The Federal Energy Regulatory Commission on Friday granted PJM’s request to increase the cost-based energy offer cap to $1,800/MWh through March.
“We find that PJM has demonstrated that the current offer cap of $1,000/MWh in PJM is unjust and unreasonable for the winter months,” FERC said in its order, which became effective immediately (EL15-31). PJM had requested the Tariff revision go into effect Jan. 9.
Any cost-based offer, regardless of fuel type, will be eligible to set the LMP, the ruling said, rejecting a request by the Independent Market Monitor that it be restricted to natural gas.
“We find that restricting the proposal to natural gas costs alone would be unduly preferential to those sellers whose electricity is from natural gas-fired generation,” the order said.
Meanwhile, the commission said, it is “exploring potential improvements to market design and operational practices in order to ensure appropriate price formation in energy and ancillary service markets operated by ISOs/RTOs, which involved four staff papers and a series of workshops.”
The order included a request for comments as FERC seeks information on possible alternative offer caps and how it can mitigate seams issues among neighboring RTOs. (See PJM Seeking RTO Consensus on Offer Cap Increase.)
Responding to critics’ concerns, the commission said, “While PJM’s proposal may exacerbate seams issues by creating an incentive for external resources to attempt to sell into PJM when energy prices exceed $1,000/MWh, PJM is proposing only a short-term, temporary change applicable over the next few months.”
FERC also dismissed protesters’ assertions that the waiver would invite unsupported market-based offers above the $1,000/MWh cap.
“PJM’s proposal also provides additional protection to customers by requiring that market sellers provide cost justification for all bids above $1,000/MWh according to PJM’s cost development guidelines, in order to set the LMP,” it said.
Furthermore, it noted, “As we found in the February 2014 Waiver Order, allowing these offers to set LMP promotes efficient resource selection and sends clear market signals so that resource costs are reflected in transparent market prices.”
PJM’s proposal will allow generators to recover “justifiable costs” more than $1,800 through make-whole payments, but such offers would not set prices for other market participants.
The issue arose after a spike in gas prices last January pushed some generators’ costs to more than $1,000. At the time, FERC granted PJM’s request for a waiver from the cap to allow some gas-fired generators to cover their costs.
Because the proposal’s wording did not put a time limit on the price cap hike, FERC is requiring PJM to submit a filing by Feb. 27 to remove the waiver effective April 1. Because that change is ministerial, FERC said it will not entertain protests.
FERC also declined to establish hearing procedures, as some had requested. It also denied PJM Load Group’s motion for extension, saying that “the current situation requires immediate relief.” (See PJM Offer Cap Proposal Sparks Opposition.)
In addition, it disagreed with the Load Group that the proposal would result in retroactive ratemaking.
“The Tariff provisions revise offers solely in the energy market and are prospective, as of the date of this order. They, therefore, have no retroactive effect on past offers or energy prices,” the order said.
PJM’s Section 206 filing seeking the higher cap came after stakeholders failed over eight months to reach consensus on changes to the current $1,000/MWh cap. (See Last-Ditch Effort to Break PJM Offer Cap Deadlock Fails.)
The Federal Energy Regulatory Commission yesterday asked the Supreme Court to overturn an appellate court ruling voiding its authority to regulate the rules used by RTOs to pay for demand response, a day after PJM filed a contingency plan for including DR in its upcoming capacity auction.
The 59-page petition for a writ of certiorari, filed by attorneys for FERC and the U.S. Department of Justice, said the D.C. Circuit Court of Appeals erred in its May 23 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) that FERC lacked authority under the Federal Power Act to issue Order 745. The order requires RTOs to pay DR providers the same way they pay generators in energy markets — through LMPs.
“FERC’s conclusion that it has the authority [and the responsibility] to regulate the compensation paid by wholesale-market operators for demand-response commitments — and recouped in the wholesale rate set in the auction markets run by those operators — is the best and indeed only sensible reading of the statutory text,” FERC said.
The petition said the Supreme Court should take the case because of the growing importance of demand response.
“Even read most narrowly — as invalidating only FERC’s authority to regulate the level of compensation paid by wholesale-market operators to demand-response providers in energy markets — the decision … threatens significant damage to the nation’s wholesale-electricity markets,” FERC said.
FERC said its regulation of DR participation in wholesale markets “is essential to the commission fulfilling its statutory responsibility to ensure that [wholesale] rates are just and reasonable” and that the EPSA ruling also threatens the participation of DR in wholesale capacity markets.
“Because the court concluded categorically that ‘[d]emand response is part of the retail market,’ and determined that the FPA ‘unambiguously restricts FERC from regulating the retail market,’ its holding throws into serious question whether FERC may review any of the rules established by wholesale-market operators to govern demand-response participation — or perhaps even whether it has authority to permit the participation of demand-response providers in wholesale-electricity markets at all,” FERC said.
PJM Filing
On Wednesday, PJM submitted to FERC its contingency plan to incorporate DR in May’s Base Residual Auction if the Supreme Court rejects the petition and allows the ruling to stand (ER15-852).
General Counsel Vince Duane outlined the plan Dec. 18 to the Markets and Reliability Committee. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.) It would allow a load-serving entity “or other wholesale entity” to submit demand-side bids — “wholesale load reductions” — causing PJM to procure less capacity in the BRA.
PJM requested a response from FERC by April 1. If the court agrees to hear the case, PJM would withdraw the filing.
Duane said last month that PJM can expect a decision on whether the court will take the case in March or April.
The New Jersey Board of Public Utilities staff has recommended approval of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. in a settlement that would give Atlantic City Electric customers $62 million in rate credits.
The settlement, announced yesterday, came as the board was holding public hearings on the merger. If approved by the BPU, Exelon would need only approval from regulators in Delaware, Maryland and D.C. for a deal that would result in a company with more than 8 million customers from Illinois to the Atlantic.
Pepco Holdings, headquartered in D.C., includes Atlantic City Electric, the Pepco utility serving the District, and Delmarva Power & Light, with customers in Delaware and Maryland.
The $62 million in rate credits amounts to $114 for each of Atlantic City Electric’s 544,000 customers. The settlement also includes:
An energy-efficiency program that would provide $15 million in energy savings over five years;
Promises to hire 60 union employees, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s $709,000 annual giving for 10 years.
Rate Counsel Rejects Settlement
While the settlement with the BPU staff is a major step toward final approval in New Jersey, it was not signed by New Jersey’s consumer advocate, the Division of Rate Counsel.
Rate Counsel Stefanie Brand told a BPU evidentiary hearing yesterday that she did not sign the settlement because it includes no limit on the post-merger transition costs Atlantic City Electric can seek or any “stay out” — a period of time when the company is prevented from seeking a rate increase.
“Without express limitation on the level of post-merger transition costs recoverable by Atlantic in a future proceeding, costs associated with the merger — such as installing new computer systems or severance payments that would not have been incurred by Atlantic but for the merger — may be sought by the company in Atlantic’s next base rate case without limitation,” Brand said. “In other words, the $62 million of benefits to Atlantic’s customers may be offset or totally wiped out.”
Brand also criticized the settlement’s claims that it would require Exelon to improve Atlantic City Electric’s reliability performance.
The settlement says the company would forfeit 50 basis points in the next electric distribution base rate case filed after January 2021 if it fails to meet a System Average Interruption Frequency Index (SAIFI) of 1.05 interruptions per customer per year or a Customer Average Interruption Duration Index (CAIDI) not to exceed 100 minutes.
Brand said the thresholds represent no improvement over the commitments the company made in the Reliability Investment Program as part of its 2009 base rate case. Brand said the company already has met the 100-minute target and would likely meet the SAIFI goal before the program’s expiration in 2016.
Brand also said the “most favored nation” clause in the settlement — an assurance that New Jersey will benefit from any additional concessions achieved by states yet to approve the merger — was too narrow.
“The decision to approve the merger in New Jersey is not a slam dunk,” Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said in an interview. “The board will now have to consider the concerns of the non-signing parties and decide whether to approve the joint stipulation.”
Burcat’s group didn’t oppose the settlement. In return, Burcat said, Exelon has agreed not to oppose MAREC’s request that the BPU open a docket to order Atlantic City Electric to use a competitive process for the procurement of a portion of its obligations under New Jersey’s Renewable Portfolio Standards.
Public Hearings Begin in Maryland
The announcement of the New Jersey settlement came the day after a public hearing on the merger in Maryland.
About 100 people attended a Public Service Commission hearing on the merger in Rockville Tuesday night, the first in a series of public-comment hearings before evidentiary hearings begin in late January.
The majority of the crowd either belonged to or were supportive of environmental groups Chesapeake Climate Action Network (CCAN) and 350 Montgomery County, and they cautioned the commission on Exelon’s record on renewable energy.
Many of the speakers said Exelon’s goal was to use Pepco’s ratepayers to subsidize its nuclear fleet, which has become unprofitable.
About 100 attended a Maryland Public Service Commission hearing on the Exelon-Pepco merger in Rockville Jan. 13.
Others, including County Councilmember Roger Berliner, did not take a position on the merger at the hearing. Instead they urged the commission to make Pepco open up its transmission line right-of-ways for recreational use, if it approved the deal. Some speakers were hiking and mountain biking enthusiasts who enjoyed open right-of-ways in the territory of Exelon subsidiary Baltimore Gas and Electric but lamented that their trails were interrupted in Pepco’s territory.
Those who spoke in support of the merger included the Montgomery County Chamber of Commerce, the Maryland Chamber of Commerce, the Hispanic Chamber of Commerce and the Salvation Army.
Exelon has offered $100 million in credits for customers in Maryland and other states, but the PSC’s staff has said it thinks $167 million would be a more appropriate offer. (See Exelon-Pepco Merger Faces Headwinds in Maryland.)
The state Office of People’s Counsel has already urged rejection of the deal, calling Exelon’s “purported benefits … either non-existent or woefully deficient.”
PJM’s Independent Market Monitor Joe Bowring told the PSC in a letter that the merger “raises potential vertical and horizontal market power issues,” repeating concerns he expressed to the Federal Energy Regulatory Commission.
Bowring recommended that FERC require the companies agree to remain in PJM and permit independent third-party interconnection studies. He said Exelon should agree to a review of ratings of all elements of the combined transmission systems and a regular process for reviewing and updating transmission limits. Despite Bowring’s comments, FERC approved the merger without conditions in November.
Hard Sell in D.C.
In D.C., where some public hearings have already been held, Exelon faces a hard sell.
People’s Counsel Sandra Mattavous-Frye urged the D.C. Public Service Commission to reject the merger. “The office’s painstaking, comprehensive review and analysis details how the Pepco/Exelon application fails to meet each of the commission’s seven public interest factors,” she said in a statement last month. “Overall, there are far too many risks for consumers and nothing but benefits for Pepco and Exelon.”
A coalition calling itself Power D.C. is also opposing the merger. Although Exelon has promised $14 million in incentives for the District, the coalition, which includes the Sierra Club, CCAN, D.C. Working Families and the D.C. Environmental Network, said the merger wouldn’t benefit ratepayers or businesses.
Delaware PSC Wants $63M
Exelon has offered $17 million in customer credits in Delaware, but a Delaware Public Service Commission consultant has said $62.9 million, or $100 per customer, would be a proper offer. Public hearings are scheduled for February there.
Delaware Public Advocate David L. Bonar said he didn’t expect a settlement in New Jersey so soon.
“I was somewhat surprised the BPU signed off on the agreement as quickly as they did, but not surprised that the New Jersey Rate Counsel declined,” he said.
Bonar said all parties are continuing to work toward a settlement in Delaware, but added, “We are not quite there yet. A merger worth billions of dollars can’t be taken lightly.”
He said his office is “not ready, at this time, to say it’s in the best interest of Delaware as presently constructed.”
Burcat said he didn’t think what happened in New Jersey, where ACE serves a minority of the state, will have an impact on the question in Delaware, Maryland or D.C.
“In the other jurisdictions, Exelon will end up controlling the vast majority of the service territories and will also end up serving most of the electricity load,” Burcat said. “Consequently, the ramifications of the merger in these jurisdictions are substantially higher.”
Exelon has repeatedly said the merger would be a good thing for all concerned. “We believe that the facts — which are available in the testimony we’ve filed with the commission and other information we have provided to the parties through the regulatory process — will show that this merger is in the public interest and will benefit customers and the community,” spokesman Paul Adams said last month.
Justice Department Review
RTO Insider reported last month that the U.S. Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its anti-trust review of the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
Exelon said yesterday that the Justice Department’s review period expired Dec. 22, meaning the Hart-Scott-Rodino Antitrust Improvements Act no longer precludes completion of the merger.
“Exelon and PHI will continue to work cooperatively with the DOJ until it advises them that it has concluded its evaluation of the merger,” Exelon said.
Michael Brooks contributed to this article.
[Editor’s Note: An earlier version of this article incorrectly said the Maryland Public Service Commission had sought $167 million in concessions from Exelon. That recommendation was by the PSC’s staff.]
The Market Implementation Committee will review modeling practices that PJM said may be shortchanging loads with transmission agreements that pre-date the RTO’s capacity market.
The MIC last week approved an issue charge proposed by Stu Bresler, vice president of market operations.
Bresler said the issue arose last year after a PJM member in Commonwealth Edison’s locational deliverability area (LDA) sought a waiver of PJM’s Reliability Assurance Agreement before last May’s base residual auction.
Bresler was referring to the Illinois Municipal Electric Agency, which won a waiver from the Federal Energy Regulatory Commission regarding its means of serving the Naperville, Ill., portion of its load.
Last week, IMEA filed a second waiver request for May’s 2018/19 BRA.
“The fundamental problem is that when a PJM zone is identified as a potentially constrained LDA (and therefore separately modeled with its own [variable resource requirement] curve), internal resource requirements are triggered that do not recognize or give credit for the capacity transfer capability rights of [load serving entities] that have historic, long-term, firm transmission rights to serve their network loads with external resources,” IMEA wrote in its request (ER15-834).
Market Monitor Joe Bowring questioned the impact of the rule change being considered by PJM. “It’s a broad issue because it creates the possibility of others requesting the same thing,” he said.
Bresler, however, said potential changes would affect an “extremely small population of market participants who find themselves in this situation.”
MIC to Work Synch Reserve Payments Inquiry
The MIC will hold special meetings to consider the Market Monitor’s effort to change compensation for Tier 1 synchronized reserves.
PJM’s Lisa Morelli suggested the approach after briefing the MIC last week about a Jan. 5 education session on the issue. No members objected to her recommendation.
Tier 1 synchronized reserves — all on‐line resources following economic dispatch and able to ramp up at PJM’s request — are paid the Tier 2 synchronized reserve market clearing price whenever the non-synchronized reserve price is more than zero. Bowring said it’s wasteful to pay Tier 1 the same price as Tier 2, because only Tier 2 are subject to penalties for non-performance. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)
PJM Posts MISO Price Predictions Before CTS Vote
IT SCED provides four look-ahead solution intervals over a two-hour period, from Interval 4 (135 minutes before flow) to Interval 1 (30 minutes before flow). Click to zoom.
Last week PJM, which will seek stakeholder approval next month for an interchange trading product with MISO, released statistics on the accuracy of its predicted prices at the MISO interface.
The statistics were included in an MIC briefing on the proposed Coordinated Transaction Scheduling (CTS) product, which is similar to one PJM launched Nov. 4 with NYISO.
Under CTS, traders would be able to submit “price differential” bids that would clear when the price difference between MISO and PJM exceeded a threshold set by the bidder.
The product would use price forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch engine (IT SCED). From January through November 2014, IT SCED successfully predicted the MISO price within +/-$5/MWh about 60% of the time (see chart).
CTS is intended to reduce uneconomic flows between PJM and its western neighbor. PJM says almost half of the transactions from PJM into MISO occur when prices are higher in PJM.
Intermittent Resources Panel Wants to Stick Around
The Intermittent Resources Task Force, which completed its last assignment in October, is proposing a charter revision that would turn it into a standing subcommittee.
Among other duties, the subcommittee would monitor the participation of intermittent resources in the energy, capacity and ancillary services markets, and recommend improvements to PJM systems and procedures.
Like the task force, which was created in 2008, the subcommittee would report to the MIC. It would conduct business primarily through quarterly conference calls.
The MIC will be asked to vote on the new charter next month.
The Federal Energy Regulatory Commission last week approved rule changes allowing New England grid operators to fully integrate demand response into their wholesale markets, including their reserve markets (ER15-257).
The changes were proposed by ISO-NE and the New England Power Pool to bring their rules into conformance with FERC Order 745.
Some changes became effective on Jan. 12 in advance of the ninth Forward Capacity Auction, scheduled for Feb.2. Others will take hold on June 1, 2017.
FERC turned aside objections from power generators who want any rulings related to Order 745 deferred until a successful challenge to FERC jurisdiction over DR in a federal appeals court is resolved.
The New England Power Generators Association has argued that the D.C. Circuit Court of Appeals ruling in Electric Power Supply Association v. FERC says that FERC lacks jurisdiction to regulate rates for supply-side demand response resources and could extend to the forward capacity and forward reserve markets.
“We find it appropriate at this time to proceed with these market enhancements until further action is taken,” FERC wrote.
In 2011, ISO-NE and NEPOOL proposed a two-stage process to incorporate DR into the wholesale markets. Stage one defined an initial transition period that began in June 2012. Stage two rules were proposed in this docket in October 2014.
ISO-NE currently models a single DR asset that can both reduce its load and inject energy into the electric grid as two separate assets, according to FERC. ISO-NE and NEPOOL say the changes will allow DR to provide operating reserves as other resources without altering the existing co-optimized energy and real-time operating reserves market. “These changes include revisions to demand response resources’ energy market offer parameters to allow such resources to provide 10-minute and/or 30-minute reserves,” FERC said.
NEPGA also said the revisions discriminate against generation resources in the compensation of DR for avoided line losses.
FERC rejected that argument, saying that “under a common market structure, all resources will have comparable obligations and be paid the comparable price for delivery.”
PJM generation owners conducted winter preparation tests of 156 infrequently used power plants between Dec. 5 and Jan. 2, cranking up 7,549 of a possible 9,349 MW for a success rate of 81%.
Units failed to start due to problems with fuel-handling systems and emission systems, as well as oil leaks, tube leaks and cranking diesel generator failures, PJM officials told the Operating Committee last week. The tests were considered successful if the units were able to generate installed capacity levels, even if it took two or three attempts to get them running.
Warm weather in December forced numerous test cancellations and pushed the testing into January. An additional 18 units (980 MW) were scheduled for testing last week.
The testing will result in more than $3 million in make-whole payments, officials said.
Operators of 91% of generating units — representing 98% of installed capacity — reported to PJM that they had completed their own cold weather checklist or the one in PJM Manual 14D.
PJM will seek stakeholders’ input on ways to encourage interconnection customers to file their requests earlier, officials told the Planning Committee last week.
A more granular review of PJM’s interconnection queue over the past 14 years indicates that about 80% of requests are for new generation projects, and that 15% of those are now in service. Proposals for upgrades had a 58% success rate, said David Egan, manager of interconnection projects.
The review, which excluded active projects, looked at queues A through AA1 since 2000, when the queuing process began.
The review was sparked by last month’s queue status update, which showed that PJM’s new graduated queue-entry cost structure had failed to persuade developers to file applications earlier. (See PJM: Interconnection Customers Still Procrastinating.)
Under the new structure, the deposit for applications filed in the first four months was set at $10,000; for the fifth month it was set at $20,000; and for the last month, $30,000. Despite the cost increases, most developers waited until the last days to file, leading to an uneven work load for project managers.
“We’re not jumping to any immediate changes but will be coming back with further discussion,” said Steve Herling, vice president of planning. “We’ll be coming up with a problem statement. We now have a much more complete picture of these queues.”
The 2,394 project applications in the queues represent 289,742 MW, according to Egan. Of those, 30,546 MW (11%) are in-service and 16,360 MW were withdrawn.
Duke Energy plans to make its first substantial purchase of solar power in Indiana, giving customers the option to buy “locally sourced” solar energy credits to help cover the cost.
The utility, with more than 800,000 customers in 69 counties, asked the Indiana Utility Regulatory Commission on Dec. 29 (Docket No. 44578) for permission to acquire a total of 20 MW of power from four solar farms: 5 MW each from Geres Energy, McDonald Solar, Pastime Farm and Sullivan Solar.
The sites are under construction, or soon will be, in Clay, Howard and Sullivan Counties. They’re set to go on line by the end of 2016.
The 20 MW of solar power is miniscule for a utility with more than 7,500 MW of mostly coal-based generating capacity in Indiana. But it amounts to the first utility-scale solar commitment for Duke in Indiana, spokesman Lew Middleton said.
Beyond Net Metering
Virtually all Indiana-generated solar power entering Duke’s system is currently on a net-metering basis. According to the IURC’s 2014 net metering report, Duke Indiana had 241 customers with their own solar panels that generated 1,458 kW in 2013. That year Indiana ranked 19th in the nation for photovoltaic solar deployment, with only about 88 MW installed, according to the Solar Industry Association.
The proceeds from the sale of renewable energy credits (RECs) would be applied toward the ratepayers’ share of the cost to buy energy from the solar farms.
Middleton said it’s too early to say how much it will cost customers to buy the solar renewable energy credits.
A REC is a tradable instrument that represents the environmental attributes of electricity generated from renewable energy. The credits are distinct from the electricity commodity, allowing them and the actual electricity to be traded separately, Duke said.
Customers would be able to buy the solar RECs through an expansion of Duke’s GoGreen program. Currently, that program allows customers to buy at a premium blocks of wind-generated power, for a minimum of $1.80 a month.
Since 2006, customers opting to participate in the program have supported 43 MWh of wind energy, the utility says. About 1,322 customers — or less than 1% of Duke’s Indiana customer base — participate in GoGreen.
But in its filing with the IURC, Duke said a number of customers have expressed interest in locally sited renewable projects, as opposed to out-of-state RECs.
It also touted the plan as diversifying its generation portfolio and fostering economic development.
Indiana’s nascent photovoltaic deployment got a boost in 2013, when a 12.5-MW solar farm was constructed at the entrance to Indianapolis International Airport. Subsequently, another 10 MW of panels were added, making it the world’s largest airport solar farm. Indianapolis Power & Light purchases the power under a feed-in tariff.
More Solar
Under Duke Indiana’s 2013 Integrated Resource Plan “blended approach” scenario, the utility envisions potentially 2,000 MW of nameplate wind capacity and 330 MW of solar by 2033.
The Charlotte, N.C.-based utility notes that solar is the least-expensive renewable fuel source and typically amounts to more reliable capacity during summer peaking conditions than wind.
Much of Duke’s renewable activity has been focused at its Duke Energy Renewables unit, an arm of its commercial division. DER owns 150 MW of capacity at 21 solar farms. It also owns or has a management role in 15 wind farms totaling 1,800 MW in 12 states.
Solar power remains a tiny but growing portion of the energy mix in the Midwest. In the MISO region, renewables comprise about 12% of generation, and most of that consists of 13,000 MW of wind generation.
The price to install photovoltaic systems has fallen more than 34% since 2010, according to the Solar Industry Association. That’s piqued interest in solar even in Midwestern states such as Wisconsin, where solar is just one-tenth of 1% of the state’s installed generating capacity.
Yet several Wisconsin utilities last year, including Milwaukee-based We Energies, proposed to increase fixed costs customers pay on monthly bills and reduce how much they pay customers for their own solar generation fed back to the grid.
Utilities argue they need more revenue to cover their fixed costs as customers generate more of their own power and reduce consumption through energy efficiency efforts.
Duke Energy is facing opposition to plans to dispose of coal ash in abandoned clay pits in two North Carolina counties. Commissioners in Chatham County passed a resolution against the disposal plan in December, and Lee County commissioners did the same thing last week.
Duke, which has committed to cleaning up coal ash dumps and ponds at four retired generating stations within five years, says storing the ash in the abandoned surface mines is an environmentally responsible and safe plan. It says the landfills would be lined and capped. “This is a very industry-tested, safe application of how to dispose of this material,” said Duke spokesman Jeff Brooks.
Environmentalists are skeptical. “It’s not a matter of ‘if’ it will leak; it’s a matter of ‘when,’” said Therese Vick of the Blue Ridge Environmental Defense League.
FirstEnergy’s Davis-Besse Nuke Generates $1 Billion for Ohio
Davis-Besse Nuclear Power Station (Source: FirstEnergy)
The Davis-Besse nuclear power plant generates about $1 billion annually for the Ohio economy, according to a study by the Nuclear Energy Institute.
Richard Myers, the NEI’s vice president for policy development, said FirstEnergy commissioned the organization to produce the report in anticipation of using the information when it next goes before the Public Utilities Commission of Ohio for a long-term rate plan.
“This study confirms that Davis-Besse greatly strengthens the local, regional and state economies through job creation, tax payments, and direct and secondary spending,” Myers said.
Two western uranium miners are merging operations, spurred by a sluggish market for yellowcake uranium, which is refined into nuclear fuel.
Uranerz Energy, of Casper, Wyo., is merging with Denver’s Energy Fuels Inc. Uranerz shareholders will control 55% of the new company, which will adopt the Energy Fuels name.
Uranerz operates a mine in northeast Wyoming in which the uranium is extracted by “in situ leaching,” a process in which water is injected into rock and then pumped to the surface where the uranium is separated from the liquid. Energy Fuels operates a mine in Utah that employs conventional mining of uranium ore.
Nicole Kivisto is the new president and CEO of MDU Resources Group, the company that owns Montana-Dakota Utilities, Great Plains Natural Gas, Cascade Natural Gas and Intermountain Gas. Together, the companies serve 1 million electric and natural gas customers in Washington, Oregon, Idaho, Montana, Wyoming, Minnesota, North Dakota and South Dakota.
A native of North Dakota, Kivisto replaces K. Frank Morehouse, who resigned.
The owners of two small wind farms in Minnesota have filed for bankruptcy protection, putting the investments of a consortium of 360 farmers at risk.
Minwind Energy said expensive repair costs and a paperwork error that leaves them open to a possible federal fine of $1.9 million mean it no longer has enough money to run the wind farms.
The farms have 11 turbines, went online in 2002 and 2004, and were profitable until 2012. Most of the facilities’ energy is sold to Alliant Energy and Xcel Energy.
Entergy Spending $187 Million on Lake Charles Tx Project
Entergy Gulf States Louisiana has filed with the Louisiana Public Service Commission to build a transmission line and two substations to bolster service reliability in the Lake Charles area.
The 25-mile line is designed to supply an estimated 500 MW of load growth in the area in the next few years. Another 500 MW of load could develop in the near future, Entergy officials said. The company said construction would begin in 2016 and be completed in 2018.
Duke, Dominion Set Records During Cold Wave Last Week
Duke Energy Progress, the electric utility serving customers in parts of North Carolina and South Carolina, set a record for winter power use during last Thursday’s frigid temperatures.
The new peak of 14,473 MW was set for the hour ending 8 a.m. The previous record was 14,190 MW set last Jan. 7, during the Polar Vortex. Duke asked customers to conserve when temperatures began to plunge. By 8 a.m., the temperature in Charlotte, N.C., dipped to 8 degrees Fahrenheit.
Dominion Virginia Power’s 2.1 million customers also set a new winter peak during last week’s cold snap.
The utility’s load climbed to 19,870 MW at about 8 a.m. Wednesday. That eclipsed the previous record of 19,785 MW set on Jan. 30 of last year.
Hawaiian Electric Shareholders to Vote on Acquisition by NextEra in Spring
Shareholders of Hawaiian Electric Industries will vote this spring on NextEra Energy’s $4.3 billion offer for subsidiary utility Hawaiian Electric.
The acquisition also needs the approval of the Hawaii Public Utilities Commission. The companies say they expect to close the deal by the end of this year. The merger was announced late last year.
Clean Line Facing More Opposition to Illinois Transmission Line
Clean Line Energy’s Grain Belt Express, a proposed 750-mile direct-current transmission line designed to deliver wind energy from Kansas to markets east, is facing mounting opposition in Illinois.
A public meeting on the plan in Jacksonville, Ill., last week was attended not only by landowners whose property the 600-kV line could cross, but activists from three other states with experience in fighting Clean Line projects. A group calling itself Block GBE Illinois is forming to help coordinate opposition.
A company spokesman said Clean Line was committed to an “open, transparent process that keeps landowners, the public, elected officials, community leaders and the media informed about all facets of the project’s planning and construction process.”
Negotiations that could determine the future of an upstate New York nuclear power plant are set to conclude this week, following a 60-day schedule set out by state regulators.
The New York Public Service Commission in November ordered the owner of the 580-MW R.E. Ginna plant on Lake Ontario to negotiate a temporary contract with the local utility, Rochester Gas & Electric.
The plant has been deemed necessary to maintain system reliability in western New York in a study ordered by the PSC.
However, plant owner Constellation Energy Nuclear Group, a unit of Exelon, said it has lost $100 million over the past three years and will mothball the plant if it can’t get higher prices for its output.
The PSC wants the companies to negotiate a reliability support services agreement (RSSA) in which RG&E would buy Ginna’s output, which is currently sold at a loss into the NYISO wholesale market, according to Constellation. A negotiated settlement is due on Thursday, or the parties must inform the PSC they were unable to reach one.
Spokesmen for both Constellation and RG&E said negotiations are continuing but would not discuss details.
Ginna was formerly owned by RG&E but was sold to Constellation in 2004. The plant, which is licensed through 2029, had a 10-year power purchase agreement with RG&E that expired last June.
Rochester-area customers are likely to face higher electricity costs regardless of the outcome. A higher, above-market price would presumably be negotiated with Constellation, or if Ginna is eventually taken offline, the reduced supply will drive up prices in the western New York region.
Entergy, another nuclear power generator that owns the Indian Point Energy Center north of New York City, has opposed the RSSA. It argued, unsuccessfully, that Constellation has effectively tried to file a retirement notice without the proper procedures, time and expense any other nuclear power plant owner would be required to do under similar circumstances. It also said an RSSA presented directly to the PSC would not permit review and comment, to which other “must-run” agreements are subject.
RG&E, a subsidiary of Iberdrola USA that serves 371,000 electricity customers in a nine-county region, said it would face reliability issues anytime its load exceeded 1,430 MW. Its modeling indicates that would occur at least for 205 hours per year.
RG&E said a transmission project expected to be in service in late 2018 will shorten the length of the Ginna agreement.
The $250 million Rochester Area Reliability Project will access power from the New York Power Authority’s 345-kV cross-state transmission lines originating in Niagara Falls.
It includes 1.9 miles of new 345-kV transmission, 23.6 miles of new or rebuilt 115-kV lines, a new 345-kV/115-kV substation and equipment upgrades. The project was first intended to maintain reliability in the event of a long-term outage at Ginna.
