The owner of the R.E. Ginna nuclear power plant announced an agreement with Rochester Gas & Electric on Friday that will keep the plant operating for another three and a half years with fixed monthly payments of about $17.5 million.
The New York Public Service Commission in November ordered a reliability support services agreement between the Rochester utility and plant owner Constellation Energy Nuclear Group in an effort to save the 580-MW generator on Lake Ontario. NYISO and RG&E said the plant is needed until at least 2018 to maintain system reliability in western New York.
RG&E estimates an average residential customer using 600 kWh a month will see bills rise about 4.2%, or about $3.89. The exact amount will depend on the monthly output of the plant and changes in wholesale energy and capacity market prices.
RG&E will recover some of its $17.5 million in monthly payments through its share of the plant’s “applicable revenues”: 85% of energy and capacity sales and 100% of ancillary services.
The companies originally faced a Jan. 15 deadline to complete talks for the agreement. Two extensions were granted by the PSC while negotiations continued until Friday. The agreement, which was also filed with the Federal Energy Regulatory Commission, runs from April 1 of this year to Sept. 30, 2018.
“The RSSA will ensure grid reliability in the greater Rochester area while RG&E completes a host of necessary transmission and distribution upgrades,” Exelon said in a statement. “In addition, the agreement protects 700 facility jobs, up to 1,000 skilled contractor jobs and critical tax revenue for Wayne County and the region.”
RG&E CEO Mark Lynch said the company “worked diligently in the best interests of our customers to reach an agreement with Ginna, recognizing the importance of ensuring reliable service on reasonable terms for all parties.”
The agreement is subject to approval by the PSC and FERC.
“The focus of PSC’s in-depth review will be to ensure that the reliability of the electric grid is maintained,” PSC spokesman James Denn said in a statement. “This review will include a significant opportunity for public and stakeholder comment and input.”
RG&E, a subsidiary of Iberdrola USA, has the right to terminate the agreement early with 12 months’ notice. The proposed end date in late 2018 is when a transmission upgrade in western New York is scheduled to go online. That project is intended to provide enough energy into the RG&E service territory without Ginna.
The agreement could be extended for 18 months if RG&E gives notice by Jan. 30, 2017.
Constellation, a unit of Exelon, said the plant has lost $100 million over the past three years and would be mothballed without better financial terms.
Hedge fund twins Kevin and Richard Gates, already embroiled in a battle with the Federal Energy Regulatory Commission’s Office of Enforcement, have now taken on PJM.
The Gates brothers and a trader for their Powhatan Energy Fund are awaiting a ruling from FERC on an order to show cause why they shouldn’t be fined for allegedly making round-trip up-to-congestion trades to collect line-loss rebates.
A PJM analysis done at the request of the Office of Enforcement showed that Powhatan’s trading strategy cost more than 20 market participants at least $100,000 each. PJM issued a statement Feb. 3 criticizing Powhatan’s trading activities, saying the fund failed “to appreciate the unique legal and regulatory framework governing organized wholesale electricity markets.” (See PJM: Gates’ Trades Cost Exelon, AEP, Dominion $1M Each.)
“Yeah, perhaps we do not understand this ‘uniqueness,’” Powhatan said in a press release last week. “We were under the impression that constitutional protections applied to all regulated markets in this country, including theirs.
“Our activities were perfectly legal,” the statement continued. “And the thing is — PJM knows it.”
PJM spokesman Ray Dotter’s response to the latest Gates salvo was short and to the point.
“While we stand by our position, the simple fact is that Powhatan’s problems will be resolved by FERC and the courts and not by any opinions held by PJM or Powhatan,” he said.
A Utah company trying to a develop a small wind generation project filed a complaint with the Federal Energy Regulatory Commission last week accusing PacifiCorp of violating commission rules and making racially and sexually disparaging remarks toward its employees.
Sage Grouse Energy Project told FERC that PacifiCorp employed “trickery” in its management of the interconnection queue in order to secure an agreement with rival Utah wind company Blue Mountain Power Partners. Calling PacifiCorp and Blue Mountain “conspirators,” Sage Grouse claims that parcels of land identified in Blue Mountain’s interconnection request actually belonged to Sage Grouse, rendering Blue Mountain’s request invalid.
Additionally, Sage Grouse accused PacifiCorp employees of repeatedly calling its company principal a “voodoo bitch,” and suggesting that she “go back to where she came from,” citing this as a microcosm of its treatment of minority-owned interconnection customers. A PacifiCorp spokeswoman said the allegations were “unsubstantiated and baseless.”
A decision by the Department of Energy to terminate funding for the FutureGen 2.0 clean coal/carbon-capture project in Illinois likely means the project’s demise. FutureGen Alliance CEO Ken Humphreys said the department decided to ax its $1 billion funding because the 2009 federal stimulus deal set a deadline of September of this year for project completion. Despite being in the works for more than a decade, the plant is nowhere near being operational and still faces substantial opposition, including legal challenges from the Sierra Club.
NRC’s IG Finds Room for Improvement in Spent Fuel Pool Oversight
The Nuclear Regulatory Commission’s Inspector General’s Office released its report on the agency’s spent fuel pool oversight program and while it found no safety issues, it pointed to some areas that could be improved. The report, issued last week, found that spent fuel pool inspections vary from site to site.
The IG recommended that the NRC pool-inspection program develop a “generic” regulatory framework of inspections and regulations. It also recommended that inspections of older pools be stepped up to check for degradation. The agency inspects a total of 93 spent-fuel pools at operating or retired reactors in the U.S.
NRC Staff OKs Watts Bar 2 Operating License Approval
The Tennessee Valley Authority’s Watts Bar 2 nuclear station, currently under construction, received an important approval from a Nuclear Regulatory Commission committee in its bid for an operating license. The commission’s Advisory Committee on Reactor Safeguards said “there is reasonable assurance that the [unit] can operate as a second unit of the dual-unit Watts Bar Nuclear Plant without undue risk to the health and safety of the public.”
The approval will be considered by the NRC in its final decision on granting an operating license. The plant is due to go on line between September and June 2016.
Brattle Group Report Finds Few Reliability Concerns with Clean Power Plan
A group of clean energy companies said in a report last week that there is no clear evidence reliability would suffer if the Environmental Protection Agency’s Clean Power Plan was adopted by all states. The Advanced Energy Economy Institute, made up of Competitive Power Ventures, EnerNOC, General Electric and other companies invested in clean-power technology, commissioned the report. The Brattle Group concluded in the report that, “Following a review of the reliability concerns raised and the options for mitigating them, we find that compliance with the CPP is unlikely to materially affect reliability.”
A 109-mile transmission line in Arizona running from Maricopa County to Pinal County went into service last week, strengthening a crucial energy junction serving Arizona, Nevada and California. The Electrical District No. 5-to-Palo Verde Hub line, which came in on time and about $3 million under budget, eases constraints in that region. It was a joint project between the Department of Energy’s Western Area Power Administration and the Southwest Public Power Resources Group. The $79 million project was funded through the American Recovery and Reinvestment Act.
“This transmission line is a clear example of how, through partnerships, we can modernize our energy infrastructure to jumpstart our energy-based economy ahead of its time. We are extremely optimistic that the new line will add reliability to the region’s grid and provide another pathway to interconnect more renewable generation resources,” said Western Administrator and CEO Mark Gabriel.
The Federal Energy Regulatory Commission last year approved 19 hydro licenses totaling 1,936 MW, according to its Energy Infrastructure Update. In 2013 there were 12 such approvals. This year, the commission will consider 18 applications for license and exemptions that were filed in 2014. The FERC update said hydro makes up 8.42% of the installed capacity in the U.S.
Vermont Yankee Plant Gets ‘Green’ Finding After Closing
The now-closed Vermont Yankee nuclear plant received a “green” finding from the Nuclear Regulatory Commission because of a problem found the day after the plant shut down for good. Entergy workers realized that water levels in the reactor core were lower than they thought because of faulty calculations, according to the NRC. The 43-year-old reactor was shut down Dec. 29 and is being decommissioned. The NRC said the problem was of “very low safety significance.”
DTE’s Fermi 3 Takes Next Step Toward Getting License
Nuclear Regulatory Commission staff have recommended that DTE’s proposed Fermi 3 nuclear plant be granted a combined construction-operating license. Although DTE has not yet made a final decision to build the reactor, the licensing process is moving forward. If the license is granted by the NRC, it will give DTE more options in deciding on a final plan. “We have not announced or committed to building a unit at this time,” said Guy Cerullo, DTE spokesman. “We’re keeping our options open.”
Exelon’s $6.8 billion bid to acquire Pepco Holdings Inc. took two steps forward last week when it gained approvals from both the New Jersey Board of Public Utilities and the staff of the Delaware Public Service Commission.
The New Jersey BPU gave final approval Wednesday to a settlement that will give Atlantic City Electric customers $62 million in rate credits.
The BPU’s approval means that the acquisition now needs only the regulatory approval of Delaware, Maryland and D.C. The Delaware PSC must vote on the staff settlement agreement, which was announced Friday.
Among other incentives in the agreement is a stipulation that guarantees New Jersey customers benefits equal to those eventually approved by Delaware, Maryland or D.C.
Pepco Holdings is headquartered in D.C., and includes Atlantic City Electric, Pepco, which serves D.C., and Delmarva Power & Light, with customers in Delaware and Maryland.
The $62 million in rate credits comes out to about $114 for each of Atlantic City Electric’s 544,000 customers.
Wednesday’s agreement contains other incentives, including:
An energy-efficiency program that would provide $15 million in energy savings over five years;
Promises to hire 60 union workers, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s current $709,000 annual giving for 10 years.
“This merger represents a great compromise that will provide many benefits to New Jersey,” BPU President Richard S. Mroz said in a written statement. “Additionally, the settlement protects the jobs of nearly a thousand New Jersey residents and keeps the company’s local operational headquarters in Mays Landing.”
Exelon CEO Christopher Crane and Pepco CEO Joseph Rigby also issued statements praising the agreement.
One party that didn’t sign the agreement was New Jersey’s consumer advocate, Stefanie Brand, director of the Division of Rate Counsel. Brand said the agreement, which was approved by the BPU staff last month, fails to protect consumers.
“There is nothing in the agreement that keeps Exelon from coming in and asking for a rate increase later that wipes out” the customer credits, she said in an interview Wednesday. “We certainly made our concerns known” during hearings and negotiations, she said.
Brand said Exelon more than doubled its initial rate credits offer during the negotiations that led to the settlement. “We do think [the BPU] got some good concessions, and I’m hopeful that Exelon won’t do things to wipe them out,” she said. “We were looking to lock it down a little bit more.”
More Approvals Needed
While Exelon has the approvals needed from the Federal Energy Regulatory Commission, Virginia and now New Jersey, it still needs those of Maryland, D.C. and Delaware.
“We are working cooperatively and productively with the public service commissions and other stakeholders in Delaware, the District of Columbia and Maryland to demonstrate how the merger will benefit the PHI utilities’ customers and communities,” Exelon Spokesman Paul Elsberg said Wednesday night. “We continue to expect the merger to close in second or third quarter of this year.”
Maryland
Maryland finished evidentiary hearings yesterday. Those hearings were supposed to conclude last week, but it took so long to go through every witness that two more hearings were added. Because of that, the decision of the Public Service Commission has been pushed back a week, from April 1 to April 8.
The state’s consumer advocate, the Office of People’s Counsel, has urged the PSC to turn down the deal as it stands, calling the benefits Exelon is offering “either non-existent or woefully deficient.”
Exelon has offered $40 million in customer credits in Maryland. The PSC staff has recommended $167 million in credits.
District of Columbia
Exelon and Pepco are also facing headwinds in D.C., where People’s Counsel Sandra Mattavous-Frye has called on the Public Service Commission to reject the merger.
Exelon has promised $14 million in incentives for D.C. Evidentiary hearings were to begin this week, but Mattavous-Frye asked the commission for more time to review additional information filed by Exelon and Pepco. A revised schedule for the hearings was released Wednesday night, which has evidentiary hearings pushed back to the end of March.
Delaware
Delaware has three days of hearings scheduled to start Feb. 18, but they may not be needed.
Late Friday afternoon, Exelon issued a statement that said it reached a settlement with the PSC staff, the Delaware Public Advocate, the Department of Natural Resources and Environmental Control and several trade groups.
The agreement calls for:
$49 million in rate credits for Delmarva electric and gas customers over 10 years;
$2 million in energy-efficiency program funding;
Reliability improvement commitments;
Hiring of at least 83 union employees;
Maintaining a headquarters in Newark and company facilities in Wilmington and Millsboro; and
Charitable contributions exceeding Delmarva’s 2013 level of $699,000 for 10 years after the merger.
Earlier in the week, Public Advocate David Bonar said Exelon initially offered $17 million in customer credits for Delmarva Power’s Delaware customers. “Obviously, we felt that was substantially low,” he said.
So did a consultant hired by the Public Service Commission, who said $62.9 million, or about $100 per customer, would be a more appropriate figure.
ISO-NE announced Thursday it had chosen a land-based, alternating current transmission project to address reliability concerns in the Boston area that came in about $260 million less than a competing undersea cable proposal.
The Greater Boston and Southern New Hampshire Reliability Project, proposed by Eversource (formerly Northeast Utilities) and National Grid, has a price tag of $739.7 million and is expected to be completed in 2018.
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The all-AC project was chosen over a proposal from New Hampshire Transmission, which included both AC and underwater high voltage, direct current transmission.
ISO-NE said the AC plan was selected because it is significantly less expensive and it promised superior operating performance.
“Greater Boston is the largest area of consumer demand on New England’s power system, and its transmission system is in critical need of an upgrade,” said Stephen Rourke, vice president of system planning.
The project is past due, ISO-NE said in a statement. “The year of need for certain components of the Greater Boston Reliability Project was pre-2013. The ISO is analyzing whether additional special operating plans need to be developed to be able to manage the system in Greater Boston during peak load conditions” before the project is complete, it said.
The land-based AC plan is a 25-mile series of overhead lines in existing rights-of-way, connecting a substation in New Hampshire with one in Massachusetts, along with two eight-mile underground sections.
SeaLink Falls Short
The competing project outside Boston, dubbed SeaLink, was proposed by NHT, a subsidiary of NextEra Energy, owner of the Seabrook nuclear station in southern New Hampshire. It would have run 50 miles of undersea HVDC cable from the Seabrook substation to a substation in Massachusetts, with another 18-mile section buried on land.
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The two project sponsors engaged in a vigorous debate about their opponents’ estimates and the costs to be incurred by ratepayers. The AC partners pointed to the initial high cost of SeaLink, its expensive technologies and the risks associated with undersea cables.
NHT contended SeaLink would be cheaper, saying the AC project would affect service, forcing utilities to buy more expensive replacement power during its construction. NHT upped the ante by offering to swallow any overruns above a cost cap of $679 million.
Both plans include the reconductoring of several 115-kV lines and other substation and transmission equipment upgrades, estimated to cost $221 million.
Concerns Identified in 2009
ISO-NE said the Boston area’s reliability concerns were identified in 2009. Several upgrades, including line reconductorings, were advanced to ensure reliability could be maintained after the retirement of all four Salem Harbor generating units — two in 2011 and two in 2014, according to the RTO.
In 2013, ISO-NE updated its original needs assessment to reflect several major system changes, including resource additions and retirements, changes in underground cable ratings in Boston, and updated load forecasts.
ISO-NE planning engineers worked with NHT to help develop its plan from a conceptual proposal into a workable solution. The RTO also worked with Eversource and National Grid to update components of the AC project based on the findings of the 2013 needs assessment. Updated versions of both plans were presented to the ISO-NE Planning Advisory Committee in June 2014.
The project will be discussed at Wednesday’s PAC meeting.
Eversource ups Tx Spending
In an earnings call with analysts last Thursday, Eversource identified the Boston area as one of its key areas for investment. It announced that it will spend $3.9 billion on transmission upgrades and expansions from 2015 to 2018, a $900 million increase over the $3 billion proposed a year ago.
It identified several big-ticket items in the area, including its share of the AC plan, totaling at least $707 million. There are also “hundreds” of reliability projects throughout New England coming in at $968 million.
Exelon’s $6.8 billion bid to acquire Pepco Holdings Inc. took another step forward Wednesday when the New Jersey Board of Public Utilities approved a settlement that will give Atlantic City Electric customers $62 million in rate credits.
The board’s approval means that the acquisition now needs only the regulatory approval of Delaware, Maryland and D.C.
Among other incentives in the agreement is a stipulation that guarantees New Jersey customers benefits equal to those eventually approved by Delaware, Maryland or D.C.
Pepco Holdings is headquartered in D.C., and includes Atlantic City Electric, Pepco, which serves D.C., and Delmarva Power & Light, with customers in Delaware and Maryland.
The $62 million in rate credits comes out to about $114 for each of Atlantic City Electric’s 544,000 customers.
Wednesday’s agreement contains other incentives, including:
An energy-efficiency program that would provide $15 million in energy savings over five years;
Promises to hire 60 union workers, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s current $709,000 annual giving for 10 years.
“This merger represents a great compromise that will provide many benefits to New Jersey,” BPU President Richard S. Mroz said in a written statement. “Additionally, the settlement protects the jobs of nearly a thousand New Jersey residents and keeps the company’s local operational headquarters in Mays Landing.”
Exelon CEO Christopher Crane and Pepco CEO Joseph Rigby also issued statements praising the agreement.
One party that didn’t sign the agreement was New Jersey’s consumer advocate, Stefanie Brand, director of the Division of Rate Counsel. Brand said the agreement, which was approved by the BPU staff last month, fails to protect consumers.
“There is nothing in the agreement that keeps Exelon from coming in and asking for a rate increase later that wipes out” the customer credits, she said in an interview Wednesday. “We certainly made our concerns known” during hearings and negotiations, she said.
Brand said Exelon more than doubled its initial rate credits offer during the negotiations that led to the settlement. “We do think [the BPU] got some good concessions, and I’m hopeful that Exelon won’t do things to wipe them out,” she said. “We were looking to lock it down a little bit more.”
More Approvals Needed
While Exelon has the approvals needed from the Federal Energy Regulatory Commission, Virginia and now New Jersey, it still needs those of Maryland, D.C. and Delaware.
“We are working cooperatively and productively with the public service commissions and other stakeholders in Delaware, the District of Columbia and Maryland to demonstrate how the merger will benefit the PHI utilities’ customers and communities,” Exelon Spokesman Paul Elsberg said Wednesday night. “We continue to expect the merger to close in second or third quarter of this year.”
Maryland
Maryland finished evidentiary hearings yesterday. Those hearings were supposed to conclude last week, but it took so long to go through every witness that two more hearings were added. Because of that, the decision of the Public Service Commission has been pushed back a week, from April 1 to April 8.
The state’s consumer advocate, the Office of People’s Counsel, has urged the PSC to turn down the deal as it stands, calling the benefits Exelon is offering “either non-existent or woefully deficient.”
Exelon has offered $40 million in customer credits in Maryland. The PSC staff has recommended $167 million in credits.
District of Columbia
Exelon and Pepco are also facing headwinds in D.C., where People’s Counsel Sandra Mattavous-Frye has called on the Public Service Commission to reject the merger. Exelon has promised $14 million in incentives for D.C.
Evidentiary hearings were scheduled to begin this week, but Mattavous-Frye asked the commission for more time to review additional information filed last week by Exelon and Pepco. According to a revised procedural schedule released Wednesday night, evidentiary hearings have been pushed back to the end of March. D.C.
Public Service Commission spokeswoman Kellie Didigu said that commission policy is to issue a decision within 90 days from the date the record closes. Under the revised schedule, the record will close May 13, pushing a decision to as late as August.
Delaware
Delaware has three days of hearings scheduled to start Feb. 18, but Public Advocate David Bonar thinks they may not all be needed. “We’re still working very hard to try to reach a settlement agreement,” he said in an interview Wednesday, “and we’re fairly confident that we can achieve that goal.”
He said Exelon initially offered $17 million in customer credits for Delmarva Power’s Delaware customers. “Obviously, we felt that was substantially low,” he said.
So did a consultant hired by the Public Service Commission, who said $62.9 million, or about $100 per customer, would be a more appropriate figure.
Since then, Exelon has sweetened the pot, according to Bonar. While he wouldn’t give hard figures, he said “it has grown substantially.”
He said he feels the sides are close to a settlement. “We are pretty well done meeting face to face,” he said.
The original version of this story incorrectly stated that two more “public sessions” were added to Maryland PSC evidentiary hearings due to the amount of people who wanted to testify. The sentence has been corrected to reflect that two more hearing dates were added due to the length of time it took to hear every witness.
The 36% increase in prices in last week’s ISO-NE capacity auction likely represents the peak for the foreseeable future, analysts say.
The ninth Forward Capacity Auction cleared at $9.55/kW-month — up $2.52 over FCA 8 — outside of the Southeastern Massachusetts-Rhode Island (SEMA) zone, where prices were administratively set at $17.73/kW-month for 353 MW of new resources and $11.08/kW-month for 6,888 MW of existing resources.
The auction cleared about 1 GW of new generators, which can lock in their initial prices for seven years. During the lock-in period, they take a place at the bottom of the supply stack as zero-bid price takers.
“All else being equal, we believe that in the upcoming auction … the clearing price will decrease and will be set by the de-list bids of existing generators,” analysts for ICF International said, estimating that about 300 MW of excess supply cleared the auction. “Assuming no change in any parameters from FCA 9 … the maximum impact of the excess capacity in FCA 10 prices will be around $2/kW-month. Depending on the de-list bids, the impact may be less.”
Analysts for UBS Securities agreed that last week’s results “[signify] the near-term ‘top’ of this market.”
“We estimate next year’s auction could tentatively be in the ~$6-7/kW-month range … seeing this as the level at which transmission backs out of the auction (1.028 GW of [New York] imports cleared at $7.97/kW-month) as well as expecting a continued decline in demand response,” UBS said.
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They also predict that prices in the SEMA region will converge to the pool-wide average as the zone around Boston did this year.
Transmission Didn’t Clear Auction
Analysts said it appeared no transmission cleared last week. “It may be that the combination of transmission and generation costs are too high, the volumes required might be high or additional incentives associated with potential new CO2 regulations may be required to improve the economics of transmission projects,” ICF said. “Alternatively, some transmission projects may not have qualified.”
UBS said merchant transmission is a potential “wildcard” for future auctions, saying a project such as Eversource Energy’s (formerly Northeast Utilities) Northern Pass could offset as much as 400 MW of supply.
Demand Response Continues Contraction
Demand response, which cleared 3,041 MW in FCA 8, fell to 2,803 in last week’s auction, a drop of about 238 MW, or 8%, analysts said. ICF said about 600 MW of existing DR was de-listed while 367 MW of new DR resources — believed to be energy efficiency — cleared.
DR has been on a steady decline in New England’s capacity market since peaking at 3,645 MW in FCA 6.
In contrast, ICF said there appeared to be no significant de-listing of existing generators, indicating that their de-list bids were below clearing prices.
“This implies that existing generators believe that capacity prices are high enough to offset potential penalties from underperformance under the [Pay-for-Performance program] or that penalties will be adequately compensated by credits for performance under scarcity conditions,” ICF said.
New generators from Exelon, LS Power and Competitive Power Ventures were the apparent winners in New England’s capacity auction last week, while NRG Energy and Public Service Enterprise Group walked away empty handed.
ISO-NE’s ninth Forward Capacity Auction added more than 1,000 MW of gas generation to the region’s mix. Two of the sites are expansions of existing power generation facilities and the third, and largest, is a greenfield site that has been slated for development for at least 16 years. (See Prices up One-Third in ISO-NE Capacity Auction.)
The new resources are a 725-MW combined-cycle resource in Oxford, Conn., under development by Competitive Power Ventures, and Exelon Generation’s two-unit 195-MW CT in Medway, Mass., according to the companies.
Analysts agree that LS Power, with two 45-MW combustion turbines in Wallingford, Conn., was the other successful bidder. LS Power did not return telephone calls seeking comment.
Analysts at ICF International called the new generation a validation of ISO-NE’s Pay-for-Performance program, which increased both performance expectations and penalties for plants that fail to deliver power when called. “The restructured capacity market is working,” ICF said. “Since 2002, most of the capacity additions in ISO-NE have either been sponsored by a state or driven by administratively set prices. FCA 9 is the first auction with major economic capacity additions.”
All of the new generators are believed to have dual-fuel capabilities, meaning they should be able to operate even if they cannot obtain natural gas.
PSEG, NRG Units Did not Clear
PSEG confirmed that its proposed 475-MW combined-cycle plant at its existing Bridgeport Harbor Station site had not cleared and analysts for UBS Securities said it appeared NRG’s proposed 340-MW combined-cycle repowering of its Canal Generating Station also failed to clear.
UBS said NRG still may develop the Canal plant, possibly aided by bilateral contracts with local municipal utilities. The site is in the Southeast Massachusetts-Rhode Island (SEMA) zone, which failed to procure enough capacity resources for the 2018/19 commitment period.
PSEG said that although its Bridgeport plant did not clear in FCA 9, it will continue development work and seeking community approvals to “allow us to be ready when and if the markets indicate support for this investment in the future.”
CPV Site’s Long History
The site of CPV’s Towantic Energy Center in Oxford has a rather storied history. First proposed in the 1990s, the site appeared ready to be developed more than a decade ago until the bankruptcy of Calpine scuttled the plan. Rights to the plant were acquired by General Electric in 2007, which designed the current configuration. It is a partner in the plant with CPV.
The site was fully permitted in 1999 for a 512-MW plant. Plans that call for a larger footprint have sent the project back before the Connecticut Siting Council.
CPV spokesman Braith Kelly said the company fully expects the project to be completed on time when the capacity commitment period starts on June 1, 2018.
“The technology is greatly improved from the time of the previous permits, so the environmental impact will be even less than before,” he said.
However, an active citizen group has been opposed to the plant, citing environmental and health concerns.
Delays, if they occur, would not necessarily impair the company’s standing in the ISO-NE market.
“A resource delayed for reasons beyond its control (one example could be lawsuits that delay the issuance of needed permits) can go to [the Federal Energy Regulatory Commission] and request a one-year deferral of its capacity supply obligation,” said Marcia Blomberg, a spokeswoman for ISO-NE.
She also said a resource that cannot meet its schedule can trade out of its obligation through annual and monthly reconfiguration auctions leading up to each capacity commitment period.
“Or it can make a bilateral trade with another resource. This is the most likely path to be taken by resources that are delayed for some reason,” she added.
Peakers
The successful peaking units likely wouldn’t face the challenges CPV has, as they are expansions of existing sites.
However, last year it reached an agreement with Wallingford, Conn., to add two peaking units to its existing array of five 50-MW units. The town owns and operates its own municipal electric system and leases the power plant site to LS Power. The company bought the generating plant from Pennsylvania-based PPL in 2011.
Exelon said both of its Medway units will run mainly on natural gas but will have the ability to run on ultra-low-sulfur distillate fuel oil as a back-up. ISO-NE has been encouraging the development of dual-fuel-capable generation to ease natural gas pipeline constraints during the winter.
Exelon said it is currently in the permitting phase for the Medway expansion. Construction is expected to begin in 2017 and be completed by mid-year 2018.
The company currently owns and operates approximately 2,200 MW of both combined-cycle and peaking generation in the Boston area, including the existing three-unit, oil-fired 117-MW peaking facility in Medway.
The Medway facility also is in the generation-short SEMA zone.
UBS estimates the plant, expected to cost about $150 million, will generate $35 million to $40 million in incremental cash flow, based on the $17.73/kW-month clearing price, adding 2 cents per share to Exelon’s earnings.
Entergy yesterday reported a drop in fourth-quarter earnings, but executives gave an upbeat outlook, citing stronger-than-expected growth in retail sales and forecasts of increasing demand as a result of the “industrial renaissance” in the Gulf.
Entergy Louisiana’s 560-MW Ninemile 6 generating plant, its first new power plant in nearly 30 years, will help power Louisiana’s industrial growth.
The company posted fourth-quarter net income of $120.1 million, or 66 cents a share, down from $146.9 million, or 82 cents a share, for the same quarter in 2013. Entergy cited higher taxes and increased operating costs as a cause for the drop. But revenue grew by 5% to $2.83 billion, beating estimates of $2.7 billion.
For the year, retail sales grew by 2.3% versus a forecasted 1.9%. “Industrial sales led the way with 5% growth, beating our estimates of 2.8% by a wide margin,” Entergy CEO Leo Denault told analysts during a Feb. 5 conference call. Chemicals, petroleum refining and pulp and paper were responsible for nearly 60% of the industrial growth.
While most of the increases came from existing customers, Entergy said it is also seeing increasing numbers of new customers, forecasting that retail sales will grow by 3.25 to 3.75% annually through 2017. “We continue to believe that Entergy has some of the best growth fundamentals in the business,” Denault said.
Lake Charles Tx Project
Entergy cited that growth in a filing with MISO in December for out-of-cycle approval of a $187 million transmission project near Lake Charles, La., which the company says will be “one of the largest transmission projects in Entergy history.”
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News of the project, which will include new substations and 25 miles of 500-kV and 230-kV lines, sparked controversy among MISO transmission developers. Entergy requested expedited approval of the project, saying it needed to be started in the first half of 2015 for completion by summer of 2018, meaning that it would be built by Entergy and not considered for a competitive solicitation under the Federal Energy Regulatory Commission’s Order 1000.
Entergy’s footprint in the Gulf Coast includes fast growing petroleum refining, industrial gases and wood products.
Declining petroleum prices and cutbacks in drilling portend some reduction in growth among certain petrochemical customers, but the outlook for Entergy’s core industrials remain robust, Entergy executives said.
Entergy Wholesale
Company executives said reduced drilling could increase natural gas prices, improving the margins for the company’s nuclear power plants, which operate in competitive markets in New York and New England.
Executives said the Entergy Wholesale Commodities group also will benefit from ISO-NE’s Forward Capacity Auction this week, which saw prices increase by about one-third. “We are seeing some positive changes in capacity markets,” Denault added. (See Prices up One-Third in ISO-NE Capacity Auction.)
MISO Integration
Reviewing 2014 trends, he also pointed to Entergy’s first year as part of MISO’s new southern region. “Although the numbers are still estimates, it now appears that customers across the utility will in fact realize more MISO-driven savings than we had originally expected.”
Arkansas Rate Structure
Entergy recently said it intends to file a new rate case in Arkansas, likely in March or April. It has been seeking regulatory changes from the state legislature that could boost earnings. “I would expect that we would [back] some legislation around this” soon, said Theo Bunting, group president of utility operations.
Some 24,447 MW of capacity resources cleared Monday’s auction at $9.55/kW-month, an increase of more than one-third over the $7.025/kW-month clearing price for most resources in FCA 8 last year. Administrative pricing was used in the Southeastern Massachusetts-Rhode Island zone, with prices set at $17.73/kW-month for 353 MW of new resources and $11.08/kW-month for 6,888 MW of existing resources. (Click to zoom.)
ISO-NE’s ninth Forward Capacity Auction saw prices increase by about one-third as 1,400 MW of new resources cleared to replace retiring coal plants.
While the RTO exceeded its six-state requirement of 34,189 MW by more than 500 MW, the Southeastern Massachusetts-Rhode Island zone failed to meet its obligation.
Monday’s auction was held to meet demand for the capacity commitment period from June 1, 2018, to May 31, 2019.
A preliminary estimate of the total cost is about $4 billion, compared to the 2014 auction that resulted in a total cost of about $3 billion.
The 24,447 MW of new and existing capacity resources that cleared the auction outside of SEMA/RI will be paid $9.55/kW-month. In FCA 8, most resources cleared at $7.025/kW-month.
The auction results included 1,400 MW of new capacity to help make up the shortage of generation created by the announced or pending retirements of more than 3,000 MW. New resources include three power plants — two in Connecticut and one in Southeastern Massachusetts — and 367 MW of new demand-side resources.
The resources include a 725-MW combined-cycle resource in Oxford, Conn., under development by Competitive Power Ventures. Two 45-MW combustion turbines in Wallingford, Conn., and a 195-MW CT in Medway, Mass., also cleared.
The auction started with 5,432 MW of new resources qualified to compete, according to the RTO.
“The capacity market is working as designed. The price signals from last year’s auction helped spur investment in new resources, including more than 1,000 MW of new generating capacity, which will help address the region’s resource shortage and meet peak demand in 2018-2019,” ISO-NE CEO Gordon van Welie said in a statement.
He credited the Pay-for-Performance incentive that rewards the best performing resources — an innovation being used for the first time in FCA 9 — a sloped demand curve, a seven-year price lock-in for new resources and the ability to defer a capacity obligation for one year under extraordinary circumstances.
The region was divided into four zones: Connecticut; Northeast Massachusetts/Greater Boston (NEMA/Boston); Rest of Pool (ROP); and a new zone, Southeast Massachusetts/Rhode Island (SEMA/RI).
Shortfall
In SEMA/RI — home of the 1,517-MW Brayton Point generating station, which is set to close in 2017 — 7,241 MW qualified, falling short of the 7,479 MW needed to meet the zone’s local sourcing requirement.
The shortfall meant the zone was not opened to bidding. Instead, administrative pricing rules were triggered: 353 MW of new resources will receive the auction starting price of $17.73/kW-month, while the 6,888 MW of existing resources will receive $11.08/kW-month, which is based on the net cost to build a new resource.
