Depressed coal stockpiles have led to increases in MISO’s off-peak power prices and the cost impacts could increase with a repeat of last winter’s severe cold, officials said last week.
Coal generators in MISO, SPP and ERCOT have complained of difficulty obtaining coal for more than a year due to insufficient railroad capacity.
MISO clearing prices for fall were up 9% compared to fall 2013, with off-peak prices up 16%, due to increased coal-delivery costs and reduced output by generators seeking to conserve fuel due to low supplies, Todd Ramey, MISO vice present of system operations and market services, told the Federal Energy Regulatory Commission during a presentation at the commission’s open meeting Thursday.
MISO’s Market Monitor estimates that more than one-third of coal generation in MISO has implemented some form of coal conservation measures over the last six months, Ramey said.
Alan Haymes, of FERC’s Division of Energy Market Oversight, said coal stockpiles in the Midwest have declined since last year and are below five-year averages, although a mild summer helped mitigate the deficiency going into this winter.
“If the coming winter presents challenges similar to last year’s experience, the coal inventory problems could result in significant market impacts,” he said.
“It is likely the below-level stockpiles will persist through 2015 as railroads struggle to keep up with overall demand before system upgrades are complete. This is raising concerns among some generators that low stockpiles coming out of the winter could create challenges in the summer of 2015,” Haymes said.
Haymes said 166 power plants that burn coal from Power River Basin Mines in Montana and Wyoming have been struggling to maintain supplies because of insufficient capacity on BNSF Railway.
The railway has been pinched by an increase in shipments of grain and other cargo as the economy has improved. In addition, rail traffic to and from the Bakken oil fields of North Dakota have more than doubled since 2009, BSNF says.
Congestion in the east-west rail gateway in Chicago also has been a problem, said Michael Higgins, deputy director of the Surface Transportation Board.
A BNSF executive said the railroad is boosting capital expenditures and maintenance spending to $6 billion in 2015 from $5.5 billion this year. Last month BNSF said it would add 330 new locomotives to its 7,500-locomotive fleet.
The railroad, which serves 28 states and three Canadian provinces attributed some of the constraints to construction on its northern routes that increased congestion in the central part of its system. It says it expects to be rebuilding its customers’ coal stockpiles through 2016.
“We clearly understand that our service has not met customer expectations,” said Steve Bobb, an executive vice president of BNSF.
Commissioner Tony Clark asked BNSF whether and how the railroad determines which commodity receives priority during periods of tight constraint. Bobb replied that the railroad focuses on customers who report they have 20 days or less of inventory.
The commission also heard from Minnesota Power, which said that it experienced “severe” disruptions at its coal-fired plants last winter and at one point was down to a four-day supply of coal. Some units had to suspend operations; the utility purchased $27 million of higher-priced replacement power.
“The good news is that organized markets like MISO work and work well. We’ve had no electric service disruptions,” said David McMillan, senior vice president of external affairs at Minnesota Power parent Allete. “The bad news is that purchased energy prices were significantly higher than our own self-generation costs.”
A surcharge paid by Delmarva Power & Light customers to subsidize fuel-cell manufacturer Bloom Energy will come in at $3.3 million in January, down slightly from the previous month.
Under rules set by the Public Service Commission, a customer using 1,000 kWh will be assessed $4.52 for the Bloom Energy surcharge, down from $4.86 the previous month.
The PSC allowed Delmarva to collect the surcharge after declaring the natural gas used in fuel cells as renewable energy. The surcharge, which has generated nearly $63 million so far, was part of an economic incentive for Bloom to open a fuel cell manufacturing plant in Newark.
Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. picked up new opposition during the Public Service Commission’s first public hearing on the merger last week.
A coalition including the Sierra Club, Chesapeake Climate Action Network, D.C. Working Families and the D.C. Environmental Network introduced itself during the five-hour session. The group, which calls itself Power D.C., also set up a website that calls Exelon “a Chicago-based utility with a bad record,” whose acquisition of Pepco will not benefit ratepayers or businesses.
The state Supreme Court will hear Commonwealth Edison’s appeal of a Commerce Commission order requiring it to enter into supply arrangements with the non-profit, clean-coal FutureGen 2.0 plant.
The ICC’s order forces ComEd to buy electricity from the plant as part of the state’s renewable energy mandates. The Illinois Power Agency Act requires that a quarter of the electricity consumed in the state by 2025 be generated by cost-effective clean-coal plants.
FutureGen 2.0, a project plagued by construction delays and cost overruns, is one of the only clean-coal power sources in the state. ComEd and other utilities have argued that the ICC’s mandate excludes other out-of-state clean-coal sources. The court is expected to make a decision before the end of 2015.
Consumer Advocate Says Duke Owes Customers $114.8M Refund
Edwardsport IGCC Plant (Source: Duke)
The Office of Utility Consumer Counselor is asking state regulators to force Duke Energy to reimburse customers $114.8 million in costs that it says were associated with the startup of the problem-plagued Edwardsport coal gasification power plant.
The Utility Regulatory Commission allowed Duke to collect up to $2.6 billion from customers to offset the plant’s construction costs, but it prohibited Duke from passing on any costs relating to testing and startup.
Duke said the plant was operational in June 2013. But the consumer counselor contends the plant didn’t officially go into commercial operation until March 2014 and that Duke improperly passed on startup costs between 2013 and 2014.
The Public Service Commission will hold two public hearings to investigate future investments in smart grid technology.
Advocates say smart grid technology, including smart meters, can allow utilities and customers to better gauge electricity consumption and to induce customers to conserve energy. None of the four investor-owned utilities in Kentucky – Louisville Gas & Electric, Kentucky Utilities, Duke Energy and Kentucky Power – have launched smart meter programs yet.
The PSC will record comments at the hearings and accept written comments until Feb. 27 before releasing recommendations sometime next year.
Abigail Ross Hopper, director of the Maryland Energy Administration, has been named the next director of the federal Bureau of Ocean Energy Management, whose duties include managing offshore wind development.
Secretary of the Interior Sally Jewell announced Hopper’s appointment last week. “Abigail Hopper’s knowledge of the energy sector, experience working with a wide variety of stakeholders and her legal expertise will be valuable assets to the bureau and the department as we continue to ensure the safe and responsible development of our domestic energy and mineral resources and [create] an offshore wind program,” Jewell said.
Hopper was an energy adviser to Gov. Martin O’Malley before she became head of the Energy Administration in 2012. She was involved in helping the state pass the Maryland Offshore Wind Energy Act of 2013.
DTE is seeking a 3.2% rate increase – about $9.75 for an average customer’s monthly bill – to pay for system upgrades and power purchases, the company said in a filing with the Public Service Commission. The request would increase revenue $370 million for the Detroit company.
DTE said the rate increase would apply only to residential customers because the commission has already approved rate decreases for businesses and industrials. DTE said that commercial customers have been subsidizing residential customer rates for years.
DTE, which has about 2.1 million customers, said it has made about $3.5 billion in system upgrades in the past three years. DTE’s last residential rate increase was in 2010, when it asked for $444 million, and the PSC allowed $188 million.
JCP&L Rate Case Drags on for 3 Years, Lawmakers Angry
Consumer advocates and lawmakers say it is time for the Board of Public Utilities to make a decision in a three-year-old case involving Jersey Central Power & Light, the state’s second largest utility.
The Division of Rate Counsel in 2011 asked the BPU to force JCP&L to file a rate case, arguing that the utility was charging at least $200 million too much. The utility, whose parent company is FirstEnergy, filed a request in 2012 seeking a $31 million rate increase. An administrative law court judge has granted several delays but is expected to announce a recommendation on Dec. 29.
“This is simply too much,’’ said Ev Liebman, associate director of AARP’s New Jersey chapter. “It is actually worse that the BPU has failed to act on the petition to establish provisional rates.’’
“JCP&L has been shamelessly collecting too much money (from customers) for too many years,’’ state Sen. Linda Greenstein said.
The Public Utility Commission is considering a ban on utilities assessing a charge on customers who want a paper bill, rather than an electronic accounting of their charges.
A four-year investigation into paperless billing found that paper billing invoice fees constitute “unreasonable and inadequate service.”
To date, no electric or gas utilities have separate charges for mailing a paper bill, a practice that has been limited to a few telecommunications companies. A rule prohibiting charging for a paper bill will be introduced next month.
SunCoke Cutting Coal Production by Half in ‘Challenging Environment’
SunCoke Energy, the largest independent producer of coke used in U.S. steelmaking, announced last week that it was cutting coal production by 50% and laying off 175 workers.
The company, based near Chicago, said it is cutting production from 1.1 million annual tons to about 500,000 annual tons and could be shutting some of its Appalachian coal mines completely.
“While we plan to continue pursuing opportunities to sell all or a portion of our coal mining business, the challenging coal price environment has led us to make these hard decisions,” Fritz Henderson, SunCoke chairman and CEO, said in a statement.
Public Service Commission member Jon McKinney is stepping down at the end of the month, leaving only one member of the three-member commission available to hear any issues regarding the 2013 chemical spill that shut down part of the West Virginia American Water system.
First appointed in 2005, McKinney’s term officially ended in 2011, but a law allowed him to continue serving until officially replaced.
Until Gov. Earl Ray Tomblin appoints a replacement, McKinney’s departure will leave only Brooks McCabe, who joined the commission just last month, to decide on the ongoing American Water issues. PSC Chairman Michael Albert has recused himself from that case.
XTO Energy to Pay $5M for Damaging Wetlands in Fracking Operations
The U.S. Environmental Protection Agency and the Department of Justice announced yesterday that XTO Energy will spend an estimated $3 million to restore eight sites damaged by unauthorized discharges of fill material into streams and wetlands during fracking operations in the state.
The company was also fined $2.3 million for violations of the Clean Water Act, which prohibits the filling or damming of wetlands and streams without permission of the U.S. Army Corps of Engineers. Half of the penalty will go to the state Department of Environmental Protection, a co-plaintiff in the settlement.
Officials said that the company, a subsidiary of ExxonMobil, dumped sand, dirt, rocks and other fill material into streams and wetlands to construct well pads, road crossings, freshwater pits and other facilities during fracking operations in Harrison, Marion and Upshur counties. More than 5,300 linear feet of stream and 3.38 acres of wetlands were affected. The EPA said it was alerted to some of the violations by the state and discovered others through routine joint inspections conducted with the Corps. The company also disclosed violations at five sites following an internal audit.
PSC to Maintain Vote Timeline on Wisconsin Energy-Integrys Deal
The Public Service Commission rejected a request by consumer groups and businesses to delay a vote on Wisconsin Energy’s acquisition of Integrys Energy Group. The commission plans to vote on the deal on March 20.
Merger opponents had encouraged Wisconsin regulators to follow the lead of Michigan regulators, who postponed their vote on the $9.1 billion deal while it works with Wisconsin Energy’s utility, We Energies, to address energy supply concerns on the Upper Peninsula.
“We are not sticking our heads in the sand,” PSC Chairman Phil Montgomery said. “We are aware that the decisions in other jurisdictions may affect Wisconsin ratepayers.” Montgomery said the commission could attach conditions to the agreement later.
A North Carolina environmental group last week asked the Federal Energy Regulatory Commission to force Duke Energy and other utilities in the Southeast to form a regional transmission organization to share power reserves, rather than keep building new generating plants and boosting prices to pay for them.
The North Carolina Waste Awareness and Reduction Network (NC WARN), a frequent critic of Duke, noted that the merger of Duke and Progress Energy resulted in Duke supplying 95% of the electricity in North Carolina either directly or through municipal providers or cooperatives.
“Duke Energy manipulates the electricity market by constructing costly and unneeded generation facilities, directly leading to generating capacity far above what is reasonable or necessary to meet demand,” NC WARN’s complaint (EL15-32) said.
NC WARN also said Duke, in “not effectively connecting” its transmission system with neighboring utilities, has not complied with Order 1000.
The group said those utilities, including Dominion Resources, Southern Co. and the Tennessee Valley Authority, also have excess reserve margins. “The excess capacity throughout the Southeast region can and should be used among the various utilities to supplement each other’s generation requirements, rather than to duplicate the waste of unneeded or underutilized generation,” the group said.
The group cited the North American Electric Reliability Corp.’s 2014 Summer Reliability Assessment, which showed reserve margins of 24% in SERC-E (the Carolinas), 26% in SERC-N (primarily TVA), 37% in SERC-SE (primarily Georgia and Alabama) and 29% in the Florida Reliability Coordinating Council.
“The resulting total for [the] Southeast is much greater than the [NERC] reference margin of 14.8%,” the group said.
Duke said in a statement that it is following a responsible building program, and that its natural gas plants are necessary, replacing older, coal-fired plants.
“The North Carolina Utilities Commission has repeatedly rejected NC WARN’s similar arguments in the past,” Duke said. “In addition, the North Carolina Public Staff — which represents customers and the public — has repeatedly supported, as reasonable, Duke Energy’s investment in power plants and electricity reserves to meet customer needs at all times.”
NC WARN asked FERC to hold hearings in Raleigh, investigate Duke’s building plans and order Duke and its neighbors to form an RTO.
FERC has repeatedly ruled that RTO membership is voluntary. However, it has pushed Duke to join with its neighbors in interregional planning under Order 1000. (See FERC Rebuff of Duke Could Mean Closer Ties with PJM.)
New York regulators have doubled the cap on the amount of solar energy the state’s utilities are required to purchase under its net metering program.
The New York Public Service Commission ordered the increase to 6% of utilities’ peak demand from the current 3% (14-E-0151).
The commission acted in response to a request by environmentalists for an increase and a petition by Central Hudson Gas & Electric, which said it expected to reach the 3% cap in mid-2015, mostly through its residential solar programs.
The state’s 2008 Public Service Law set net metering at 1% of a utility’s peak demand, using 2005 as the base year, then gave the PSC discretion to increase the amount “in the public interest.” Central Hudson’s cap was increased to 3% in 2012 and a 2013 order raised the cap for the state’s other utilities.
Central Hudson is currently at about 83% of its 36-MW cap. National Grid is at 102% of its 196-MW cap, including projects proposed but not yet built within its service territory. As of Sept. 30, no other utility is above 63% of its cap.
The Solar Energy Industries Association, the National Resources Defense Council and other environmental groups had asked the commission to clarify the process for increasing the cap while Central Hudson had proposed increasing it to 12%.
The PSC expressed concerns about shifting costs onto ratepayers that decline or are unable to participate in a solar program. The 3% cap increases the average delivery bill of Central Hudson’s customers by about 0.5%. If all of the new net metering capacity is from solar generation, additional cost increases are expected to be from 0.5% to 1%, the PSC said.
In 2012, Gov. Andrew Cuomo announced the NY-Sun Initiative with a goal of installing 3 GW of solar power by 2023. In April 2014, Cuomo promised $1 billion for the program. Current capacity is more than 316 MW.
The new cap is effective Jan. 2. Central Hudson, Consolidated Edison, New York State Electric and Gas, National Grid, Orange & Rockland Utilities and Rochester Gas & Electric are to make compliance filings by Dec. 22.
The revisions were filed with FERC on Dec. 15, PJM Assistant General Counsel Jim Burlew told the Markets and Reliability Committee.
The revisions dictate that at least 90 days before the deactivation or disposing of a generator, the source receiving reactive power payments submit a filing with FERC either revising its rates or explaining why it has decided not to do so.
New York Gov. Andrew Cuomo’s administration last week banned hydraulic fracturing (fracking) in the state, saying there was insufficient data to overcome concerns over the practice’s health risks.
The long-delayed decision came during a year-end cabinet meeting after the state Department of Health completed a two-year review of the controversial technique to extract natural gas from deep shale formations.
“I have considered all of the data and find significant questions and risks to public health, which as of yet are unanswered,” acting DOH Commissioner Dr. Howard Zucker said. “I think it would be reckless to proceed in New York until more authoritative research is done.”
The Marcellus Shale formation extends from West Virginia, through Pennsylvania and Ohio, to western New York.
In 2012, the Department of Environmental Conservation asked the DOH to review its draft Supplemental Generic Environmental Impact Statement for High-Volume Hydraulic Fracturing (SGEIS). Prior to the health study, the DEC had conducted its own studies dating back to 2008.
The Health Department said it found significant “uncertainties about adverse health outcomes” and inadequate mitigation measures to protect public health.
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The department said several years of study are needed to determine how much risk is associated with fracking. “Until the science provides sufficient information to determine the level of risk to public health from [fracking] to all New Yorkers and whether the risks can be adequately managed, DOH recommends that [it] should not proceed,” the department said in the study.
The ban is unlikely to slow the shift to gas-fired generation in the state, however. According to the U.S. Energy Information Administration, the state generated nearly 60,000 GWh from natural gas in 2012, more than double the output in 2004.
The Federal Energy Regulatory Commission granted MISO’s request to suspend action on long-term transmission service requests (TSRs) between its north and south regions through April 1 as it tries to resolve a flow dispute with SPP.
The waiver (ER14-2022) also allows MISO to waive Tariff requirements and North American Energy Standards Board standards involving flows exporting from MISO South to PJM.
MISO requested the waiver through April 1, 2015, to help it address transmission constraints resulting from its dispute with SPP.
SPP alleged its joint operating agreement with MISO was breached after Entergy joined MISO last year and began transferring electricity over SPP’s lines. SPP has billed MISO more than $35 million for flows exceeding the 1,000-MW physical contact path limit between MISO North and MISO South.
MISO told the commission that the waiver request would affect 10 pending long-term firm TSRs from a single customer totaling 2,831 MW.
MISO’s waiver request provided some insight into its thinking in integrating Entergy before the dispute with SPP arose.
Originally, MISO said it anticipated that the primary restrictions on flows between its north and south regions would be set under the Operations Reliability Coordination Agreement (ORCA), a seams agreement with SPP, and that it would have extra time to negotiate seams agreements governing flows between those regions.
MISO told FERC the need for a 1,000-MW limit on flows between the north and south was a “sudden and unexpected development” and that it hopes to have alternative seams agreements in place by April 1 — the end of the operations transition period under the ORCA.
Interveners — including Southern Co., Louisville Gas & Electric and the Tennessee Valley Authority — opposed the waiver, saying it was “premature for MISO to assume that the [transition period] will not be extended” past April 1.
They said a waiver would prevent an extension of the transition period and deny their ability “to obtain much-needed reliability information on MISO’s planned flow activity.”
In approving the waiver, the commissioners said MISO “has acted in good faith with respect to the Tariff provisions for which [the] waiver is sought. The circumstances that effectively placed a 1,000-MW limit on MISO’s ability to grant additional long-term TSRs over the MISO North-MISO South interface arose relatively suddenly.”
The commission noted that transmission customers likely would be unwilling to fund construction of new upgrades to obtain service at the north-south interface given that the capacity limit is potentially a temporary situation.
MISO had argued that entities faced a difficult choice of consenting to build new capacity that later may not be needed — or losing their queue priority if they decline construction of the capacity.
Duke Energy has agreed to excavate all 3.2 million tons of coal ash at its soon-to-be-closed W.S. Lee Steam Station in South Carolina and to bury the material in a lined landfill.
The move came after lengthy discussions with the Southern Environmental Law Center over the proper disposal of coal ash from the plant.
“This is a historic accomplishment for South Carolina’s rivers and clean water,” SELC lawyer Frank Holleman said. It is the first time environmental groups reached an agreement with Duke on coal ash disposal in either North or South Carolina, he said.
FirstEnergy CEO Alexander Stepping Down After 10 Years
Anthony Alexander, 63, FirstEnergy’s CEO since 2004, is stopping down Jan. 1 to be replaced by Charles Jones, 59, who started with the company in 1978 as a substation engineer and has managed FirstEnergy’s regulated companies since 2010.
The transition occurs as FirstEnergy is reducing its focus on competitive power-generating markets and is returning to its roots as an operator of regulated utilities. Jones said he doesn’t expect any dramatic changes under his leadership. “I don’t think that means I am going to operate the company significantly differently than Tony,” he said.
Alexander will assume the title of “executive chairman” and will remain on the company’s board.
Exelon Generation’s Delaware Station May Have Buyer by Jan. 1
Exelon Generation said it expects to name a buyer by Jan. 1 for its retired Delaware Station on the Delaware River waterfront, north of Philadelphia’s Center City district.
More than a dozen prospective buyers have toured the property, according to Exelon spokesman Bob Judge. Delaware Station, built in 1920, was designed by Philadelphia architect John T. Windrim, who also designed the famous Franklin Institute. The 223,000-square-foot building comes with 10 acres of land and another 6 acres underwater.
The site, near the booming Northern Liberties and Fishtown neighborhoods, was the northernmost of three waterfront Philadelphia Electric power stations, each a variation on a classical temple. All three are retired. One has been repurposed as an office.
Exelon Files for License Renewal for LaSalle Nuclear Station
Exelon has filed license renewal applications for both units of its LaSalle Nuclear Generating Station southwest of Chicago, asking to be allowed to operate the plant until the 2040s.
The plant’s reactors went into operation in 1984. Nuclear Regulatory Commission-issued license renewals are good for 20 years. The application is 2,100 pages long.
Dominion to Buy Carolina Gas Transmission for $492.9M
Dominion Resources has signed an agreement to buy SCANA’s Carolina Gas Transmission for $492.9 million.
Carolina Gas is based in Cayce, S.C., and operates nearly 1,500 miles of interstate natural gas pipeline in South Carolina and Georgia. Its customers are wholesale and industrial. When the deal is closed, it will become part of Dominion Midstream Partners, the arm of the business that also includes Dominion Cove Point LNG, a liquefied natural gas terminal on the western shore of the Chesapeake Bay in Maryland.
Thomas F. Farrell II, chairman and chief executive of Dominion Resources, and chairman and CEO of Dominion Midstream, called the acquisition “a compelling strategic opportunity.”
NRG Energy has agreed to sell its Storm Lake 1 wind farm to Minnesota-based ALLETE Clean Energy for $15 million.
The 108-MW facility at Storm Lake, Iowa, went into commercial operation in 1999. The sale comes after ALLETE bought an adjacent 78-MW wind farm from AES in January.
Susquehanna Unit 1, taken off line two weeks ago due to a water leak inside the containment area, returned to service Friday after repairs.
The unit shut down Dec. 13 to allow workers inside the containment area to fix a minor leak. There was no release of radiation during the event, operator PPL said.
Calpine Signs Gas Delivery Deal with Eastern Shore Natural Gas
Calpine Energy Services has signed a deal with Eastern Shore Natural Gas to supply fuel for the company’s new 309-MW Garrison Energy Centre in Dover, Del.
Eastern Shore, a subsidiary of Chesapeake Utilities, will deliver natural gas to the combined-cycle plant for the next 20 years. Eastern Shore will build seven miles of new pipeline and a compressor station at a cost of about $30 million to fulfill the contract.
Duke Energy continued to expand its solar generation fleet with the purchase of a 20-MW turnkey project in Roanoke Rapids, N.C.
The Halifax Solar Power Project, which went into service this month, was built by solar developer Geenex with backing from ET Capital. The plant was built on a decommissioned airport. The output is being sold through a 15-year agreement to Dominion North Carolina Power.
Duke owns 15 wind farms and 22 solar facilities in 12 states, totaling about 1,000 MW.
The Federal Energy Regulatory Commission said PPL’s plan to spin off its generation and energy marketing business and combine it with Riverstone Holdings to form Talen Energy could get its OK — if it beefed up its market mitigation plans.
“We find [the] applicants’ proposed mitigation is insufficient to address the competitiveness concerns,” the commission wrote (EC14-112).
FERC gave the companies 30 days to come back with a new mitigation plan. Among other demands, it wants PPL to sell off 700 more megawatts of generation than originally proposed, for a total of about 2,000 MW.
PPL and Riverstone Holdings announced in June they would join their generation businesses into a publicly traded independent power producer named Talen Energy. The new company would own 15,320 MW of capacity, including 12,000 MW in PJM.
In their application, the companies proposed selling about 1,300 MW of PJM generation to avoid market power complaints. The companies said that no company with more than 10% of PJM’s summer installed capacity would be permitted to bid for the plants. That would leave out Public Service Enterprise Group, Exelon and NRG Energy.
In its proposal to FERC, PPL gave two mitigation packages. One involved six Riverstone plants and one PPL plant in New Jersey and Pennsylvania — all combined-cycle plants — for a total of 1,315 MW. The second involved the same six Riverstone plants, plus a 399-MW coal-fired plant in Maryland and two PPL hydro plants in Pennsylvania for a total of 1,346 MW.
FERC’s mitigation demands closely mirror those suggested by PJM Independent Market Monitor Joe Bowring. The commission said it will:
Require Talen to make cost-based offers in the energy and regulation market; and
Require Talen to offer into PJM markets the same plants and output as PPL did, prohibiting it from holding back generation to drive prices up.
FERC declined to accept Bowring’s recommendation that it add American Electric Power, FirstEnergy, Dominion Resources, Duke Energy and Calpine to the companies barred from purchasing the plants sold in mitigation.
The commission said that it would subject any buyers to a competitive screening process to prevent market power concerns.
“PPL is carefully reviewing the order,” PPL spokesman George Lewis said. “We are assessing the options presented by FERC in detail and will submit a reply within the 30-day response period that addresses the market power mitigation issues FERC has raised.”
Connecticut regulators approved a $130 million rate increase for Connecticut Light & Power, endorsing a staff draft decision to cut the company’s requested hike by 41%.
The Public Utilities Regulatory Authority’s ruling boosts the fixed residential monthly charge by 20% to $19.25. Regulators also OK’d the utility’s plan for transmission upgrades.
The decision reduces CL&P’s requested 10.2% return on equity to 9.17%. It also imposes a 0.15% penalty for one year for the company’s performance in preparing for and restoring service from two storms in 2011. A $257 million capital spending budget was also approved.
An average residential customer using 700 kWh of electricity will see an increase of approximately $7.12 per month.
A BNSF executive said the railroad is boosting capital expenditures and maintenance spending to $6 billion in 2015 from $5.5 billion this year. Last month BNSF said it would add 330 new locomotives to its 7,500-locomotive fleet.
