The Federal Energy Regulatory Commission gave preliminary approval last week to rules to protect the grid from geomagnetic disturbances and a final OK to a reliability standard for frequency response.
Geomagnetic Disturbances – EOP-010-1
The commission’s Notice of Proposed Rulemaking (RM14-1-000) endorsed Reliability Standard EOP-010-1, the North American Electric Reliability Corp.’s initial response to the commission’s July order calling for rules to close the “reliability gap” regarding geomagnetic disturbances (GMDs) caused by solar events. (See FERC Orders Rules on Geomagnetic Disturbances.)
1989 Solar Storm (Source: Metatech Corp.)
Geomagnetically induced currents can flow through transformers and transmission lines, leading to increased reactive power consumption and disruptive harmonics that can cause system collapse.
The standard requires reliability coordinators and some transmission operators to institute operational procedures to mitigate the effect of GMDs. (The rule applies to transmission with a “transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV.”)
Not covered are balancing authorities and generator operators although the second stage of the standards could apply to generators, FERC said.
In stage two, NERC must determine what severity GMD will constitute a “benchmark” GMD event. Covered entities will be required to assess the potential impact of such benchmark events on their equipment and systems.
Comments on the proposed standard will be due in 60 days after publication in the Federal Register.
PJM Procedures
PJM already has GMD operational procedures, which are detailed in section 3.7 of Manual 13. The plan calls for PJM to notify generation and transmission members via the PJM All-Call system and Emergency Procedure posting application when the National Oceanic and Atmospheric Administration (NOAA) issues an alert for a potential GMD with a ranking of 5 or greater on the 9-point “K-index.”
Once a GMD has been confirmed, PJM dispatchers must operate the system under transfer limits determined from studies that modeled several scenarios, including the loss of the Hydro-Quebec Phase 2 DC line to Sandy Pond and the loss of generation at Artificial Island, the site of the Salem and Hope Creek nuclear plants.
Frequency Response – BAL-003-1
The BAL standard sets requirements for the provision and measurement of frequency response, which is not covered by current standards.
The rule establishes a minimum frequency response obligation for each balancing authority, provides a uniform calculation of frequency response, establishes frequency bias settings, and encourages coordinated automatic generation control (AGC) operation.
The commission ordered NERC to increase the violation risk factor for Requirement R1 — mandating minimum frequency response obligations — to high from medium.
“Without sufficient primary frequency control, a frequency decline may not be arrested in sufficient time to prevent instability, uncontrolled separation or cascading failures,” the commission wrote. “…The fact that one entity’s violation of Requirement R1 may be offset by the efforts of others is not a basis for ignoring or downplaying the substantial risk posed by inadequate frequency response.”
It also ordered NERC to remove references to performance of R1 by other entities: “We believe that violation severity levels for this requirement should be set so as to discourage particular responsible entities from `leaning on’ other entities to provide sufficient frequency response collectively to meet the relevant Interconnection Frequency Response Obligation.”
The commission directed NERC to submit two reports, one addressing the results and recommendations of a light-load case study of the Eastern Interconnection, and a second evaluating the use of the linear regression methodology for calculating frequency response and the availability of resources to meet the frequency response obligation.
The commission said the reports will indicate the effectiveness of the Reliability Standard in assuring sufficient frequency response is available to respond to system events and whether changes are needed.
The Chicago City Council approved a $13 million, 62-building retrofit project, the first and only one stemming from Mayor Rahm Emanuel’s Chicago Infrastructure Trust initiative, which aims to make city buildings more energy efficient. The cost is only 11% of what was envisioned when the trust was launched two years ago. Bank of America is to finance the project, earning 4.95% on its investment for 15 years.
Louisville Gas & Electric and Kentucky Utilities asked the Public Service Commission for approval to build a second natural gas combined-cycle plant and a solar facility. The 700 MW gas plant would be at the Green River plant site, where the utilities are retiring coal-fired generation capacity. They already plan to build a 640 MW gas unit at the Cane Run plant site. The utilities also plan a 10 MW solar facility at the Brown station.
LG&E and KU also asked the PSC to let them expand several energy efficiency programs and add an option for customers to get advanced meters. The programs to be expanded are those for home energy rebates, home and commercial energy analyses and commercial demand conservation. The utilities also would extend education and public information programs.
Dianne Solomon, wife of a former president of the Board of Public Utilities, was appointed to that position last week when Bob Hanna left the presidency to assume a judgeship on the state Superior Court. Solomon’s husband, Lee Solomon, who preceded Hanna in the presidency, is also a Superior Court judge.
Gov. Chris Christie made no announcement of his appointment of Dianne Solomon, who has been a commissioner since last summer. A paralegal, she is a former commissioner at the South Jersey Transportation Authority.
U.S. Deputy Energy Secretary Daniel Poneman met with state business and community leaders in a roundtable at Public Service Enterprise Group’s headquarters to discuss electricity infrastructure needs and PSEG’s controversial grid-investment plan, Energy Strong.
The Southern Environmental Law Center filed court papers on behalf of seven water conservation groups that want to participate in state environmental officials’ lawsuits against Duke Energy over coal ash disposal sites. The Department of Environment and Natural Resources’ enforcement actions involve seven operating and retired plants.
Invenergy Wind Development reached an agreement with the Department of Defense to mitigate impacts of the company’s Pantego Wind Energy Project in the eastern part of the state. Turbines would be placed no closer than four nautical miles from the centerline of a flight route used by Seymour Johnson Air Force Base.
The project is not a certainty, however, and Invenergy continues to evaluate its development plans, “with a specific time line still to be determined.”
A market researcher ranked the state as second highest for solar demand in 2013, behind only California. In NPD Solarbuzz’s year-ago report, the state ranked fifth. The director of the Nicholas Institute for Environmental Policy Solutions attributed the state’s rise to solar-friendly policies, which include a 35% solar tax credit and a 12.5% renewable portfolio standard.
A fired worker allegedly threatened to blow up Dayton Power and Light’s coal-fired Stuart Station on the Ohio River, but no bomb was found there. DP&L had to shut down one of four units at the plant while law enforcement agencies investigated.
FirstEnergy’s American Transmission Systems Inc. and Ohio Edison asked the Ohio Power Siting Board for authorization to build a 3.5-mile, 138-kV line to the Hickory Bend cryogenic gas-processing plant operated by Pennant Midstream, a NiSource subsidiary.
The plant, which is almost operational, will separate wet from dry gas from the Utica shale formation. The siting board put the transmission application on an accelerated consideration track, and FirstEnergy said it could start construction as soon as February.
FirstEnergy is replacing a transformer at its Beaver Valley Nuclear Power Station after the plant shut down January 6. It was not clear whether the severe cold weather played a role in the sudden shutdown. The company did not say how long the transformer replacement would take.
Two members of the state legislature expressed concern about PJM’s generation adequacy in the wake of the severe cold snap that tested the grid’s strength. In letters to the Public Utility Commission and PJM, Sen. Tim Solobay and Rep. Pam Snyder said the RTO’s difficulty during the polar vortex raised questions about the closure of the Hatfield’s Ferry and Mitchell plants, which PJM has said would not affect reliability.
A NextEra Energy Resources wind turbine on a ridge in Springfield Township apparently fell over and crumpled. The company said it was investigating the cause. A nearby resident said the night was still, although the area has had high winds this season. According to a NextEra official, the turbines are on private property away from buildings, and “The risk to the public (from a collapse) is zero.”
A bill to protect birds and bats from wind turbines passed the state Senate Committee on Agriculture, Conservation and Natural Resources 9-5, advancing to the full Senate for consideration. The bill would require the Department of Game and Inland Fisheries to consult with the Department of Environmental Quality when it writes regulations for wind and other renewable energy projects.
Sponsor Sen. Tom Garrett (R) rejected allegations by some wind power advocates who criticized the measure as anti-wind. “We will, I hope, generate a greater and greater percentage of our power in the coming years via renewable energy resources… That doesn’t mean we should do so irresponsibly.”
Below is a summary of PJM’s proposed changes to the incremental auctions. Alternative proposals are also described where they differ from PJM’s plan or current rules. See the matrix for full descriptions.
Capacity Resource Deficiency Charge:
Under current rules, bidders who fail to deliver on promised resources must pay a capacity resource deficiency charge equal to the higher of 1.2 times the weighted average resource clearing price or the resource clearing price plus $20.
PJM would increase the penalty by about 25% to 38%, according to an analysis based on clearing prices from the 2013 base residual auction (BRA). The strictest proposals would increase that penalty by 50% to 67%, though one of them, by RC Cape May Holdings, LLC, would allow a reduction in the penalty for new resources that met certain development milestones short of completion (see chart in “Capacity Panel to Vote on Arbitrage Fix”).
Number of incremental auctions (currently three):
PJM would retain the final IA, one year before the beginning of the delivery year, with the other two occurring only if needed for PJM to obtain additional capacity due to increases in its reliability requirement.
PJM would release capacity only in the final IA, the only one in which other capacity buyers could participate.
Another proposal, by RC Cape May Holdings, LLC, would reduce the number of IAs to two.
PJM sell offer price:
PJM would continue the current practice — an upward sloping offer curve with starting price determined based on intersection of the variable resource requirement (VRR) curve and vertical line at current commitment level — but the price would be floored at the clearing price in BRA.
RC Cape May would continue the current practice but with a non-zero offer floor at 10% of BRA clearing price.
The Market Monitor would bar PJM from selling any excess capacity.
Allocation of 2.5% Short-term Resource Procurement Target:
Current rules allocate 0.5% each to the first two IAs with 1.5% in the final IA. That would continue under PJM’s proposal, assuming all three auctions are held. If not, the allocation from any cancelled auctions would be carried over to the next auction.
Incremental Auction Settlement Calculation:
Cleared sell offers and buy bids currently settle against the IA clearing price. PJM would continue to clear sell offers against the clearing price. Buy bids, however, would have to pay the clearing price plus the difference between the BRA and the IA clearing prices — eliminating the ability of market participants to profit by selling at a high price in the BRA and buying back at a cheaper price in the IA. “The goal of the settlement adjustment is to eliminate the ability to profit from the IA,” said Stu Bresler, PJM vice president of market operations.
Implementation Schedule:
PJM would implement most changes for all auctions related to delivery year 2017/18, starting with this year’s BRA.
The sell offer price and mitigation changes would become effective immediately upon FERC approval.
The Market Monitor would implement all changes to all future auctions upon FERC approval “with appropriate transition.”
At the annual National Association of Regulatory Utility Commissioners conference in Orlando last November, the Todd Snitchler Show was one of the hottest tickets.
NARUC gatherings are not known for their production effects or sense of humor, but Snitchler — the moderator of a session titled “The Environmental and Economic Implications of Carbon Restrictions” added a bit of show biz flair. The session opened with a soundtrack featuring Pink Floyd’s Money and a clip from a Will Ferrell movie. The six speakers stood at podiums, debate-style, while Snitchler strode among the audience like Oprah with a handheld microphone.
Snitchler won’t be enlivening any future NARUC conferences. The colorful, controversial chair of the Public Utilities Commission of Ohio announced last week he won’t seek reappointment, ending a three-year run during which he championed electric choice and alienated environmentalists with his Twitter posts expressing skepticism about renewable power and climate change. The 43-year-old Republican’s term as head of the 320-person agency ends April 10.
Legacy
Don Mason, an energy attorney and former PUCO member called Snitchler “one of the finest regulators that Ohio has ever had.”
“Wicked smart,” was the way Gov. John Kasich described Snitchler when he appointed him to the commission. Kasich praised the chairman in a statement last week as an “effective leader” and a “fierce defender of the PUCO’s independence.”
The Columbus Dispatch summed up his legacy in less glowing terms, writing, “Snitchler has been part of decisions that angered utility companies, consumer advocates and large businesses, sometimes all at the same time.”
Electric Deregulation
In an interview with RTO Insider yesterday, Snitchler expressed few regrets and said he was proud of his agency’s role in the state’s transition to electric deregulation.
Ohio PUC Chair Todd Snitchler at FERC technical conference on capacity markets, September 2013.
“I think we have moved steadily and consistently into a more competitive posture,” Snitchler said, citing the “dramatic increase” in the number of competitive suppliers and the increased shopping activity by individuals and municipal aggregators. The PUC announced last month that, for the first time, more power customers are buying their power from alternative suppliers than incumbent utilities.
Consumer advocates give Snitchler and the commission he headed mixed marks, acknowledging that electric prices declined since 2009, due to the combined effects of the recession and the influx of cheap natural gas.
“The outgoing chair is very much a devotee of the free market, à la the Texas model, which our organization doesn’t see as very advantageous to consumers,” said David Rinebolt, executive director of Ohio Partners for Affordable Energy. That model forces everyone to shop rather than allowing default service providers, which Rinebolt said forces consumers to absorb marketing costs.
While Ohio law requires default service in electricity, it doesn’t in natural gas. Rinebolt’s group is currently challenging a move to eliminate default service for some commercial gas customers.
Rinebolt praised Snitchler, however, for pushing electric distribution companies to use competitive procurement to obtain energy for their standard service offer.
Sam Randazzo, counsel to the Industrial Energy Users-Ohio, faulted PUCO for allowing utilities to collect “massive amounts” of transition, or “stranded” costs. As a result, he said, Ohio businesses and individuals are paying rates that are much higher than what are reflected in PJM capacity prices.
ALEC
Gov. Kasich appointed Snitchler in January 2011 to complete the term of former Chairman Alan Schriber.
Then a member of the Ohio House of Representatives, Snitchler was, like Kasich, active in the American Legislative Exchange Council, a conservative group that promotes free markets and reduced regulation. Snitchler was a keynote speaker at an ALEC task force meeting in April 2011 after joining the PUC.
Last year, Ohio legislators battled over legislation backed by ALEC to weaken or repeal the state’s renewable portfolio standard (RPS).
The legislation targeted Ohio’s “25-by-25” standard, which requires power companies to get 12.5% of their electricity from renewables and an equal amount from “advanced energy,” such as fuel cells, “clean coal” or new-generation nuclear power by 2025.
The legislation stalled in committee in December in the face of opposition from stakeholders including the Ohio Manufacturers Association and the Ohio Office of Consumers’ Counsel.
Snitchler and PUCO took no public position on the legislation. But he has made clear his misgivings about renewable power in frequent Twitter postings.
Tweets
The Columbus Dispatch reported a year ago that among more than 1,000 tweets from the previous year, “Snitchler did not once share anything positive about renewable energy.”
Among the tweets: “After [Hurricane] Sandy no one lined up for wind turbines,” and the “‘green’ religion is taking over from Christian religion.”
He also shared posts expressing doubts about climate change, quoting a report that noted that “the Himalayas and nearby peaks have lost no ice in past 10 years.”
On another occasion, he re-tweeted a story from the Communist Party newspaper Pravda, titled “Elites of West have cranked up myth of Global Warming.” Snitchler said he found the article “interesting.”
State Rep. Mike Foley, a Democrat, called Snitchler’s posts “radical.”
“The First Amendment entitles Snitchler to say what he wants. But Ohio isn’t paying Snitchler to do stand-up,” the Cleveland Plain Dealer wrote in an editorial. “Ohio is paying Snitchler to do the judgelike job of setting utility rates. That requires an open mind, not a juvenile one.”
“The guy is a right-wing ideologue and he doesn’t belong in a regulatory body that’s supposed to be impartial and protect the consumers, which he’s not doing,” Henry Eckhart, former commissioner who now represents utility consumers, told the Massillon, Ohio, Independent.
He quoted America’s Natural Gas Alliance so often that one commenter said “on some days @snitch92 might be confused for the ANGA’s feed.”
In fact, Snitchler has expressed concerns about the state becoming overly dependent on natural gas as an electric source, and called for a continued role for coal.
“While shale gas may be a major component in the here and now planning by our utilities there is no doubt coal needs to continue to play a major role in our future generation mix,” he told an Ohio House committee in October.
Snitchler declined yesterday to talk about specific postings or his view of climate change science.
“That’s not been a focus of my effort at the commission,” he said. He acknowledged, however, “You always learn lessons about better ways to communicate, and that was a lesson learned on my part.”
AEP Solar Project
The tweets came to light after Snitchler voted with a 3-1 majority to reject American Electric Power’s proposed Turning Point solar energy project.
The 50 MW project — about 250,000 solar panels on a reclaimed strip-mine — would have been the largest solar farm east of the Rocky Mountains. It had been championed by Gov. Ted Strickland, a Democrat, during his unsuccessful 2010 reelection campaign against Kasich.
The PUCO staff supported it, saying additional solar capacity was needed to comply with the state’s renewable mandates.
Ohio’s industrial energy users and FirstEnergy Corp. were among those who opposed the project, criticizing the funding mechanism AEP sought — a surcharge on all AEP distribution customers, including those who purchase power from competitive suppliers.
Snitchler joined with Commissioners Lynn Slaby and Andre Porter — now Kasich’s Commerce Department director — in finding that the project sponsors had failed to demonstrate it benefited ratepayers and was in the public interest.
“It wasn’t a question of being anti-renewables or anti-solar,” Snitchler said. “The Ohio Power Siting Board, on which I also served, approved a number of renewable projects, particularly wind, during my tenure.”
Former PUCO Commissioner Cheryl Roberto, now the Environmental Defense Fund’s Associate Vice President of Smart Power, said although she disagreed with Snitchler on environmental issues, she found him “pragmatic” and cooperative.
“I really enjoyed working with Todd,” said Roberto, who left the commission in December 2012. “I think Todd works very hard to understand some very complex and arcane issues.”
Travel Expenses
Snitchler came under criticism this month after the Dayton Daily News reported that the commission spent nearly $35,000 to send the five commissioners and 15 staff members to the NARUC conference.
The Ohio PUC delegation was the largest among those attending from PJM states. The Pennsylvania Public Utilities Commission was second with 16 attendees. None of the other state regulatory agencies sent more than seven attendees.
“You don’t need 15 staff people listening to a bunch of lectures,” former PUCO chairman Henry Eckhart told the Daily News. “Get a copy of the handouts and bring it back.”
A PUCO spokesman responded to the criticism by noting that the commission is the fifth largest state regulatory agency in the country.
Voluntary Departure?
Kasich and Snitchler described the end of the chairman’s tenure as Snitchler’s choice. After five years of commuting weekly to Columbus from his Canton-area home two hours away, Snitchler said, he wanted to spend more time at home, particularly with a daughter about to enter her senior year of high school.
Some in Columbus, however, speculated that Snitchler wanted to keep the post, which pays more than $124,000 annually, but was rebuffed by the governor.
“Those folks are wrong,” Snitchler insisted. “I thought long and hard about it…Everybody has an expiration date.”
Snitchler, who previously had a private legal practice, said he hopes to continue working in the energy field but has no landing place yet.
Before his term expires, he hopes to complete PUCO’s investigation into whether the state’s electric utilities have a true separation between their regulated and unregulated sides. A staff report issued last week recommended the commission audit utilities every four years to ensure compliance with code of conduct rules that bar sharing of competitive information between regulated and competitive subsidiaries.
Replacement
Under state law, the five-member commission can have no more than three from any political party. Snitchler’s departure will leave it with a single Republican, Slaby, Democrat Steven Lesser and two members not registered with either party, Asim Haque and Beth Trombold.
Twenty-seven aspirants applied to replace the chairman by last week’s deadline, including two PUCO staffers, former elected officials and several attorneys and engineers. All but two of the candidates are men.
A 12-member nominating council that includes consumer, labor and industry stakeholders will screen the candidates and forward a list of four finalists to Kasich.
PJM’s dispatch of demand response helped avoid the need to shed load during the polar vortex Jan. 7, when the RTO set a new winter demand record of about 141,500 MW.
PJM dispatched DR for both the morning and evening peaks. An estimated 2,029 MW responded for hour ending 1800, according to the graphs released by PJM last week (above). Actual reductions will be known after customer meter data is provided.
AEP Transmission Holding Co. is partnering with AltaLink to bid on the Fort McMurray West 500-kV project in Alberta, Canada. The joint venture was selected by the Alberta Electric System Operator as one of five qualified bidders for the 300-mile project, designed to meet large industrial load growth. The company expects to submit its proposal in November and have a decision late in the year. If successful, the project would be developed by AEP Transmission subsidiary Transource Energy LLC.
The other bidders are NorSpan Partners LP (EPCOR Utilities Inc. and LS Power Associates LP); Alberta PowerLine (Canadian Utilities Limited and Quanta Capital Solutions Inc.); TAMA Transmission LP (MidAmerican Energy Holdings Company and TransAlta) and TransCanada/Elecnor (TransCanada PipeLines Limited and Elecnor S.A.).
Dominion named seven new vice presidents effective Jan. 1. Corynne Arnett became vice president for financial management at Dominion Generation; Michael Frederick vice president for LNG Operations; Lee Katz vice president and general auditor, reporting directly to CEO Thomas Farrell; Mark Mitchell vice president for generation construction; Brian Sheppard, vice president for pipeline operations; Alma Showalter vice president for tax; and Chester Wade, vice president for corporate communications.
New York, Connecticut and a shareholder advocacy group agreed to withdraw their shareholder resolution on the subject after FirstEnergy committed to study and report on ways it could help meet President Obama’s goal of cutting greenhouse gas emissions 80% by 2050. The New York State Comptroller’s Office has won other such settlements with utilities, and has outstanding submissions with CMS Energy and Ameren.
Iberdrola USA named an eight-member board of directors as part of a corporate reorganization that structured Iberdrola S.A.’s U.S. business to align with the international company’s other structures. Board member Robert Kump, CEO of Iberdrola USA Networks, has also been appointed chief corporate officer, leading U.S. strategy.
The board, led by Iberdrola Chairman Ignacio Galan, includes four independent members: John Baldacci, former member of Congress and governor of Maine; Jose Fernandez, former assistant secretary of state; Alan Solomont, former ambassador to Spain and Andorra; and Alfredo Ayub, former director general of the Comision Federal de Electricidad in Mexico. Other members are José Sainz Armada, chief financial officer for Iberdrola Group and Pedro Azagra Blázquez, chief development officer for Iberdrola Group.
GDF Suez Energy North America named Eric Bradley senior vice president of strategy. In addition to heading the strategy function, Bradley also will oversee acquisitions and financial analysis, communications, government and regulatory affairs and new business incubation.
Stakeholders will hold a formal vote on measures to eliminate speculation in the capacity market this week after narrowing the proposals from seven to five in a lengthy meeting Friday.
Because clearing prices in incremental auctions (IAs) are usually lower than those in the base residual auction (BRA), participants can profit by selling capacity in the BRA and buying out their commitments in the IAs. PJM and the Market Monitor say such buyouts are suppressing capacity prices and could undermine system reliability.
PJM’s proposed solution (#2 in the matrix) would reduce the number of incremental auctions (currently three) and set conditions eliminating the potential to arbitrage between the BRA and IA.
RC Cape May Holdings LLC (#3), Old Dominion Electric Cooperative (#4), the Market Monitor (#9) and Exelon (#10) adopt some of PJM’s changes but differ in other details. (See “Incremental Auction Proposals Compared”)
Increased penalties for bidders who fail to deliver promised capacity, under proposals by PJM and other stakeholders. (Based on May 2013 clearing prices.)*MAAC includes EMAAC, SWMAAC. **Assumes no reduction for milestones.
All of the proposals would increase the penalties for failing to deliver promised resources. (See chart, right)
An informal poll conducted last week among 41 respondents representing 206 members and affiliates found overwhelming support for reducing speculative offers in the base auction but a split over the urgency of the issue: 59% of votes called for implementing changes in time for this May’s base auction as PJM has insisted; 34% said stakeholders should take more time to vet the issue. About 7% said there was no need for changes.
PJM’s proposal was the most popular proposal, followed by ODEC and the Market Monitor.
At Friday’s meeting of the Capacity Senior Task Force, Calpine (#7) and Duke (#8) withdrew their proposals, with Duke throwing its support behind the PJM plan. Citigroup Energy (#6) had withdrawn its proposal earlier.
Force Majeure
Much of the meeting was spent discussing the Market Monitor’s demand that the new rules bar bidders from buying out of their obligations except under force majeure.
Market Monitor Joe Bowring said the condition wouldn’t be limited strictly to “acts of God.” The reason for buying replacement capacity “has to be out of your control and it can’t be [a] financial” motive, he said.
None of the proposal sponsors were willing to add that condition to their packages Friday although some said they might agree after vetting it with their companies. Stu Bresler, PJM vice president of market operations, said he feared the restriction would be difficult to administer.
“Our concern is the pancaking of a variety of issues,” Griffiths said “We’ve repeatedly asked PJM about the impact of these changes and have been repeatedly told: `We don’t know.’”
Carl Johnson, representing the PJM Public Power Coalition, said the changes could result in “a huge number of megawatts whose price is administratively determined” rather than set by the market.
Walter Hall, of the Maryland Public Service Commission, said the PSC is concerned that PJM may not be able to sell excess capacity in incremental auctions if it refuses to sell below the base auction clearing price, as it has proposed.
Milestones
The task force also discussed the inclusion of development milestones, which Exelon and RC Cape May Holdings LLC proposed using to reduce credit requirements. RC Cape May would also use the accomplishment of milestones to reduce penalties for failing to deliver promised resources.
Hall and a second stakeholder said they supported the concept of development milestones but feared it would make it more difficult to reach consensus. “It just feels like it doubles the complexity of the replacement capacity issue,” the stakeholder said.
The vote on the proposals will run between tomorrow and Friday, with results released next Monday, in time for a first read at the Markets and Reliability Committee Jan. 30. The MRC will vote on Feb. 27, with a Members Committee vote the same day or at a special meeting afterward in time for a mid-March filing with the Federal Energy Regulatory Commission.
Bresler said the Board of Managers may file the PJM proposal with FERC even if it does not receive a two-thirds vote in support.
With two new types of demand response about to be introduced, members last week took steps to clarify rules on substitutions and maintenance outages for the products.
Extended Summer DR (7 days a week between May-Oct.) and Annual DR (12 months) will be available for the first time in the 2014/15 delivery year, joining the existing Limited DR (available for 10 dispatches annually on weekdays during June-Sept.).
Manual Change OKd for DR Substitution
Members last week approved changes to Manual 18: PJM Capacity Market governing how demand response providers may substitute for underperforming resources when called to dispatch.
Under the changes endorsed by the Market Implementation Committee Wednesday, the substitute and under-performing registration must:
Be located in the same dispatch area;
Have comparable capacity commitments (defined as the within ±25% or ±0.5 MW); and
Have the same designated lead time (e.g., long lead or short lead)
Under the rules, providers may use Limited DR to replace Annual DR but the substitution will not count against Limited’s 10 dispatch-per-year cap, said PJM’s Pete Langbein. Annual DR has no limits on the number of dispatches.
Maintenance Outages
The MIC also agreed to develop rules for approving maintenance outages for Annual DR.
The Tariff allows Annual DR to take maintenance outages between October and April, but members asked for rules to specify the application and approval procedures.
Under an Issue Charge approved by the MIC, the Demand Response Subcommittee will seek to develop manual changes that clarify what is eligible for a maintenance outage and how Curtailment Service Providers can apply for one. Members hope to complete the proposed changes for MIC endorsement by March.
PJM is adding more items to the to-do list resulting from the September heat wave, during which officials ordered limited load sheds to prevent a wider system collapse.
A 104-page analysis of the operational events and market impacts resulted in 22 recommendations, including 11 not previously announced (see sidebar). RTO officials briefed members on the report last week — ironically amidst the arctic blast that set a new winter demand record.
The analysis reads a bit like a thriller, documenting PJM dispatchers’ minute-by-minute decision-making — and identifying mistakes and missed opportunities for reducing or eliminating some of the five load sheds Sept. 9 and 10.
The city of Sturgis, Mich., emerges as a hero in the drama, as the city’s behind-the-meter generator and conservation measures by residents combined to provide 8 MW of relief, preventing a third day of load shedding on Sept. 11.
The report attributed the load sheds in part to inaccurate transmission, weather and load forecast models and also cited errors in synchronized reserve estimates. Load sheds did not significantly affect prices, the report concludes. But the dispatch of demand response caused both price increases and decreases and shortfalls in Financial Transmission Rights funding.
The report also illustrates the limits of demand response in relieving transmission constraints and identified operator errors and communication lapses.
Among the previously undisclosed details in the report:
Closing the South Akron-Clay 138 kV line might have prevented the Sept. 10 load shed in FirstEnergy’s Tod area near Warren, Ohio.
PJM might have avoided the load shed in the AEP Summit area Sept. 10 by dispatching 395 MW of combustion turbines that were off line. It did not do so because of a modeling error and because it was not monitoring a 138 kV line not under RTO control.
The Sept. 9 and 10 load sheds in AEP’s Pigeon River area in southern Michigan might have been avoided had a scheduled rebuilding of a 69-kV line been complete. PJM is working with AEP to “fast-track” the project, which is currently scheduled for completion in June 2017 under the Regional Transmission Expansion Plan.
PJM should have ordered the Sept. 10 load shed in Erie South area of Penelec 40 minutes earlier than it did, immediately after an analysis indicated it was the only solution to prevent a potential cascading outage. The load shed was preceded by the unplanned outage of two hydropower units (Seneca #1 and #2) that were scheduled to run at full output, a combined 421 MW.
The Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) indirectly contributed to one load shed. The planned outage of the South Canton 765 kV/345 kV transformer — required to support an upgrade needed prior to the retirement of five New Castle generators —contributed to less than 1 MW of the 16 MW FirstEnergy (ATSI) Tod area load shed.
Access to recently retired generation would not have eliminated the load sheds, although the five Bay Shore and East Lake generators retired in September 2012 could have reduced the Tod load shed by 75% and the AEP Summit outage by almost half.
Modeling
Many of the report’s findings and recommendations deal with PJM’s transmission modeling:
PJM’s contingency analysis of the Pigeon River area failed to include both a planned outage on the 69-kV Moore Park Tap-Industrial Park line and a relay limitation on the Lagrange-Howe (NIPSCO) section of the line. Because of the relay limitation, the most severe real-time contingency would automatically relay the Lagrange-Howe 69-kV line out of service. The Moore Park Tap-Industrial Park line was not modeled by PJM because it is below the 100-kV level; current PJM rules do not require reporting of outages below 100-kV.
Ratings on the Summit-Industrial 138 kV line, which figured in the 25 MW load shed in the AEP Summit area, were incorrectly listed as 251 MVA for normal (24 hours), emergency (four hours), and maximum (15 minute) conditions. “The reason for having different ratings is to give the dispatcher time to trend and validate the flows as well as take action to reduce the flows on the line,” the report said. “The impact of all the ratings being the same is there is no time for the dispatcher to perform anything but the most extreme action that must be taken once the load dump rating is reached. In this case, it was to issue the PCLLRW [Post Contingency Local Load Relief] and ultimately shed load.”
PJM incorrectly modeled a 138 kV series device, resulting in a 20 MVA difference between PJM and AEP’s state estimator solutions. PJM correctly compensated for the difference in real-time by conducting a cascading outage analysis at AEP’s lower threshold.
Because of the modeling error and because the Industrial-Summit 138 kV line is classified as a monitored priority 2 (MP 2) facility — which is above the 100 kV NERC Bulk Electric System (BES) level but not turned over to PJM for control — PJM did not dispatch 395 MW of combustion turbines that were off line, “which may have eliminated the need for the load shed.”
Synchronized Reserve
The heat wave also exposed problems with PJM’s estimates of synchronized reserves.
PJM issued a call for synchronized reserves Sept. 10, believing it had 1,665 MW available. It never got more than 400 MW of relief, with only 200 MW showing up in the first 10 minutes. As a result, the spinning event — which normally last only 10 minutes — ran for more than an hour.
The report concluded that some generation operators do not respond to PJM requests to confirm their synchronized reserves — called an Instantaneous Reserve Check (IRC) — or “provide stale or unreliable data.”
It also cited errors by operators who manually reduced output from some generating units to relieve transmission constraints Sept. 10. Because they failed to log the units as “Manual Dispatch,” PJM’s Security Constrained Economic Dispatch (SCED) software returned the units to a higher output and calculated available Tier 1 reserves from some units on the sending end of transmission constraints, although those units could not increase their output.
Heat Wave Forecasting Errors
RTO Temperatures During Sept. 13 Heat Wave (Source: PJM Interconnection LLC Technical Analysis of Operational Events and Market Impacts during the Sept. 13 Heat Wave)
Forecasting temperatures also proved problematic. Temperature forecasts for 10 PJM zones missed actual conditions by an average of 2 to 3 degrees over the three days, with errors as high as 10 degrees.
These contributed to load forecasts that fell up to 3.6% short. “Backcasting” — rerunning the load forecast using actual temperatures to separate the effect of the weather forecast errors — still produced average errors of 2% to 4.5%.
PJM said this is because its “Neural Net” forecasting tool relies on the previous day’s temperature and load trends. “When temperatures change significantly from one day to the next, it takes time for the Neural Net to catch up. Therefore the model inherently does not handle this first day of change well.”
Communications
The report also raises questions about how PJM operators communicated their actions to others on the grid and within PJM headquarters.
It noted that operations management chose not to call a System Operations Subcommittee Transmission (SOS-T) conference call on Sept. 10, because although “temperatures were higher than normal there were no forecasted events that would adversely impact the bulk electric system.” The calls are scheduled on an as-needed basis during emergency events to share information.
After the five load sheds, on Sept. 9 and 10, a conference call was held on Sept. 11. “While most SOS-Transmission members agreed that the communications of the conference call were adequate, some conference call participants stated that they would have liked more detailed information provided for the operations issues being discussed.”
Generic Logging
Dispatch staff logged the load sheds as generic transmission events because they were unaware of a category in the Emergency Procedures application for a “Local Load Relief Action.” Officials said dispatchers were unaware of the category because it had rarely if ever been used before and because its name did not exactly match the “Post Contingency Local Load Relief Action” instructions in PJM Manual 13: Emergency Operations. “As a result, those parties who depended on the Emergency Procedures application for notification were not notified of the load shed events.”
Many PJM officials, including the State Government Policy, Member Relations, Federal Government Affairs, and Corporate Communications departments were not informed about the load sheds, delaying their ability to communicate with stakeholders. “Dispatch has no formal notification checklist to follow except for certain emergency procedures steps requiring specific notifications pursuant to DOE, FERC, NERC, or PJM Manual requirements.”
Demand Response
The September heat wave illustrated that demand response — which proved a valuable tool during capacity shortages during the July heat wave — is less useful in relieving transmission constraints.
PJM dispatched DR on Sept. 10 and 11 after load forecasts fell 4,000 to 5,000 MW short of actual load. Of 740 MW called in ATSI and the South Canton subzone, 695 MW responded (94%).
Curtailment service providers provide street addresses for their resources but this information is not mapped electrically to the nearest substation. “When using these resources for transmission constraints, it is important for the dispatchers to know precisely where the curtailment will occur so that they can better understand the impact on the observed constraint,” the report said. “Too many DR resources on the wrong side of a constraint can make a constraint worse.”
The report identified 11 MW of demand response in the Summit area, which it said could have reduced, but not eliminated, that Sept. 10 load shed. The exact impact of the DR is unknown because of the lack of electrical mapping.
In addition, the long lead time of most of the DR resources does not lend itself well to addressing transmission constraints, which often need controlling actions within 30 minutes.
Starting in delivery year 2014/15, DR is required to respond on a subzonal basis if PJM establishes subzone the day before issuing a dispatch order. Only seven subzones are currently defined.
In December, members approved changes that will allow PJM operators more flexibility in dispatching demand response, including a reduction in the lead time to 30 minutes. (See Members OK DR Dispatch Rules after Late Amendments.)
Price Impact
The load sheds “did not have significant impacts on market outcomes,” the report concluded. Demand response, however, set prices in the ATSI zone at about $1,800 for hours ending 15 through 20 on Sept. 11 while causing prices to crash from more than $200 to less than $70 in some other regions in HE 16.
PJM said such a price drop usually results from a sudden influx of imports coming into PJM as price-takers. In this instance, it resulted from operators calling for more DR than was ultimately needed.
The DR deployment was called based on an expected peak load of 153,000 MW — nearly 6,600 MW above the actual peak. “Since PJM does not account for these MW as additional reserves, LMP is set by the marginal resource and demand response did not … set price when dispatched because this volume of demand response was not ultimately required,” the report explained.
After dropping below $70 in HE 16, prices rebounded to more than $200/MWh in HE 17.
FTR Funding Shortfalls
The dispatch of DR contributed to large differences between day-ahead and real-time prices in the ATSI zone, increasing FTR funding shortfalls for the month.
September 10 and 11 showed $29.3 million in FTR underfunding, more than half of the $56.3 million shortfall for the month. “Under the current market rules, FTR holders can be adversely impacted significantly by such emergency procedures taken to maintain system reliability when they have no impact to the Real-Time Market or system operations. PJM believes that this is a flaw in the market design that needs to be addressed.”
Fearing a potential shortage of reactive power, PJM last week won stakeholder support for an initiative to consider requiring that renewable resources add technology capable of providing grid support.
The Planning Committee meeting gave near unanimous approval to a problem statement and issue charge to explore whether to require renewables such as solar PV to install enhanced or “smart” inverters that can produce and absorb reactive power in addition to inverting DC power to AC. Reactive power (vars) is required to maintain the voltage to deliver active power (watts) through transmission lines.
With the increasing amount of renewables, which do not provide reactive support, and the retirement of large traditional generators that do, “there’s a need for additional reactive support to avoid voltage problems,” said PJM’s Frank Koza.
“This is not a here-and-now problem for PJM, but something we should look at to see what the cost and benefit is,” he said.
Koza told the committee that running additional conventional generators for reactive support is not cost effective and could cause negative Locational Marginal Prices. Adding static VAR compensators is cost prohibitive. Neither address frequency issues, he said.
smart inverter with reactive power ability (Source: SMA Solar Technology AG)
Renewable power generators in Great Britain and Germany are already using smart inverters to improve grid reliability. Smart inverters can allow renewable generators to stay on line despite low voltages and fluctuating frequencies and reduce the “flicker” that can occur with solar generators on days of mixed sun and clouds, Koza said.
One question to be addressed in the inquiry will be whether smart inverters should be installed on existing equipment, or only required on future installations. (Currently installed smart inverters have their reactive capabilities disabled.)
The Planning Committee plans to develop technical standards for inverters along with related Tariff, Operating Agreement and manual changes. Koza said he hoped work could be completed in time for a FERC filing in August.
