Holding firm on their plans to redefine the capacity market, PJM officials Tuesday offered a revised proposal that they said is less punitive and restrictive.
The revisions attempt to address the concerns of stakeholders who filed numerous comments complaining about aspects of PJM’s original proposal. The changes also include a plan to address an appellate court ruling voiding federal jurisdiction over demand response.
The revised proposal retains two products: Capacity Performance and Base Capacity. But it contains several proposed changes from the original plan released in August:
Simplified eligibility requirements for Capacity Performance resources.
Resources would not be required to provide officer certifications. Instead, capacity sellers offering the product would be “representing that [they have] taken sufficient actions to ensure the resource has the capability to provide energy when needed during both summer and winter peak-load conditions and extreme weather events.”
Resources would not be excluded based on eligibility requirements but would be held to stringent performance standards. PJM said the change should “avoid the potential for inadvertent barriers to participation.”
Reduced risk uncertainty. Non-performance penalties would be based on the net cost of new entry (CONE) rather than LMPs. Penalties would be capped at 1.5 times net CONE for the delivery year and 0.5 times net CONE for a single event.
Simplified flexibility requirements for Capacity Performance resources. PJM has eliminated “resource classes” and would instead depend on the “demonstrated physical capabilities of each resource.”
A more incremental transition mechanism. The proposed transition will “include a more gradual phase-in approach.” PJM said it “recognizes the need to develop a balanced transition mechanism that provides incremental improvements to address the issues while recognizing the need to allow time for investment, transition of contracts and transition cost management.”
PJM’s original schedule called for filing a revised proposal incorporating stakeholder feedback. The only question was how much PJM would change in response to the widespread criticism it received. (See Something for Everyone to Dislike in Capacity Performance Proposal.)
Demand Response Change
PJM also proposed changing its handling of demand response and energy efficiency in response to the D.C. Circuit Court of Appeals’ May 23 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission, case No. 11-1486) that overturned FERC Order 745. The court ruled that FERC’s order, which required PJM and other RTOs to pay DR resources market-clearing prices, violates state ratemaking authority. (See Appeals Court Snuffs Hope for FERC Demand Response Jurisdiction.)
To sidestep the legal issues, PJM proposes to have load-serving entities use DR and EE to reduce their demand beginning with the May 2015 Base Residual Auction.
LSEs would submit bids specifying how much they are willing to cut their demand at a given price. Cleared bids would effectively shift the demand curve left and reduce the volume of capacity procured.
PJM said it “continues to believe that it is critical for wholesale demand to indicate its preferences with respect to the price it is willing to pay for capacity but above which it does not wish to purchase capacity and instead commits to limiting its consumption when PJM approaches emergency conditions.”
Because of uncertainty about how FERC may respond to the court’s ruling, PJM said it “reserves the right to modify the timing and approach of its proposal for allowing demand response participation in [capacity] auctions based on subsequent actions of the courts and the FERC.”
PJM detailed its proposed DR changes in a white paper also issued late Tuesday. It will brief stakeholders on the proposed DR approach at 9 a.m. Wednesday, before the Market Implementation Committee.
PJM will discuss the revised Capacity Performance proposal with stakeholders from 1 to 4 p.m. Oct. 15.
The Board of Managers will make the ultimate decision on what PJM files with FERC following an Enhanced Liaison Committee meeting with members Nov. 4 in Philadelphia. PJM officials are targeting a FERC filing by Dec. 1 in order to have the changes in place for the May 2015 BRA.
PSC Official Urges People to Pay Attention to Pepco Takeover
After three public meetings about Exelon’s pending takeover of the parent company of Delmarva Power & Light drew scant interest, the Public Service Commission’s executive director called on residents to come forward and voice their concerns.
Robert Howatt said he was disappointed that only 13 speakers attended the sessions over the future of Delmarva, which has more than 300,000 customers. “Hopefully, more Delmarva customers will take the opportunity to submit written comment on the merger,” he said. Most of the 13 speakers said they support Exelon’s purchase of Pepco Holdings Inc., although one was concerned about Exelon’s opposition to renewal of the federal wind production tax credit.
The PSC is taking written comments until Dec. 10. Comments can also be emailed to psc@state.de.us, referencing PSC Docket 14-193, or by using the Public Comments link on the Public Service Commission electronic filing system, DelaFile.
Commonwealth Edison will refund customers $46 million in a settlement the company reached with Illinois Attorney General Lisa Madigan and approved by the Illinois Commerce Commission.
The settlement, which came out of a dispute over rates dating back to 2008, will be used to credit customers on their November bills. The average refund will be about $8, the company said.
The settlement ends arguments over two issues. The first was a method the company used to compute its capital investments, part of a complicated rate calculation. The second concerned a surcharge to finance the company’s smart meter program.
In its last session, the Indiana legislature eliminated the state’s energy-efficiency program, known as Energizing Indiana. Last week, a legislative study report concluded that the program was a success and will provide benefits for several years to come, even though it has fallen off the books.
A report on the program by The Energy Center of Wisconsin, a utility-funded organization that promotes sustainability, showed that for every dollar spent on the state’s energy-efficiency program, it provided $3 in benefits. Indiana Utility Regulatory Commissioner David Ziegner said the program provided millions in benefits. Legislators, however, eliminated the program and are now calling for a new program that concentrates on rate controls, rather than energy efficiency.
Northern Indiana Public Service Company halved the estimated rate hike it said would accompany its seven-year modernization plans for its electric and natural gas systems. Earlier reports put rate hikes associated with the plan at 10%, but documents filed last week show that the requested increase will be closer to 5%. The lower rate estimates came after NIPSCO adjusted its allowed rate of return to comply with Indiana Utility Regulatory Commission orders. The utility said it plans to spend about $1.9 billion in the next seven years.
Saying they are butting up against construction deadlines, the developers of a 755-MW power plant are asking the Public Service Commission to expedite final approval of the project. In a letter dated Wednesday, Genesis Power asked the commission to shorten the deadline for challenges to the Keys Energy Center, which is scheduled to take 33 months to complete.
The company said it had agreed to the recommendations from all parties in the proceeding and that it has to be in operation by June 2017 in order to meet a guarantee that was set when it bid into the PJM capacity auction in May. “Prompt approval is vital to being able to complete construction and begin operation by June 1, 2017, to satisfy PJM requirements,” the company told the commission. “Time is already short.”
The Keys Energy Project is a two-on-one combined-cycle plant in Brandywine, Prince George’s County.
Consumer advocates say that customers should receive refunds from We Energies as a result of a MISO order last year concerning a Michigan power plant.
We Energies was going to close its 430-MW Presque Isle Power Plant in Marquette, Mich., last year when its biggest customer, the operator of two iron ore mines on the Upper Peninsula, switched to a different supplier. But MISO ordered WE to keep the plant in operation to ensure grid reliability. Since February, ratepayers in Wisconsin and Michigan have been paying more than $4 million a month to cover the plant’s costs.
The Wisconsin Industrial Energy Group and the Citizens’ Utility Board say that ratepayers have already been charged for plant costs and that the MISO payments are allowing We Energies to exceed its maximum profit rate set by the Wisconsin Public Service Commission.
The Wisconsin PSC is beginning public hearings on the We Energies rate case. The next one is Oct. 8.
The company behind a proposed 25-MW offshore wind pilot project that has failed to gain state approval is asking the Board of Public Utilities for a chance to resolve regulators’ concerns through negotiations. Fishermen’s Energy, which has garnered federal funds for its project but not state approval, said it hasn’t been able to gain a clear understanding of its difficulty in gaining state approval and that it wants help.
“It is inconsistent with a government regulatory process for FCAW [Fishermen’s Atlantic City Windfarm] to continue to attempt to guess at these concerns, a continual moving target, without the benefit of real negotiation,” Fishernen’s said in a letter to the BPU.
A state appellate court in August overturned a previous BPU ruling against Fishermen’s request for ratepayer subsidies, saying the BPU must recognize that Fishermen’s already had federal funding equal to about a quarter of the project’s cost.
“Two independent respected branches of government have found in favor of FACW, and FACW can’t even secure a meeting to discuss this matter with BPU,” according to the letter. Although the BPU has scheduled time in its November meeting to discuss the project, a BPU spokesman said it was unlikely that a meeting before that would happen.
Turkey Waste-Fired Plant at Risk, Wants PSC Ruling
The owners of a plant scheduled to switch from burning timber waste to fuel derived from turkey droppings want the state’s Public Service Commission to referee a dispute it has with Duke Energy.
Coastal Carolina Clean Power’s facility in Kenansville sells its power to Duke now. The two companies have been negotiating a new contract since 2012. Duke said CCCP wants to charge too much for its power once it switches to turkey-derived fuel, up to 500% more than similar plants. CCCP says it will close the plant at the end of the year unless it reaches a contract with Duke, leaving turkey farmers with no place for their birds’ waste.
“In today’s renewable energy landscape, the price being requested by CCCP is noncompetitive and would be a burden to Duke Energy customers,” Duke spokesman Randy Wheeless said. Duke wants the PSC to throw out the request.
A rate proposal by American Electric Power should have been ruled on by the Public Utilities Commission by now, but the deadline has passed and PUCO hasn’t said when the ruling will come. “They will rule on it when they are ready,” a PUCO spokesman said.
AEP filed the proposal in December and said it would probably lead to a small rate decrease for Central Ohio customers, but it contains one provision that would have rate payers guaranteeing income to one of AEP’s coal-fired plants, Kyger Creek plant in southeastern Ohio. Similar proposals have been floated by Duke Energy and FirstEnergy in an attempt to keep plants profitable while guaranteeing a supply of power for the region. Opponents of the plans call them a bailout for merchant generators.
Ohio law calls for rate-ruling decisions within 150 days of the initial filing, but the deadline is rarely observed. Some utility analysts believe that the AEP plan, the first of several anticipated, could be so divisive that the commission may be waiting until after the November election to rule.
Pennsylvania’s natural gas lines sprang more than 31,000 leaks last year but the location of the pipelines — and whether they still leak — is kept secret by the Public Utility Commission. “It’s important to … protect that information because of security interests and security concerns. You don’t want everyone outside the utility knowing exactly where the pipelines are,” PUC Commissioner Gladys Brown told the Pittsburgh Tribune-Review.
The newspaper reported that the secrecy policy has had dangers, such as when a pipeline cracked in Lehigh County in 2011, and Allentown workers couldn’t find the shutoff valve and didn’t have access to the gas system maps. A fatal gas explosion followed. “There’s no regulation in the state that requires these folks to share this information with us. They get away with it by saying, ‘You know, we have Homeland Security issues’ and such,” Allentown Mayor Ed Pawlowski said.
Dominion’s Cove Point facility today (Source: Dominion)
The Federal Energy Regulatory Commission yesterday gave Dominion Cove Point LNG the green light to build a natural gas liquefaction plant along the Chesapeake Bay.
FERC also approved parts of the project located in Virginia, including a compressor station and metering and regulating sites (CP13-113).
Dominion has said it will have the $3.8 billion Cove Point project in service by June 2017. Although hotly contested by some residents and environmentalists, FERC, with its ruling, has found that the project is in the public’s interest. The agency’s ruling comes after two years of analysis, three public meetings, 140 speakers and more than 650 comments.
Despite requests from U.S. Sens. Ben Cardin and Barbara Mikulski (both D-Md.), FERC Chairmain Cheryl LaFleur declined to schedule additional public meetings on the project or to extend the comment period by 30 days.
FERC has approved three other LNG export projects, all in the Gulf of Mexico: the Sabine Pass Liquefaction Project, the Freeport LNG Project and the Cameron LNG Project. Fourteen LNG export proposals are still pending.
NRC Considers ‘Graded’ Look at Foreign Nuke Ownership
Calvert Cliffs
The Nuclear Regulatory Commission is taking a fresh look at the implications of foreign ownership of U.S. nuclear generating facilities, a review that could allow a French company to build a third reactor at Maryland’s Calvert Cliffs plant. An NRC staff paper released this month recommended the commission replace its Cold War-era prohibition on foreign ownership with a “graded” approach.
The Nuclear Energy Institute praised the staff report, saying that the agency has been relying on an “unnecessarily restrictive interpretation” of the 1954 Atomic Energy Act, which prohibits foreign ownership of a U.S. nuclear station if such ownership could be a threat to the country. “Experienced foreign nuclear energy companies including AREVA, EDF, Toshiba and Mitsubishi have participated in the U.S. market for decades,” NEI Vice President and General Counsel Ellen Ginsberg said. “The U.S. nuclear industry and the U.S. economy benefit from both foreign financial investment and foreign construction and operating experience.”
France’s UniStar asked the NRC to reconsider the rule after the agency’s Atomic Safety and Licensing Board rejected its request to build a third reactor at the Maryland plant. UniStar is seeking a U.S. partner for its Calvert Cliffs project while waiting for the full commission to take action. Although the staff’s recommendation was prompted by the Calvert Cliffs plan, whatever the NRC decides could apply to all U.S. nuclear facilities.
McCarthy: Don’t Believe Talk About States Resisting Rules
Gina McCarthy
Environmental Protection Agency Chief Gina McCarthy said she’s not worried that states like Texas and West Virginia will refuse to implement the agency’s proposed carbon emission rule, despite public opposition from their governors.
“The public discussion may be a little bit different than the roll-up-the-sleeves discussion that we are actually having on a technical basis around these rules,” McCarthy told reporters on Friday at EPA headquarters. “And I’m really anticipating that those discussions will continue and that you will have many states see that the standards that we set were reasonable.
“I think the states know that we are within the Clean Air Act. The best thing they can do is to design their own plans and really create their own path forward that is in line with where they want to go economically and energy wise,” she added.
The Department of Energy is investing $2 million in a study to find ways to build even taller wind turbines in an effort to reach higher winds.
Tower heights currently top out at about 260 feet, a limitation primarily of transportation constraints in moving components such as blades. But newer plans call for towers to reach nearly 400 feet. Such towers would allow blades to be powered by the stronger winds found at higher elevations. That could boost wind energy production by a factor of five at some sites.
The Federal Energy Regulatory Commission’s 2015 schedule for its open meetings has been announced. The meetings take place at FERC headquarters at 888 First St. NE on the third Thursday of each month. No meeting is held in August.
The open meeting dates:
Jan. 15, Feb. 19, March 19, April 16, May 21, June 18, July 16, Sept. 17, Oct. 15, Nov. 19, Dec. 17.
At least one-third of the nation’s 125,000 schools could save money by installing solar PV systems, according to a study conducted for the Solar Energy Industries Association. The report found that solar systems would be cost-effective for 40,000 to 72,000 schools and that 450 school districts could each save more than $1 million over 30 years.
Solar installations nationwide have grown from 303 kW to 457,000 kW in the last decade. New Jersey schools ranked second nationally in solar capacity, behind only California. Pennsylvania, Ohio and Maryland ranked sixth, seventh and ninth, respectively.
“In a time of tight budgets and rising costs, solar can be the difference between hiring new teachers — or laying them off,” SEIA CEO Rhone Resch said.
A novel project: Energy generated from wind turbines (in Wyoming) powers compressors (in Utah) that inject high-pressure air into salt caverns underground. The compressed air is stored for high-demand hours.
Duke Energy is joining a novel $8 billion project using Wyoming wind energy and Utah salt mines to provide power to Los Angeles.
Duke-American Transmission Co. (DATC) is one of four companies proposing the project, which would be the first time underground compressed-air storage would be used on such a scale in the U.S.
“This project would be the 21st century’s Hoover Dam — a landmark of the clean energy revolution,” said Jeff Meyer of Pathfinder Renewable Wind Energy, one of the four companies involved.
Meeting California Renewable Goals
The project is one of about 200 plans California officials will consider to help it reach its renewable-energy goals. Duke and the other companies said they would be submitting the proposal in early 2015.
The project would start with a $4 billion, 2,100-MW wind farm north of Cheyenne, Wyo., to be built by Pathfinder Renewable Wind Energy. Power from the facility would be sent to an energy storage facility near Delta, Utah, on a $2.6 billion, 525-mile transmission line to be built by DATC.
In Utah, four massive caverns — each a quarter-mile high and 290 feet in diameter — would be carved out of underground salt formations.
At times of low demand, electricity from the wind farm would power compressors that would inject high-pressure air into the caverns.
At times of high demand, the high-pressure air, combined with a little natural gas, would power eight generators. The $1.5 billion facility, to be built by Pathfinder, Magnum Energy and Dresser-Rand, would be rated at 1,200 MW.
An existing 490-mile transmission line would deliver the power through Utah, Nevada and California to Los Angeles.
Intermittent Wind
(Source: Dresser-Rand)
The project is intended to address the challenge of matching wind’s variable output with energy usage patterns.
California’s wind farms tend to generate most of their power in the evening, dropping off when energy demand reaches its peak. Wyoming wind, by comparison, tends to increase later in the day.
Dresser-Rand designed and built the first facility using compressed-air energy storage (CAES) in Alabama; the facility is linked to a coal-fired generating station. The 110-MW unit went into operation in 1991, and boasts a 96.7% reliability record in generation mode. There is one other operating CAES facility in Huntorf, Germany.
If the project goes forward, one of the first jobs will be excavating the caverns, using a process called solution mining. Magnum Energy, which has excavated other storage caverns, said it would inject water into the underground salt formations, dissolving the salt and pumping the salt solution to the surface, where it would be dried. Underground caverns have long been used for oil and natural gas storage.
The project, which is not expected to be completed until 2023, would be subject to numerous state and federal regulatory approvals, none of which has been applied for yet.
Exelon Generation is adding another 2,000 MW of fossil generation to its fleet in Texas, which will bring the company’s total generation in ERCOT to nearly 6,000 MW.
The company announced Monday it was investing more than $500 million in four gas and two steam turbines to build combined-cycle plants at two of their existing sites.
General Electric H-Class Turbine (Source: BusinessWire)
In addition to using the most fuel-efficient technology, the plants will be air-cooled, rather than water-cooled, a big plus in drought-threatened Texas. The turbines will be General Electric H-class models, which GE says will allow more than $8 million in fuel savings per turbine a year.
French company Alstom is providing the heat recovery steam generators. Earlier this year, GE agreed to buy the power arm of Alstom for $16.8 billion.
It will be the first use of the new GE turbines in the U.S.
“What we see is a clean-energy future that includes this kind of new technology, which uses little water and produces few emissions while generating electricity at a very low cost,” said Ken Cornew, president and CEO of Exelon Generation.
The new combined-cycle plants are to be built at Exelon Generation’s Wolf Hollow site in Grandbury, southwest of Fort Worth, and the Colorado Bend plant in Wharton County, southwest of Houston.
Exelon Generation currently has six generating stations in Texas with a combined output of about 3,700 MW. It has wind farms generating an additional 281 MW, for a total of nearly 4,000 MW.
The two new plants will boost that total to nearly 6,000 MW. Exelon said it would start construction of both plants in 2015 and expects both to be in service by 2017.
Exelon needs $580 million in additional revenue annually to keep its Illinois nuclear fleet in operation, Senior Vice President Kathleen Barron told the Illinois Commerce Commission last week.
Exelon has been saying for months that unless pricing for the output of its Illinois nuclear stations improves, it may need to shut them down. Barron said the company figures it needs about $6 more per MWh for continued operation. That would translate to rate increases of about 8% in Chicago and more downstate, where prices are cheaper.
And even that might not do it. “While a $6/MWh payment or even less would be sufficient for some units, $6 may not be enough for others,” the company said in a statement. “Each of our 11 nuclear units in Illinois has a different cost structure and different requirements.”
Barron’s comments are part of a national campaign by Exelon to gain credits for its carbon-free output, and cut or reduce the federal wind production tax credit, to let its plants compete. Company lobbyists and executives have been delivering a consistent message since the spring. (See Exelon in Lobbying Push to Save Ill. Nukes.)
Barron said the result of closing the nuclear stations would be significant for Illinois. “If the units at risk of closing today — representing 43% of the state’s nuclear generation — retire, they cannot be mothballed and later brought back online,” Barron said. “Together, they represent more than 30 million metric tons of avoided carbon emissions, given that they will need to be replaced with fossil generation to provide the around-the-clock electricity needed to serve customers in the state.”
Dominion Virginia Power is starting a $2 billion project that will underground 4,000 miles of outage-prone lines by 2026.
The target represents about 11% of the company’s overhead distribution lines, and placing them underground should result in increased reliability, the company said. About a third of the company’s 58,000 miles of distribution lines are now underground.
It said it will spend about $175 million a year moving the lines. The company is expected to file an application for a rate increase to pay for the project with the Virginia State Corporation Commission by the end of October. The rate increase would go toward the project, it said.
South Carolina Official Upset Duke Hasn’t Removed Ash Yet
A South Carolina Public Service commissioner said he thought Duke Energy was already removing stored coal ash from its sites in the state. He was surprised to learn it hasn’t started yet.
“I think it’s somewhat of a surprise to this commission that no ash is being removed because this has been an ongoing situation that we’ve heard about and talked about,” Commissioner G. O’Neal Hamilton said. “We’ve seen reports of trucks moving in North Carolina and I assumed that was happening here and it’s a little disappointing.”
The issue arose after environmentalists said that the company’s W.S. Lee Steam Station has coal ash lagoons that are leaking toxins into the surrounding area. Duke said it will present the commission with plans for the removal by the end of the year. Duke is converting the plant to burn natural gas. A Duke spokesman said plans are being made to remove coal ash from a number of sites in North Carolina as well, but they have not yet been implemented.
Ralph Rogers, Tennessee Valley Authority’s top lawyer, is retiring at the end of the year. Rogers started with the federal authority in 1979 and became TVA’s senior litigation attorney and ethics officer. He was the highest paid attorney in TVA history, making $1.9 million last year and $2.5 million the year before. High executive salaries at TVA have drawn fire from former Knoxville Mayor Victor Ashe, who said “most East Tennessee attorneys do not make a quarter of that amount (paid to Rodgers) in one year.”
Under the corporate-like board structure adopted for TVA by Congress in 2006, pay levels for the general counsel and other top officers at TVA have risen significantly over the past decade to more closely align with investor-owned companies rather than the government-level pay grades used by TVA in the past.
Public Service Electric and Gas started construction of a 10-MW solar plant on a former garbage dump in New Jersey, the latest and largest system of solar arrays the company is building. The project will sit atop a capped dump in Bordentown.
It’s part of a state-wide effort to use brownfields and under-used industrial sites to build solar plants to deliver energy to the grid. The company is planning to spend $247 million on this and similar projects. It is eying plans to build an even larger solar plant on another former dump in New Jersey.
Grid operators demonstrated resiliency during January’s polar vortex but more needs to be done to prepare for future cold spells, the North American Electric Reliability Corporation said in a report released today.
All-time Winter Peaks vs. Polar Vortex Loads by Pct. (Source: NERC)
NERC’s Polar Vortex Review noted that only one balancing authority shed load despite the fact that many areas in the Midwest, South Central and East Coast experienced temperatures 20 to 30 degrees below normal. (South Carolina Electric and Gas (SCE&G) dropped less than 300 MW, less than 0.1% of the total load for the Eastern and ERCOT Interconnections.)
Howard Gugel, NERC director of performance analysis, said the industry performed well “under extremely challenging circumstances. Industry owners and operators used all the resources at their disposal to keep the grid reliable.”
Grid operators relied on voltage reductions and demand side management to prevent load sheds. NERC said the performance validated its regular training and drills “as the operators and other [… entities were able to effectively and successfully implement emergency procedures.”
Record Cold
Forty-nine cities set new record lows, with Minneapolis shivering through 62 consecutive hours of temperatures below zero from Jan. 5 to Jan. 7. On Jan. 6, the average daily temperature in the U.S. was 17.9 F, the first time the average dropped below 18 F since 1997. The 17-year run of temperatures above 18 was the longest such span on record and occurred during a period in which an increasing portion of the generating fleet had become fueled by natural gas, NERC noted.
The cold pushed many generators beyond the temperature range for which they were designed.
Nevertheless, an analysis of NERC’s Generating Availability Data System (GADS) found that most generators units performed within the equivalent forced outage rate (EFOR) range expected based on the past five years. The exception was natural gas units, which had a higher-than-expected forced outage rate in January in two regions, the Midwest Reliability Organization and Southeast Reliability Corp.
Demand Records
Eight of 10 areas included in the study — all but ISO-NE and the Florida Reliability Coordinating Council (FRCC) — set all-time winter demand records on Jan. 6 or 7. The VACAR South reliability coordinator, which includes SCE&G, busted its record by almost 18%. (NERC’s review did not include the Western Electric Coordinating Council, which was largely unaffected by the polar vortex.)
Causes
Like PJM, other regions experienced fuel deliverability problems, natural gas pipeline outages and frozen equipment. The report catalogues dozens of cold-weather problems that led to outages, delayed starts or deratings, most of them involving the freezing of water and the gelling of oil and diesel fuel.
NERC’s report makes a number of recommendations but does not call for changes to existing mandatory reliability standards. Many of the recommendations are already being taken in PJM and other regions.
Among the recommendations:
Generators
Review and update power plant weatherization programs, including procedures and staff training.
Continue or consider implementing a program for winter preparation site reviews at generation facilities.
Review the basis for reporting forced and planned outages to ensure appropriate data for unit outages and de-ratings. The review found that planned and forced generation outages in some regions exceeded worst-case scenarios used in seasonal assessments.
Consider where appropriate the temperature design basis for their plants to determine if improvements are needed for the plants to withstand lower winter temperatures without compromising their ability to withstand summer temperatures.
Review internal processes to ensure their ability to secure necessary waivers of winter environmental and/or fuel restrictions.
Oil & Natural Gas
Review natural gas supply and transportation issues, and work with gas suppliers, markets and regulators to develop appropriate actions.
Include in winter assessments reasonable losses of gas-fired generation and considerations of oil burn rates relative to oil replenishment rates to determine fuel needs for continuous operation.
Continue to improve operational awareness of the fuel status and pipeline system conditions for all generators.
Ensure that on-site fuel and fuel ordered for winter is adequately protected from gelling.
NERC will conduct a webinar Thursday to provide a preview of its 2014-15 winter outlook and to discuss cold weather events including the polar vortex and the 2011 Southwest winter outage.
PJM officials said Wednesday they are amending their proposed capacity overhaul in response to dozens of mostly critical stakeholder comments.
“Already, based on the comments, we are making adaptations to our proposal. It’s extremely helpful to get your feedback,” Executive Vice President for Markets Andy Ott said at the beginning of the three-and-a-half-hour question-and-answer session on the proposal.
“We said all along it was a proposal,” Ott said later in the session. “I can’t say it enough. You’re not talking to a wall here. This isn’t a traditional stakeholder process but it is still a stakeholder process.”
On Monday, PJM released more than 300 pages of comments from more than 50 stakeholders. While the comments reflected the traditional load vs. supply divide, there was near universal unease with how quickly PJM is attempting to introduce a new Capacity Performance product and rewrite compensation and penalty policies. (See Something for Everyone to Dislike in Capacity Performance Proposal.)
Although Wednesday’s discussion was the last scheduled stakeholder meeting before PJM issues its final proposal Oct. 7, officials said they would consider one or two additional meetings.
The Board of Managers will make the ultimate decision on what PJM files with the Federal Energy Regulatory Commission following an Enhanced Liaison Committee meeting with members Nov. 4 in Philadelphia. Although the meeting will be limited to PJM members, representatives of state regulatory commissions will also have a chance to address the board before or after the meeting, officials said.
Ott said officials are targeting a FERC filing by Dec. 1 in order to have the changes in place for the May 2015 Base Residual Auction.
Ott said the board will likely make additional changes in the plan before filing with FERC. “I think there’s a very small chance that [the Oct. 7] proposal will be filed” at FERC, Ott said.
Below are some of the issues that generated discussion Wednesday.
Force Majeure
Mike Borgatti of Gabel Associates said PJM’s proposal for “the outright elimination of force majeure is untenable.”
Borgatti said the rules would allow a coal-fired plant to escape penalties if it were unable to operate because a sinkhole swallowed a nearby substation but not if the hole made the road to the plant impassible for coal deliveries. Another stakeholder observed force majeure would not apply for a gas-fired generator that lost its pipeline to the sinkhole.
Independent Market Monitor Joe Bowring, who opposes PJM’s proposal to add an additional class of capacity, said he supports the tightened force majeure rules. “The market doesn’t care why you’re out [of service]. If you’re not producing energy, you’re not producing energy. That’s all the market cares about. It’s impossible [for the Monitor and PJM] to manage a long list of excuses.”
Ed Tatum of Old Dominion Electric Cooperative said Bowring’s analysis was an inaccurate description of the Reliability Pricing Model. “This is a resource adequacy concept. It’s not a market. … Taking an academic view of what is not a market is not going to get us” improved performance.
Officer Certification
Generators are also balking over requirements that officers certify their plants’ ability to meet the Capacity Performance requirements. Borgatti said it could be impossible to certify that a generator holds a firm gas contract three years into the future.
Another member said the requirement introduced both organizational risk and personal risk to the officer. “You’re asking the officer to certify to an unknown risk that won’t be known until after the fact,” he said. He said PJM should eliminate the requirement or add a “safe harbor” provision.
The IMM says performance incentives will be sufficient to ensure reliability and that officer certifications are unnecessary.
Ott said PJM is aware of the risk of unintended consequences from the requirement. “We certainly heard that” from the comments, he said.
Capacity Performance Requirements
Others said PJM should relax its requirement that Capacity Performance resources be able to run at full output for 16 hours for three consecutive days during weather emergencies, saying it unnecessarily excludes demand response, energy efficiency and storage.
Wil Burns, an attorney representing public interest groups said PJM should broaden its Capacity Performance definition to include resources such as DR, EE and renewables that have no fuel risk and “that can be and have been there when needed.”
PJM’s Adam Keech said the requirement was intended to cover the daily summer peak or the two daily winter peaks. But he suggested PJM might relax the requirement saying, “I don’t want to say anything is etched in stone.”
“You’re getting a sense from us that the last thing we want to do is to discourage resources that can be there,” Ott said. But he said the RTO felt that it needed operational requirements and not “just rely on the economic pressure of a performance penalty. Striking that balance will be very key.”
Despite the appellate court ruling voiding FERC’s authority over DR, “PJM believes there’s a continuing role for demand response in the wholesale market,” Mike Kormos, executive vice president for markets, assured stakeholders. “It may be there in a different format.”
Kormos said PJM would integrate its plans for DR with the capacity market “once it’s clear how FERC wants us to move forward.”
Base Capacity Assumptions
Several speakers challenged PJM’s assumption that no base capacity will be available during the peak winter week. Tatum noted that the RTO uses a probabilistic approach to account for forced outages in its calculation of loss-of-load-expectation (LOLE) and installed reserve margins (IRM).
“Zero seems pretty on-off – kind of a low number to me,” Tatum said. “I think it would be good to have a consistent approach.”
Kormos said that to count on any base capacity during the winter peak “might be overoptimistic.”
“If you look at the number of gas units that never get gas on peak [winter] days,” when generation has to compete against gas demand for heating, “it’s not as draconian as it sounds,” Kormos said.
PJM has proposed that all but 15% of peak winter load be served by the new product. “I don’t think our thinking has changed a lot on that,” agreed PJM’s Tom Falin.
Market Power
Load representatives asked PJM and the Monitor to address market power concerns, saying the new product could be subject to withholding.
Susan Bruce, representing the PJM Industrial Customer Coalition, said “strong market power protection” would be essential to winning her group’s support.
Ott endorsed the Market Monitor’s suggestion of a must-offer requirement that allows generators to submit “coupled” offers with one price for Base Capacity and a higher price for Capacity Performance.
Bowring said the best way to reduce withholding risk is to use a single annual capacity product without the new product. (Bowring also has called for eliminating Limited and Extended Summer DR). Given the higher requirements and penalties on CP, Bowring said, there will be a “very substantial incentive” for generators to withhold.
But Bowring said his staff could review proposed costs for winterization or firm fuel within coupled offers the same way it currently screens offers under the avoidable cost rate (ACR) and avoidable project investment recovery rate (APIR).
“It’s very doable. I don’t want to understate the complexity of it. It’s going to be much more complicated than it is now.”
Cost Recovery
One generator representative said his company is concerned with being able to recover the additional costs to allow its plants to meet the CP standards. “Just because you put those costs in has no bearing on whether you’ll actually see recovery for more than one year,” he said.
Bowring acknowledged capacity revenues have “not been adequately compensatory.”
Ken Carretta of Public Service Enterprise Group said generators would face additional maintenance costs as well as capital expenditures – a disconnect with the current backward-looking ACR mechanism.
“We have to figure out a way to reflect that,” Bowring agreed.
The Federal Energy Regulatory Commission last week approved actions on four standards and policies proposed by the North American Electric Reliability Corp. and the North American Energy Standards Board (NAESB).
Notices of Proposed Rulemaking
Demand and Energy Data Reliability Standard
The NOPR (RM14-12) proposed to accept NERC reliability standard MOD-031-1 (Demand and Energy Data), which governs the collection of demand, energy and related data to support reliability studies. NERC said the proposal clarifies data collection requirements and adds transmission planners as entities that must report demand and energy data. Applicable entities are required to report actual peak hour demand from the previous year for comparison with forecasted values. They also must explain how their peak demand forecasts and demand side management forecasts compare to actual demand and demand side management. (See related story, Brattle: Missing EE Costing PJM Load $433M Annually.)
Communications Reliability Standards
The NOPR (RM14-13) proposed approval of two revised NERC standards, COM-001-2 (Communications) and COM-002-4 (Operating Personnel Communications Protocols). Among the requirements is the use of a three-part communications process when issuing operating instructions: recipients must repeat the instruction and receive confirmation from the issuer that the response was correct, or request that the issuer reissue the instruction. The standard establishes “zero-tolerance” enforcement for failure to use three-part communications during an emergency.
The commission ordered NERC to modify COM-001-2 or develop a separate standard that ensures that entities maintain adequate internal communications capabilities. It noted that a task force report on the 2003 blackout found that one of the causes of the outage was that FirstEnergy’s control center computer support and operations staff lacked effective internal communications procedures and “lacked procedures to ensure that its operators were continually aware of the functional state of their critical monitoring tools.”
Final Rule
Standards for Business Practices and Communication Protocols for Public Utilities
The final rule (RM05-5-022) incorporates the latest version of NAESB’s Standards for Business Practices and Communication Protocols for Public Utilities into FERC regulations. The revised standards reflect the commission’s Order 890 series of rulings and other orders. They include standards supporting Network Integration Transmission Service on an Open Access Same-Time Information System (OASIS); Service Across Multiple Transmission Systems (SAMTS); and commission policy regarding rollover rights for redirects. Modifications were also made to ensure consistency across the OASIS-related standards.
The rule also includes changes reflecting updates to e-Tag specifications and gas-electric coordination standards to provide consistency between the two markets.
Compliance Filing
Find, Fix, Track and Report (FFT) program
The commission approved NERC’s annual compliance filing on its Find, Fix, Track and Report (FFT) program, as well as two changes to the program. The order (RC11-6-004) approved NERC’s proposal to continue processing some moderate risk violations as FFTs. The commission also approved NERC’s proposal to extend the mitigation period after an FFT is posted from 90 days to one year, but it rejected a proposal to allow some mitigation activities to go beyond a year. “We do not believe that NERC has provided adequate support for the need for this proposal,” the commission said. “Further, we are concerned that mitigation periods of greater than one year could weaken the incentive for entities to expeditiously mitigate possible violations and delay necessary corrections.”
The following issues were approved by stakeholders with little or no opposition Thursday.
Markets and Reliability Committee
Manual Changes
Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines were revised to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Manual 14A: Generation and Transmission Interconnection Process was revised with the addition of a new section 1.14 regarding interim deliverability studies.
Manual 14D: Generator Operational Requirements was updated as part of an annual review. It includes changes reflecting North American Electric Reliability Corp. standard MOD-025-2.
FTR/ARR Senior Task Force
Members approved changes in the scope of the Financial Transmission Rights Senior Task Force. The task force was formed to identify ways to improve FTR funding levels. The new scope includes an examination of the role of virtual transactions on revenue adequacy and proposed solutions by the Market Monitor.
One sentence was struck from the revised problem statement as a result of objections by the Market Monitor. The sentence stated that: “With FTR underfunding that has occurred over the last several years, FTRs no longer perform the function of an effective hedge against congestion in the Day-Ahead market.” While PJM officials said it was factually accurate, the Monitor said it wasn’t appropriate for inclusion in the problem statement.
Credit Requirements
The MRC and Member Committee approved the following changes recommended by the Credit Subcommittee:
Risk Documentation Requirements – Removes the requirement that officer certifications be notarized, and allows electronic submissions. Eliminates the requirement for annual submissions of risk policy documentation; PJM will accept certification that no substantive changes have been made since the last submission.
Peak Market Activity (PMA) Exclusions – Spot market energy, transmission congestion and transmission loss charges resulting from virtual transactions will be excluded from the peak market activity (PMA) credit requirement. Virtual transactions have their own credit screening rules. Screened export transactions also will be excluded from the PMA. The PMA is used to set baseline credit requirements for members based on historical activity.
Virtual and Export Transactions Credit Requirement Timeframe – Reduces the credit requirement timeframe for export transactions to two days from four days. The MIC approved a similar change in August for virtual transactions. (See PJM MIC OKs Settlement, Credit Changes.)
Demand Bid Volume Limits – Establishes a daily demand bid limit for each load-serving entity by transmission zone. Bids would be limited to the LSE’s calculated zonal peak load reference point for the day plus whichever value is more, 30% of the reference point or 10 MW. PJM said the need for such limits was illustrated by the default of People’s Power & Gas in January.
Transition to 30-Minute Demand Response
The MRC and Members Committee approved a transition mechanism related to changes requiring more operational flexibility from demand response providers. The change would allow curtailment service providers to designate previously cleared megawatts as “non-viable” — unable to meet the new 30-minute-lead-time requirement. CSPs would be relieved of their obligations and have their capacity payments reduced. The transition mechanism was developed to comply with the Federal Energy Regulatory Commission’s May 9 ruling on the DR changes (ER14-822). Members also agreed to sunset the Capacity Senior Task Force.
Transparency of TO Calculations
Members voted to close an issue relating to the transparency of the calculations transmission owners use for allocating energy, capacity and transmission costs. PJM has created a webpage listing the methodologies transmission owners use for calculating total hourly energy obligations (THEO), peak load contributions (PLC) and network service peak loads (NSPL). The issue arose because some TOs have not filed tariffs disclosing the methodology they use. Some members complained that the lack of transparency made it difficult to ensure they were being properly charged. (See TOs Will Disclose Calculation Methodologies.)
Members Committee
Supplemental Transmission Project Definition
Members approved revisions to the Operating Agreement clarifying the definition of supplemental transmission projects as one that is not a state public policy project and is not required for system reliability, operational performance or economic criteria. The change removes a reference to supplemental projects as “Regional RTEP” (Regional Transmission Expansion Plan) projects. It also clarifies that any reliability upgrades required as a result of the supplemental project are considered part of that project and are the responsibility of the entity sponsoring it.
Data Submittal Deadlines
Members endorsed Tariff revisions extending the deadlines for electric distribution companies (EDCs) to submit Power Meter and InSchedule data. The changes would allow load reconciliation data to be included in the calculation of balancing operation reserve deviation charges.
Members also endorsed Reliability Assurance Agreement revisions to allow EDCs to submit corrections to peak load contribution and network service peak load assignments until noon on the next business day. The changes, which will also be reflected in Manuals 18 and 27, are intended to aid Pennsylvania EDCs squeezed by new Pennsylvania Public Utility Commission deadlines. (See PJM MIC OKs Settlement, Credit Changes.)
Reduced risk uncertainty. Non-performance penalties would be based on the net cost of new entry (CONE) rather than LMPs. Penalties would be capped at 1.5 times net CONE for the delivery year and 0.5 times net CONE for a single event.
