The Coalition of MISO Transmission Customers (CMTC) has asked the Federal Energy Regulatory Commission to reconsider its approval of a 50-basis-point incentive adder for MISO membership.
FERC conditionally approved the adder last month, saying that the resulting base return on equity must be in the zone of reasonableness — 7.03 to 11.74%. The commission said that industrial customers, including the CMTC, had failed to provide sufficient evidence for their argument that TOs did not need an incentive to remain in the RTO. (See MISO TOs Can Collect Membership Adder — Once Base ROE is Found Just.)
In its rehearing request, the coalition said that FERC’s ruling violated Section 205 of the Federal Power Act, which holds that the burden of proof in a ROE-related filing falls on the filers, not the complainants. FERC “not only failed to hold the MISO [transmission owners] accountable for demonstrating that the RTO adder in this case is just and reasonable, but also effectively, and erroneously, shifted the burden onto protestors to show that the RTO adder is unjust and unreasonable,” the coalition said (ER15-358).
MISO TOs requested the adder last November. Industrials criticized the adder as an attempt to hedge against a potential decrease in the TOs’ base return on equity, which industrials have contended is too high. Settlement talks between the TOs and industrials broke down in December.
MISO planners recommended Wednesday that Entergy’s request for a $187 million transmission upgrade near Lake Charles, La., be sent up the line for consideration by the RTO’s board, despite continued objections from transmission developers.
“I know there are some contentious issues around this,” Jeff Webb, MISO’s director of planning, acknowledged shortly after opening a discussion of the project at a meeting of the South Technical Study Task Force in Metairie, La.
On Dec. 15, Entergy Gulf States Louisiana filed an out-of-cycle request with MISO, saying the need for the transmission upgrade was identified on Dec. 1. Entergy told MISO that increased industrial demand for power requires it complete the Lake Charles project by June 2018.
The company requested that the project be treated as an out-of-cycle project outside of the usual MISO Transmission Expansion Planning (MTEP) process and the competitive solicitation rules under the Federal Energy Regulatory Commission’s Order 1000.
At MISO’s Planning Advisory Committee meeting Jan. 28, transmission developers questioned the timing and motives behind Entergy’s request, which would deny them a chance to compete for the project. (See Entergy Out-of-Cycle Transmission Request Draws Competitors’ Ire.)
Webb started last week’s meeting by spending more than 30 minutes explaining MISO’s transmission planning rules, which limit out-of-cycle requests to reliability projects identified after the submittal cutoff date of the prior annual MTEP cycle with a need date within three years of the request date and expected in-service date within four years.
“We see the [Lake Charles] projects as fitting [the out-of-cycle] requirements,” Webb said.
Stakeholders Dubious
But, as during last month’s PAC meeting, stakeholders questioned how Entergy could only recently decide it needed the project and whether it needed to be done on a fast-track outside the MTEP.
A representative of NRG Energy asked Webb whether MISO had done any due diligence or simply took Entergy’s word “at face value.”
MISO officials replied that they are aware of substantial growth in the Gulf Coast region and that Entergy’s Module E load forecast data was consistent with the amount of load growth that’s been represented in the Lake Charles project. It would include two new substations, expansion of another and 25 miles of 500-kV and 230-kV transmission.
Edin Habibovic, manager of expansion planning at MISO, said that between MTEP 14 and MTEP 15, an additional 617 MW of growth was identified. Without upgrades, the increased loads could result in North American Electric Reliability Corp. violations due to overloaded transmission lines and voltage issues, Habibovic said.
George Dawe, vice president of Duke American Transmission, said evidence provided by Entergy amounts to anecdotal information.
“In our view, what’s the urgent need? I don’t see it anywhere. … It’s not a baseline reliability project,” Dawe said.
MISO officials said they have talked with Entergy’s industrial load customers, but that the customers haven’t been transparent about the timing of their power needs. Habibovic said obtaining detailed demand information from individual industrial companies is challenging in part, because they often make decisions at the last minute.
That wasn’t good enough for Dawe.
“A normal planning process has been thrown out the window,” he said. “It’s not a defined new load addition. It speculates on future economic development.”
Webb replied that if MISO ran the proposed project through the developer selection process, it would not meet Entergy’s deadline.
“We can’t risk going through that process and speculate that Entergy is wrong here — that the process could be done in two years versus two and a half years.”
MISO will not let the planning process stand in the way of needed transmission, he added, saying that’s why FERC allows exceptions to the competitive process under Order 1000.
No Attractive Alternatives
Habibovic said MISO has looked at alternatives to Entergy’s proposal to meet the increased demand, including routing power from Beaumont, 35 miles to the west in Texas, and from Lafayette, 50 miles to the east. Also modeled was an update of existing 230-kV lines.
He said the alternatives presented a number of problems, including reliability issues during construction, right-of-way challenges and high-impedance issues.
Kip Fox, director of transmission strategy and grid development at American Electric Power, asked if MISO reviewed recent public filings of electric customers who have deferred plant expansions. Other stakeholders cited reports that the drop in petroleum prices has put some liquefied natural gas projects in the Gulf region in limbo.
An Entergy representative replied that the timing of plant expansions can be volatile. Even if industrials delay a project, the need often resurfaces within a few years’ time, he said.
Cost-Overrun Concerns
Stakeholders also asked whether MISO had conducted due diligence on Entergy’s estimated costs for the project, questioning whether the $187 million price tag may grow.
Webb responded that most state regulatory agencies have provisions to deal with cost escalation and require utilities to justify overruns.
Board Consideration
Entergy’s out-of-cycle request will be discussed again at MISO’s Feb. 18 PAC meeting. It would then proceed to the System Planning Committee of the Board of Directors, likely in March, with potential consideration by the full board in April.
Overshadowed at the Metairie task force meeting by the Lake Charles discussion was a recommendation to approve five other out-of-cycle projects in the region, the largest at $10.3 million.
VALLEY FORGE, Pa. — PJM is developing design, engineering and construction standards for non-incumbent transmission developers who can win “designated entity” status under the Federal Energy Regulatory Commission’s Order 1000.
PJM’s Suzanne Glatz told Thursday’s Planning Committee meeting that the RTO is seeking a balance between “innovative designs” and reliability. Greenfield projects would not have to conform to an incumbent transmission owner’s design standards but would have to meet reliability standards.
A non-incumbent could reference standards filed in FERC Form 715 for other jurisdictions, adhere to standards approved by PJM’s Transmission and Substation Subcommittee or win the subcommittee’s approval for the developer’s own standards.
Voltage Floor Among Changes to Improve Order 1000 Process
PJM is considering changes to improve the Order 1000 process and expects to present a problem statement to the Planning Committee after its fourth and final “lessons learned” conference call on the issue Feb. 27.
One possible change would exempt projects below 200 kV from the competitive process.
Improvements already underway include the use of webcasting, development of a new tool to permit the secure exchange of large files and process improvements to gain access to annual transmission planning and evaluation reports.
Light-Load Study: Generation Up, Load Down
PJM is considering changes to the assumptions it uses for modeling light-load conditions in transmission planning.
“We want to determine whether the assumptions we made four years ago should be revisited,” PJM’s Mark Sims said. “We have a lot more wind now. We have a lot more data.”
An analysis of light-load historical data confirmed that the windiest hours continue to be 1 to 5 a.m. November through April — a time when load often is less than the assumed 50% of the summer peak.
Meanwhile, wind generation often exceeds the 80% capacity factor assumed in the modeling.
Planners will discuss potential changes with stakeholders in March.
DR Assumption Model to Change
PJM is proposing to change the way it models demand response in planning studies to reflect the amount of DR that is replaced by other resources before the delivery year.
Currently, the model relies on the amount of DR that clears the Base Residual Auction and any Incremental Auctions for a delivery year. That amount is held constant for all future years.
One alternative PJM is considering would reduce DR by the lesser of either the locational deliverability area’s existing uncleared generation for the delivery year, or a rolling three-year average of the amount of DR replaced by other resources RTO-wide.
The three-year rolling average ending June 1, 2014, showed about 34% of DR was replaced RTO-wide.
VALLEY FORGE, Pa. — Software problems have led PJM to delay implementation of an eMKT tool allowing gas-fired generators to make intraday changes in price schedules, Chantal Hendrzak, PJM general manager of Applied Solutions, told the Operating Committee last week.
The optional system, called the Intraday Cost Schedule Update, had been set to go live Feb. 9. It is now expected to go into production Feb. 23. The changes, intended to more accurately reflect the cost of generation, will allow users to file a different cost schedule for each hour every day, not just during cold weather alerts.
Implementation was delayed in part because of coding that required members to upload fuel information with every single entry. That is being changed so members will be able to download all fuel types and upload them in XML.
Once the update is functional, the previous manual process will no longer be supported.
Additionally, fuel data enhancements in eMKT were scheduled to be introduced to the eMKT “sandbox” for testing Feb. 13. Beginning April 1, all members will be required to supply energy fuel type and subtype, as well as startup fuel type and subtype, in order for their offers to be accepted — regardless of whether the generator plans to make intraday price changes.
January Operations Show Improvement
A report on last month’s operations showed that the forced outage rate was much lower than in January 2014, with outages peaking at 10% during an RTO-wide cold weather alert Jan. 7-8.
Gas problems were responsible for about half of the 18,861 MW that failed to operate during the morning peak on Jan. 8 and the 13,481 that faltered on the evening of Jan. 7.
The preliminary reported load for Jan. 8 was 136,669 MW, the fifth-highest winter peak on record. Jan. 7 saw the seventh-highest peak at 136,119 MW.
No units changed their costs intraday during the cold weather alert.
Wind generation during the cold weather event also was good, at 2,500 to 5,300 MW during peak hours.
Cold Weather Preparation Test Fails 10 Generators
PJM tested 168 generators in December and January, and all but 10 were successful.
In all, 443 units were eligible to participate in the exercise. Of those that did, 26 experienced initial failures. In a retest, 16 succeeded.
The largest cause of failure, at 31%, was liquid fuel handling problems, followed by cranking diesel failure and circuit breaker issues, each accounting for 15% of the total. Control system problems made up 12%. The remaining 27% of failures were chalked up to miscellaneous reasons, such as generator instrumentation issues and excessive vibration.
The participating units experienced a significantly lower percentage of forced outages in the first week of January compared with units that either declined or were not eligible to take part.
The cost of the winter testing came to $4.88 million.
Sought: Ways to Incent Training, Certification Compliance
Some PJM generation operators are guilty of “chronic non-compliance” with training and certification requirements, PJM told members.
While non-compliant companies are supposed to submit mitigation plans, many have not, and there are no financial penalties for failing to do so.
PJM officials asked the Operating Committee to consider whether the RTO should impose financial penalties or deny offenders access to PJM markets and tools.
Transmission operators generally are in compliance, officials said.
System Restoration Coordinators Task Force Becomes Subcommittee
Members approved a charter change upgrading system restoration coordinators from a task force to a subcommittee.
The change was made because task forces are supposed to sunset. The subcommittee will report to the Operating Committee.
VALLEY FORGE, Pa. — PJM’s plan to change the definition of the IMO interface with Ontario’s Independent Electricity System Operator received a lukewarm review from Market Monitor Joe Bowring, who said it would not correct what he has called “sham scheduling.”
“We think it’s an improvement. We don’t think it resolves it,” Bowring told the Market Implementation Committee last week, saying he would determine its effectiveness by the prices that result.
In 2013, the MIC approved Bowring’s request to investigate whether traders could be manipulating PJM’s interface pricing points by breaking schedules into multiple “back-to-back” transactions. (See MIC to Probe ‘Sham Scheduling’.)
In the 2012 State of the Market report, the monitor described the practice as “sham scheduling,” in which he said traders were hiding the actual source of generation. PJM prices transactions with external balancing authorities based on the source and sink identified on the North American Electric Reliability Corp. eTag. Breaking the transaction into portions with separate eTags can lead to loop flows and incorrect pricing.
The IMO interface pricing point was created because transactions that originate or sink in Ontario IESO balancing authority create flows that are split between the MISO and NYISO interface pricing points. The Monitor wants PJM to eliminate the IMO pricing point and assign transactions that originate or sink in IESO to the MISO interface pricing point.
Bowring said that he may recommend banning some transmission paths to prevent the abuse, as NYISO did in 2008 (ER08-1281).
New Definition
PJM’s new definition recognizes that flows from transactions scheduled between IESO and PJM are affected by the performance of the Michigan-Ontario phase angle regulators (PARs).
Because actual flows are not known in advance, the price will reflect historical flows over the PARs, using an average price split weighted with 40% NYISO and 60% MISO.
The new definition, which will be effective with the new planning year beginning June 1, will be used in both the annual financial transmission rights auctions and auction revenue rights allocations.
In addition, a new aggregate, named “ONTARIO,” will be created that maintains the current IMO definition in order to eliminate impacts to long-term FTR positions. It will be defined as 100% of the BRUCEA 17-kV pnode. It will also become effective June 1.
PJM says critics of its requests to safeguard capacity for the 2015/16 delivery year ignored the context of its filings with the Federal Energy Regulatory Commission.
Fearing that it might run short due to retirements of coal-fired generation, PJM asked for a one-time waiver on rules that would otherwise require it to release 2,000 MW of capacity in the Feb. 23 third Incremental Auction for 2015/16 (ER15-738). Dominion Resources called the filing “premature and speculative.” (See PJM Capacity Release Filings Draw Critics.)
PJM countered that “Dominion ignores the resource adequacy planning context of PJM’s request. By its very nature, planning is forward-looking and prudently anticipates a variety of possible conditions and scenarios. Dominion’s argument is comparable to contending that the possibility that loads could substantially exceed forecast levels this summer is ‘premature and speculative;’ or that the possibility that forced generation outages could greatly exceed average levels next winter is ‘premature and speculative.’”
PJM also dismissed arguments that the 2,000-MW figure was too broad, saying that it is barely more than 1% of the resources committed in the Base Residual Auction for this delivery year.
PJM also proposed revising its Tariff to allow it to enter into capacity agreements made outside the Reliability Pricing Model auctions (ER15-739).
In its protest, Old Dominion Electric Cooperative argued that PJM had “not demonstrated a threat to reliability sufficient to warrant its proposal for undefined and unlimited authority to enter into agreements” outside of the RPM. It also said that “no [reliability-must-run] procurement should be pursued or entered into without further being informed by the third Incremental Auction results.”
PJM said that it appears that the amount of uncommitted resources is not enough to meet the potential capacity deficiency. “Therefore, PJM likely cannot rely on the third Incremental Auction as a source of supplemental capacity to increase overall capacity commitment levels and help mitigate the identified resource adequacy concerns,” the RTO said.
PJM also disputed the allegation made by Direct Energy that the RTO is seeking a “blank check.”
“PJM showed in the Dec. 24 filing that if generator outage and peak load conditions like those seen in January 2014 were to recur in the 2015/2016 winter, the PJM region could be short by up to 2,600 MW,” the RTO said. “PJM therefore is seeking supplemental capacity agreements of no more than 2,600 MW.”
PJM is asking FERC to approve its proposals before the third Incremental Auction on Feb. 23.
Electric cooperatives operate in 93 of North Carolina’s 100 counties.
The North Carolina Electric Membership Corp. is protesting a request by Dominion Resources to push back the effective date for a rate revision by more than a year.
Last April, the Federal Energy Regulatory Commission approved Dominion’s request for revised transmission depreciation rates with an effective date of April 1, 2013 (ER14-1549).
On Jan. 15, Dominion asked FERC to change the effective date to Jan. 1, 2012, saying its request would only change the effective date of the revised rates, not the rates themselves.
NCEMC, however, says that Dominion’s request would run afoul of the commission’s prohibition against retroactive ratemaking.
“This filing effectively seeks to retroactively charge increased rates to Dominion’s transmission customers for transmission service purchased during the locked-in period Jan. 1, 2012, through March 31, 2013,” NCEMC said in its protest (ER15-856).
Dominion is requesting the extension because of a Virginia State Corporation Commission ruling that set the 2012 date for the updated depreciation rates for bookkeeping purposes. The SCC filed comments in support of Dominion, saying that its precedent holds that a “change in costs must be recorded in the appropriate accounting period coincident with the change; this is true for depreciation expense as well as other costs.”
“Thus, while Dominion correctly notes that its filing is necessitated by the directive of the [SCC] … this implementation date is also consistent with sound utility accounting practice,” the SCC said.
NCEMC argues that, based on prior similar cases, FERC “is not bound by state determinations regarding retail rate proposals. And Dominion cited no precedent to indicate that other commission policy considerations require consistency between state and federal depreciation rates, plant balances or depreciation reserves.”
VALLEY FORGE, Pa. — A senior PJM official acknowledged last week that a proposal to allow load-serving entities such as the Illinois Municipal Energy Agency to use external resources to meet their capacity requirements could be construed as “somewhat preferential.”
Stu Bresler, vice president of market operations, outlined a proposal to allocate capacity transfer rights (CTRs) to resources external to the PJM region that historically have been used to serve the needs of the PJM load.
“We think this is a relatively small population and we can do this … very narrowly,” Bresler told the Market Implementation Committee.
PJM estimates 1,037 MW of historic external resources would qualify under its proposal: 122 MW in the DOM zone, 533 in COMED, 261 in AEP and 121 in DAY.
GT Power Group’s Dave Pratzon, who represents generation owners, took issue with the plan. “What you’re proposing seems like a real sweetheart deal, and any rules I’d want to see would be very strict in terms of identification and not be able to be expanded in the future,” he said.
“I’ll be the first to admit the treatment here could be seen as somewhat preferential,” Bresler responded. The question for stakeholders, he said, is “does the historic nature of the commitments justify that solution?”
Independent Market Monitor Joe Bowring asked whether IMEA could sell its rights to a third party under the proposal.
Bresler said “that level of detail is not decided yet.” He said PJM will expand the detail of the proposal and return it to the committee in March.
Members on Wednesday approved an optional scheduling product intended to reduce uneconomic power flows between PJM and MISO, similar to the Coordinated Transaction Scheduling product launched Nov. 4 with NYISO. (See NYISO Scheduling Product Wins FERC OK.)
The product would allow traders to submit bids that would clear only when the price difference between the two regions exceeds a threshold set by the bidder.
The product would operate on a joint clearing mechanism in which each party would evaluate the prices individually, and the common set would be the transactions that flow.
PJM stakeholders will have to vote on the accuracy of the product’s prices before the offering goes live.
The RTOs are expected to agree upon a common method of interface pricing by November 2016.
PJM, MISO near Agreement on M2M Language
PJM and MISO expect to file a revised Joint Operating Agreement this spring on three market-to-market rules.
PJM’s Asanga Perera told the MIC that the two RTOs have agreed in concept on all three issues and drafted language for one, a change to the threshold for naming flowgates. Perera said RTO officials were still “wordsmithing” provisions regarding conflicting constraint control and hold-harmless settlements for planned outages submitted after the day ahead market deadline.
The threshold for flowgates will be amended for transmission lines at 138 kV or less. The change means that 138-kV and lower elements will not be named as flowgates unless flows from the neighboring RTO amount to 35% or more of the line’s rating, up from the current 25%. The 20% threshold will remain for lines more than 138 kV.
Perera said language on the other two rule changes should be complete by the March MIC meeting. A filing with the Federal Energy Regulatory Commission is targeted for early in the second quarter.
Test Shows Highest Promised Load Reductions
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Summer limited demand response produced 135% of promised load reductions in tests this year, the highest ever.
The test showed 9,668 MW of limited DR responding, 2,510 more than the commitment. However, some providers failed the test, resulting in penalties of $2.7 million, at an average penalty rate of $140/MW-day.
PJM has not actually called on DR during delivery year 2014/15.
Faulty Models Hamper Net Energy Metering Study
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PJM’s attempt to track the growth of distributed solar generation is being hampered by modeling issues. In a briefing on its net energy metering quarterly review, PJM told members that the locations identified as sources of “negative energy” — net energy injections at load buses — are not where most solar PV is located.
“Usually the largest ‘injections’ are because of modeling issues on the distribution system,” PJM’s Ken Schuyler said. “We haven’t really seen a trend of negative injections because of net energy metering.”
PricewaterhouseCoopers’ fourth-quarter 2014 power and utilities mergers and acquisitions report showed an increase in both the number and value of deals greater than $50 million. The firm recorded 22 deals in the last quarter, compared to 12 in the third and 14 in the fourth quarter of 2013. The total value of the deals increased 57% to $17.4 billion in Q4 from $11.1 billion in Q3.
PSE&G Ranks Highest in Gas Service Customer Satisfaction in East
Public Service Electric & Gas was named No. 1 in gas-service business customer satisfaction in a poll by J.D. Power, with a score of 690 on a scale of 1,000. The ranking comes on the heels of PSE&G’s first-place ranking in electric-service business customer satisfaction among 12 utility companies earlier this year. It is the first time the company has achieved first-place rankings in both categories.
PPL Shutting Down J.E. Corette Coal Plant near Billings, Mont.
A PPL subsidiary said that it will permanently shut down its mothballed 153-MW coal-fired J.E. Corette plant near Billings, Mont. PPL Montana closed the plant in 2012 because of low market prices and the high cost of environmental upgrades. At the time, it said that the plant might be returned to service if power prices warranted. It is not part of the PPL-Riverstone Holdings deal that will form a new merchant generation company, Talen Energy.
Entergy Says Vermont Yankee Decom Money not Guaranteed After 60 Years
Entergy is not guaranteeing that it will finance any decommissioning costs at the now-closed Vermont Yankee plant if it takes longer than 60 years.
Entergy Vice President Michael Twomey told Vermont legislators that if decommissioning isn’t completed by then, “there would probably be quite a lot of litigation” concerning additional funding. Vermont Yankee’s decommissioning fund currently holds about $600 million. He said he believes the fund will grow enough to cover the cost of dismantling the reactor and at least part of the cost of managing the plant’s spent fuel.
Because there is still no federal spent-fuel storage facility, all of the spent fuel since the plant started up in 1972 remains on site in pools. Twomey said the company has arranged two lines of credit to pay for transferring the fuel to dry casks and expects to be reimbursed by the U.S. Department of Energy.
Atlantic Coast Pipeline Signs $400 Million Pipe Contract
While awaiting approval from the Federal Energy Regulatory Commission, and battling with opponents in Virginia, Atlantic Coast Pipeline is moving forward with a planned 550-mile natural gas pipeline and just signed a $400 million contract with a steel pipe company. The line is intended to bring shale field gas through Virginia into North Carolina. Last week, the consortium behind the pipeline said it contracted with Dura-Bond Industries to produce steel pipe ranging from 30 to 42 inches in diameter. It is the largest single order in Dura-Bond’s history, and the company’s Steelton, Pa., plant will add a second shift to help complete the order.
Duke Energy Buys Majority Stake in Calif. Solar Company
Duke Energy added to its solar portfolio last week by buying a majority stake in REC Solar, a commercial solar company based in San Luis Obispo, Calif. Industry figures put REC Solar as the eighth largest solar installation company in the U.S. It has installed more than 400 commercial systems totaling more than 140 MW. Although the terms of the transaction were not disclosed, Duke has said it is ready to invest up to $225 million more in REC projects.
Duke Energy said it plans to spend up to $68.7 million on solar projects in South Carolina over the next five years, adding 111 MW of solar capacity to the state’s grid. The plan calls for 53 MW of commercial solar capacity and 58 MW of rooftop solar. The residential rooftop solar will be spurred by customer incentives of up to $5,000 each, the company said.
Dominion Awaiting FERC OK for Gas Tx Projects in Md.
The Federal Energy Regulatory Commission is in the final phase of reviewing two natural gas transmission projects proposed by Dominion Transmission to fuel two new power plants in Maryland. The 725-MW CPV St. Charles Energy Center in Waldorf and the 735-MW Keys Energy Center in Brandywine will be fed from Dominion’s existing pipeline, but the taps on the pipeline need to be approved by FERC. The $775 million St. Charles plant is under construction and due to come online by June 2017. Construction of the Keys Energy Center, a $750 million plant, will begin this year and come online in early 2018.
The Tennessee Valley Authority board last week approved a plan to buy a 760-MW natural gas-fired combined-cycle plant in Ackerman, Miss., for $340 million. The board also approved plans to enter into a power purchase agreement with an 80-MW solar plant to be built near TVA’s Colbert Fossil Plant in North Alabama. Charles “Chip” Pardee, chief operating officer, said the decisions were driven by a desire to add a cleaner mix to its coal-heavy portfolio to help meet pending Environmental Protection Agency emissions mandates. TVA has built or purchased five combined-cycle plants totaling 3,900 MW.
FirstEnergy Investing Nearly $35 Million in Tx Projects to Support Shale Gas
FirstEnergy said it is upgrading existing transmission lines and building new substations in a $35 million project to support the Marcellus Shale gas industry in western Pennsylvania. Although the projects are aimed at serving the growing power needs of the shale gas industry, FirstEnergy customers will also reap the benefits: new shale gas projects account for about 370 MW of projected load growth in the area, the company said.
Maria Korsnick, Exelon Generation’s senior vice president for Northeast operations and chief nuclear officer of the company’s joint venture with Electricite de France, is being loaned to the Nuclear Energy Institute for an 18-month assignment as the lobbying group’s chief operating officer. Korsnick has 28 years of experience in the nuclear industry.“Under Maria’s leadership, nuclear energy facilities at Constellation Energy Nuclear Group and Exelon have operated at exceptional levels of safety and performance,” said Marvin S. Fertel, president and chief executive officer at the NEI. “Maria will provide that same organizational effectiveness, vision and leadership working with our staff and members at NEI.”
Google Signs 20-Year Wind Contract with NextEra Energy
Google has signed a 20-year power purchase agreement with NextEra Energy to buy wind-generated electricity for its Googleplex headquarters in Mountainview, Calif. The company committed to buying half of the output from NextEra’s windmills on the Altamont Pass in eastern Alameda and Contra Cost counties. The output is estimated at 43 MW. Terms of the deal were not disclosed.
Ameren Asking for More Time to Meet EPA Emissions Goals
Ameren is asking for an additional five years to meet emissions-reduction goals set by the Environmental Protection Agency, saying the current schedule that calls for incremental goals to be reached by 2020 is unreasonable. It said that expecting states to meet the goals “with such stringent targets at short notice” would lead to “staggering costs” of approximately $4 billion. It said it could meet the targets of compliance by 2035, five years past the suggested 2030 deadline.
“The EPA should allow states that put in plans that show they would be hitting the 2030 targets within a reasonable time frame around that 2030 date — in our case 2035 — the EPA should be flexible and allow that,” said Joe Power, Ameren’s vice president of federal legislative and regulatory affairs.
Dynegy has reached a settlement with PJM’s Independent Market Monitor to alleviate market power concerns over its purchase of 12,400 MW of generation from Duke Energy and Energy Capital Partners.
In an agreement filed Feb. 6 (EC14-140), Dynegy said it would not to buy any of the plants that will come on the market as a result of the PPL-Riverstone Holdings spinoff to form Talen Energy.
Additionally, Dynegy committed to offer all of its units into PJM capacity market auctions and promised it wouldn’t retire any units unless they failed to clear. It also promised to enter such plants into reliability-must-run agreements if PJM decided they were necessary. The settlement also contained commitments concerning energy and ancillary services offers, which Dynegy said would be good for seven years.
Dynegy is hoping to acquire 11 Duke generating units in the Midwest and 10 Energy Capital Partners generators in the Midwest and New England. Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO. (See Dynegy Back in the Game with Duke, ECP Acquisitions.)
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In their application for approval of the purchase, the companies told the Federal Energy Regulatory Commission that Dynegy’s 6.5% share of the PJM market post-acquisition would have a minimal impact on competition.
The settlement was filed along with a response to a Jan. 16 deficiency notice in which FERC said that the applicants had not addressed all of the commission’s competitive concerns.
The response included market power analyses it said proved that the transactions “will not have an adverse effect on competition” in PJM or any PJM submarket.
Noting that the Monitor was the only intervenor to raise competitive concerns in PJM, the companies asked FERC to approve the deals by April 1. Dynegy said additional delays would cost it $1 million a day in financing costs, impact outage coordination activities needed to prepare for summer operations and threaten the consummation of the deal.
