Stakeholders agreed Thursday to consider lowering credit requirements for Qualifying Transmission Upgrades (QTUs).
The Markets and Reliability Committee gave near unanimous approval to a problem statement and issue charge proposed by Janine Durand, attorney for developer H-P Energy Resources LLC.
Durand said current rules require credit postings that can be multiples of the construction cost of QTUs, small transmission projects that can be offered into the capacity market to relieve transmission constraints in Locational Deliverability Areas (LDAs).
A $7 million reconductoring, for example, would require posting of about $32.5 million, she said. She said the majority of QTUs “move ahead quickly” and are relatively low risk compared with generation projects that offer into capacity auctions.
The issue will be considered by the Market Implementation Committee.
Commonwealth Edison must do more for energy efficiency than it has proposed, the Illinois Commerce Commission ruled, requiring the utility to save 25,000 MWh a year more than it currently plans. Even so, ComEd would not come close to the 2% consumption cut that Illinois requires by mid-2015.
The ICC agreed with environmentalists and consumer advocates that the utility was proposing too much spending on consumer education and not enough on efficiency programs. The commission also ordered ComEd to start getting results from its $2.6 billion smart-meter project by planning with smart-device companies to get appliances that interact with the meters.
Big Rivers Electric Corp. found a buyer for half the output of its 417 MW D.B. Wilson plant for two months, and so did not shut it down Feb. 1 as planned. The cooperative hopes it will make another power purchase deal to keep the plant running beyond March. It had said earlier that it was shutting Wilson and would close the 443 MW Coleman plant in June because it had lost its two biggest customers, Century Aluminum smelters.
NRC Inspecting Calvert Cliffs After Recent Shutdown
Calvert Cliffs Nuclear Plant (Source: Constellation Energy Nuclear Group)
The Nuclear Regulatory Commission is doing a special inspection of Constellation’s Calvert Cliffs nuclear plant after an electrical malfunction caused both units at the facility to shut down. The event appeared to be caused by snow and cold that affected a ventilation louver filter. The plant restarted after several days. The company said such NRC special inspections are common, but an NRC spokesman said they were not, explaining that complications in the shutdown prompted the inspection.
Jersey Central Power & Light not get the $31 million rate increase it wants, but instead should have its rates cut $207.4 million, the Board of Public Utilities staff says. The staff filed a brief that essentially agreed with the Division of Rate Counsel, which started the rate case after accusing JCP&L of overearning.
The company is studying the matter and will file its own brief. This rate case is separate from the one in which JCP&L seeks $580 million for storm-related costs.
Wind power developers want the U.S. Interior Department to delay sales of offshore leases, but a frustrated state legislator and environmentalists want no delay.
In a letter to Gov. Chris Christie and legislative leaders, the developers asked them to lobby Interior for postponement of a sale, which is expected sometime this year, because Board of Public Utilities regulations have not been written yet to award offshore renewable energy credits to developers. The letter also urged officials to force BPU action.
Environmentalists also have been frustrated by BPU inaction, but they said the federal lease sale should go ahead.
Torch Renewable Energy said it would no longer pursue development of the Mill Pond Wind Project in Carteret County, where its plans had called for about 40 turbines. There were concerns about the project’s impact on nearby Cherry Point military base activities as well as health and safety issues, and the county had placed a moratorium on permits while it reviews its wind turbine regulations.
Florida-based NTE Energy plans a 500 MW natural gas combined cycle plant in Middletown, Ohio, between Dayton and Cincinnati. The company, which said it has entered the project into PJM’s interconnection queue, plans to start construction in 2015, with operations beginning in 2018.
Gov. John Kasich has four Republicans to choose from to fill the Public Utilities Commission seat being vacated in April by Todd Snitchler. Finalists for nomination to the five-year term are: Tom Johnson, a former state representative; Patrick Donlon of the PUC staff; Stacey Polk, a sustainability attorney; and Tom Waniewski, a Toledo city councilman.
Five competitive suppliers submitted winning bids for the one-year product and four submitted winners for the two-year product in FirstEnergy’s eighth auction to determine its retail generation service rates through May 2016. The one-year average clearing price was $55.83/MWh for June 2014 through May 2015. The two-year average price was $68.31/MW, through May 2016. The results will be blended with previous auctions and two upcoming auctions to establish the retail generation rates.
Bird Group Opposition Makes Military Cancel Wind Turbine
Opposition by bird-conservation groups has led to cancellation of a wind turbine installation at Camp Perry on Lake Erie. The groups had threated to sue the Air National Guard and had 5,000 signatures on a petition opposing the turbine, which was slated to go up in a few months. The Black Swamp Bird Observatory’s executive director said the groups would use legal research from this case to challenge other projects that endanger birds and would lobby for state laws to better regulate turbine site selection.
The state’s coal industry called for legislative hearings on the effect of coal plant closures on power supplies, noting PJM’s emergency actions during the January cold snaps. The Pennsylvania Coal Alliance’s statement followed similar calls from two state lawmakers, Sen. Tim Solobay and Rep. Pam Snyder.
The Commonwealth Financing Authority approved $4.5 million for seven projects that Gov. Tom Corbett touted as more evidence of the state’s commitment to expanding diverse energy industries. Six of the seven involve compressed natural gas installations. One grant, for $500,000, is for a $3.2 million, 265 kW combined heat and power installation at Cathedral Village retirement community in Philadelphia.
The Senate Committee on Commerce and Labor approved two bills backed by Dominion Virginia Power that could increase customer rates. One measure would let the company write off $420 million of the $600 million it has spent on nuclear and wind power development costs over the past six years, much of it development work toward a possible third unit at the North Anna plant. The write-off would reduce Dominion’s profits and allow it to avoid possible State Corporation Commission-ordered refunds in the next couple of years.
Another bill would let Dominion ask the SCC for a rate rider to pay for burying power lines. The utility said power restoration times could be cut in half if only 20% of its lines were buried. It would bury about 350 miles a year, at about $175 million, until 4,000 miles are underground. The state House has already approved the bill.
Natural gas pipelines will move their nominating schedules to later in the day, and PJM will move its day-ahead schedule forward, under plans revealed last week to increase the coordination between the gas and electric industries.
PJM’s Frank Koza told the Markets & Reliability Committee Thursday that gas industry officials offered an early nominating schedule and a third intraday nomination at a meeting with the ISO/RTO Council last month.
Comparison of Gas Day and Electric Day Schedules (Source: NERC)
Rae McQuade, president of the North American Energy Standards Board, confirmed yesterday that the gas industry is developing proposals that will help coordination between the two industries. “I think that everyone is really committed to looking at the market issues and determining what solutions are out there for continued dependence for natural gas generation,” she said.
Natural gas industry officials developed a “straw man” proposal that would move the timely gas nominating schedule from its current 11:30 a.m. Central Time spot to one later in the day. The straw man also proposes a new intraday 3 cycle and modifies the two other intraday cycles to allow nominations during regular business hours.
The proposal was developed by the Natural Gas Council, a group comprised of the American Gas Association, America’s Natural Gas Alliance, the Independent Petroleum Association of America, the Interstate Natural Gas Association of America, the Natural Gas Supply Association and the American Public Gas Association.
“We believe that the NGC straw man addresses in large part the electric industry’s concerns about the mismatch in the gas and electric schedules,” the group said in a statement released yesterday by INGAA communications director Cathy Landry. It said further discussion and approvals on both sides will be necessary for permanent changes.
Fantastic News
Andy Ott, PJM executive vice president for markets, called the proposal “fantastic” news that will help PJM with its daily scheduling of generators. Ott said PJM will also have to move its day ahead scheduling earlier in the day. He said PJM will seek to make a FERC filing by the end of the summer to enact changes in time for next winter.
Ott said the gas industry also needs to provide more scheduling staffing on weekends.
The disparity between the gas and electric schedules has been identified as an obstacle to increasing coordination of the two industries as the growth in power demand has strained pipeline capacities.
A report issued last May by the North American Electric Reliability Corp. highlighted what it called the “planning gap” between the gas and electric days: “…The electric day, in essence, completes its planning for the next day by 6:00 p.m. of the current day. While the completed electric utility plan identifies which electric units will run the next day (which in turn provides the basic information to project the next day’s fuel consumption), the pipeline deadlines for nominations historically have been at 10:00 a.m. of the current day. Thus, there is a six‐or‐more‐hour gap of incompatibility between the two traditional approaches to planning and scheduling.”
“The net result of this scheduling gap is that electric generator nominations, with their relatively large gas loads, are based upon estimates by the individual fuel planners of each Generator Owner (GO) between 24 and 36 hours in advance. The issue could be magnified when scheduling on a Friday, since gas markets are closed for the weekend.”
Other Challenges
The Gas Council said it agreed to make changes although it “would result in material changes and costs” to the industry.
“It is important to recognize that while scheduling enhancements will facilitate greater coordination, this straw man does not address the fundamental issue of how to finance infrastructure additions where capacity is tight and where competitive wholesale market rules do not provide incentives for generators to hold pipeline capacity,” it added.
FERC Action
A November order by the Federal Energy Regulatory Commission allows gas pipeline operators to exchange non-public operational information with PJM and other RTOs to better coordinate operations. (See FERC OKs Gas-Electric Talk.)
Because PJM has not yet amended its rules to accommodate the order, it received a temporary waiver from FERC to allow it to communicate with pipelines during last month’s cold snap. PJM held conference calls with pipelines and individually validated nominations for the RTO’s gas generators.
Dominion is selling the electricity side of its competitive retail energy business and hopes to have a transaction closed in the next several months. “It just doesn’t fit our business model,” CEO Tom Farrell told analysts, according to an earnings call transcript from Seeking Alpha.
Shrinking margins and higher volatility have struck other retailers, too, Farrell observed. “It’s a volatile market out there. We are not going to quantify it for you, but it’s extraordinary to watch.”
At the same time, the company said it would expand its portfolio of contracted utility-scale solar projects by nearly 250 MW, with projects coming online in 2014 and 2015.
The Fourth Circuit ruled that the Federal Energy Regulatory Commission properly granted incentives to a Dominion unit for five transmission projects, rejecting the claims of North Carolina utility regulators that the commission abused its discretion (case #12-1881).
The North Carolina Utilities Commission had challenged the incentives FERC granted in 2008 to five Virginia Electric & Power Co. transmission projects under FERC order 679. The North Carolina commission contended that four of the five projects didn’t satisfy a three-prong test to determine eligibility for incentives.
Former Duke Chief Rogers Would Be Utility ‘Attacker’
Jim Rogers
If he were starting in the business today, former Duke Energy chief Jim Rogers would go all out for solar roofs and would be an “attacker, not a defender” of the traditional utility model. In an interview with EnergyBiz magazine, Rogers spoke of “a continuing battle between central and distributed generation.”
The Alliance for Solar Choice welcomed Rogers’ remarks and urged him to persuade Duke and the utility industry to “see a better way forward” instead of defending their central-station model.
The Federal Energy Regulatory Commission told Duke Energy it would audit the utility’s compliance with conditions FERC put on its 2012 merger with Progress Energy. The conditions included making power sales to third parties while North Carolina transmission upgrades that would ease competition concerns were completed. A Duke spokesman said the upgrades were ahead of schedule, and Duke was complying with other conditions.
Tax experts are closely watching Exelon’s challenge of a $517 million tax bill stemming from transactions in 1999, when the company sold some power plants and acquired others in what it characterized as a tax-free exchange. The Internal Revenue Service says the transactions were taxable and the matter awaits Tax Court resolution. If Exelon loses, such transactions risk being viewed by the IRS as “abusive tax shelters,” tax lawyers said. No trial date been set.
Exelon Generation’s 10 nuclear plants in Illinois, Pennsylvania and New Jersey produced 134 million net MWh in 2013, their highest output ever, exceeding the previous record set in 2007. The plants operated at a 94.1% capacity factor.
AEP River Operations, a subsidiary of American Electric Power, received the first of 20 tank barges that will constitute its new Liquids Division. Starting Feb. 20, the unit’s barges will carry liquid cargoes, including petrochemicals and agricultural chemicals. “Entering the liquid cargo market means we can offer our customers a more complete range of services,” company President Keith Darling said.
January’s arctic cold lasted only a few days, but its impact could be felt for years depending on how the Federal Energy Regulatory Commission rules on the RTO’s request to waive its $1,000 price cap.
The commission agreed Jan. 24 that PJM could make whole natural gas generators that can prove that the spike in natural gas last month pushed their operating costs above the $1,000/MWh offer limit. (See FERC Lifts Price Cap as Cold Grips PJM.)
Still pending before the commission is PJM’s request to lift the price cap altogether for the remainder of the winter so that generators with costs over $1,000 set the PJM clearing price (ER14-1145). Among the factors the commission will consider in weighing the request to waive the PJM Tariff is whether the request is of “limited scope” and that it not harm third parties.
Windfall
Opponents told FERC in filings last week that PJM’s proposal would provide a windfall to generators at ratepayers’ expense.
“Tens of billions of dollars of obligations among sellers and buyers are committed every year on the basis of market rules, including the $1,000/MWh offer price cap,” NextEra wrote in opposition. “…This is precisely the circumstance in which market participants should be able to rely on a market rule that protects against unlimited price exposure. Indeed, the only time such a rule actually matters is when prices are extremely high.”
Opponents said the price cap was a trade-off consumers won in return for making capacity payments.
“The regulatory and pricing risk associated with exceptions to the offer-price cap rule will increase the cost of hedging instruments long after March 31, 2014,” wrote the PJM Industrial Customer Coalition and consumer advocates for seven states and the District of Columbia.
The consumers group said the waiver would gouge ratepayers as a result of bad business decisions by generators that failed to hedge gas prices or install dual fuel capability.
At the same time that operating costs for simple-cycle combustion turbines hit $1,200/MWh, generators with similar heat rates were producing power at about $310/MWh by burning oil.
The consumers said allowing “the least efficient generators that chose not to hedge” to set the market-clearing price will create undesirable incentives.
A company that owns four generation units — one fueled by natural gas purchased on the spot market and three that are not fueled by natural gas — could have an incentive to pay higher natural gas prices because of the potential gain to its other plants, they said.
Supporters
Among those who filed in support of the waiver were PJM generation owners and the Market Monitor.
“In a time of extreme cold weather events, it’s more important than ever that the market clearing prices reflect the value of resources that are needed to support reliable operations,” wrote Exelon. It said the commission should approve the waiver “to support accurate price formation and reliable operations going forward.”
The PJM Power Providers said the use of a single market-clearing price is a “fundamental tenet” of the PJM market. “Reflecting the marginal cost of fuel in uplift payments is a fundamentally flawed market design that must be stopped as soon as possible.”
It added: “the growth in demand response in PJM since 2002 suggests that there may be good cause to address whether an offer cap is even necessary in today’s market.”
PJM’s Market Monitor told the Federal Energy Regulatory Commission last week that rule changes approved by PJM stakeholders to increase the flexibility of demand response are insufficient and that the commission should impose a must-offer requirement similar to that for generation resources.
Monitoring Analytics asked that its complaint (EL14-20) be merged into docket ER14-822, in which FERC is considering the proposed changes.
Current rules require PJM operators to provide two hours’ notice before dispatching DR. Under the proposal approved by PJM stakeholders in December, resources will be dispatchable in 30 minutes.
The new rules also limit the “Emergency DR” designation to resources using back-up generators that are subject to environmental permits. Other resources will be known as “Capacity DR.” In addition, the minimum event duration will be reduced from two hours to one hour and the strike price will be reduced. (See Members OK DR Dispatch Rules after Late Amendments.)
The Monitor said the proposed changes fail to address all of the disparities in PJM’s treatment of DR and other capacity resources. It said FERC should limit DR’s offer cap — now effectively $1,800/MWh — to the $1,000 allowed generators.
“The current rules allowing non comparable demand resources are unjust, unreasonable and unduly discriminatory, and PJM should be directed to take immediate action to correct this design flaw,” the Monitor wrote.
In a filing in December (ER13-2108), four Ohio utilities, FirstEnergy, AEP, Dayton Power & Light and Duke-Ohio, also called on FERC to impose a must-offer requirement on DR. The lack of such a requirement obscures the cost of energy in high demand periods, resulting in higher production costs and uneconomic dispatch of DR, the utilities said. A must-offer obligation would allow PJM operators to dispatch DR economically rather than as a block, they said. (See Generators: Ban Planned DR.)
January’s sky high energy prices claimed its first casualty Friday as green energy retailer Clean Currents abruptly suspended service, returning its customers to their distribution utilities.
Average on Peak Prices – Total LMP PJM RTO (Source: PJM Interconnection, LLC)
“The recent extreme weather, which sent the wholesale electricity market into unchartered territories, has fatally compromised our ability to continue to serve customers,” the company said in a notice on its website.
Clean Currents had 6,000 residential and 2,000 commercial customers in Maryland, Pennsylvania and the District of Columbia. Based in Silver Spring, MD, the company had 19 employees.
The company was headed by CEO Charles Segerman, a lawyer and engineer who had worked in green real estate development, and President Gary Skulnik, a former Sierra Club lobbyist and CNN writer. Its board included two executives with SolarCity, a leader in residential solar power.
“This all happened very rapidly,” Skulnik told the Baltimore Sun. “Obviously this is not the way we would have hoped things would have happened, but this polar vortex and extended cold weather sent the electricity market into an extreme situation. Prices were through the roof and beyond anything we could afford to cover.”
The company’s former customers will revert to their distribution utilities’ Standard Offer Service until they choose an alternative retailer. Clean Currents said it was waiving any advanced notice requirement or early termination fees.
Could this be the first of a string of defaults?
“There is some concern that other electric or gas suppliers may do the same thing, so we will monitor this situation closely,” Maryland People’s Counsel Paula Carmody said in an email. “I also will be monitoring, to the extent we can get the information, price increases with variable price contracts, as we suspect consumers with see significant increases in their supplier bills as a result.”
Tom Matzzie, CEO of competitor Ethical Electric, mourned Clean Currents on Twitter as “pioneers,” but in a bullish sentiment quickly added that he would consider hiring its former employees.
PJM’s bills for energy purchased during the cold snap will be due this Friday, Matzzie said. “It’s probably going to be a bloodbath,” he said in an interview.
Many retailers likely received calls from PJM last week to provide more collateral due to the high prices — a demand Clean Currents apparently was unable to honor.
Matzzie said his company will survive despite excess energy costs “in the seven figures” because it hedged the day ahead market and will be able to pass along some of the costs to customers with variable price contracts. The company has a credit support “sleeve” backed by a bank. “You’re naked without that sort of credit support,” he said.
“The PJM uniform clearing price model is not suited for emergency events, which allows for tremendous windfalls for some parties and tremendous losses for other parties during emergencies,” Matzzie said. “The [$1,000] price cap is already too high. There should be a different set of rules for emergency events. The problem is the generators all get made whole. The suppliers and customers are left holding the bag.”
For his part, Skulnik claimed not to regret his failed venture. “We showed there was a demand for clean energy,” he told the Sun. “People want a solution for climate change.”
The Federal Energy Regulatory Commission approved PJM’s request to cap the quantity of Limited and Extended Summer demand response that clears in the annual base capacity auction, rejecting protests of opponents, who said it will increase costs and stunt the growth of DR.
The commission’s 4-0 ruling late Thursday (ER14-504) allows the changes to take effect in May’s Base Residual Auction for delivery year 2017-18.
The new rules cap the amount of Limited and Extended Summer DR at 10% of PJM’s reliability requirement, with Limited DR providing no more than 4%.
The changes — which the PJM Board filed with FERC despite a lack of stakeholder consensus — could boost capacity prices by $1.8 billion over two years, according to PJM simulations. (See PJM Goes it Alone in Bid to Limit DR in Capacity Auction.) PJM said those increases will be more than offset by a $3.4 billion reduction in energy prices over the same period.
“While we cannot confirm the simulation’s relative estimates,” the commission wrote, “we agree with PJM that additional generation resources clearing the capacity auction under PJM’s proposal would, unlike demand response that does not participate in the energy market until an emergency event occurs, contribute more energy in the energy market, which in turn would tend to place downward pressure on energy price.”
PJM told FERC the volume of limited DR clearing in the capacity market had to be reduced because current rules result in a vertical demand curve that threatens reliability. The RTO said it had erred in 2011 when it won FERC approval for rules incorporating limited and extended summer demand response into the capacity market.
PJM CEO Terry Boston issued a statement this morning praising the FERC ruling. “FERC’s action expands the usefulness of demand response and will allow demand resources to make a bigger contribution during tight power supply situations outside of the summer peak season, as we have been experiencing this January,” Boston said.
UBS Investment Research called the ruling “a coup” for PJM generation owners such as Exelon, FirstEnergy, PSEG, Calpine and NRG Energy, saying it could boost capacity prices by $25/MW-day in the RTO and $10/MW-day in MAAC.
USB termed it “a clear setback” for DR providers, although it said sector leader EnerNOC might benefit because its “relative technological advantage” will allow it to provide more Annual DR.
FERC rejected the arguments of consumer advocates, industrial load, cooperatives and state regulators opposed to the changes. However Commissioner John Norris did acknowledge some of their concerns in a concurring statement, expressing “caution that we not lose sight of the extraordinary benefits demand response has brought to consumers.”
“We must continue to provide demand response opportunities to participate in the PJM market on a level playing field with other types of resources,” Norris wrote.
“…It is my hope that this Commission will strike the right balance that maintains a reliable system while ensuring competition among resources that result in the most efficient costs to consumers.”
FERC is one commissioner short since the departure of former Chairman Jon Wellinghoff, who had championed DR. President Obama last week nominated FERC Enforcement Director Norman Bay as Wellinghoff’s replacement.
The PJM proposal won only 45% support from the Members Committee and 37% from the Markets and Reliability Committee in votes in November. A simulation by PJM found that the changes would have increased total capacity costs by nearly $2 billion over the last two Base Residual Auctions. (See Demand Response Changes Could Cost $1B Annually.)
FERC took note of the stakeholders’ misgivings but ruled that it was “reasonable for PJM to distinguish between each class of resources when designing its capacity market rules.
“On balance, we find that PJM’s proposal retains an adequate opportunity for limited-availability demand response to participate in PJM’s capacity markets,” the commission wrote.
It added: “While there may be other ways to address the problem identified by PJM, as suggested by intervenors, that does not mean that the solution proposed by PJM is unjust and unreasonable.”
PJM’s spending on black start generators will increase by at least $3.4 million — and perhaps as much as $21.6 million — under proposals outlined to the Markets and Reliability Committee Thursday.
The proposed changes, developed by the System Restoration Strategy Senior Task Force, are intended to increase the incentives for existing black start resources to continue providing the service, PJM’s Chantal Hendrzak said. PJM initiated the changes over concern that it will lose much of its existing capacity by 2015 due to coal plant retirements.
Minimum Incentive Proposal
Almost two-thirds of the task force voting supported a “minimum incentive” proposal that would set annual compensation for a 20 MW combustion turbine at $71,609, a 40% boost from the current $51,270.
The proposal, which will be the main motion when the MRC votes on the issue Feb. 27, would increase PJM’s annual black start costs to $24.4 million from the $21 million revenue requirement as of last Sept. 1.
Proxy Proposal
(Source: PJM Interconnection, LLC)
A second “proxy” proposal, which won 63% support from the task force, would increase compensation for a 20 MW CT five-fold to $312,486 while more than doubling annual black start costs to $42.7 million (see charts). It may be considered by MRC if the minimum incentive proposal fails to win support.
The mininum incentive proposal would:
Change the incentive factor from 10% to the greater of 10% or $25,000;
Allow non-ICAP (energy-only) units to receive compensation based on the offered black start MW;
Permit automatic load rejection units (ALR) to recover NERC Compliance costs as documented to the Market Monitor;
Allow compensation for storage of fuels other than oil;
Provide for a 5-year PJM internal review of formula.
The proxy proposal would replace the base formula rate, variable operations and maintenance costs, fuel storage and training costs with a formulation based on the average of responses to PJM’s recent solicitation for black start resources.
No Change to Capital Recovery
Neither proposal changes the capital recovery rate for units requiring capital investments to become black start-capable.
Hendrzak said PJM expects to issue awards to the winners of the solicitation by April 1. The task force also is working on changes to the “back stop” compensation in zones that did not receive bids.
(Source: PJM Interconnection, LLC)
The impact of the proposed changes vary dramatically by region. For example, the minimum incentive proposal would increase costs less than 10% in 10 zones while seven zones would see costs jump by more than a third, with PPL’s doubling (see chart).
Token Incentive
John Horstmann, of Dayton Power & Light Co., said increasing incentives for existing units will be cheaper than paying for new ones, which could cost $250,000 or more annually. The $20,000 increase a 40-year-old 20 MW CT would receive under the minimum incentive is “at least a token effort to keep some of the older units around.”
Black start units must be capable of starting without an outside electrical supply, maintaining frequency and voltage under varying load, and maintaining rated output for a specified time, typically 16 hours.
In September, the Federal Energy Regulatory Commission approved Tariff revisions that PJM said will increase the pool of potential black start generators by 64,000 MW (ER13-1911).
The Markets and Reliability Committee last week endorsed changes to Manuals 14B and 18 to implement proposed capacity import limits and clarify rules on substitution of demand response resources.
Manual 14B: PJM Region Transmission Planning Process
Reason for Change: The MRC endorsed changes to Manual 14B to implement PJM’s proposed capacity import limits, now pending before the Federal Energy Regulatory Commission. (See related story, FERC Demands More Details on Import Cap.)
Stakeholders approved the limits in November out of concerns that PJM might lack sufficient transmission to accommodate its growing volume of capacity imports. Cleared imports grew from about 3,000 MW to more than 4,500 MW in 2009-2012 before more than doubling to nearly 7,500 MW last year.
Impact: The revised methodology would limit external generation resources in this year’s base capacity auction to 6,200 MW — a 17% drop from the volume of imports that cleared in the May 2013 auction — while also setting five import zones with their own limits. (See Members OK Capacity Import Limit; Prices May Rise.)
Manual 18: PJM Capacity Market
Reason for Change: The committee endorsed changes to Manual 18 to clarify Tariff provisions that allow substitutions of demand response resources.
Impact: The change makes clear that curtailment service providers may substitute a non-performing DR registration with one or more other DR registrations in the same geographic area and with the same lead time. Providers may use Limited DR to replace Annual DR but the substitution will not count against Limited’s 10 dispatch-per-year cap. Annual DR has no limits on the number of dispatches.
