PJM will attempt to win stakeholder approval for limited changes to the compensation rules for black start units and a plan for selecting “backstop” resources for regions that fail to secure service through competitive solicitations.
The changes that will be considered by the Markets and Reliability Committee July 31 would make relatively minor changes to compensation rules, allowing:
Compensation for storage of propane and liquefied natural gas. Current rules permit compensation only for oil storage.
Compensation for energy-only resources.
Recovery of the costs of complying with the rules of the North American Electric Reliability Corp. (NERC) for automatic load rejection (ALR) units.
The changes received only 58% support in a poll of the System Restoration Strategy Task Force, well below the two-thirds vote it will need to clear at the MRC.
The task force unanimously approved a second proposal for selecting black start resources for zones that are unable to obtain black start services through PJM’s requests for proposals (RFPs). The “backstop” provision would be triggered by a failure of an RTO-wide RFP and two incremental RFPs. It would apply to zones that cannot be serviced by generation in another zone or through transmission upgrades to improve their cranking path.
Under the proposal, the host transmission owner would be responsible for obtaining black start service either through its generation affiliate or by contracting with a third-party generator. The unit providing black start capability under the scenario would be prevented from offering into the energy or ancillary services markets.
The alternative, explained PJM’s Chantal Hendrzak, “is to wait for another part of the system to come up” to jump start the zone.
Delmarva Power & Light Co. will accept applications for a Solar Renewable Energy Credit (SREC) Spot Market Auction through July 7. SRECs let renewable energy producers sell credits to Delmarva to help it meet its renewable mandates set by the state. Delmarva intends to buy 2,000 to 6,000 SRECs to help it meet its 2013-2014 renewable portfolio standards set by the state.
Public Service Commission staff said Delmarva Power & Light Co.’s planned reliability investments may shoot too high and suggested the company scale back some of the projects.
Delmarva proposed spending $397 million over the next five years upgrading its system and replacing aging infrastructure. But in a recently released report, PSC staff said they found that much of the Delmarva distribution system “is relatively young in terms of asset life” and that the company hadn’t shown “that its customers are dissatisfied with the current level of system reliability.”
The staff thinks Delmarva should limit its five-year investment plan to $200 million “until a more detailed annual review process can be completed.”
Chicago Mayor Rahm Emanuel’s deal with Integrys Energy Services to provide electricity to city homes and businesses could end up costing more than if customers had stayed with Commonwealth Edison, according Crain’s Chicago Business. A credit on ComEd bills for the months of June and July will lower electricity costs to less than 7.1 cents per kilowatt-hour. Prices negotiated for the 720,000 residences and businesses under Emanuel’s deal vary depending upon consumption. Under the Integrys plan, apartment dwellers would pay 8 cents per kilowatt-hour. The average homeowner would pay 9 cents in June and 7.8 cents in July. But the city has said that it could renegotiate terms if power prices turned out to be higher than ComEd’s.
Quinn, Clean Energy Trust Start $4.6 Million Renewable Fund
The Clean Energy Trust and Gov. Pat Quinn last week announced the creation of a revolving equity fund to stimulate investment in clean energy businesses in the state. “Illinois is a national leader in embracing green energy through innovation, and this fund will help us do even more,” Quinn said. The state Department of Commerce and Economic Opportunity is putting up $2.3 million from federal funds, and the Clean Energy Trust is matching that.
The new fund will award convertible notes ranging from $100,000 to $500,000 to startups working on renewable energy, energy efficiency, smart grids or other energy-related projects. Any returns from the resulting projects will be re-invested into additional businesses. A panel of judges will listen to project pitches and award the grants.
The Bowie City Council accepted a $92,000 grant from the Maryland Energy Administration on June 16 to help the city cut energy consumption and to develop a renewable energy policy. The award, part of the Maryland Smart Energy Community program, will help the city develop policies for a 15% cut in energy consumption within five years and meet a goal of using 20% renewable energy for government-owned buildings by 2022.
The state attorney general filed felony racketeering charges last week against Chesapeake Energy Corp. related to what the state says was a fraudulent land lease scheme. Attorney General Bill Schuette said Chesapeake’s leasing agents entered into gas leases with landowners, and then backed out of the leases by falsely claiming that mortgages on the properties were a legitimate basis for cancellation.
Chesapeake, the second-largest natural gas producer in the U.S., allegedly entered into the gas leases in order to keep other gas producers from obtaining drilling rights during the state’s recent fracking boom. Chesapeake spokesman Gordon Pennoyer said all charges facing the company are “baseless allegations” and pledged to battle them in court.
In March, Schuette accused Chesapeake and rival Encana Corp of colluding to keep oil and gas lease prices artificially low in Michigan during the oil and gas rush in its Collingwood Shale region in 2010.
The Board of Public Utilities is considering a change in tax policy that would align the state with most others, to the benefit of utilities. The issue concerns utility holding companies that file consolidated taxes not only for their utilities but also for other unregulated subsidiaries.
Consolidated income tax returns allow members of the company to take advantage of tax losses incurred by other businesses owned by the parent. Under current practice, customers received 100% less certain adjustments, making New Jersey one of only four states that allow losses to be returned to ratepayers.
Under the proposed change, 75% of any savings from consolidated filings would be returned to the companies, with only 25% going to ratepayers. Rate Counsel Director Stefanie Brand, however, is concerned with the proposed change in tax laws. “You want to share more with ratepayers, not less,” she said. “It could be where it’s going to get down to where ratepayers get very little, or nothing.”
Duke Residential Customers to Pay More for Renewables
Duke Energy Progress wants to charge residential customers more for solar and other renewable energy than it would charge business customers, the company told the state Utilities Commission last week. Residential customers currently pay 20 cents per month for renewable energy – primarily from solar farms – but Duke wants to push that up to 83 cents per month beginning in December. The charge goes toward subsidies to independent power producers to cover the higher cost of that type of energy that Duke must buy under state-mandated standards.
While the cost to residential customers would go up under Duke’s plan, the cost to businesses would drop from $8.08 a month to $6.11 a month and from $29.68 a month to $24.56 a month for industrial customers. The cost changes are tied to annual caps set by state law. The annual caps for business and industrial customers stay the same for 2015, but the cap for residential customers will rise from $12 a year to $34 a year.
AEP Energy, American Electric Power’s competitive electric service provider, announced last week that it will begin offering natural gas in the state. AEP joins several other competitive natural gas suppliers in the Columbia Gas of Ohio service territory. “By offering natural gas together with electricity, AEP Energy now can provide Ohio residents with a full-service energy solution,” said Scott Slisher, an AEP executive.
Ohio State University and the engineering firm of Babcock & Wilcox are working together to develop a coal-fired power plant that incorporates carbon-capture technology. Funded by a $2.5 million federal grant, the team is planning to use a chemical process to capture carbon dioxide waste during the combustion process. The university’s College of Engineering has already constructed a pilot plant, which generates about 25 kW of thermal energy. It has already run for 680 hours. The planned unit will produce 550 MW.
Public Utility Commission Chairman Robert F. Powelson was sworn in as president of the Mid-Atlantic Conference of Regulatory Utilities Commissioners last week. “I’m thrilled to expand my role with MACRUC and continue to work toward advancement and uniformity of public utility regulation throughout the Mid-Atlantic region,” Powelson said. Powelson was appointed to the PUC in 2008 by then-Gov. Edward G. Rendell. He also is a member of the Marcellus Shale Advisory Commission and is former president of the Chester County Chamber of Business & Industry.
A former GOP strategist who is facing Sen. Mark Warner in November’s Senate election has proposed an energy plan that would eliminate the recent EPA emissions rules, allow more offshore oil and gas leases and push through the Keystone XL Pipeline, all in the name in economic growth. “Virginia should be a model for the rest of the nation in promoting ‘all-of-the-above’ energy policies,” GOP candidate Ed Gillespie said last week. “Technologies that have enabled the shale gas boom have unleashed enormous possibilities for the future, and the nation is positioned to become energy-independent for the first time ever. All that is lacking is national leadership.”
Shares of NiSource Inc., parent company of Northern Indiana Public Service Co. (NIPSCO), rose 60 cents (1.5%) last week after news that it has been engaged in “soft” merger talks with Dominion Resources. Citing industry sources, The Deal reported that NiSource and Dominion have been talking for months, but that pricing has prevented an agreement. One source said that the two companies have “chatted” but talks have not turned serious and NiSource is not working with a financial adviser.
The report said Duke Energy Corp., Exelon Corp., Southern Co. and American Electric Power Co. have been approached by industry bankers trying to assemble a deal to acquire NiSource. The company owns 15,700 miles of interstate gas pipelines and gas distribution operations in seven states in addition to NIPSCO, which provides power to 450,000 customers in 20 counties in northern Indiana.
Rumors of a NiSource-Dominion deal date back to at least December, when Mergermarket reported that Dominion was attempting to raise more than $10 billion in debt to acquire an unidentified Midwest utility. One analyst said Dominion was NiSource’s most likely acquirer because it is already involved in the interstate pipeline business and is interested in the Marcellus shale play, where NiSource has pipelines and storage.
Operators at PPL’s Susquehanna nuclear generating station shut down Unit 2 last week to check for cracked turbine blades. Equipment that monitors the turbines for excessive vibration indicated that some of the finely balanced turbine blades in the steam generator may have developed small cracks.
“We have been monitoring turbine performance closely for the last several years and continue to work with the manufacturer to address conditions that are associated with cracks developing,” said Timothy S. Rausch, PPL’s chief nuclear officer. “That’s why we decided to shut down Unit 2 now to inspect blades and replace any that are found to have developed cracks.”
Workers replaced turbine blades at Unit 1 during a refueling outage in May. After the Unit 2 inspection, PPL will install new blades during the 2015 refueling outage, Rausch said.
Atlantic City Electric, Union Reach Pact Through 2018
Atlantic City Electric Co. and the International Brotherhood of Electrical Workers Local 210 reached a labor agreement last week that lasts through 2018. Local 1238, which represents workers at the company’s Carneys Point call center, also agreed to extend its collective bargaining agreement to 2020.
Atlantic City Electric’s parent company, Pepco Holdings Inc., announced in April that it was merging with Exelon, who said it will honor all union contracts and not issue any merger-related layoffs for at least two years after the merger.
Two former New York state regulators are opening a public utility consulting firm in Albany, N.Y. Maureen Harris, who served on the New York State Public Service Commission between 2006 and 2013, and Tom Dvorsky, former senior advisor to the commission, call their new firm Claritas Energy Advisors LLC.
Hess Corp. said it is selling its 50% stake in the Newark Energy Center to private equity firm Energy Investors Funds (EIF) for an undisclosed amount. The 705-MW natural gas-fired plant, currently under construction, is slated to go operational in May 2015. The transaction will make EIF the sole owner of the project. The plant is located on a 23-acre brownfield site adjacent to the Hess Newark petroleum storage terminal.
An Indiana developer is building a $7 million, 3-MW plant at a former gravel mine to turn cow manure to power. Brian Furrer said Green Cow Power should be running by September and will be the largest manure-fed power plant in the U.S. “We’re going to use less dirty coal in this country,” Furrer said. “That is just a fundamental fact of life. We’re going to do it through many different mechanisms. This is one mechanism that’s going to help.”
The plant will pump cow manure into tanks, where bacteria breaks it down and generates methane gas to produce power. Leftover solids are reused as bedding for cow barns, while leftover liquids are treated and spread on farm fields. The electricity will be sold to Northern Indiana Public Service Co. (NIPSCO).
The Federal Energy Regulatory Commission gave final approval last week to the first phase of rules to protect the grid from geomagnetic disturbances. It also finalized a standard regarding personnel training opposed by PJM and gave preliminary approval to a standard on capacity modeling.
Geomagnetic Disturbances – EOP-010-1
The commission approved the North American Electric Reliability Corp.’s Reliability Standard EOP-010-1, NERC’s initial response to the commission’s July order calling for rules to close the “reliability gap” regarding geomagnetic disturbances (GMDs) caused by solar events. Geomagnetically induced currents can flow through transformers and transmission lines, leading to increased reactive power consumption and disruptive harmonics that can cause system collapse.
Artist’s depiction of solar winds shaping earth’s magnetosphere. The magnetic field keeps earth’s atmosphere from being blown away by solar wind. But when it is disturbed by solar storms, problems with the electric grid can result. (Source: NASA)
The standard requires reliability coordinators and some transmission operators to institute operational procedures to mitigate the effect of GMDs. The rule applies to transmission with a “transformer with a high side wye-grounded winding with terminal voltage greater than 200 kV.”
FERC approved the rule without changes, rejecting comments by the Foundation for Resilient Societies and others that the rule should apply to transmission operators with systems less than 200 kV. The Foundation noted that during a March 1989 solar storm cited by FERC, utilities reported effects on static VAR compensators and other reactive power equipment operating between 100 kV and 200 kV.
But FERC said that transformers operating at 200 kV or less “are likely to have a limited impact” on the grid during a GMD event.
The commission also rejected criticism from George H. Baker, a U.S. Defense Department consultant on GMD threats, who said the standard will be ineffective. Baker said failures of equipment and disruptions to communications networks will inhibit grid operators’ ability to respond to a GMD event and that they will be reluctant to shed load.
The commission acknowledged that the operational procedures spelled out in this first-stage response “are not a complete solution to the risks posed by a GMD event.
“While we recognize the concerns in the comments of Baker and others regarding the efficacy of operational procedures, Order No. 779 weighed those concerns in ultimately directing NERC to develop operational procedures in the First Stage GMD Reliability Standards and more comprehensive protections in the Second Stage GMD Reliability Standards,” FERC said in its ruling.
In stage two, NERC must determine what severity of GMD will constitute a “benchmark” GMD event. Covered entities will be required to assess the potential impact of such benchmark events on their equipment and systems.
PJM already has GMD operational procedures, which are detailed in section 3.7 of Manual 13.
Personnel Training – PER-005-2
The commission also approved an expansion of NERC’s personnel training standard to include operations support personnel, as well as employees of transmission owners and generator operators who support real-time grid operations (RD14-7).
The new training requirements will apply to:
System operators for reliability coordinators, balancing authorities and transmission operators, defined as “[p]ersonnel, excluding field switching personnel, who can act independently to operate or direct the operation of the Transmission Owner’s Bulk Electric System transmission Facilities in Real-time”;
Operations support personnel for reliability coordinators, balancing authorities and transmission operators, who perform current day or next-day outage coordination or assessments, or who determine system operating limits (SOL), interconnection reliability operating limits (IROL) or operating nomograms in support of real-time operations; and
Dispatch personnel of generator operators at centrally located dispatch centers who receive direction from Reliability Coordinators, Balancing Authorities, Transmission Operators or Transmission Owners.
The revised standard will eliminate a requirement that all system operators receive at least 32 hours of emergency operations training annually regardless of the entity’s characteristics or reliability risk.
Solar wind shapes the planet’s magnetosphere – the region in which charged particles are controlled by the planet’s magnetic field. Bursts of solar wind warp the magnetosphere causing geomagnetic disturbances. (Soure: Wikipedia)
The proposed standard was endorsed by the California ISO, ERCOT, ISO New England, MISO, NYISO and SPP. But PJM called it “an unnecessary and a potentially ineffective means to address an otherwise straightforward requirement; namely to train appropriate personnel.”
PJM said that program accreditation would be more effective because it would place “the emphasis on the training program itself, and associated controls,” rather than on “applicable individuals, their personal training and performance records, individual pieces of training content, and other administrative documentation.”
FERC said an accreditation-based training program is not precluded “as an alternative means of compliance” if it otherwise meets the NERC standard.
Modeling, Data, and Analysis Reliability Standard MOD-001-2
The commission issued a Notice of Proposed Rulemaking (RM14-7) to revise NERC’s standards on the calculation of available transfer capability (ATC) and available flowgate capability (AFC).
ATC and AFC calculations, which dictate the amount of transmission capacity that a transmission service provider will sell to third parties, also raise reliability concerns, the commission noted, because transmission providers need “to know of its neighbors’ system conditions affecting its own ATC values.”
The proposed standard would require documentation of the methodologies for determining ATC and AFC, total transfer capability, total flowgate capacity, capacity benefit margin and transmission reliability margin. It also sets requirements for sharing the methodology and data inputs with registered entities with a “demonstrated reliability need.”
It would also eliminate from current standards requirements that NERC said may be necessary for market or commercial purposes. NERC asked the North American Energy Standards Board (NAESB) to consider whether any of the retired requirements should be incorporated into its Wholesale Electric Quadrant (WEQ) Standards to maintain a non-discriminatory market for transmission service.
Murray Energy, the largest privately owned coal company in the U.S., filed suit last week against the Environmental Protection Agency, seeking to block implementation of the agency’s new carbon emissions rules. “This is clearly an illegal attempt by the Obama EPA to impose irrational and destructive cap-and-tax mandates, which Congress and the American people have consistently rejected,” said Gary M. Broadbent, media director for Murray. The company, based in Ohio, operates 13 mines and employs 7,200 people. Founder Robert Murray has alleged that the EPA is lying about the existence of global warming.
Meanwhile, Idaho Republican Rep. Mike Simpson said that a spending bill being drafted for the EPA and the Department of the Interior could provide a way to hobble implementation of the rules. Rep. Ken Calvert (R) of California also indicated a willingness to look at possible legislation to block the rules.
Rep. Kevin McCarthy
New House Majority Leader Kevin McCarthy of California also vowed to stop the EPA rules. “We have legislation moving here from appropriations and others that we do a lot of our different riders on,” McCarthy said. “That becomes some of the most effective areas to combat it.”
A new Wall Street Journal/NBC News poll shows that two-thirds of Americans support President Obama’s climate initiative, with more than half saying they’re willing to pay higher electric bills to help reduce global warming. The EPA’s new emissions rules brought support from 67% of respondents, with 29% in opposition. The poll also found that 61% of Americans believe climate change is happening, an increase from 54% five years ago.
High Court Upholds EPA GHG Standard, with Some Limits
The Supreme Court yesterday largely approved the Environmental Protection Agency’s authority to regulate greenhouse gas emissions from power plants, while criticizing what it called the agency’s overreaching.
“EPA is getting almost everything it wanted in this case,” Justice Antonin Scalia said. “It sought to regulate sources it said were responsible for 86% of all the greenhouse gases emitted from stationary sources nationwide. Under our holdings, EPA will be able to regulate sources responsible for 83% of those emissions.”
Scalia said the agency was free to do so as long as the sources in question “would need permits based on their emissions of more conventional pollutants.”
The court’s ruling was on the EPA’s regulations of new power plants. It did not directly affect the agency’s June 2 rulemaking, which concerns existing plants.
Sempra Energy Louisiana facility to be converted for LNG exports (Source: Sempra Energy)
The Federal Energy Regulatory Commission last week approved Sempra Energy Corp.’s plan for a liquefied natural gas export facility in Cameron Parish, La. The commission also approved necessary pipeline and compression facilities for the project. Cameron plans to export up to 14.95 million metric tons of gas per year. When completed, the plant would also be able to import LNG and regasify it for domestic use. The first phase of the project is planned for a 2017 completion, with the final two phases to be completed the following year.
The Cameron project is the second LNG export terminal approved by FERC, following the agency’s OK of the Sabine Pass Liquefaction Project in April 2012. Sabine Pass’s request to expand the project is among 12 LNG export proposals pending before the commission.
A group of environmental organizations called for the immediate resignation of Nuclear Regulatory Commission Commissioner William Magwood, saying he “fatally compromised” his position as a safety regulator when he applied for a new job as director-general with the Organisation for Economic Co-Operation and Development’s Nuclear Energy Agency in Paris.
A group of 34 environmental organizations, including the Sierra Club and Friends of the Earth, said Magwood should have recused himself from any NRC safety decisions when he decided to seek his new position.
The NEA identifies its mission as assisting member countries developing nuclear energy for peaceful purposes. Magwood announced he would leave the NRC for the NEA in September.
The Federal Energy Regulatory Commission last week rejected a request to hold a technical conference to review the impact of the commission’s November 2013 order allowing the sharing of non-public operational information between interstate gas pipelines and electric transmission providers.
The commission said (RM13-17-001) that while it invites feedback on the effectiveness of the new communications standards in Order 787, there was no need for a technical conference requested by the Natural Gas Supply Association (NGSA).
FERC also rejected a request by Enable Gas Transmission LLC and Enable Mississippi River Transmission LLC to revise Order 787’s no-conduit rule, which prohibits recipients of non-public operational information from disclosing the information to a third party.
Order 787 allows interstate pipelines such as Enable to seek a waiver of the no-conduit rule if the fact that they share operational employees with local distribution companies (LDCs) or other affiliates makes compliance difficult.
Enable said that under the pre-Order 787 rules, employees its interstate pipelines share with their intrastate and gathering affiliates were already being exposed to sensitive non-public, operational information as part of their regular activities without ill-effect. Enable asked the commission to revise the rule to allow disclosures to third parties, other than marketing function employees, for reliability and planning.
But the commission ruled that “rather than attempting to craft a generic regulation, the best course would be to proceed on an individual case-by-case basis through waivers.” The commission noted that it had received only three waiver requests to date and had granted all of them (the Enable pipelines, National Fuel Gas Supply Corp. and Empire Pipeline Inc.).
“As demonstrated by these orders, we find that the waiver process is a reasonable means … to address compliance issues involving shared employees,” the commission said.
Enable’s waiver order (RP14-453) allows employees shared by Enable pipelines and their affiliated intrastate and gathering systems to receive non-public operational information as long as they don’t take part in marketing functions or share it with workers in those functions.
The California ISO won approval last week to expand its real-time energy imbalance market (EIM) beyond state borders, with PacifiCorp and NV Energy slated to become the first to join.
With the Federal Energy Regulatory Commission’s approval of CAISO’s proposal (ER14-1386) and related PacifiCorp Tariff changes (ER14-1578), the expanded market is set to begin Oct. 1. NV Energy, which sits between PacifiCorp’s two main service regions, plans to join the market by October 2015 under an implementation agreement approved by FERC earlier this month (ER14-1729).
PacifiCorp and NV Energy say they expect economic efficiencies, improved renewable integration and increased reliability from their collaboration with CAISO. With the expansion, the EIM would serve most of Nevada, Utah and Wyoming, along with California and portions of Washington, Oregon and Idaho.
That has some in the West asking the question: Will CAISO’s expanded footprint grow into something more than a simple imbalance market?
Not an ‘RTO West’
FERC Commissioner John Norris said last week the market could bring “a lot of efficiencies” to the 38 independently operated balancing authorities in the western interconnection. But he hastened to add, “This isn’t an effort to push those balancing areas into an ‘RTO West.’”
Indeed, CAISO will not assume operational control over the generation or transmission facilities of PacifiCorp. The utility will also remain responsible for maintaining its reliability, including meeting operating reserve and capacity requirements; scheduling; curtailing transmission; and manually dispatching resources out-of-market to maintain reliability. The company is not planning to join CAISO as a member or to participate in its ancillary service and day-ahead energy markets. There will be no exit fee for EIM participants that leave the market.
But the American Public Power Association is worried nonetheless that CAISO’s market may “morph into a regional transmission organization.”
APPA says RTOs have not lived up to their promises of reducing costs. Instead, the group says, they have created higher profits for merchant generators and high administrative and operational costs for consumers.
‘Scope Creep’
“Scope creep” is the concern of public power members, said Elise Caplan, manager of APPA’s Electric Market Reform Initiative, in an interview yesterday. While the imbalance market itself is not problematic, Caplan said the concern is that the scope would grow to include financial transmission rights and mandatory capacity markets, “which have given our members a lot of headaches.
“Our concern is you start with an EIM and that’s where you get to,” she said.
FERC’s actions, such as the April 2011 orders that took away the self-supply exemption, “makes a lot of our members nervous that they will lose their jurisdiction over what that market looks like,” she added.
NWPP Initiative
Caplan said no APPA members are considering joining the CAISO market, although some are participating in discussions to create an EIM with the Northwest Power Pool (NWPP). “They’re looking at doing their own thing,” including ways to “wall it off” from FERC jurisdiction, Caplan said.
NWPP issued a study last year finding the benefits of an EIM outweighing costs and that no Northwest entity, including the Bonneville Power Administration, would be a net loser. The power pool is currently researching the cost of implementing security constrained economic dispatch (SCED).
Among those in discussions with NWPP is the Western Area Power Administration (WAPA), which serves 15 states in the central and western U.S. with power from 56 hydropower plants operated by federal agencies.
WAPA decided not to join the CAISO market following a study by the Argonne National Laboratory, which concluded it was not well suited for the EIM, in part because federal resources are contractually committed to customers and because water delivery obligations and environmental operating limits reduce WAPA’s ability to respond to market price signals. The study also predicted high startup costs.
“At this time it doesn’t make economic sense to join that market,” WAPA spokesman Randy Wilkerson said.
WAPA-SPP
However, WAPA’s Upper Great Plains region, which sells power in Iowa, Minnesota, Montana, Nebraska and the Dakotas, is planning to join the Southwest Power Pool. SPP’s board last week approved Tariff revisions to accommodate WAPA’s entry, which is projected to be complete in October 2015.
Heartland Consumers Power District and Basin Electric Power Cooperative also are joining SPP.
WAPA’s facilities in the Eastern Interconnection will be fully integrated with SPP, which launched its Integrated Market March 1. The Integrated Market added a day-ahead market and transmission congestion rights to SPP’s real-time imbalance function. Facilities in the Western Interconnection “wouldn’t be fully integrated, at least at the start,” Wilkerson said.
The Argonne study found that while the CAISO EIM was not a good fit for WAPA, it could benefit entities inside WAPA’s balancing areas (BAs) that have flexible resources or excess capacity for bidding into the market, including those with variable energy resources and those that frequently run high-cost peaking resources. Thus, the study said, there was a risk of a “reshuffling of entities within BAs” regardless of whether WAPA joins or not.
Scope
California’s EIM will allow participants to buy and sell energy in five-minute increments. Supporters say the market will improve congestion management and situational awareness as well as reduce the costs of balancing the increasing volume of variable resources in the West. The Western Electricity Coordinating Council estimates renewable energy will more than double from 2010 levels by 2022.
PacifiCorp and CAISO conducted a study that projects annual consumer benefits of $21 million to $129 million from the EIM. Start-up costs for PacifiCorp will be $2.1 million.
PacifiCorp serves about 1.8 million customers in two BAs: PacifiCorp East (Idaho, Utah and Wyoming) and PacifiCorp West (Washington, Oregon and California). NV Energy, the product of the 1999 merger of Nevada Power Co. and Sierra Pacific Power Co., provides electricity and natural gas to 1.3 million customers in Nevada. NV Energy was acquired by PacifiCorp’s parent, Berkshire Hathaway Energy, last year.
Market Explained
FERC’s unanimous orders last week modified some aspects of CAISO’s and PacifiCorp’s proposals. The commission rejected CAISO’s proposal that its Board of Governors would decide whether to implement market power mitigation at the interties, saying any such mitigation would be subject to commission approval. The commission also ordered CAISO to make informational filings on the presence of structural market power in PacifiCorp BAs due to intertie transmission limits.
The order also requires the ISO to create a mechanism for EIM resources to avoid being dispatched into California, where they would be liable for the state’s greenhouse gas regulation costs.
PacifiCorp’s transmission customers will have the option of bidding into the EIM or continuing to serve their loads through self-supply or bilateral trades.
Transmission and generator interconnection customers who do not participate in the EIM will be billed based on the locational marginal prices resulting from the EIM to settle imbalances.
PacifiCorp will use firm transmission rights voluntarily offered by transmission customers to enable EIM transfers between its BAs and CAISO.
The commission rejected PacifiCorp’s proposal to require generating resources in the company’s BAs to purchase additional transmission service from PacifiCorp in order to participate in the EIM, saying this would result in a double-charge to loads and conflict with CAISO’s proposal to use reciprocal transmission rates.
Pepco Atlantic City District Energy System (Source: Pepco)
Pepco’s Midtown Thermal Control Center, which provides heating, cooling and electricity to some of Atlantic City’s biggest casino-hotels, was awarded the International District Energy Association’s Annual Innovation Award. The 16,200-ton multiple-chiller district cooling plant cuts energy consumption while providing essential climate control services to casino-hotels such as the Trump Plaza, Caesar’s Palace and the Atlantic City Convention Hall.
The $106 million facility produces 54,000 tons of cooling, 700,000 pounds per hour of heating and 5.7 MW of generation. It has a central generating station and several satellite generators; five miles of steam, chilled water and condensate piping; and a fiber-optic control system. The center has shown energy savings of 30% for its clients since going into operation in October.
Exelon, Pepco Continue Regulatory Approval Process
Exelon and Pepco Holdings Inc. filed applications with regulatory agencies in Delaware, New Jersey and the District of Columbia, continuing the approval process for Exelon’s purchase of the D.C.-based utility. “The filings we are making today describe in detail how our proposed merger will serve the public interest,” Chris Crane, Exelon president and CEO, said last week.
Crane said Exelon’s emergency-response experience will improve service for Pepco customers, who have long complained about their utility company’s long restoration times and regular rate hikes. Crane promised Exelon will set, and meet, tougher reliability targets by 2020 if the deal is approved. Exelon announced its proposed purchase of Pepco for $6.8 billion in May. The company has already filed an application with the Virginia State Corporation Commission and plans to file with the Maryland Public Service Commission in August.
Huntoon Hangs Shingle as Regulatory Law Specialist
Steve Huntoon
Steve Huntoon, who spent the past three decades practicing energy regulatory law with companies such as PECO, Florida Power & Light Co., Dynegy and Conectiv, has opened his own law firm in the District of Columbia. Energy Counsel LLP will specialize in energy regulatory issues, especially those before the Federal Energy Regulatory Commission. Huntoon is the former president of the Energy Bar Association. Most recently he was senior attorney at Florida Power & Light Co.
A bill mandating the closure of all 33 of Duke Energy’s ash ponds cleared three North Carolina committees last week and could come to a vote on the Senate floor this week. The bill calls for full coal ash removal at four power plants near waterways: Riverbend, near Charlotte; Dan River, scene of the massive coal ash spill in February; Asheville; and Sutton in Wilmington.The remainder of Duke’s coal ash ponds would be closed after a prioritization review by a new, nine-member Coal Ash Management Commission. The bill requires Duke to pay all cleanup costs and levies a new regulatory fee that would go toward hiring 25 more employees for the state Department of Energy and Natural Resources.North Carolina officials also warned Duke Energy last week to fix what it said were “numerous gushers, drips and stains” at a coal ash dam at its Weatherspoon plant in Lumberton. State Attorney General Roy Cooper said last week that lawmakers should ensure that the costs for cleaning up coal ash ponds are borne by Duke, not the public.
NextEra Energy Inc.’s wholly owned subsidiary, NextEra Energy Partners LP, announced terms of its initial public offering. The company, which will operate 10 wind and solar energy projects, wants to raise $325 million by offering 16.3 million shares of stock at a price of $19 to $21.
Power sellers in PJM and other RTOs and ISOs will no longer have to submit market power screens under proposed changes to the Federal Energy Regulatory Commission’s market-based rate (MBR) regulations.
The change is one of dozens included in FERC’s first major overhaul of the MBR rules since their creation in 2007.
The commission’s Notice of Proposed Rulemaking (RM14-14) would streamline several MBR rules while adding some new requirements. FERC said current rules create some paperwork burdens that outweigh their benefits.
Here’s a guide to what’s in the 143-page NOPR, including applicable paragraph numbers.
What’s Added
Rows to the indicative screen format for sellers to specify simultaneous transmission import limit (SIL) values as well as long-term firm purchases and remote capacity from outside the study area. Screens must be filed in “a workable electronic spreadsheet format.” (paragraph 13)
Solar to the definition of energy-limited generation resources, which use a five-year average capacity factor. Resources that do not have five years of historical data may use regional capacity factor estimates from the Energy Information Administration (EIA). (15)
A redefinition of uncommitted capacity to include all long-term firm purchases of capacity or energy in their indicative screens and asset appendices, regardless of whether the seller has operational control over the generation capacity supplying the purchased power. FERC said the change will help size the market correctly and will establish consistent treatment of long-term firm transactions. (16)
A provision that asset appendices must be in an electronic spreadsheet format. Some headings will be changed for clarity. Some filing instructions are changed. (19)
A requirement that sellers provide an organizational chart as descriptions of their affiliates and upstream owners when filing initial applications, updated market power analyses and notices of change in status involving new affiliations. The chart would be similar to that required from applicants under section 203 of the Federal Power Act. (22)
What’s Subtracted
The requirement that MBR sellers in RTOs, who use FERC-approved monitoring and mitigation, submit market power screens. (11)
The requirement that generation owners submit indicative screens if all of the capacity owned or controlled by them and their affiliates in a balancing authority area is fully committed. (11)
The requirement that MBR sellers file quarterly land acquisition reports and provide information on their control of sites for development of new generation capacity. (17)
The requirement that changes in status below a 100-MW threshold have to be reported. Going forward, long-term firm purchases of capacity or energy will be included in the calculation. (18)
What Else is Changed
Broadens the default geographic market for independent power producers (IPPs) with generation capacity located in a generation-only balancing authority area (BAA). Instead of being limited to the home balancing authority area, the IPP’s default market would include all balancing authority areas directly interconnected to the IPP’s home BAA. (12)
Provides an updated region map and three-year filing schedule for market power analyses from Category 2 sellers. (20)
Adds a distinction between power marketers (which should include all affiliated generation in a region) and power producers (which would include only affiliated generation capacity that is located in the same region as the power producer’s generation assets) for the determination of seller category. FERC is proposing the change “based on the fact that a power marketer is assumed to have no home market, while it is assumed that a majority of a power producer’s sales will be in market(s) in which it owns generation assets.” (21)
Sellers should include all load associated with the balancing authority area(s) within the study area, including non-affiliated load in Submittal 1. Row 8 will be amended to read “Adjusted Historical Peak Load.”
Submittal 1 requires sellers to use FERC Form No. 714 load values or explain the source of the data used. FERC is seeking comment on the appropriate source of historical peak load data. (26)
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will vote on endorsing revisions to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements that incorporate requirements for installation of SynchroPhasor Measurement Units (“PMU”) at new generation interconnections. Related Tariff changes were approved by members last June and approved by the Federal Energy Regulatory Commission in February. The requirements apply to interconnection customers entering the new services queue on or after Oct. 1, 2012 with facilities with a maximum output of 100 MW or greater. (See Members Approve PMU Requirement.)
Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements and Manual 14D: Generator Operational Requirements governing rules for members wishing to purchase access to the PJMNet data feed. (See Final OK for Membership Inquiry, PJMNet.)
3. Designated Entity and Interconnection Coordination Agreements (9:30-9:45)
Members will be asked to approve the proposed Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA) developed by the Regional Planning Process Task Force (RPPTF).
The documents define the duties, accountabilities and obligations of companies designated to build and operate transmission projects awarded under the competitive rules of FERC Order 1000. They include project scope, planning criteria, development schedules, project milestones and terms and conditions. The committee will also be asked to sunset the RPPTF.
FERC ordered PJM to file the DEA for commission approval by July 14. (See: 147 FERC ¶61,128).
4. MOPR Unit Specific Review (9:45-10:00)
PJM’s chief economist Paul Sotkiewicz will seek MRC approval for a joint PJM-Independent Market Monitor proposal to improve unit-specific reviews under the Minimum Offer Price Rule (MOPR). The proposal is intended to develop more standardized assumptions and reduce PJM-IMM discretion. It would require use of nominal levelized values, a 20-year asset life and a residual value of zero. It would also bar inclusion of sunk costs.
The proposal received the support of 72% of participants in a poll by the Capacity Senior Task Force. An alternative by PSEG Energy Resources & Trade won 64% support and may be brought to a vote if the PJM-IMM proposal fails. PSEG says it would use the best available evidence of the developer’s costs, while the PJM-IMM proposal would provide developers incentives to understate costs. The PSEG proposal also makes the main cost element publicly available, unlike the PJM-IMM plan, under which key cost items are confidential and cannot be challenged by other stakeholders. (See comparison in MOPR Unit Specific Review Matrix.)
5. RPM Supply Curve Transparency (10:00-10:15)
The MRC will vote on a proposal supported by Exelon and opposed by the Market Monitor to create more informative supply curves from capacity auctions. The measure was approved by the Market Implementation Committee with only 54% support, short of the two-thirds sector-weighted vote it will need to clear the MRC.
Stakeholders had approved a problem statement by Exelon on the issue without opposition last June. But support for the change eroded after Market Monitor Joe Bowring signaled his opposition, saying it could reveal sensitive data about price-quantity offers and cause collusion among generators. Load representatives opposing the change cited Bowring’s concerns and news reports indicating Exelon had helped boost clearing prices in the May auction by offering 4,255 MW of nuclear capacity at the maximum price allowed. (See Load Balks at Supply Curve Fix in Response to Auction Strategies.)
PJM’s Becky Carroll will ask for MRC approval to proceed with implementation of the new Coordinated Transaction Schedule (CTS) product for trading between PJM and the New York ISO. CTS, which is intended to reduce uneconomic power flows between the two regions, could be implemented as soon as November if the MRC votes to endorse the accuracy of the scheduling tool that would be used to optimize the cross-border transactions. PJM officials told members in March that the Intermediate Term Security Constrained Economic Dispatch (IT SCED) tool is accurate within $5/MWh more than two-thirds of the time. (See PJM Price Forecasts: Close Enough for Power Trading?)
7. TO Data Feed (10:30-10:45)
The committee will be asked to approve a revised issue charge for the Transmission Owner Data Feed Task Force (TODFTF) to include consideration of generator real-time reactive capability data. Members approved creation of the task force in April to consider an easier method for transmission owners to access real-time generator data, an effort intended to improve situational awareness and emergency response.
During initial task force discussions, stakeholders shared concerns about TOs having access to generator-characteristic data in addition to real-time telemetry. Exelon responded that generator real-time reactive capability data is necessary for accurate state estimator and contingency analyses. Exelon will present the revised issue charge. (See Members to Consider Easier Sharing of Real-Time Generator Data.)
8. Cost Development Subcommittee (CDS) Sunset (10:45-11:00)
The committee will be asked to sunset the subcommittee, which was created in 2011 to develop standard procedures for calculating the costs of products or services provided to PJM when those products or services are required to be provided at a cost-based rate.
9. FTR/ARR Senior Task Force (FTRSTF) (11:00-11:15)
The MRC will be asked to approve the proposed FTRSTF charter. The MRC approved the creation of the task force in May to determine the causes of financial transmission rights underfunding and whether changes to current FTR and auction revenue rights (ARR) processes could improve funding levels. (See New Task Force to Target FTR Underfunding.)
10. Cap Review Senior Task Force (CRSTF) (11:15-11:30)
3. Regional Planning Process Senior Task force (RPPTF) (1:25-1:40)
Members will be asked for approval of Operating Agreement (OA) and Tariff revisions governing multi-driver transmission projects, which are intended to lower costs for public policy transmission projects under FERC Order 1000. (See States Still Miffed with TOs’ `Multi-Driver’ Cost Allocation.)
4. Designated Entity and Interconnection Coordination Agreements (1:40-2:00)
The MC will vote on the proposed Designated Entity Agreement (DEA) and Interconnection Coordination Agreement (ICA). See MRC item #3 above.
5. Frequently Mitigated Unit Adders (2:00-2:15)
The committee will be asked to approve a joint proposal from PJM and the Independent Market Monitor to reduce payments to frequently mitigated units (FMUs). The Tariff changes were approved by the MRC in May. (See PJM-IMM Limits on FMU Adders Prevail.)
6. Operating Agreement Errata (2:15-2:20)
Members will be asked to revise OA Schedule 11 to correct a typo that refers to “Section 16” as “schedule 16.”
