SPP asked FERC last week to resolve a “Catch-22” situation facing the RTO regarding the handling of settlement revenue stemming from a dispute with MISO (ER16-791).
A March FERC order conditionally accepted SPP’s proposal to distribute to its members $16 million in funds reached in a settlement with MISO over the latter’s use of SPP’s transmission system to transfer power freely between its North and South regions. The order also set the docket for hearing and settlement procedures to resolve factual issues in dispute. (See “MISO Settlement Funds Held Up,” SPP RSC Briefs.)
SPP said it has begun distributing settlement revenue to members with its May invoices, but only to those members who signed on to the settlement agreement. At issue, the RTO says, is what to do with transmission-owning members not subject to FERC jurisdiction that have not agreed to a voluntary refund commitment as part of the commission’s final order on allocation.
The RTO asked FERC to confirm it can hold those members’ “allocated shares” until the hearing and settlement procedures end. It also requested the commission clarify SPP will not owe interest on any revenues not distributed to any non-jurisdictional TO that has not signed the refund commitment.
The clarification, it said, “will resolve the ‘Catch-22’ facing SPP, whereby SPP cannot … disburse funds to entities over which the commission cannot order refunds in the event of overpayment by SPP; yet, on the other hand, SPP lacks any explicit authority to hold funds on behalf of these entities.”
SPP said “many, but not all” of its impacted TOs have provided the requested voluntary refund commitment. The proceeding’s first settlement conference was held April 21, with a second scheduled June 16.
SANTA MONICA, Calif. — Ed Randolph, energy division director at the California Public Utilities Commission, does not care if his state meets its 50% renewable mandate by 2030.
That statement, delivered at the Infocast California Energy Summit last week, came with an important qualifier: “Let me be clear — we will meet the 50% RPS.”
The more pressing concern for the PUC, Randolph said, is reforming the agency’s long-term planning process (LTPP) to ensure California will meet its ambitious greenhouse gas reduction goals for 2050. In 2005, Gov. Arnold Schwarzenegger issued an executive order establishing the state’s objective to reduce 2050 GHG emissions to 80% below 1990 levels. Gov. Jerry Brown reinforced that measure through a 2015 order creating an interim target of a 40% reduction by 2030. [Editor’s Note: An earlier version of this article incorrectly reported that the 80% cut was the product of state legislation.]
The State Senate last year passed legislation to codify both standards, but the bill stalled in the State Assembly. Still, the state Air Resources Board intends to include both targets in an updated version of its GHG scoping plan, which defines the state’s climate change goals and lays the groundwork for achieving them.
The state’s load-serving entities — which include the three investor-owned utilities, electric service providers and community-choice aggregators — will play a key role in the effort.
The problem: The current LTPP, which emphasizes reliability, does not provide a blueprint for achieving GHG reductions.
Other state objectives further muddle the planning picture. Randolph pointed out that efforts aimed at improving energy efficiency and increasing the use of demand response rely on their own cost methodologies.
That will change in 2017 when the commission adopts a process requiring each of California’s LSEs to file an IRP that prioritizes emission reductions alongside other — more standard — requirements, such as resource diversity, reliability and cost-effectiveness.
Among the most fundamental steps to getting there: “We need to determine what the GHG metrics are going to be,” said Randolph, referring to the need to determine each LSE’s share of emissions reductions. “What’s the savings target?
“We know what it is for the economy,” he added, referring to the 80% target. “We need to know what it is for the energy sector.”
The IRP process will also require that the PUC produce its own long-term load forecasts, a capability the agency needs to develop. Randolph said the PUC has requested additional funding from the legislature to create an in-house modeling unit.
IRP implementation could follow one of a few approaches, according to Randolph.
Under a “CPUC-centric” IRP, the commission would set GHG targets for each of the LSEs and determine the resource portfolios that would meet them.
An “LSE-centric” approach would have the PUC establish reliability needs and GHG targets for the LSEs, while allowing them to develop their own resource mixes.
A third choice: a hybrid of the two.
With those options now on the table for next year, Randolph reminded attendees that — for now — it is still business as usual at his agency.
“Anyone who’s a fan of the CPUC’s current proceedings, they’re not going away quite yet,” he said.
SPP will hold a two-day review session for the Attachment Z2 credit-settlement system June 28-29 at its Little Rock headquarters. The session will run 9 a.m. to 4:30 p.m. each day.
The review session was initially planned for late May, but conflicts with a number of stakeholder meetings pushed the date back.
The Z2 settlement system is being used to help resolve years of incorrect credits for transmission upgrades; the Board of Directors last month approved a payment plan that will begin in November. (See “Board Approves Z2 Level Payment Plan,” SPP Board of Directors Briefs.)
Staff said attendees will gain an understanding of how the settlement system was designed and built and how its calculations are performed.
SPP is asking attendees to complete the Z2 online course on SPP’s Learning Center, review a Z2 white paper and sign a nondisclosure agreement, which will be sent after registering for the review session.
Albany, N.Y. — More than 120 people attended the Independent Power Producers of New York’s annual spring conference at the Desmond Hotel and Conference Center. Here are some highlights.
John Reese, IPPNY chairman and senior vice president at Eastern Generation, mused about the conference’s theme, “Bolstering New York’s Energy Markets in a Changing Landscape.”
“The New York landscape changes so often it should be made of Play-Doh,” he said, noting that both the former state Senate majority leader and the former Assembly speaker were sentenced to prison this month on corruption charges.
In addition, a former aide to Gov. Andrew Cuomo is the subjects of a wide-ranging federal influence peddling probe that has ensnared both SolarCity and Competitive Power Ventures. “We have every major energy agency in the state under subpoena by the U.S. attorney: the New York Power Authority, NYSERDA [New York State Energy Research and Development Authority] and the Public Service Commission,” Reese said.
Sen. Joseph Griffo, chairman of the Senate Committee on Energy and Telecommunications, said the Senate will be considering “reset legislation” for the state’s energy service companies while monitoring PSC proceedings on the issue. (See Retailers Ask for Rehearing of NY Guaranteed Savings Order.)
“We’re looking at things designed to protect customers, to weed out some of the bad actors, establish a more robust, legitimate ESCO market,” Griffo said.
Assemblywoman Amy Paulin, chairman of the Assembly Committee on Energy, said she is backing legislation that would give electric vehicle owners discounted rates for charging their cars during off-peak times. She said she also supports a tax credit for farmers leasing land to solar developers and noted that a fuel cell sales tax exemption was included in the state budget.
Scott Weiner, deputy for markets and innovation at the New York Department of Public Service, said he initially thought the Supreme Court’s ruling last month rejecting Maryland regulators’ attempt to subsidize a combined cycle plant through a contract-for-differences was “very narrow.” (See Supreme Court Rejects MD Subsidy for CPV Plant.)
“Nothing in this opinion should be read to foreclose Maryland and other states from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation,’” the court said.
But after rereading the order, Weiner said, he changed his mind.
“There will be a lot of lawyers spending a lot of time defining ‘tethering,’” he said. “There’s a lot that the order didn’t say. That leaves white space for all of us to work our way through.”
FERC Chairman Norman Bay gave his thoughts on continuing state-federal jurisdictional battles over the electric industry and calls for reregulation in states with retail choice.
“At FERC we clearly don’t have the authority to tell a state that it can’t be vertically integrated. We don’t have the authority to tell a state that, if it chooses to do so, that it can’t reregulate,” he said. “The case to be made for a market-based approach to further important public policies has to be made. And I think that case is being made in RTOs and ISOs across the country.”
NORTH FALMOUTH, Mass. — More than 200 people attended the Northeast Energy and Commerce Association’s 23rd Annual New England Energy Conference last week. Here are some highlights.
Paul Roberti, a member of the Rhode Island Public Utilities Commission, on the suspension of the Northeast Energy Direct pipeline project: “The recent decision by Kinder Morgan to suspend its project should not come as a surprise. Why? Because the capacity market … is doing what it’s supposed to do by bringing forth dual-fuel generators. … It’s the economics and the market construct that is driving the decision not to have gas pipelines at this point in time.”
Christopher Recchia, commissioner of the Vermont Department of Public Service, on the success of the state’s clean energy programs and their impact on development: “We’re at 10 times the amount of solar that we had in 2011, so we’re over 250 MW that’s installed or approved or permitted, with also 100 MW of wind. … Of course, it’s not baseload, but it’s more nameplate wattage than we ever got from [closed nuclear plant] Vermont Yankee,” whose output was sold into the grid and did not serve in-state load exclusively.
New Hampshire Consumer Advocate Donald Kreis said utilities appear to be embracing smart meters and distributed resources, even though they may reduce their revenues. “If you listen to the utilities, you would have no idea that any of them have shareholders. What are the shareholders willing to do, risk-wise, on the way to those double-digit [returns on equity] that utilities crave?”
Kerrick Johnson, vice president of Vermont Electric Power Co., said his state relies on intermittent renewables for at least 18% of its 1,000-MW load. “That’s incredible. That’s something that is very challenging. … This blossoming of distributed generation behind the meter is really impacting us.”
Matthew Morrissey, managing director of Offshore Wind Massachusetts, a coalition of offshore wind developers, on the decreasing prices in Europe, where new projects are coming in at 15 cents/kWh: “We are seeing a sea change in costs in terms of the industrialization of this resource.”
David Littell, principal for the Regulatory Assistance Project, on the development of a “grid of the future”: “I am not sure if New England will have the grid of the future in five years, but I am sure that California will be on the way. … We can watch what they’re doing so we can learn. … New England can get there if it wants to.”
Micah Remley, senior vice president of product for demand response service provider EnerNOC, said customer usage data have little value if the customer cannot respond in real time or if market design does not incent a change in behavior. “We need three things in place: you need the data, you need to get the data all of the time and you need the market design to take advantage of the technology.”
VALLEY FORGE, Pa. — The Market Implementation Committee unanimously approved a problem statement and issue charge to consider changes to rules governing day-ahead scheduling reserve eligibility.
Supply resources are profiting at the expense of load by buying out of their obligations in Incremental Auctions, according to Direct Energy. Since delivery year 2012/13, the company says, load’s unforced capacity (UCAP) obligation has declined by an average of 6% between the Base Residual Auction and the final Incremental Auction, while load has received an average credit of only 3%. For DY 2016/17, PJM “overcollected” almost $200 million, the company says.
Current rules allow resources to clear DASR even though some — nuclear, run-of-river and self-scheduled pumped hydro, wind and solar units — cannot fulfill their obligations in real time. If such units are made ineligible, cleared DASR megawatts will be able to reliably fulfill their obligations in real time.
The issue will be worked at the MIC and is expected to result in updated language to Manual 11.
Price Floor for Incremental Auctions?
Jeff Whitehead of Direct Energy suggested PJM establish a price floor for incremental auctions and said he will return to the MIC with a problem statement.
The large amount of capacity released in incremental auctions has led to low clearing prices — giving supply resources the opportunity to buy out of their obligation and net profits that are financed by load, he said.
Whitehead raised the issue following a PJM presentation on the release of base capacity for delivery year 2017/18.
In the third incremental auction for delivery year 2016/17, PJM released 4,556 MW of prior capacity commitments. PJM said more than double that amount — 10,000 MW — would be included in the third incremental auction for the 2017/18 delivery year. (See PJM Transition Auction Capacity not Included in Incremental Auction.)
PLS Exception Process Proposal Presented
PJM presented the first read of a proposed parameter-limited schedule (PLS) exception process.
The revisions would allow for exception requests to be submitted after the Feb. 28 deadline and for a temporary exception to be extended to a period exception under certain circumstances.
The changes would give PJM and the Independent Market Monitor more time to review requests and provide determinations to market sellers. The persistent PLS exception option would be eliminated. (See “Manual Changes to Detail Unit-Specific Operating Parameter Adjustment Process Under CP,” PJM Operating Committee Briefs.)
PJM Seeks to Clarify Terms of Auction Specific Bilateral Transactions
Members will be asked at the next MIC meeting to endorse rule clarifications to preserve the physicality of auction-specific bilateral transactions.
The changes clarify that performance bonus payments related to such transactions accrue to the buyer, and the obligation to perform remains with the seller. In addition, the buyers would be required to indemnify PJM Settlement against seller performance defaults.
The buyer would be the party to enter into a replacement transaction if desired, and there would be no restrictions on the source of replacement.
CPower Proposes to Study Necessity of DR Registration Submission Deadline
Bruce Campbell presented a problem statement and issue charge on behalf of CPower to review the demand response registration submission deadline.
Currently, DR may only register for capacity auctions from Jan. 1 to May 15 and only for the delivery year that follows the May 15 deadline. That prevents customers who may be willing to contribute to reliability during the delivery year but after the deadline from participating as a demand resource, Campbell said.
The registration window is a legacy of seasonal performance requirements and penalty structures, he said.
“The implementation of [Capacity Performance] has changed demand resource obligations and penalties, which may allow for more flexible registration submission timeline requirements,” Campbell said.
Widening the registration window could increase reliability and reduce provider risks and customer costs, he said.
The goal would be to present proposed changes to the Markets and Reliability Committee in November.
Exelon, Direct Energy Suggest Studying Residual ARR Process
Direct Energy’s Whitehead and Sharon Midgley of Exelon presented a problem statement and issue charge to discuss potential enhancements to the residual auction revenue rights process.
“The current residual ARR process poses a risk that’s unhedgeable,” Midgley said.
Currently, PJM may allocate residual ARRs that become feasible after the annual allocation process in specific months where transmission capability becomes available to accommodate them, according to the problem statement. Market participants have no choice regarding whether to accept or reject them.
Residual ARRs for a portion of the planning year can have vastly different values from the same ARRs allocated across the entire planning year; in some cases they can be negatively valued.
“As a result, LSEs may be saddled with an undesired, unexpected and unhedgeable reduction in expected ARR credits,” the problem statement said.
“We’re looking to firm up ARR credits to what it was three or four years ago so you can know what kind of cash flow you can expect,” Whitehead said.
Xcel Energy is expected to present new data to the city of Boulder this week to try and persuade the City Council to nix plans to acquire the utility’s assets and operate as a municipal entity.
City Attorney Tom Carr told the council that if the city is unable to come up with a plan that maintains service reliability and competitive customer rates, while also reducing greenhouse gas emissions at the pace mandated by the city charter, he would recommend abandoning municipalization plans.
The state’s Public Utilities Commission ruled in November that Boulder cannot acquire Xcel facilities that exclusively serve customers outside city limits. The commission declined to force Xcel to share its facilities with the city.
The Public Service Commission should not spend $21.55 million from the merger agreement between Exelon and Pepco Holdings Inc. in case the decision is returned to the courts, the Office of the People’s Counsel said in a filing last week.
The public advocate, along with district government and several clean energy groups, is asking the PSC to reconsider its decision allowing the $6.8 million deal.
Peoples Gas and parent company Integrys Energy Group will pay customers $18.5 million for allegedly withholding information about its $8 billion program that replaces 2,000 miles of old iron gas mains beneath Chicago streets.
The settlement reached last week ends investigations by Attorney General Lisa Madigan and the Commerce Commission into allegations that project leaders failed to disclose $3.5 billion in cost overruns to regulators until Wisconsin Energy acquired Integrys last June. Peoples Gas maintains it did nothing wrong.
The settlement involves a combination of bill credits, legal reimbursements and grants to provide relief to low-income households for heating expenses.
The state will officially suspend its work devising a plan to comply with the federal Clean Power Plan on May 19. It is at least the third state to take such a step after a U.S. Supreme Court ruling in February staying the rules until legal challenges are resolved.
Republican Gov. Sam Brownback signed the measure into law last week after the GOP-dominated Legislature approved it by wide margins late last month. The law prohibits state agencies from conducting studies or doing other work toward drafting a compliance plan until the U.S. Supreme Court’s stay is lifted.
Kansas was among 27 states challenging the rules, finalized by President Obama’s administration last year.
The Public Service Commission has appointed Chief Engineer Morris Schreim to senior commission adviser. He takes the place of Walter Hall.
Schreim, who has been with the commission since 2013, will advise it on matters related to PJM and FERC.
Andrew Dodge will assume the position of chief engineer and director of emergency management. Dodge retired in December as vice president of technical services at Baltimore Gas and Electric.
The CEOs of three of the Colstrip plant’s owners sat down with Gov. Steve Bullock last week to discuss what will happen to the aging coal-fired complex as out-of-state political forces push toward the eventual closure of its two older units.
Kimberly Harris of Puget Sound Energy, Paul Farr of Talen Energy and Bob Rowe of NorthWestern Energy represented half the plant’s ownership. Talen owns 50% of Units 1 and 2 and a 30% share of Unit 3. It also operates the entire four-unit Colstrip complex.
Farr made it clear that Talen wants to sell its stake in the plant. He suggested that industrial customers sign a power purchase agreement with the plant to keep it operational.
Eversource Predicts Increase In Service Charge in July
Eversource Energy is predicting an increase in its energy service charge starting in July at the same time that three other state utilities, which purchase power from regional markets, are expecting lower prices.
The company filed a price forecast with regulators but is not formally requesting the rate change. It is predicting that it will request a rate of 10.94 cents/kWh, a 9.5% increase from the current 9.99 cents/kWh. Utilities in the state adjust their rates every six months to reflect shifting generation prices.
Eversource, which produces its own power, is allowed to pass through the cost of operating coal-fired power plants that it owns into its rate. Three other utilities buy power on the wholesale market, and their rates have dropped because of historically low natural gas prices.
The state surpassed 1,000 MW of installed wind capacity last year, and analysts say the state is well positioned to expand its renewable power output.
Industry experts say the state has excellent wind resources, and investors already have put almost $2 billion into developing turbines in the state. Wind power accounted for 6.3% of all power generated in the state, according to John Hensley, manager of industry data and analysis for the American Wind Energy Association. An additional 300 MW of capacity is expected to come online this year.
The state currently has 14 wind projects that support more than 1,000 jobs and generate enough power for 189,000 homes.
A state judge last week denied the city of Farmington’s motion to dismiss the city of Bloomfield’s breach of contract lawsuit, filed in August as part of its attempt to purchase an electric utility from Farmington.
“A municipality must be able to control the utilities within its jurisdictional boundaries and acquire the necessary property and equipment to do so,” Judge Bradford Dalley said. “It cannot be said that the passage of time extinguishes that role, especially when the right has been recognized in an agreement preserved in a court order.”
The city of Bloomfield alleges that a 1960 court case and the subsequent judgment and decree served as a contract between the two cities that recognized Bloomfield’s right to purchase the utility from Farmington at any time. Farmington argues that the 1960 decree, known as the Culpepper Decree, was not a contract and was subject to the statute of limitations.
SolarCity acknowledged it has been subpoenaed in a federal probe of improper lobbying and undisclosed conflicts in state contracts.
The company is developing a state-funded “gigafactory,” the centerpiece of Gov. Andrew Cuomo’s “Buffalo Billion” initiative. U.S. Attorney Preet Bharara is investigating how certain vendors were selected to construct the projects, including SolarCity’s. A company spokeswoman said it is complying with the investigation and that the company had no say in the selection process.
The governor’s office, the state economic development agency, the State University of New York Polytechnic Institute, the Public Service Commission’s Department of Public Service and the New York State Energy Research and Development Authority also have been subpoenaed.
At a packed public hearing, the state Energy Facility Siting Board heard opposition to a new $700 million natural gas-fired power plant that would be built in the western part of Burrillville.
Residents told the board that Invenergy’s proposed facility does not belong in an area surrounded by woodlands, including protected lands in the Buck Hill and George Washington management areas.
About one-half of the plant’s 1,000-MW capacity was successfully bid into the ISO-NE Forward Capacity Auction for the 2019/20 commitment period. A decision from the siting board is expected early next year.
The Pierre City Commission last week approved leasing 5 acres at the Pierre Regional Airport to Geronimo Energy in what is expected to be the state’s largest solar energy project.
Minnesota-based Geronimo will install the 1-MW facility this summer. The power will be distributed into Pierre’s municipal electrical system.
It also will be first solar project for Missouri River Energy Services, which provides 43% of the city’s electrical power. The city gets the remaining 57% of its electricity from the Western Area Power Administration, which is not part of the project.
A little-known exemption has allowed 147 school districts to exceed state-imposed revenue limits by spending a combined $138 million on energy efficiency measures.
The Wisconsin Taxpayers Alliance says that a 2009 law allowed state school districts to exempt energy efficiency expenditures from state rules that require voter approval if revenue limits are exceeded. The Wisconsin Association of School Boards said the exemption encourages school districts to make investments in energy efficiency to achieve long-term operating savings.
A bill to end the exemption, sponsored by two Republican legislators, was stalled in the Legislature last session.
Whitley, who retired last October after seven years at the ISO, emphasized the importance of wires and pipelines in his keynote speech Wednesday at the Northeast Energy and Commerce Association’s 23rd Annual New England Energy Conference.
He reflected on his career, which also included 30 years of operations and management positions at the Tennessee Valley Authority before he moved to the Northeast. His personal highlight reel seemed to be a solid string of crisis management. Nuclear shutdowns at TVA in the late 1980s. The 2003 blackout. A horrific New England cold snap in 2004. Hurricane Sandy. The polar vortex.
“It seemed like these problems followed me around,” he joked.
A common theme was “the need for transmission” to navigate through these near-disasters.
Five-Year Shutdown
In 1985, the Nuclear Regulatory Commission ordered shutdowns of the Brown’s Ferry plant in Alabama and the Sequoya station in Tennessee over safety concerns.
“It was 6,000 MW of capacity and we thought it would be three or four months, but it turned out to be five years,” he said.
The TVA hydro system simultaneously suffered through two droughts, so 4,000 MW of hydropower were reduced to 2,500 MW for much of that time, causing “a few tough years.”
“The way we got through it most of the time was through the transmission grid,” Whitley said.
Whitley said the system survived through imports from areas with greater fuel diversity, an experience that would be repeated in his later jobs in New England and New York.
7,000 MW out of Service
In 2004, New England — less reliant on natural gas for power generation than it is now — suffered through five days with minus 10-degree temperatures and 45-mph winds, recalled Whitley, who was ISO-NE’s chief operating officer at the time. “One day I went to the control room and one of the operators told me we had 7,000 MW of power plants that couldn’t come online.”
The crisis was eased when some New York generators switched to oil-fired generation, which freed up some gas pipeline capacity.
“That’s when you see it’s not just the electric system that is so important, it’s the infrastructure of the gas supply system and the diversity of the generation capacity,” Whitley said.
Transmission, fuel diversity and imports also got NYISO through Hurricane Sandy in 2012 and the polar vortex in early 2014.
Whitley said he worries the next crisis could result from the Northeast’s switch to “all renewables and gas” without, he says, adequate infrastructure to support it. He said the recent suspension of the Northeast Energy Direct pipeline was disappointing. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)
Without diverse energy supplies and robust infrastructure, he said, the system will be stressed.
“Each region is going to have to be more capable of carrying its own load,” Whitley said. “As all these coal plants shut down, there just isn’t going to that much surplus available.”
VALLEY FORGE, Pa. — Interconnection customers would face a stricter submittal process for their projects beginning Nov. 1 under Tariff changes unanimously approved Thursday by the Planning Committee.
The revisions were recommended by the Earlier Queue Submittal Task Force, which was convened to figure out ways to incent earlier participation in the process after current rules failed to influence behavior. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)
In general, the changes require earlier submittal of documentation in order to secure a place in the project queue. PJM would perform a deficiency review only after all elements, aside from site control, were in hand.
Applications would have to clear their deficiencies by the close of the queue window or be terminated.
The revisions also would allow project deposits to become chargeable immediately, and PJM would spend the refundable portions first.
In addition, the opening of queue windows would be moved up to April from May and to October from November, which will improve the chances for large generators to participate in the May Base Residual Auction.
Typical TO Upgrades Would be Excluded from Competitive Window Under Proposal
PJM is proposing to exclude typical transmission substation equipment violations from the Order 1000 competitive window process. The Planning and Markets and Reliability committees will be asked to approve new Operating Agreement language in June.
A historical look at the Regional Transmission Expansion Plan revealed that such fixes rarely yield greenfield proposals. If analysis showed that a greenfield project is possible, PJM would open a proposal window.
The exclusion would not apply to supplemental or market efficiency projects. (See “Proposal Would Exclude TO Upgrades from Order 1000 Window,” PJM Planning Committee and TEAC Briefs.)
IRM Study Assumptions Presented for First Read
The Resource Adequacy Analysis Subcommittee is recommending that PJM retain its current load model selection process for the installed reserve margin (IRM) study with one minor change: The procedure will be modified to recognize that the annual peak can only occur in the peak summer week.
PJM’s Tom Falin said that had the change been implemented for the 2015 reserve requirement study, it would have resulted in the same load model being chosen and produced the same IRM and forecast pool requirement.
The Planning Committee will be asked to endorse the study assumptions at its next meeting.
“It’s really a minor change with no consequence,” Falin said.
Planners will continue to model a 2,500-MW ambient derating in the summer period.
The RAAS met six times over five months to study all of the assumptions used in the IRM study after PJM’s methodology was questioned. (See “IRM, FPR Rising; PJM Methodology Challenged,” PJM Planning Committee Briefs.)
The group identified three assumptions that warranted in-depth investigation: the load model selection process, world modeling and the capacity benefit of ties, and the ambient derating of generators in the summer period.
“It’s essentially the same as last year, but the subcommittee is more comfortable with those assumptions after having drilled into them,” Falin said.
PJM-MISO to Create ‘Targeted Market Efficiency Projects’
PJM and MISO are working to revise their joint operating agreement to create a category of “targeted market efficiency projects” that could be undertaken quickly and relatively inexpensively to remedy historical congestion. These would be treated separately from traditional market efficiency projects, which look at projected model conditions under future assumptions, said PJM’s Chuck Liebold.
“These projects would be very targeted in nature,” he said. They probably would consist of upgrades to terminal equipment, and an aggressive in-service date would be assigned to them.
The upgrades would be recommended on an annual basis, with proposals going before the boards of each RTO in December.
He said the study process will be similar to an effort the RTOs undertook last year, when they were unable to approve any projects. (See MISO-PJM ‘Quick Hit’ Projects Shrink to Two.)
The projects would be evaluated based on five years of benefits at a benefit-cost ratio of 1.0.
Planners Choose Project to Relieve APSouth Congestion
Planners intend to recommend a $340.6 million APSouth market efficiency project to the Board of Managers, despite some stakeholders’ recommendations that they take another look at three other proposals.
LS Power’s Sharon Segner said that the 9A (without capacitors) proposal is not necessarily the most feasible and that it faces permitting problems.
“We’ve been [evaluating proposals] for more than a year now, and I am confident with what we’re proposing now,” PJM’s Tim Horger said.
He said the project provides the most congestion savings to PJM and APSouth as well as the most production cost savings.
The project would tap the Conemaugh-Hunterstown 500-kV line and build a new 230-kV double circuit line between Rice and Ringgold. The plan also calls for building a new 230-kV double circuit line between Furnace Run and Conastone and rebuilding the Conastone-Northwest 230-kV line. (See “Planners Select Dominion-Transource Project to Address APSouth Congestion,” PJM Transmission Expansion Advisory Committee Briefs.)
It is projected to be in service by 2020.
Two Dominion Zone Reliability Projects Recommended
PJM presented two reliability projects it intends to recommend to the Board of Managers out of more than two dozen it received in the first proposal window of the year.
Both are in the Dominion transmission zone in Virginia, with projected in-service dates of June 1, 2020.
One addresses the overload of the Chesterfield-Messer Road-Charles City Road 230-kV circuit. The $22 million project consists of rebuilding 21.3 miles of existing line between Chesterfield and Lakeside.
The other addresses the overload of the Carson-Rogers Road 500-kV circuit. The $48.5 million project would rebuild the circuit.
Cogentrix Hopewell Units to be Deactivated
PJM has received a deactivation notice from James River Genco for Units 1 and 2 of Cogentrix Hopewell in the Dominion zone.
Together, the units represent 92 MW. The requested deactivation date is May 31, 2017.
PJM is conducting a reliability analysis.
Preliminary CPP Compliance Analysis Presented
PJM presented some of the first findings of its study of Clean Power Plan compliance to Transmission Expansion Advisory Committee members.
The review continues to indicate that regional compliance is cheaper. In addition, it showed that mass-based compliance provides more certainty in emissions levels than rate-based but that the latter approach can lead to fewer retirements.
Rate-based compliance also reduces wholesale energy market prices. (See “Reference Model for CPP Study Introduced,” PJM Planning Committee and TEAC Briefs.)
VALLEY FORGE, Pa. — About 1,900 MW of behind-the-meter generation may be unavailable because of tightened environmental rules, PJM told the Operating Committee last week.
PJM shared with the committee new EPA guidance issued in response to an appellate court decision last year that voided a rule exempting diesel generators providing demand response from air emissions limits.
EPA had exempted reciprocating internal combustion engines providing “emergency demand response” from emissions limits for up to 100 hours each year. The D.C. Circuit Court of Appeals ruled that the agency had “cavalierly sidestepped its responsibility to address reasonable alternatives” to the use of the generators. (See Appellate Court Rejects EPA Rule on Back-Up Generators.)
As a result of the ruling, EPA said such an engine “may not operate … for any number of hours per year unless it is in compliance with the emission standards and other applicable requirements for a nonemergency engine.”
That means behind-the-meter generation may only be used if it can respond when dispatched by PJM and comply with local, state and federal laws, including environmental permits, PJM said. Demand response that fails to perform when dispatched by PJM will be penalized, and there are no exceptions for the status of environmental permits.
“We have reached out and talked to our [curtailment service providers], and virtually everyone we talked to has made arrangements so they can meet their commitment for the summer,” PJM’s Pete Langbein said. “We at PJM do not see an impact going into the summer on capacity.”
Generators Employing Best Practices for Winterization
ReliabilityFirst Corp. gave the Operating Committee a lessons learned presentation resulting from its plant winterization visits since 2014.
PJM members have deployed “inventive solutions,” including additional enclosures to prevent freezing, portable heaters and a downspout system to divert rain and moisture away from inlet air filters, ReliabilityFirst said.
It identified just three areas for improvement: routinely operate any idle or standby equipment; make sure heat “tracing” or freeze protection is installed on any vulnerable equipment; and ensure the plant instrument air system is continuously supplying moisture-free air.
PJM Proposes to Sunset SIS, Move Topics to DMS
PJM is proposing to sunset the Systems Information Subcommittee and move some of its discussion topics to the Data Management Subcommittee, whose charter would be expanded.
Those topics relate to inter-control center communication protocol data links, Manual 01 changes and phasors.
The proposal also includes creating an “implementation forum,” which will be the primary venue for PJM to communicate technical changes to members and vendors.
Summer Base Case Study Yields No Reliability Issues
No reliability issues were identified in the 2016 summer base case study.
Off-cost generation re-dispatch and switching was required to control local thermal or voltage violations in some areas.
All voltage violations on networked transmission were controlled by capacitors, and all other such violations were caused by radial load, PJM said.
A March FERC order conditionally accepted SPP’s proposal to distribute to its members $16 million in funds reached in a settlement with MISO over the latter’s use of SPP’s transmission system to transfer power freely between its North and South regions. The order also set the docket for hearing and settlement procedures to resolve factual issues in dispute. (See “MISO Settlement Funds Held Up,” SPP RSC Briefs.)
City Attorney Tom Carr told the council that if the city is unable to come up with a plan that maintains service reliability and competitive customer rates, while also reducing greenhouse gas emissions at the pace mandated by the city charter, he would recommend abandoning municipalization plans.
The Public Service Commission should not spend $21.55 million from the merger agreement between Exelon and Pepco Holdings Inc. in case the decision is returned to the courts, the Office of the People’s Counsel said in a filing last week.
Peoples Gas and parent company Integrys Energy Group will pay customers $18.5 million for allegedly withholding information about its $8 billion program that replaces 2,000 miles of old iron gas mains beneath Chicago streets.
Eversource Energy is predicting an increase in its energy service charge starting in July at the same time that three other state utilities, which purchase power from regional markets, are expecting lower prices.
SolarCity acknowledged it has been subpoenaed in a federal probe of improper lobbying and undisclosed conflicts in state contracts.
At a packed public hearing, the state Energy Facility Siting Board heard opposition to a new $700 million natural gas-fired power plant that would be built in the western part of Burrillville.
The Pierre City Commission last week approved leasing 5 acres at the Pierre Regional Airport to Geronimo Energy in what is expected to be the state’s largest solar energy project.
