Entergy said Monday it will close the 838-MW James A. FitzPatrick Nuclear Power Plant near Syracuse, N.Y., in late 2016 or early 2017. The company blamed reduced plant revenues due to low natural gas prices, a market design that doesn’t compensate nuclear power for carbon-free emissions and high operational costs.
The decision, which was expected, was announced in conjunction with the company’s third-quarter earnings. Entergy had already announced it was taking a $1.6 billion impairment charge as it wrote down FitzPatrick and the Pilgrim nuclear plant in Massachusetts, which it is also closing. (See Entergy may Announce FitzPatrick’s Fate this Week.)
“Given the financial challenges our merchant power plants face from sustained wholesale power price declines and other unfavorable market conditions, we have been assessing each asset,” Entergy CEO Leo Denault said in a statement.
James A. Fitzpatrick Nuclear Power Plant (Source: Entergy)
“Entergy and New York state officials worked tirelessly over the past two months to reach a constructive and mutually beneficial agreement to avoid a shutdown but were unsuccessful,” he added. FitzPatrick, which has been operating since 1975, employs more than 600 workers.
Current and forecast power prices have fallen by about $10/MWh, costing FitzPatrick $60 million in annual revenue, the company said.
It also blamed a “flawed market design” that “fails to recognize or adequately compensate nuclear generators” for their fuel diversity and environmental benefits.
Like Pilgrim and Vermont Yankee, which Entergy closed in 2014, FitzPatrick has a high cost structure because it is a single unit. (See Entergy Closing Pilgrim Nuclear Power Station.)
Entergy said it has informed NYISO and the New York Public Service Commission that it will retire the plant at the end of the current fuel cycle. Under PSC rules, closure of units 80 MW or larger will prompt a reliability study for the affected region.
Unlike other areas in New York with either inadequate generation or constrained transmission, however, FitzPatrick is located where there is excess power supply. The plant is in Central New York Zone C, which has generating capacity of 6,650 MW to meet peak summer demand of about 2,574 MW, according to NYISO.
“We’ve had NYISO do analyses on whether FitzPatrick qualifies for a reliability-must-run agreement, and that most recent analysis says that it does not,” Bill Mohl, president of Entergy Wholesale Commodities, said on a call with financial analysts.
Entergy said the plant’s nuclear decommissioning trust had a balance of $729 million as of Sept. 30, $77 million more than the minimum for license termination, according to a Nuclear Regulatory Commission report earlier this year.
The trust is held by the New York Power Authority, which sold the plant to Entergy in 2000. The parties are discussing whether NYPA would transfer the decommissioning trust and the liability to Entergy or enter into a fixed-price decommissioning contract with Entergy for the amount in the trust.
With FitzPatrick’s closure, Entergy will have one generator in operation in New York state, the Indian Point Energy Center in Buchanan. Gov. Andrew Cuomo has said his preference is to close that facility due to its proximity to New York City.
Exelon’s proposed acquisition of Pepco Holdings Inc. has been re-energized by the D.C. Public Service Commission, which unanimously agreed to reopen the case and denied intervenor status to a group that wants to buy PHI’s district assets.
The companies also won approval of an expedited timeline for reconsideration, with closing briefs due Dec. 18.
On Oct. 30, regulators rejected a late request to intervene by D.C. Public Power, a newly formed advocacy group that has proposed to buy Pepco’s district holdings post-merger and create a non-profit utility. (See Group Proposes to Buy Pepco DC’s Assets.)
Overturf
“We are obviously disappointed with the PSC’s decision, and at this time we are evaluating our options and considering what’s next,” CEO Michael Overturf said.
Meanwhile, seven of the D.C. Council’s 13 members have sent a letter to the PSC adding their support to a settlement agreement brokered by Mayor Muriel Bowser’s administration that would offer the district $78 million in public benefits.
The letter, dated Oct. 16, was not posted to the PSC site until after the commissioners voted Oct. 28 to reopen the matter. Among the signers were council members Brianne Nadeau and Brandon Todd, who previously had expressed to the PSC their opposition to the deal.
Nadeau
Nadeau posted the letter to her website, saying she had “decided to support the proposed settlement, which addresses her original concerns by protecting ratepayers through early 2019, providing assistance for low-income citizens and including a commitment to expand solar and wind power along with millions to support additional renewable energy development.”
Neither the council nor the mayor has a formal role in the decision-making process. The three-member commission unanimously rejected the merger in August, ruling that it was not in the public interest. However, Commissioner Willie Phillips issued a partial dissent, saying he was “disappointed in the loss of the many opportunities” the merger could have brought the district. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
The acquisition already has been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia. In Maryland, however, the Office of People’s Counsel is trying to get a court-ordered review of the PSC’s decision. That effort was joined by Attorney General Brian Frosh, who filed an amicus brief in Queen Anne’s County Circuit Court on Oct. 28.
In agreeing to reconsider the merger in the district, PSC Chairwoman Betty Ann Kane said, “We will be releasing more of the details of the process, but we are all committed to seeing that this proceeds in a manner that is open, that is transparent, that is fair and that gives the commission the information and the opportunity that it needs to make a decision on whether this proposal is in the public interest.”
While winning over a number of former critics, notably People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine, the settlement failed to garner the support of intervenors representing environmental and green energy interests. They say the fundamental conflict between Exelon’s commitment to its merchant generation and the district’s move toward renewable energy — a concern cited by the PSC in its denial — remains.
Exelon and Pepco requested a 150-day timeline for consideration of the revised deal. If the acquisition doesn’t close by Dec. 31, Exelon must buy back $2.75 billion of debt it financed to pay for the takeover at $1.01 on the dollar, CEO Christopher Crane recently told Bloomberg. Meanwhile, the company is paying $10 million per month in interest on the bonds it sold in June.
Crane also said that Exelon might walk away from the deal if it is not approved within five months.
Power DC, a coalition of public interest groups opposed to the merger, expressed disappointment with the PSC’s decision to reconsider the merger and the approved timeline. It had asked the PSC to take until June 30 to provide ample time for public input. With more than 3,000 comments, the deal has attracted the most public participation of any issue in the PSC’s history of more than a century.
“Exelon’s latest settlement offer still does not address the fundamental conflicts of interest identified by the PSC when it rejected the merger in August,” Power DC said in a statement after the Oct. 28 vote. “We will continue to work tirelessly over the coming weeks to ensure that the people are protected from this bad deal for D.C.” (See Merger Opponents Question Pepco’s Tactics.)
Expectedly, PHI was pleased with the vote.
“The procedural schedule approved by the commission has reply briefs filed on Dec. 18, which would allow for the commission’s decision sometime in the first quarter of 2016,” said Myra Oppel, PHI’s vice president for regional communications. “The schedule affords all parties and the public a fair opportunity to present their positions and ensures that the commission has a complete record to render its decision.”
The New York Public Service Commission for the second time rejected a New York assemblyman’s attempt to force the disclosure of bidding information from the state’s generators (13-01288).
Assemblyman James Brennan
James Brennan (D-Brooklyn) had appealed Freedom of Information Law rulings by the Records Access Officer in 2014 and this year that deemed such information protected trade secrets. (See Generator Records Ruling Expected This Week.)
“Assembly member Brennan, however, fails to point to any new facts or circumstances that have developed over the past year which would warrant a departure from the 2014 appeal determination,” commission Secretary Kathleen Burgess wrote in a 26-page determination Tuesday.
Brennan had charged that the New York wholesale market was not competitive and that the bidding information filed by the state’s utilities, which is redacted in their filings, is available in other publicly available sources.
The Independent Power Producers of New York responded that information in the New York filings is incomplete and could be misinterpreted.
“A thorough review of those documents shows that the entities proved the existence of competition in the wholesale energy markets and that disclosure of the information at issue would cause substantial competitive injury to the entities participating in those markets,” Burgess wrote.
In a cover letter announcing the ruling, Burgess said she was directing PSC staff to share it with FERC and the NYISO Independent Market Monitor to “request their respective opinions as to whether release of the information at issue in this determination would result in substantial competitive injury to the market participants.”
Brennan in a statement on Wednesday indicated the ruling is not the last word. “It is disappointing that the Public Service Commission chooses to conceal what should be public records of New York’s utility industry. My office will continue to fight to bring sunshine to electricity prices in New York,” he said. “Authentic competition does not exist in New York electricity markets. Instead, the power producers benefit from an administered market where prices are set way above cost to allow massive profits. That is why the industry needs reform.”
IPPNY CEO Gavin Donohue said Wednesday that Brennan “neither appreciates the consumer benefits nor understands the mechanics” of New York’s uniform clearing price auctions.
“Keeping the financial and operational data of generators private is critical to ensuring competitive bids. If that data were to become public, a generator could use the information to determine how much it could raise its bids into the market and still remain below the bids of its competitors,” he said in a statement.
“That’s why the information in question is considered a trade secret. I’m sure that the assemblyman wouldn’t expect Coca-Cola to reveal its secret recipe or McDonald’s to divulge how it prepares its special sauce, but that’s exactly what he’s asking of the power sector. Fortunately, yesterday’s decision by the PSC secretary will protect consumers from a very poor course of action.”
The D.C. Public Service Commission on Wednesday voted to reopen the Exelon-Pepco Holdings Inc. merger case to consider a proposed settlement with Mayor Muriel Bowser’s administration. The commission also granted the companies’ requested expedited timeline, with closing briefs due Dec. 18.
“We will be releasing more of the details of the process, but we are all committed to seeing that this proceeds in a manner that is open, that is transparent, that is fair and that gives the commission the information and the opportunity that it needs to make a decision on whether this proposal is in the public interest,” said PSC Chairwoman Betty Ann Kane.
The commission unanimously rejected the $6.8 billion deal in August, after it had been approved by FERC and regulators in Delaware, Maryland, New Jersey and Virginia.
Bowser’s office, however, later brokered an agreement that won over principal critics, including People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine, by offering the district $78 million in public benefits. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
The settlement failed to garner the support of intervenors representing environmental and green energy interests, who said the fundamental conflict of Exelon’s commitment to its merchant generation and the district’s move toward renewable energy remained.
The joint applicants requested a 150-day timeline for consideration of the revised deal. If the acquisition doesn’t close by Dec. 31, Exelon must buy back $2.75 billion of debt it financed to pay for the takeover at $1.01 on the dollar, CEO Christopher Crane recently told Bloomberg. Meanwhile, the company is paying $10 million per month in interest on the bonds it sold in June.
Crane also said that Exelon may walk away from the deal if it is not approved within five months.
Power DC, a coalition of public interest groups opposed to the merger, expressed disappointment with the PSC’s decision. It had asked the PSC take until June 30 to provide ample time for public input. Amassing more than 3,000 comments, the deal has attracted the most public participation of any issue in the PSC’s history of more than a century.
After Wednesday’s vote, the group said in a statement, “The residents and small businesses of D.C. are disappointed with the Public Service Commission’s decision to expedite the review of Exelon’s bid to buy Pepco. Exelon’s latest settlement offer still does not address the fundamental conflicts of interest identified by the PSC when it rejected the merger in August. We will continue to work tirelessly over the coming weeks to ensure that the people are protected from this bad deal for D.C.” (See Merger Opponents Question Pepco’s Tactics.)
“The procedural schedule approved by the commission has reply briefs filed on Dec. 18, which would allow for the commission’s decision sometime in the first quarter of 2016,” said Myra Oppel, PHI’s vice president for regional communications. “The schedule affords all parties and the public a fair opportunity to present their positions and ensures that the commission has a complete record to render its decision.”
Kane said that other related motions, including a request from D.C. Public Power to become an intervenor in the case, will be ruled on shortly. (See Group Proposes to Buy Pepco DC’s Assets.)
According to the timeline approved Wednesday, the filing deadlines are as follows:
Oct. 30: Settlement agreement and supporting testimony.
Nov. 6: Data requests to settling parties regarding settlement agreement and supporting testimony.
Nov. 13: Settling parties’ responses to data requests regarding settlement agreement and supporting testimony.
Nov. 17: Non-settling parties’ testimony.
Nov. 20: Data requests to non-settling parties regarding settlement agreement and supporting testimony.
Nov. 25: Non-settling parties’ response to data requests regarding settlement agreement and supporting testimony.
Dec. 2-3 and possibly Dec. 4: Public interest hearings.
SPP asked FERC last week to allow it to waive Tariff provisions governing the selection of an industry expert panel (IEP) to evaluate proposals for the RTO’s first competitive solicitation under Order 1000 (ER16-126).
SPP Southwestern Kansas Upgrades (Source: SPP)
SPP’s Tariff requires its Oversight Committee to establish an IEP candidate pool composed of individuals with expertise in at least one of five areas of electric transmission: engineering design; project management and construction; operations; rate design and analysis; and finance.
When an IEP is needed to evaluate proposals, the committee selects three to five candidates from the pool that collectively satisfy each of the five areas.
The RTO told FERC it recently learned that one of the 10 candidates in its 2015 pool — the only one with expertise in one of the five areas required — may not be able to serve and that it won’t have time to select a replacement and meet its deadline for evaluating the upcoming project.
The Tariff requires the panel to recommend a proposal within 60 days of beginning their review.
SPP asked FERC to shorten the comment period and grant the waiver by Nov. 2, when responses to the RTO’s request for proposals are due on the 21-mile Walkemeyer-North Liberal 115-kV project in Kansas. (See SPP Issues RFP for 115-kV Transmission Project.)
“Out of respect to the candidate’s privacy,” SPP said it was not disclosing the candidate’s name, area of expertise or reason that could prohibit participation.
SPP said a suitable replacement was found in the 2016 candidate pool, but the Tariff would not allow the candidate to review proposals issued in 2015. Granting the RTO’s waiver request would ensure “no material delays arise” in the review of the Walkemeyer proposals.
In July, the board approved a staff recommendation to move the project’s “regulatory approval need date” eight months from the Notice to Construct’s issuance. The change met a Kansas Corporation Commission statutory obligation to rule on such requests within 180 days of the initial filing and give the winning entity “reasonable time” to gain utility status in the state. (See “Date Change for Walkemeyer Project RFP” in SPP BoD/Members Committee Briefs.)
SPP Sets New Highs for Wind Usage
SPP’s balancing authority set new records for wind and wind-penetration peaks last week. The BA recorded a new high for wind at 8,458 MW on Oct. 18, and a new wind penetration level of 37.8% of load on Oct. 19.
SPP’s previous wind-related highs were 8,412 MW of wind on Feb. 1 and 36.8% of load on April 16.
The record highs came less than a month after the Integrated System’s incorporation into the SPP footprint Oct. 1.
SPP set several wind records last year, when it saw wind energy account for 11.8% of the footprint’s generation.
Last-minute legal maneuvering has delayed by a week a New York Public Service Commission decision on a lawmaker’s request for release of generators’ pricing information.
Assemblyman James Brennan
The commission’s secretary postponed a ruling under New York’s Freedom of Information Law on Assemblyman James Brennan’s (D-Brooklyn) appeal of a recent ruling denying his challenge to filings that redact bidding information by the state’s generators. A ruling had been expected Monday.
In an Oct. 14 letter to the PSC, Brennan reiterated his position that disclosure by some companies should lift the veil on the others. “Once again, this demonstrates that many companies do not consider the reported information harmful and not trade secrets,” he wrote.
The Independent Power Producers of New York filed a letter on Oct. 15 that disputed the nature of the released information, saying it is not comparable to the data Brennan seeks. “That some companies release certain types of information that other companies deem confidential trade secrets has no relevance to whether information is a trade secret, no more so than the public disclosure of the recipe for Coca-Cola is relevant to whether the recipe for Pepsi is a trade secret,” IPPNY wrote.
The parties also dispute whether the PSC’s rejection of Brennan’s 2014 petition can be re-litigated.
“In light of these competing claims, a decision on the appeal will require additional time,” Secretary Kathleen Burgess wrote on Monday.
Five of the top 10 energy efficient states are in the Northeast, according to the American Council for an Energy-Efficient Economy’s 2015 State Energy Efficiency Scorecard. Massachusetts holds the No. 1 rank for the fifth year in a row, having overtaken California in 2011.
The top 10 states for energy efficiency are Massachusetts, California, Vermont, Rhode Island, Oregon, Connecticut, Maryland, Washington and New York, with Minnesota and Illinois tied for 10th place. Massachusetts retains the top spot based on a strong commitment to energy efficiency under its Green Communities Act.
In California, requirements for reductions in greenhouse gas emissions, major efforts to achieve energy efficiency in schools and implementation of a cap-and-trade program earned the state several more points this year, putting it only a half-point behind Massachusetts in the state rankings. North Dakota’s energy efficiencies were determined to be the least effective, just below Wyoming.
Consumer Counsel Elin Swanson Katz is warning electric consumers who are supplied by third-party providers to review their bills. Katz said data provided to the Public Utilities Regulatory Authority showed that more than three-quarters of customers of both Eversource Energy and The United Illuminating Co. paid more than the standard service rate in August if they used a third-party supplier.
Some customers paid prices that were as high as 23.7 cents/kWh, which is nearly three times Eversource’s standard service rate and more than two-and-half times that of UIL, Katz said. Between January and August of this year, customers of electric suppliers collectively paid about $23 million more for electricity than if they had been on standard service, she said.
“Customers should be aware that switching to a retail electric supplier can be a risky proposition,” said Katz, whose office represents the interests of consumers in utility rate cases. “Some suppliers are charging certain customers more than twice the standard service rate, even in the summer months. There is no ceiling on the rates that third-party suppliers can charge you.”
Delmarva Power Issues RFP for Wholesale Electricity
Delmarva Power and Light is requesting proposals to supply about 455 MW of wholesale electric power to meet its standard offer service obligation to customers.
Peak load contributions by customer class are 255 MW for residential, small commercial and industrial combined; 140 MW for medium general service-secondary; 20 MW for large general service-secondary; and 30 MW for general service-primary.
A pre-bid conference for prospective bidders will be held later this month.
An administrative law judge recommended that the Commerce Commission approve the Grain Belt Express transmission line, concluding that the project would help produce a competitive energy market at a small cost to customers.
Judge Jan VonQualen said Clean Line Energy Partners’ plan to build the $2 billion line to transport wind energy from Kansas through the state to Indiana would be a good thing for electric customers.
Regulators in Indiana and Kansas have already approved plans for the 202-mile transmission line. Missouri’s regulators voted against it, but the Houston company says it will reapply for permission there.
A solar installer is challenging a tariff feature that he says penalizes large Alliant Energy power customers by continuing to assess costly demand charges for a year after they switch to solar.
Barry Shear, who runs Eagle Point Solar, says the tariff approved earlier this year reduces the incentive for some large customers, such as manufacturers and wastewater treatment plants, to switch to solar. The old tariff reduced the demand charge a month after customers reduced their load. The new tariff keeps the demand charge in place for a year. Demand charges can account for up to half a customer’s monthly costs.
Alliant spokesman Justin Foss said the company changed the tariff in response to complaints from some large customers who experienced sudden “bill shock” when they were shifted between rate categories — one of which assessed the demand charge — because of short-term changes in their electricity consumption.
Collective Extols Benefits of Pooling Resources, SPP Market
The City of Chanute joined with other nearby municipalities to form the Southwind Energy Group 18 months ago, and the combined purchasing power has allowed the city to shave $800,000 in annual energy costs for its customers.
The group, which Chanute heads, buys its power from Kansas City Power and Light. Costs for the program are passed on to utility customers in the “fuel adjustments” section on utility bills.
While the KCP&L contract has been shown to offer energy savings, there are actually even more savings by participating in SPP’s day-ahead energy market.
Baltimore Mayor Stephanie Rawlings-Blake won’t say if the city is trying to reach a settlement with Baltimore Gas and Electric after the company sued the city over a recent increase in prices for using the city’s conduits for the utility’s cable.
In September, the city raised the fee it assesses to use the city’s underground conduits from 98 cents/foot a year to $3.33. The hike was estimated to increase BGE’s cable-use costs by nearly $30 million. Exelon-owned BGE sued, saying the fee violated state law prohibiting rate increases to fund other city services.
The city says it needed to triple the rate to maintain the aging infrastructure. Rawlings-Blake said the relationship between BGE and the city hasn’t suffered because of the suit.
Utility Advocacy Groups Launches Coal Plant ‘Countdown’ Campaign
An advocacy group backed by the state’s two largest utilities has launched an ad campaign warning of a possible power shortage if the state’s coal-fired power plants are shut down. Opponents dismissed the campaign as “scare tactics.”
Citizens for Michigan’s Energy Future is running ads warning that the state’s nine coal-fired plants will go “cold and dark” by 2016, helping to create a 1.3-GW capacity shortfall. The assertion conflicts with statements from MISO and the Public Service Commission that there will be no shortfall.
The group is backed by Consumers Energy and DTE Energy. The campaign urges residents to write to their lawmakers to support proposed legislation that would eliminate net metering programs and restrict energy efficiency programs.
Court: Homeowner Associations can’t Force Solar Panel Removal
A state appellate court has ruled that homeowner associations cannot force the removal of solar panels unless deed restrictions specifically forbid them.
The case centers on a couple in a St. Louis subdivision that were told they would have to remove their roof-mounted solar panels. A lower court ruled last year that the solar panels could stay because the deed restrictions didn’t specifically mention them. The appellate court upheld that ruling.
PSC Votes Against Extending Ameren’s Energy Efficiency Program
Concerned that Ameren might collect more than it needs to run a popular energy efficiency program, the Public Service Commission voted against extending the program for another three years.
Ameren’s program has earmarked $100 million for the program, which has saved, by some accounts, about 1 million MWh of electricity. The program provides rebates to customers who purchase energy-efficient appliances.
But the commission said it wants a more accurate way to measure energy savings to assess the program’s benefits. “Without that type of [measurement], I’m just uncomfortable approving that type of plan,” PSC Chairman Daniel Hall said. Without PSC approval, Ameren is not obligated to offer the program after the end of the year.
Landowners who oppose the Keystone XL pipeline are appealing to overturn a state law that turned over some route-approval decisions to the governor that were previously made by the Public Service Commission.
Attorneys for developer TransCanada have moved to get the landowners’ suit dismissed. The company said it has already announced it isn’t pursuing its eminent domain claims against landowners and has reapplied to the PSC. It says the landowners’ suit is unnecessary.
“Our focus is entirely on moving forward with the [commission] process and building the Keystone XL route in Nebraska in the most timely way possible,” TransCanada spokesman Mark Cooper wrote after the hearing.
The state’s carbon emissions increased 14% in 2014, with most of the pollution — 17 million metric tons — generated by the state’s 45 power plants. The spike reverses three previous years of declines.
The state’s carbon emissions totaled 27 million metric tons, compared with 23.75 million the previous year. Officials cited a rebounding economy, a cold winter and the retirements of plants in other states for the increase.
El Paso Electric’s attempt to create a new rate class for customers with rooftop solar systems suffered a major setback recently when the Public Regulation Commission ruled such a change would violate a regulation that has been on the books for decades.
The commission rejected a hearing officer’s denial of a motion to dismiss the new rate class. Commissioner Sandy Jones said a PRC ruling in 1999 made it clear that residential customers can’t be split into two classes.
That doesn’t mean the effort to charge solar customers more is necessarily defeated, Jones said. The company could still seek an additional charge but would have to do so by applying for a rider, he said.
A three-year, $325.4 million electric rate increase moved closer to implementation after the Long Island Power Authority board of trustees took no formal action despite objections by two board members.
Trustees would have had to pass a resolution finding that the 9% increase was “inconsistent” with three specific standards defined by the LIPA Reform Act in order to trigger public hearings on the proposal. While trustees Suzette Smookler and Matthew Cordaro raised objections to the increase, no board member offered a resolution to block it.
Several board appointees of Gov. Andrew M. Cuomo, whose administration wrote the reform act, challenged Cordaro to raise specific grounds for an inconsistency vote. Cordaro said his concern was that offering a resolution could result in a rate increase, the opposite of his intentions, and so he did not offer one. The rate hike will be built into the 2016 budget, which trustees are scheduled to consider in December.
Judges Rejects Duke’s Bid to Dismiss Coal Ash Suit
Biggs
A federal judge rejected Duke Energy’s bid to dismiss a lawsuit seeking to pressure the state to step up enforcement of coal ash regulations. The judge said she doubted that the Department of Environmental Quality was tough enough on Duke in light of the utility’s record for contaminating a river with coal ash.
U.S. District Judge Loretta Biggs ruled that the suit against Duke by the Riverkeepers group can go forward, largely because of what she saw as the state environmental agency’s lack of action. “The court notes that its determination of [DEQ’s] lack of diligence has been further confirmed in the year since the Riverkeepers filed suit. [DEQ] has now been litigating its enforcement action for over two years” and not “filed any motions requiring Duke Energy to clean up its sites.”
The state agency took issue with the judge’s characterization. “The claim that we have not been diligent is not only incorrect, it is an affront to the dedicated DEQ employees who are working to expedite the cleanup and closure of coal ash facilities,” Sam Hayes, the agency’s attorney, said in a statement.
A proposed 100-MW wind farm is on hold until the Public Service Commission can determine if the 59-turbine project would harm bald eagles.
Rolette Power Development proposed the $175 million wind farm near Rolette. The U.S. Fish & Wildlife Service noted the existence of bald eagle nests nearby. But the developer’s consultant, KLJ, countered that the nests are not within the planned facility’s boundaries. “Since the eagle nests are located outside of the project area, Rolette Power has no plans to alter the project layout,” KLJ’s Grady Wolf wrote to the PSC.
The commission has ordered a Nov. 2 hearing to review the information before it will approve the project. Commissioner Brian Kalk said the PSC has no standard setback requirement between eagle nests and wind turbines, and the hearing will focus on what the appropriate distance should be.
An attorney who spent the past three years looking after the interests of consumers in utility cases has left a state watchdog group to join utility AES.
Michael Schuler is leaving the Consumers’ Counsel to be regulatory counsel for AES in Dayton. AES purchased Dayton Power & Light for $4.7 billion in 2011. Schuler was involved in about 40 cases currently before the Public Utilities Commission.
The OCC’s budget was cut in half between 2010 and 2012 by Gov. John Kasich.
Environmental Justice Communities Eyed for Shale Gas Impacts
The state’s Office of Environmental Justice is being tasked with examining how shale gas facilities could impact the health and environment of those living in poor and minority communities.
In particular, the review will look at “environmental justice communities,” where at least 20% of residents live below the poverty line, or where 30% of the population is non-white. More than 850 such areas have been identified.
Nearly 500 wells already have been drilled in those communities. The study is part of a rejuvenation of the office, whose mission will be “rebuilt from the ground up,” according to John Quigley, secretary of the state Department of Environmental Protection.
The Public Utility Commission released a management and operations audit of Philadelphia Gas Works containing 76 recommendations that it says could generate an estimated $8.3 million to $9.4 million in annual savings and a one-time savings of about $1.1 million.
Among the suggestions: Aggressively accelerate the replacement of high-risk mains, specifically cast iron ones; reduce the number of open leaks by outsourcing the excavation work and using PGW crews to make repairs; and place greater emphasis on decreasing the number of customer accounts delinquent by more than 90 days.
PGW accepted all of the recommendations but one related to reorganizing its governance structure, which includes overlapping roles of the Philadelphia Facilities Management and the Philadelphia Gas Commission. PGW said it was beyond the authority of management to address.
PGW, owned by the City of Philadelphia, is the largest municipally owned gas utility in the country.
Twenty-two small rural businesses and farms have received a total of $1,555,448 for energy and efficiency upgrades, according to Rep. Peter Welch (D) and the U.S. Department of Agriculture.
Projects receiving the grants include photoelectric arrays, energy-efficient reverse-osmosis maple-sap pumps and milk chillers; and a wood-fired furnace. Eight of the 10 largest grant recipients are developing grid-tied solar power arrays.
The largest of the projects, Barton Solar, is a 1.89-MW solar system, for which it received $500,000.
LITTLE ROCK, Ark. — The Board of Directors’ System Planning Committee last week reviewed the status of the 2015 MISO Transmission Expansion Plan, dissecting a few large and contentious projects.
MTEP15, which will be finalized by the board in December, is expected to include 357 projects valued at $2.6 billion. The Planning Advisory Committee voted Oct. 14 to recommend the plan for board approval; the Advisory Committee will consider it in November.
“It’s a big footprint and a lot of different jurisdictions,” said MISO board member Michael Evans, remarking on the 70-plus meetings held thus far on the plan.
Duff-Rockport-Coleman Project
The plan will include the Duff-Rockport-Coleman 345-kV project in Southern Indiana, the RTO’s first project to be competitively bid.
MISO is responsible for the Duff–Coleman portion, estimated at $67.4 million, while PJM will cover the cost of the tie-in to the Rockport substation. The go-ahead on MISO’s portion of the project does not hinge on PJM’s approval of its tie-in project. (See MISO Staff Recommends 3 Economic Projects.)
Paul Kelly, director of federal regulatory policy for Northern Indiana Public Service Co., applauded MISO’s suggestion of an interregional committee for handling such projects in the future. NIPSCO had objected that the project wasn’t studied enough under the MISO-PJM Joint Operating Agreement to flesh out cross-border benefits and RTO cost allocations.
“While we think this project is valid and should be built, we think there are additional efficiencies that might have been squeezed out of this if it were looked at as an interregional project,” Kelly said.
Curran
Jennifer Curran, MISO’s vice president of system planning and seams coordination, acknowledged concerns that PJM’s involvement could add complexity to the competitive bidding process. She said that the situation provided an opportunity to refine “hybrid” projects.
“We remain committed to working towards that goal” of interregional transmission project development, she said.
In that vein, MISO is discussing with ERCOT a potential study on ways to increase transfers between the two regions.
Texas Project
MISO said it is considering a minor design modification suggested by Entergy to an economic project in East Texas included in MTEP15.
The $122.5 million project includes a new 230-kV line from Lewis Creek to a new 345/230-kV substation that will cut into the Grimes-Crocket 345-kV line and a rebuild of the Newton Bulk–Leach 138-kV line.
Resource Adequacy Update
Curran gave the committee a long-term resource adequacy update, saying MISO has high certainty of obtaining 2.6 GW of new resources by 2020 (those under construction or subject to interconnection agreements), with 2.3 GW coming from natural gas, 135 MW from wind and 81 MW from hydro.
The RTO also has 5.3 GW of generation in final studies or seeking regulatory approval. The confidence level for those developments being completed is 50%.
Finally, MISO set a 10% confidence for the completion of 20.7 GW of other active queue projects and for 2.1 GW of generation reported in the MISO-Organization of MISO States survey but not in the queue.
The survey predicts a regional surplus of 1.7 to 2.3 GW for 2016, with sufficient zonal surpluses to offset zonal shortfalls until 2020. The 2014 survey had predicted a 2.3-GW regional shortfall in 2015. (See MISO Survey: No Shortfall Until 2020.)
MISO stakeholders are considering several changes in time for the 2017-18 planning year, including seasonal capacity auctions and speeding up the interconnection queue process by reducing restudies and study cycle timelines.
Tariff Change Would Allow PJM to Sell Excess Capacity for 2016/17
WILMINGTON, Del. — Members overwhelmingly endorsed a Tariff change that would allow PJM to release Base Capacity resources to reflect the Capacity Performance resources it acquired in the transition auction for the 2016/17 delivery year.
Results of PJM Reserve Requirement Study (PJM)
While it planned to include the 2017/18 delivery year in the changes, staff decided to hold off pending a Supreme Court ruling on the Electric Power Supply Association’s challenge to FERC’s jurisdiction over demand response. (See FERC Jurisdiction over DR in Peril as Supreme Court Splits.)
PJM plans to craft the request for the Tariff change to FERC in a way that would permit it to pull it back if the Supreme Court rules that DR could not be used in energy markets and FERC applied the ruling to capacity markets as well.
“There’s some argument out there that jurisdiction is jurisdiction. The hesitancy we have is if EPSA is upheld at the Supreme Court, we don’t know what FERC would do, so we want to leave ourselves open with a safety valve,” said Stu Bresler, PJM senior vice president for markets.
In addition, PJM Assistant General Counsel Jen Tribulski noted that FirstEnergy has a case before FERC regarding DR in capacity markets (EL14-55).
“FERC could take both and make a decision regarding both markets,” she said.
The filing is expected to be made in early December. The third incremental auction is set for February.
Committee Endorses Increase in IRM
With five “no” votes and 19 abstentions, the committee approved an increase in PJM’s Installed Reserve Margin.
The Reserve Requirement Study increased the IRM for delivery year 2016/17 to 16.4% from 15.5% in the 2014 study. IRMs also rose for 2017/18 and 2018/19.
Some members expressed misgivings over PJM’s methodology, saying the rise seemed counterintuitive given the new Capacity Performance product and other efforts to ensure generator reliability. (See “IRM, FPR Rising; PJM Methodology Challenged” in PJM Planning Committee Briefs.)
Steve Lieberman of Old Dominion Electric Cooperative opposed the proposal.
“We don’t take resource adequacy lightly,” he said. “We’re not looking to make things less reliable; we’re just not comfortable with the assumptions made this year. We feel that the IRM that was in place last year is a fair and reliable value to use next year.”
Tom Falin, manager of resource planning, said that CP alone does not automatically result in a lower IRM.
“We have already assumed that generators will perform at the CP standard,” he said. “Our planning studies assume that the forced outage rate applies every day of the year, regardless of how hot and cold, that generators will have about a 7% unavailability rate.”
Winter Peak Studies to be Added to Planning Process
The committee unanimously endorsed changes to Manual 14B: PJM Region Transmission Planning Process adding the RTO’s first criteria for reliability studies focused on meeting winter peaks.
The parameters define the winter peak period as 6 to 9 a.m. and 5 to 8 p.m., from Dec. 1 through Feb. 28.
The studies will include thermal and voltage evaluations; solutions to identified problems will be developed through the Transmission Expansion Advisory Committee.
The criteria will be effective for baseline studies on Jan. 1 and for interconnection queue requests received after the effective date of the revised manual language.
Traditionally, the use of energy in PJM has peaked in the summer, but in the past couple of years, it has seen operational issues “during a lot of other times,” said Mark Sims, manager of transmission planning.
He said new transmission planning standards going into effect will require PJM to study more extreme events.
Regulation Market Proposal, Task Force Charter Approved
Members approved an interim solution to the over-procurement of RegD resources that will be reflected in changes to Manual 11: Energy & Ancillary Services Markets Operations.
The solution moves the benefits factor curve to the left so that it is at zero at 40%. A cap of 26.2% also will be implemented during identified excursion hours — hours when dispatch frequently moves the regulation signal manually.
It also features tie-breaker logic to rank RegD self-schedules or zero-cost offers. (See “Solution, Task Force Proposed to Curtail RegD Resources” in PJM Markets and Reliability Committee Briefs.)
The changes, which take effect Dec. 1, will be reviewed quarterly while a senior task force will seek a long-term solution.
“We believe this proposal goes in the right direction,” said Susan Bruce of the Industrial Customer Coalition. “It’s certainly a good placeholder until the next group does some long-term work.”
In a related vote, the charter for the task force also was approved. Some key activities were added after the issue was discussed at the Operating Committee, including evaluating the causes and effects of prolonged control deviations and identifying common causes for operators manually adjusting the regulation signal.
The group also will re-evaluate:
the regulation requirement;
regulation signal formation, including the potential of RegB and RegD neutrality;
self-schedule and zero-offer resources in the commitment process and impacts on energy market;
the scoring method for regulation testing and regulation service; and
the schedule used in the calculation for the regulation lost opportunity cost.
Subcommittee Formed to Review Governing Documents
The former Tariff Harmonization Senior Task Force will become the Governing Document Enhancement and Clarification Subcommittee, members agreed.
The group will review, identify and propose solutions to substantive and non-substantive inconsistencies and confusing language in PJM’s governing documents.
Members Committee
Nominating Committee Members Elected
Members elected the Nominating Committee for 2015-16. The sector representatives are:
Electric Distribution Sector: Lisa McAllister, American Municipal Power
End Use Customer Sector: Ruth Ann Price, Division of the Public Advocate of the State of Delaware
Generation Owner: Joe Kerecman, Calpine
Other Supplier Sector: Marji Philips, Direct Energy
Transmission Owner Sector: John Horstmann, Dayton Power & Light
NextEra Energy last week asked the D.C. Circuit Court of Appeals to overturn two FERC orders in a generator interconnection dispute with Ameren Illinois.
NextEra filed a petition for review of FERC decisions in May 2014 and August 2015 (ER14-1470), saying it was being overcharged by $6 million under a facilities service agreement between Ameren and NextEra subsidiary White Oak Energy for a wind generation project near Carlock, Ill.
In the first order, FERC conditionally accepted an unexecuted facilities service agreement under which White Oak was required to pay Ameren a monthly network upgrade charge retroactive to Aug. 28, 2007, the date of White Oak’s generator interconnection agreement with Ameren.
NextEra requested rehearing, saying it should only pay Ameren $2.4 million, instead of the almost $8.3 million FERC ordered.
White Oak wind project
NextEra says it is being overcharged because Ameren applied MISO’s “Option 1” pricing to White Oak, under which the interconnection customer provides up-front funding for network upgrades and receives a 100% refund from the transmission owner after the upgrades are complete, with the costs then recovered through a monthly network upgrade charge. The network upgrade includes a return on Ameren’s rate base, operations and maintenance expenses, depreciation and taxes.
That is in contrast with Option 2, under which the transmission owner retains the interconnection customer’s initial funding for the upgrades and the interconnection customer is assessed no further charges.
Option 1 Voided
NextEra is relying on a 2011 FERC order in which the commission ordered MISO to remove Option 1 from its Tariff, saying that it increased the costs to interconnection customers without providing any increase in service compared to other funding options (EL11-30).
The removal was ordered effective March 22, 2011, the filing date of the complaint challenging the funding mechanism. The commission said the removal would not apply to agreements effective before that date as “a reasonable remedy that balances the interests of the parties, the need for regulatory certainty and ease of administration.”
NextEra said Ameren cannot elect to apply Option 1 pricing to the facility service agreement because it didn’t select it when the GIA was executed in 2007.
Ameren responded that MISO’s Tariff did not require it to make an Option 1 pricing selection at the time White Oak agreed to take interconnection service, and NextEra never requested that Ameren commit to a compensation option.
In its Aug. 21 rehearing order, FERC told Ameren to change the GIA to avoid “confusion regarding the full extent of White Oak’s Section 206 rights” but denied NextEra’s request to void the Option 1 charges.
FERC also rejected NextEra’s argument that the FSA should be limited to a return of and on amounts Ameren invested to fund the network upgrades, saying the transmission owner also was entitled to recovery of operations and maintenance costs.
