an innovative attempt to harness previously untapped energy resources.”
The Federal Energy Regulatory Commission last week approved a revised definition of the bulk electric system (BES) that refines the exclusions for radial facilities and local networks.
The commission’s order (RD14-2) approved changes drafted by the North American Electric Reliability Corp. in response to FERC and industry concerns over how NERC was identifying facilities that are subject to its mandatory reliability rules.
In Orders 773 (December 2012) and 773-A (April 2013), FERC approved a new definition of BES facilities, eliminating regional discretion and establishing a “bright-line” threshold including most facilities operating at or above 100 kV. (See Seeking “Bright Line,” FERC Leaves BES Appeal Rules Unclear.)
Although the new definition supersedes the Order 773 definition in total, it will “result in minimal changes to the elements included in the bulk electric system,” FERC said.
NERC said the revised rules respond to the technical and policy concerns raised in the prior orders by adding “clarity and granularity that will allow for greater transparency and consistency in the identification of elements and facilities that make up the bulk electric system.”
The changes, effective July 1, 2014, mostly affect inclusion I4 (dispersed power producing resources) and exclusions E1 (radial systems), E3 (local networks) and E4 (reactive power devices).
In addition, there are minor clarifications to inclusions I1 (transformers), I2 (generating resources) and I5 (static or dynamic reactive power devices). No changes were made to the core definition, inclusion I3 (black start resources) or exclusion E2 (behind the meter generation). (See Bulk Electric Systems (BES) Inclusions and Exclusions.)
Exelon Corp., the American Public Power Association, the Transmission Access Policy Study Group (TAPS) and Public Utility District No. 1 of Snohomish County submitted filings supporting NERC’s revisions. APPA and Snohomish praised the new definition for its focus on core facilities that present the greatest risks of reliability failure.
FERC rejected requests from several other intervenors, including the American Wind Energy Association (AWEA) and the Electricity Consumers Resource Council (ELCON), for changes in NERC’s proposal.
AWEA and First Wind Holdings LLC had asked the commission to modify inclusion I4 to exclude individual power producing resources. The commission said the purpose of inclusion I4 is to include all forms of variable generation. “As we noted in Order No. 773, there are geographical areas that depend on these types of generation resources for the reliable operation of the interconnected transmission network,” the commission said. “… Nothing in the AWEA and First Wind pleadings have convinced us that our determinations in Order No. 773 need to be revisited.”
FERC cited a 2009 NERC report on variable generation that concluded that “[d]istributed variable generators, individually or in aggregate (e.g. small scale photovoltaic), can impact the bulk power system and need to be treated, where appropriate, in a similar manner to transmission connected variable generation.”
The commission said wind farms larger than 75 MVA can affect reliability if all of its wind turbines trip offline simultaneously after small fluctuations in voltage or frequency. “Because variable generation can impact the interconnected transmission network, we anticipate that wind plant owners whose facilities meet the inclusion I4 criteria who seek to exclude individual wind turbines from the bulk electric system through the exception process will be infrequent,” the commission wrote.
In other reliability actions last week FERC also:
Approved five standards requiring generators owners and, in some cases, transmission owners to provide verified data for certain power system planning and operational studies. The rules are intended to improve the accuracy of the studies and the coordination of protection system settings.
Proposed revisions to an existing standard on Transmission Relay Loadability and a new standard on Generator Relay Loadability designed to prevent generators from tripping offline unnecessarily during a system disturbance.
Denied rehearing of Order No. 791, which approved version 5 of the Critical Infrastructure Protection standards.
WASHINGTON – An appellate court panel last week grilled attorneys seeking to overturn FERC’s Order 1000, expressing skepticism over challenges to the agency’s jurisdiction and claims that allowing competition in transmission development will harm reliability.
The three-judge panel for the D.C. Circuit Court of Appeals was less aggressive in questioning FERC’s attorneys, interrupting them less frequently than they did in sparring with lawyers seeking to overturn the order.
“I’m having trouble understanding where this steps on your prerogatives,” Judge Nina Pillard said in response to the attorney for the Alabama Public Service Commission, who contended the order would render state transmission planning “meaningless.”
“It doesn’t require much of you,” she said earlier, in response to objections from Southern Co., citing what she called the order’s “very flexible and open-ended requirements.”
Judge Thomas B. Griffith questioned the South Carolina Public Service Authority’s contention that the commission lacked authority to allow non-incumbent transmission developers equal footing with incumbents in obtaining funding through regional cost allocation processes.
“It seems to be in the wheelhouse of [FPA section] 206,” Griffith said.
Judge Judith Ann Wilson Rogers also seemed unpersuaded by the challengers.
John L. Shepherd Jr., representing Public Service Electric and Gas, noted that Congress has resisted efforts to extend FERC’s natural gas pipeline siting and construction-approval authority to electric transmission. FERC’s removal of incumbents’ right of first refusal (ROFR), he said, was “a radical mandate that Congress did not authorize FERC to impose.”
Judge Rogers responded that nothing in the order gives FERC authority to decide what gets built or who does it.
Rogers and her colleagues frequently cited a Brattle Group report commissioned by Edison Electric Institute that estimated a need for nearly $300 billion in new transmission facilities by 2030. Brattle found that more than $180 billion in transmission would not be built due to shortcomings in pre-Order 1000 transmission planning and cost allocation rules.
Faced with such evidence, Rogers said, “I’m trying to understand why Congress would tell FERC to … sit on its hands.”
Judge Pillard agreed: “It would be, arguably, irresponsible for a regulator not to require planning in advance,” she said.
Attentive Audience
E. Barrett Prettyman Courthouse
The three-hour oral argument drew a rapt crowd of about 100 spectators — including numerous FERC officials, PJM Assistant General Counsel Pauline Foley and LS Power’s Sharon Segner — to the grand, wood-paneled courtroom at the E. Barrett Prettyman U.S. Courthouse a few blocks from the Capitol.
Order 1000, issued in July 2011, changes the process for planning and paying for new regional and interregional transmission lines. It also allows independent developers to compete with traditional utilities in building new lines.
The court is considering complaints from those who allege the commission overstepped its authority and those who say it didn’t go far enough in ensuring that transmission will be sufficient to satisfy public policy initiatives, such as state renewable portfolio standards.
The main threat to the order comes from challengers in the Southeast and West who allege the commission exceeded its authority under the Federal Power Act in requiring public utility transmission providers to participate in regional transmission planning, and eliminating incumbent transmission providers’ monopoly on building and running transmission.
The order is also being challenged for its cost allocation provisions, which require that those who benefit from new regional transmission facilities share in their costs while ensuring that the costs of interregional projects not be assigned involuntarily.
Repeated Interruptions
Harvey L. Reiter, of Stinson Leonard Street, spoke first on behalf of the Sacramento Municipal Utilities District, South Carolina Public Service Authorityand the Large Public Power Council, which are among those challenging FERC’s jurisdiction.
Reiter was repeatedly interrupted by the panel, which featured appointees from the last three administrations: Rogers (Clinton), Griffith (George W. Bush) and Pillard (Obama).
The pattern was repeated with Andrew W. Tunnell of Balch & Bingham, the Birmingham, Ala., law firm for Southern Co.
Tunnell said the order is “based on speculation” and not on any proof that the current rules are harming transmission. “If there really was a problem it would have come out in the rulemaking process.”
He cited a Department of Energy study praising the Southeast’s transmission planning.
“FERC is going to break what works … and replace it with a very bureaucratic and litigious process,” Tunnell said. “That means you’re not going to have a more efficient transmission planning process, you’re going to have less.”
Public Policy
The judges seemed to show a bit more sympathy for the arguments of the American Public Power Association and the National Rural Electric Cooperative Association (NRECA), who contend Order 1000 didn’t go far enough to protect public policy interests.
While the order requires that load serving entities (LSEs) have input into transmission planning, it “doesn’t require that their advice be heeded,” said the group’s attorney Randolph Lee Elliott, of McCarter & English.
Judge Pillard questioned FERC about the groups’ concerns. “If the parade of horribles came to pass, that’s tough luck?” she asked FERC attorney Beth G. Pacella.
Judge Griffith joined in. “Doesn’t the law require more than that they be part of the process? To meet their needs, not just talk about their needs? It’s not just process. It’s process that leads to a certain result.”
Pacella acknowledged that the order “doesn’t require that [public power] needs be met.” But, she said, parties whose needs are not met by the planning process can file a section 206 complaint to seek a FERC finding that the planning process “is no longer just and reasonable.”
Rebuttal
On rebuttal, Tunnell said FERC should have stopped in 2007, when it issued Order 890, which created a process of voluntary regional transmission planning. “FERC didn’t give voluntary transmission planning a chance,” he said. FERC began the Order 1000 rulemaking while “the ink was still wet” from Order 890 and the commission was considering Southern’s 890 compliance filing, he said.
Tunnell said Order 1000 will “undermine our vertical integration” and with it, its benefits: quicker storm restoration and economies of scale in operations and maintenance. “Transmission planning doesn’t address that,” he said.
“I think we’re all surprised to hear that,” shot back Judge Rogers.
“It’s changing the whole paradigm,” Tunnell insisted. “Transmission is a natural monopoly.”
State Jurisdiction on Planning
Luke D. Bentley IV, attorney for the Alabama Public Service Commission, led off the second of three sessions, this on cost allocation.
Bentley cited a list of state statutes governing transmission planning. FERC did not respond in their brief, “because they can’t,” Bentley said. Order 1000, he continued, would “relegate states to mere stakeholders in the planning process.”
“Yes for interstate transmission,” responded Judge Pillard. “That’s Con[stitutional] Law 101.” FERC balanced federal and state interests, she said, “in a relatively flexible way.”
FERC attorney Lona T. Perry said the commission’s order stops at the state border: “Any project that gets approved in the regional planning process that doesn’t get the requisite state approvals for construction and siting doesn’t get built,” she said.
Jonathan D. Schneider of Stinson Leonard Street, and attorney for the South Carolina Public Service Authority and the Large Public Power Council, said the case isn’t about cost allocation but “about a new funding mechanism that the commission thinks is better,” and that it would force utilities to fund independent transmission developers.
Judge Griffith, questioning FERC Attorney Robert M. Kennedy, observed, “There’s a significant difference between inducement and coercion.”
Kennedy said the commission was simply enforcing “long-standing, well established” principles that assign transmission costs to beneficiaries.
“We’re not imposing a relationship. We’re recognizing a relationship that exists” because of the physics of the transmission system, Kennedy said.
Right of First Refusal
The final session focused on the order’s reversal of previous FERC policy that allowed incumbent utilities rights of first refusal to add new transmission in their franchised territories.
Shepherd, of Skadden Arps, said the ruling unfairly gives non-incumbents the rights to cherry pick transmission projects they’d like to build without the obligation to serve all customers that public utilities face. “It’s not competition, it’s predation,” he said.
FERC’s Perry said that if ROFR prevails, independent developers would only be allowed to participate as merchants, without utilities’ ability to build cost of service projects. She said the commission found no reason to believe that transmission run by independents will be less reliable than that of incumbents.
Comic Relief
The intensity of the argument was briefly broken at the end of the three-hour session, when FERC relinquished some time on rebuttal to Patton Boggs’ Mike Engleman, attorney for LS Power, an independent transmission developer with much at stake in the ROFR battle.
Engleman’s move to the podium surprised one of the judges, who began addressing a different lawyer.
“That’s OK, much of the room doesn’t want me here,” Engleman said, prompting the courtroom to burst into laughter.
Engleman said LS Power spends tens of thousands of dollars on every project but often walks away empty-handed.
“There are rules in multiple regions that say, ‘You can’t play in our sandbox,’” Engleman said.
Shepherd had the last word, picking up on Southern’s claim that non-incumbent transmission developers pose a reliability risk.
“If these guys [attach to] your system and break it, you [the incumbent] have to fix it.”
[Editor’s Note: As a member of the FERC Office of Enforcement, the author of this story testified against Southern Co. in 2003 (docket no. ER03-713) and in 2006 publicly challenged a settlement negotiated between Southern and the commission’s chief of staff (EL05-102).]
Average locational marginal prices rose nearly 10% to $38.66 MWh in 2013, which Bowring noted was “still relatively low if you put it into historical perspective.”
The Energy Market was deemed competitive, despite the evaluation of the local market structure as not competitive “due to the highly concentrated ownership of supply in local markets created by transmission constraints.”
Fuel Source
Coal rebounded in 2013, generating 44% of PJM’s power, up 6 percentage points over 2012. Nuclear was next (34.8% of the RTO’s electricity, up 1.4 points). Gas’s share dropped to 16.3%, down 12.2% because of higher fuel prices.
Wind’s output was up 17.4%, though it still generates a relatively small amount of electricity (2%), while oil saw a 61% drop in energy production.
As far as installed capacity, coal ended the year with 75,559 MW, or 41.3% of ICAP, down 0.4% from the year before. Gas was up 0.6% over the course of the year, ending at 53,380 MW, or 29.2% of ICAP. Nuclear was even at 33,076 MW, or 18.1%.
Demand Response
DR revenue rebounded in 2013 from 2012 but was still below the more than $500 million in each of 2010 and 2011.
Congestion
Congestion costs were up 28% in 2013 to $676.9 million. Despite the increase, congestion remained less than a third of the $2.05 billion in 2008.
The 2013 PJM State of the Market was, to quote that noted economist Yogi Berra, mostly “déjà vu all over again.”
The 2012 report had called for substantial changes to the capacity market, demand response and the treatment of uplift. The 2013 report, which was unveiled by Market Monitor Joe Bowring during a press briefing Thursday in Washington, identifies shortcomings in the same areas.
The results of five of six markets — Energy, Capacity, Synchronized Reserve, Day-Ahead Scheduling Reserve and FTR Auctions — were judged competitive, as in 2012, along with the Regulation Market, which was judged not competitive for most of 2012.
Capacity Market
While the Capacity Market remains competitive, the 444-page report by Monitoring Analytics labeled the aggregate market structure and local market structure as not competitive, as in most prior years since 2007.(See sidebar, PJM 2013 by the Numbers.)
Bowring’s recommended changes for the market were no surprise either. Among them: Requiring that all resources be physical; making all demand response a year-round product subject to must-offer rules and requiring all imports be pseudo tied.
Alternatives to internal generation must be “full substitutes,” he said, not the currently “inferior products” which are suppressing capacity prices.
“If demand response is going to be in the capacity market…it should be available every hour and it should be treated as a real product. It is a real product,” said Bowring. The report calls for classifying all demand response as Economic and eliminating Limited and Extended Summer DR.
Bowring said DR providers can build such generation “substitutes” by aggregating resources into portfolios, a requirement he acknowledged would make DR more expensive.
Generation at Risk
Under current rules, Bowring said, DR and imports are suppressing capacity prices, particularly in western PJM. Add in low natural gas prices, which have caused LMPs to fall, and the result is 87 generators, totaling 14,597 MW of capacity, at risk of retirement. That is in addition to the 24,933 MW currently planning to close.
The 87 generating units — combustion turbines, coal, gas, oil and dual-fuel plants — were unable to cover avoidable costs in 2013, or didn’t clear the 2015/2016 or 2016/2017 base capacity auctions.
Although the report did not assess the viability of PJM’s existing nuclear fleet, Bowring said he was not surprised by reports that Exelon Corp. is threatening to close three of its nuclear generating stations in Illinois. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Bowring said although he lacked data to calculate the current nuclear fleet’s operating costs, no new nuclear plant could be profitable under current prices. “The net revenues are only covering 30 percent or so of costs,” he said.
At the other end of the spectrum, revenues for solar generation in the PSEG zone were double their fixed costs, due largely to state and federal subsidies.
Uplift
(Source: State of the Market 2013, Monitoring Analytics, LLC)
Energy uplift increased by $231 million or 36% in 2013. The two main culprits were reactive services, with an increase of $263.5 million, and black starts, which were up $78.2 million. Balancing and day-ahead charges dropped.
The report says PJM should increase its transparency by having operators record the reasons for dispatching out-of-merit generators and identifying the units that are receiving uplift payments.
Ten generating units — less than 1% of all units — received 38% of all uplift in 2013, but PJM confidentiality rules prohibit these units from being identified.
“All uplift payments should be public information. They are [currently] totally non-transparent,” Bowring said. “No one in the market really understands what’s going on.”
Identifying the causes of uplift and the generators receiving payments would allow competition to reduce those costs, he said.
In addition, the report says up-to congestion trades should be required to pay uplift charges like other virtual transactions.
Interchange Ramp
Bowring was adamant in his opposition to a proposal floated by PJM officials last week that would allow operators to reduce interchange ramp limits to reduce price volatility. (See Ramp Limits Cause Stir at MIC.)
“In our view, we see nothing wrong with [price] swings. It’s what happens in markets. [PJM] Operators should not be concerned with price volatility,” Bowring said.
State of the Market 2013 High Priority Recommendations
Editor’s Note: RTO Insider will have a full report on the State of the Market in our next newsletter, March 25.
The Market Implementation Committee endorsed updates to PJM’s Regional Transmission and Energy Practices last week in support of the RTO’s new ExSchedule software and a new product designed to reduce uneconomic power flows between PJM and NYISO.
Chapter 2 of the document was revised to standardize and simplify it to accommodate the retirement of the current EES application and replacement with ExSchedule. The data requirements and data validations section was expanded to align with the new application, which PJM plans to deploy in late April.
Language also was added to reflect the new PJM-NYISO Coordinated Transaction Scheduling product.
The scheduling tool that would be used to optimize power trading between PJM and NYISO is accurate within $5/MWh more than two-thirds of the time, according to a new analysis provided to members last week.
Intermediate Term Security Constrained Economic Dispatch (IT SCED), a tool that PJM operators use to determine resource commitments, would take on a new function in screening interregional trades if its accuracy passes muster with stakeholders.
Under a new product, Coordinated Transaction Schedules, traders would be able to submit “price differential” bids that would clear when the price difference between NYISO and PJM exceed a threshold set by the bidder.
CTS, which is intended to reduce uneconomic power flows between PJM and NYISO, was conditionally approved by the Federal Energy Regulatory Commission Feb. 20. It could be implemented as soon as November if the Markets and Reliability Committee votes to endorse the accuracy of IT SCED. (See NYISO Scheduling Product Wins FERC OK.)
PJM officials told members last week that an analysis of data for the NYISO Interface found the 30-minute forecast that would be used by CTS was accurate within +/- $5 an average of 69% of the time between February and December 2013. It missed by more than $20/MWh about 11% of the time.
The tool was most accurate during the fall months and least accurate in the winter (see chart).
One stakeholder asked PJM to provide the raw data from the forecasts, saying the $5 threshold used in the RTO’s analysis was too broad to evaluate the tool. “Margins on power trades are much less than $5/MWh,” he said.
PJM began posting IT SCED’s forecasted LMPs in December for member review. It plans to begin publishing the forecasts in real time at the end of April.
An analysis by NYISO of its 15-minute forecasts found that they were within +/- $5 from 61% to 73% of the time, based on monthly averages for 2013.
