PJM is considering ways to simplify the sharing of real-time generator data to improve situational awareness and help transmission operators respond more quickly in emergencies.
AEP’s Dana Horton urged the Markets and Reliability Committee Thursday to consider changing the current rules on data access, which he said are cumbersome and time consuming.
Horton said transmission operators would “like to be able to see real-time megawatt hour output from all generators in the PJM footprint, like PJM control operations folks do. They’re dealing with a lot of transmission overload issues. If they could see more output data, for more of the region that impacts their area, they are better able to give feedback.”
Horton said the current procedure for obtaining data access, spelled out in Manual 14D, “looks like it was written in the 1950s. It refers to making copies in triplicate.”
State Estimator (Source: ETAP)
Phil Hoffer, an AEP transmission operations manager, said the data would be used as an input to AEP’s state estimator. “Some units may be outside of our control area but have significant impact on our operations,” Hoffer explained.
PJM officials said the RTO supports the effort. “We should be as transparent as we can,” said Executive Vice President for Operations Mike Kormos.
CEO Terry Boston noted that PJM found other transmission operators’ state estimators helpful during the September heat wave, particularly for understanding conditions on lower voltage systems.
PJM Market Monitor Joe Bowring said he would support streamlining the sharing rules if it were done in a way to preserve confidential information. Existing confidentiality agreements and codes of conduct should satisfy any confidentiality concerns, AEP said.
The MRC will be asked to vote on AEP’s issue charge and problem statement at its next meeting. If approved as is, the issue would be assigned to the Operating Committee.
The Markets and Reliability and Members committees approved the following measures with little or no discussion last week:
Markets and Reliability Committee
Changes to Manual 14A: Generation and Transmission Interconnection Process, which updated Attachments F & G. These attachments list wind turbine models that do not need to be reviewed by PJM prior to submission of system impact and generation interconnection feasibility studies. Units listed reflect those PJM has modeled in the past.
Revisions to PJM’s Tariff and Operating Agreement to update the list of agreements and transmission service transactions to which PJM Settlement, Inc. is not a part.
Operating Agreement and Tariff revisions in preparation for eSuite application name changes. These revisions include changing eSchedule and Enhanced Energy Schedule (EES) to InSchedule and ExSchedule, respectively, in the documents. This is part of a larger refresh of eSuite tools, which will occur in stages through the end of the year. (See PJM Updating eSuite Apps.)
Updates to the Regional Transmission and Energy Scheduling Practices for the deployment of ExSchedule. The changes remove ramp reservation and tag timing requirements based on schedule duration. These changes were requested in part due to the new Coordinated Transaction Scheduling (CTS) between PJM and NYISO, which aims to reduce uneconomic flows between the RTOs. (See NYISO Scheduling Product Wins FERC OK.)
Changes to accelerate the schedule of the triennial review of the Cost of New Entry (CONE) by two months. The change, which was also approved by the Members Committee, will move the deadline for staff recommendations to May 15 from July 15 and the projected FERC filing to Oct. 1 from Dec. 1. The CONE review will be conducted every four years beginning with the 2018/2019 Delivery Year.
Members Committee
Tariff revisions associated with CTS and export transactions. The key change is the addition of a provision stating that export transaction screening will not apply to emergency transactions between PJM and neighboring balancing authorities.
Members reacted warily Thursday to PJM’s proposal to develop a generic transition mechanism that would hold capacity providers harmless for future rule changes.
PJM’s Adrien Ford told the Markets and Reliability Committee that the proposal was prompted by the transition mechanism approved by members to protect generators whose installed capacity ratings are reduced by seasonal verification tests. (See Transition Period OKd for Seasonal Verification Rules.)
Bruce Campbell, of demand response provider EnergyConnect, said the proposed solution, based on the Manual 21 fix for generators, may not provide protection for DR.
“This mechanism is really impractical” because it assumes the impact of the changes can be predicted, Campbell said. “We often don’t know what the impact of the changes will be.”
Susan Bruce, of the PJM Industrial Customer Coalition, said she prefers “stability” in capacity market rules. “It might make rule changes too easy to contemplate,” she said.
Exelon’s Jason Barker said his company had “reservations about a `one size fits all’ solution.”
Barker said “it would certainly be helpful to have a default” transition mechanism. But he said it should be spelled out in manuals and not the Tariff or Operating Agreement, where changes would require Federal Energy Regulatory Commission approval.
Katie Guerry, of DR provider EnerNOC, agreed, suggesting the mechanism not be a “defined solution but a set of parameters that must be abided by.”
Ford said PJM officials attempted to address DR in drafting the problem statement. “We wanted to make sure it works for all types of capacity resources,” she said.
Financial Transmission Rights holders asked PJM and Market Monitor Joe Bowring last week to take action to address the continuing shortfall in FTR funding. They received sympathy but no commitments.
In June, the Federal Energy Regulatory Commission rejected a complaint (EL13-47) by FirstEnergy Solutions Corp. that sought to bill all transmission users to make up the shortfalls. While PJM largely supported FirstEnergy’s proposed solution, the Monitor rejected it as “simplistic” and unfair to load.
The commission urged PJM and its stakeholders to reach a consensus solution and to work with its neighbors to reduce congestion on the RTO’s borders. In August, the commission granted rehearing in the case, keeping the docket open but offering no timetable for further action.
$1.1 Billion
In the interim, market participants say, the problem has only gotten worse. Cumulative shortfalls have grown to more than $1.1 billion (see chart). DC Energy’s Bruce Bleiweis told the Members Committee Thursday that March “could be the worst ever.”
“It’s a problem that hasn’t gone away,” said Bleiweis. “We’re still looking for action.”
PJM introduced FTRs in 1999, intending them to provide a financial hedge against the costs of day-ahead transmission congestion.
The value of an FTR is based upon the difference between the day-ahead congestion price between a specific source and sink. The quantity of FTRs to be auctioned is supposed to be limited by transmission capacity.
But a PJM stakeholder report found that revenues were falling short because pre-auction modeling failed to capture some transmission outages and deratings. The modeling also could not account for market-to-market flowgates added in the middle of a planning period.
Consensus Elusive
Since the report, PJM officials have worked with MISO to reduce congestion resulting from cross-border flows.
Last spring, stakeholders also approved two modeling changes recommended by the Financial Transmission Rights Task Force that were expected to provide modest improvements. But members were unable to reach consensus on others, including several proposed by the Monitor. (See MIC Rejects Change to FTR Long-Term Auction Modeling.) The task force was disbanded in December.
With no solutions coming from the stakeholder process and no action from FERC, Goldman Sachs’ J. Aron & Co. seized upon PJM’s ad hoc creation of a pricing interface in the ATSI region during the Sept. 10-11 heat wave. PJM’s action, intended to make demand response set prices in the area, exacerbated underfunding by $23 million over the two days, J. Aron said in a filing in the FirstEnergy docket in December.
Top Binding Constraints in FTR Auctions and ARR Allocations (Source: State of the Market 2013, fig. 13-1)
FTR holders found a new opportunity to bring the issue up when Bowring gave members a presentation on the 2013 State of the Market report, which also criticized the creation of such interfaces.
Harry Singh, of Goldman Sachs, said market participants used to be able to buy 1.2 or 1.3 FTRs for a path they were looking to hedge, but that the technique no longer works because the level of underfunding varies significantly from day to day. On Feb. 14, for example, the funding was only 30%; on Sept. 10 and 11 it approached zero.
In 2010, load serving entities converted almost 63% of their Auction Revenue Rights (ARRs) to FTRs, Singh said. In 2013, only 31% did so. “That tells you people think it doesn’t work as a hedge,” Singh said. Instead, he said, the market has become a way to speculate on uplift and the level of underfunding.
Sympathy, No Commitments
Bowring and PJM CEO Terry Boston acknowledged the problem but were noncommittal about pursuing solutions.
“I’m almost certain the stakeholder process is not going to come to a resolution on this issue,” Boston said. “But we need to keep it on the table.”
The State of the Market report declared the FTR market performance competitive. But it said the market design was flawed because it “incorporates widespread cross subsidies which are not consistent with an efficient market design and over sells FTRs.”
The Monitor noted that the market has responded to the shortfalls by reducing bid prices and increasing bid volumes.
Clearing prices for FTR obligations averaged $0.30/MW in planning year 2013/14, down from $0.71/MW in 2010-11. FTR obligation sell offers dropped to $0.05/MW down from $0.22/MW over the same period.
The report reiterates eight recommendations Bowring made in an April 2013 filing in response to the FirstEnergy complaint.
Bowring said the eight recommendations could increase the FTR payout ratio to almost 96% from the current rate in the mid-70s. The recommendations included a reduction in the allocation of ARRs, the elimination of portfolio “netting” and using probabilistic analysis to improve transmission outage modeling.
In response to a question from Bleiweis, Bowring said he had considered making a Section 206 filing to win FERC approval for his proposed changes. “It’s really a question of timing,” Bowring said, adding that he’d like “to see if others will join us” in support.
PJM’s day-ahead prices for last Thursday turned out to be far more modest than they initially appeared.
The RTO reposted the day-ahead results for March 27 after officials identified an error in the input data used to clear the market. A value of 350 MW was used for the West Interface instead of 3,500 MW for hours 8 through 23, causing incorrect prices and quantities in the day-ahead market solution.
A glum Stu Bresler, vice president of market operations, informed stakeholders of the error at the end of Thursday’s Members Committee meeting. In reposting the results, Bresler said PJM was invoking a provision put in the Tariff “with the hope that we’d never have to use it.”
The changes reduced prices by as much as $37/MWh, with the biggest changes seen in the AECO, BGE, JCPL, METED, PECO, PPL and PSEG zones. In the PPL zone, for example, the LMP for hour 20 — originally posted at $89.41 — was reduced to $52.16.
Bresler said yesterday that the error resulted in higher day-ahead dispatch orders for some generators east of the West Interface and lower orders for those to the west, but that the actual dispatch of the units in real time was unaffected.
Bresler said the apparent constraint at the West Interface “didn’t bind that hard, so it wasn’t enough to raise a red flag” before the day-ahead results were initially posted.
He said officials are investigating whether they can add an automated check to prevent such errors in the future. “We certainly don’t want the market to think this is going to be a regular occurrence,” he said.
Exelon has agreed to buy ETC ProLiance Energy, which supplies natural gas to commercial and industrial customers, generators and utilities. The Indianapolis-based ProLiance, which serves customers in eight Midwest states, will become part of Exelon competitive retail unit Constellation. ProLiance is a unit of ETC Marketing of Dallas. The transaction is expected to close in the second quarter.
London-based engineering and project management company AMEC has teamed up with Exelon Nuclear Partners to explore opportunities in new markets. According to AMEC, the partnership will focus on new and existing reactor marketplaces, providing engineering, consulting, project management and operations support service. “It supports our strategy to grow our nuclear capability and will create a formidable entity to target major projects in new and exciting markets such as the Middle East and mainland Europe,” said Clive White, president of AMEC’s Clean Energy Europe business, citing his company’s synergy with Exelon’s “unrivalled operational experience.” AMEC said the companies also would explore opportunities in renewables, transmission and distribution, and that they have already identified some possible projects.
JPMorgan Chase, which for months was looking for a buyer for its physical commodities trading unit, has agreed to sell it to Swiss trading firm Mercuria Energy Group for $3.5 billion. It is unclear whether Blythe Masters, head of Global Commodities at the bank, will be going to Mercuria. Masters came under scrutiny last year when the Federal Energy Regulatory Commission charged the bank with manipulating California’s energy markets. In a document that became public, FERC said Masters had made false and misleading statements under oath. FERC, however, did not pursue action against her and ultimately approved a settlement with the company, with JPMorgan paying $410 million in fines and disgorged profits. (See Analysis – JP Morgan Settlement: A Verdict on Electric Markets?)
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.”
