The Federal Energy Regulatory Commission Friday rejected a challenge by New England states to recalculate the contributions of demand response and distributed resources in advance of February’s Forward Capacity Auction.
FERC accepted the installed capacity requirement (ICR) filed by ISO-NE for the 2018/19 delivery year (ER15-325). However, FERC did order the RTO to conduct a stakeholder process to develop market rules that would consider DR in time for the 2016 FCA.
The New England States Committee on Electricity said ISO-NE has underestimated the impact of distributed generation and its pay-for-performance (PFP) program on the region’s capacity needs. FERC disagreed.
“We agree with ISO-NE that it would have no basis to use forecasted performance data in the absence of actual historical performance under this nascent two-settlement market design. We therefore support ISO-NE’s current methodology, which incorporates actual resource performance data,” FERC said.
FERC also suggested that a request to include distributed generation as part of the calculation was too soon, saying that the RTO first “must examine the market and operational issues.”
ISO-NE’s Nov. 4 filing established its ICR, local sourcing requirements and Hydro-Quebec interconnection capability credits (HQICC) for FCA 9.
The ISO proposed an ICR value of 35,142 MW, which includes 1,970 MW of emergency generation assumed obtainable from New Brunswick, New York and Quebec. The net amount of capacity to be purchased, after deducting the HQICC value of 953 MW per month, is 34,189 MW, the ISO said.
Southwestern Electric Power Co. announced that it is dropping plans to construct a $116 million, 60-mile transmission line after SPP decided it wasn’t needed. SPP told SWEPCO that its latest forecasts show lower load growth than previous ones for the area.
“Based on SPP’s new findings, we are notifying landowners, community leaders and elected officials that we have withdrawn our application to the [Public Service Commission] for authority to construct the Shipe Road to Kings River transmission project,” said Venita McCellon-Allen, SWEPCO’s president.
The 345-kV line would have run between Benton and Carroll counties. It was a source of contention for both property owners and environmentalists. Opponents to the line successfully petitioned the PSC for a rehearing on the line. SPP is in the process of withdrawing its Notification to Construct, the basis for SWEPCO’s construction plans and application.
A developer of a failed attempt to build a $1 billion data center and power plant on the University of Delaware campus is suing his former business partner.
Robert Krizman, who was recruited to work as president of The Data Centers LLC, filed suit in the Court of Chancery against chief executive Earl Kern, alleging that Kern kept him in the dark about business decisions. Krizman, who was also a minority partner in the project, wants to be released from his share of about $1 million in debt the project racked up.
After months of studies and lobbying, the university decided against hosting the project. Much of the community backlash that doomed the project centered on a proposed 279-MW power plant.
Indianapolis Power & Light asked the Utility Regulatory Commission for a rate increase that would boost the average residential customer’s bill by 8%, its first general rate increase request since 1994.
Although it has been more than two decades since IPL asked for a general rate hike, it has received other boosts, including 3% rate increases for system improvements for each year between 2013 and 2019. The company also filed a request in 2014 to add about $1 to each monthly bill to pay for the conversion of its Harding Street coal-fired plant to natural gas.
IPL’s general rate increase would generate $67.8 million a year in revenue and would boost the typical residential monthly bill by $8. If approved, it would take effect at the end of 2015.
Gov. Terry Branstad’s top energy expert was fired without notice last month, leaving a multi-million dollar energy fund without a leader.
Paritosh Kasotia, team leader of the state energy office, was asked to leave Dec. 8, according to an Associated Press report last week. Kasotia had just returned from a national energy conference when she was told she had been ousted, and she stopped working the same day.
Kasotia began overseeing the Office of Energy Independence under Democratic Gov. Chet Culver, administering grants in the $71 million Iowa Power Fund. Branstad, a Republican, began dismantling the fund after taking office in 2011, moving the energy office to the economic development agency.
Opposition is mounting in the state against a plan by Kinder-Morgan Energy to convert its existing Tennessee Gas Pipeline to carry natural gas liquids from Appalachian shale fields to the Gulf Coast.
Marion County joined Boyle County in passing a resolution opposing Kinder-Morgan’s plan to repurpose the 71-year-old pipeline to carry a mixture of natural gas liquids like propane and butane to a Gulf Coast processing plant. The pipeline passes through 18 counties in Kentucky.
Marion County last year opposed construction of the Bluegrass Pipeline, which also would have carried NGLs. That pipeline died after a state judge ruled that its planners didn’t have eminent domain powers.
The Public Service Commission has approved construction of the first utility-scale solar plant in the state. Kentucky Utilities will own 61% of the 10-MW facility and Louisville Gas & Electric will own the remaining 39%.
The plant will be built on the site of KU’s E.W. Brown Generating Station in Mercer County, with its $36 million cost subsidized by ratepayers.
KU and LG&E originally applied to build both the solar plant and a 670-MW combined-cycle plant. Plans for the natural gas-fired plant were canceled after KU lost nine wholesale power contracts from municipal customers.
Industrial Boom Points Toward Need for New Power Plants
Low utility prices and cheap natural gas are fueling a boom in industrial growth in Louisiana, and utilities are struggling to keep up with demand. Entergy just fired up a new combined-cycle plant, but some estimates show that more plants, or more imported electricity, will be needed by the end of 2015, and still more by the end of 2019.
In addition to building new plants in Louisiana and Arkansas to meet demand, Entergy is purchasing even more power from wholesale markets. “All that will help, but ultimately we’re going to need to build new generation,” said Phillip R. May, head of Entergy’s Louisiana operations. “It has to be new steel in the ground to meet all of this new load. … We’re on the front end of a pretty steep curve in growth.”
Entergy has yet to file a multiyear rate increase request to help finance the need for new plants, but consumer advocates are already marshaling forces to block them if they do. “We don’t feel it’s fair that residential and commercial customers should have to foot the bill (for power) that will be needed primarily by the large industrial sector,” said Casey DeMoss Roberts, head of the Alliance for Affordable Energy. “The industrial customers should have a special rider to pay for it.”
Judge Affirms PSC Ruling on Cove Point Power Plant
A Baltimore judge has upheld the Public Service Commission’s approval of Dominion Resources’ plans to build a 130-MW generating station to support its liquefied natural gas export terminal at Cove Point.
Circuit Court Judge Alfred Nance ruled the PSC did not act outside its authority when approving the power plant. The Accokeek, Mattawoman, Piscataway Creeks (AMP) Communities Council had appealed the PSC decision.
The power plant is part of Dominion’s $3.8 billion project to convert the LNG importation terminal into an export terminal.
Cost of Kemper Plant Keeps Growing: Another $25 Million in Overruns Reported
Mississippi Power, the Southern Co. subsidiary building a coal gasification power plant in Kemper County, revealed a further $25 million in cost overruns in a filing with the Securities and Exchange Commission on Friday. The plant’s initial cost was $2.8 billion and it was projected to begin operations in 2013. The latest overruns bring the cost to more than $6.1 billion, and a report due later this month may detail even more overruns.
Southern Co. said the overruns reduced its after-tax profit by $258 million in the third quarter. The Kemper plant is designed to convert soft lignite coal to gas that will fuel its boilers. Carbon dioxide from the combustion process is to be captured for industrial uses or storage underground.
Similar plants are also experiencing trouble. Duke Energy’s Edwardsport, Ind., plant suffered from construction delays and cost overruns. And FutureGen 2.0, a government-backed project in Illinois, was announced in 2003 and still isn’t operational.
Ameren Missouri has filed a three-year, $135 million energy efficiency plan with the Public Service Commission, saying it would provide more than $260 million in benefits to its customers over 20 years. The company’s first energy efficiency plan, mandated by the state with the intention to cut energy use and reduce emissions, covers two years and runs out at the end of this year.
The new plan, which has 10 programs to help residential and business customers cut energy use and costs, provides incentives for energy-efficient heating and air conditioning equipment, appliances and lighting systems.
A company spokesman said the programs, together, could save up to 426,000 MWh. “That’s equivalent annual use of 33,000 average-size homes on our system, so it’s a very significant amount of savings on behalf of our customers,” Dan Laurent said.
Rejecting its staff’s recommendation, the Public Service Commission voted 3-2 against allowing NorthWestern Energy to buy power from a 25-MW wind farm near Fairfield.
Greenfield Wind would have sold power to NorthWestern for $54/MWh under a 25-year contract. That compares to a recent hydro contract that did get PSC approval at $57 to $58 per megawatt hour.
Commission Chairman Bill Gallagher, one of the objecting voters, said tying the utility, and its ratepayers, into the wind power contract would cost it money when the wind power was available but not needed, and would be sold at a loss on the wholesale market. “The difference in that price is going to be left to the consumer,” Gallagher said.
BPU-Set Gas Rate Means Refunds for Some State Gas Customers
Elizabethtown Gas residential customers will get an average refund of $40 after the Board of Public Utilities approved a lower supply charge.
Company officials said the lower cost of gas from Marcellus Shale production will save its customers $10 million. The refund is on top of the lower gas rate approved by the BPU late last year.
“Essentially, there’s an abundant supply of natural gas now that’s serving to lower prices for customers,” said Duane Bourne, a company spokesman.
Environmental Group Still Concerned About Pine Barrens Pipeline Project
A proposed natural gas pipeline through the Pine Barrens that failed to gain approval by the Pinelands Commission last year poses a “real cause of concern,” according to the year-end report of the Pinelands Preservation Alliance.
The environmental group’s “State of the Pinelands Report” said the commission’s deadlocked 7-7 vote on the pipeline shows that pressures still exist on the natural resources in the area. After the vote, Gov. Chris Christie nominated two new members for the commission, but those appointments were put on hold in a contentious legislative hearing that focused mostly on the pipeline proposal. South Jersey Gas wants to build the pipeline to fuel the B.L. England power plant, which is being converted from coal to natural gas.
“The most well-known threat to the integrity of the Pinelands protection rules over the past year is the South Jersey Gas pipeline issue,” the alliance’s report stated.
PSC Approves Another 172 MW of Wind Power at Antelope Hills
A $240 million wind farm on 22,000 acres in western North Dakota received approval from the Public Service Commission. The 86-turbine, 172-MW Antelope Hills Wind Project near Beulah, Mercer County will be in service by the end of this year, according to PSC Chairman Brian Kalk.
Basin Electric Cooperative has signed a 25-year power purchase contract for the full output of the new facility. It will be added to the 1,600 MW of wind power currently operating in the state and 1,200 MW of wind power already approved by the commission.
Antelope Hills has applied for a 9.5-mile, 345-kV transmission line to carry its output to a grid connection at Basin Electric’s Antelope Valley Station coal-fired plant.
FirstEnergy Sweetens the Pot for its Proposed Rate Plan
FirstEnergy, in an attempt to show support for its controversial “Powering Ohio’s Progress” electric security plan, filed a proposed joint settlement agreement with the Public Utilities Commission.
FirstEnergy’s proposal to receive supply guarantees for several power plants has prompted a backlash from opponents, who said the company had already been rewarded for its merchant plants during the state’s transition to market rates.
Now, in exchange for the price supports, FirstEnergy proposes a freeze on distribution rates through 2019, $23 million in economic development funding and up to $7 million in low-income funding. The company said it has the support of 15 parties, including the city of Akron, labor and various user groups. PUCO will schedule hearings on the plan soon. The commission’s staff hasn’t filed its comments yet.
Sustainable Energy Board Meeting to Spotlight Coming Projects
The annual meeting of the Sustainable Energy Board on Jan. 15 will feature an update on projects for the state.
Met-Ed and Penelec will provide an overview and update on their mapping program that shows where sustainable energy grants were apportioned. West Penn Power will provide an overview of projects funded by its program and will talk about a sustainable energy fund bond program it recently launched with the state. PPL will report on an LED lighting project at Harrisburg International Airport. And PECO Energy will detail its new third-party financing project for renewable energy projects.
The meeting is set for 11 a.m. in Hearing Room 1 of the Commonwealth Keystone Building in Harrisburg.
Keystone May Have Votes in Congress, but State Approval Key
Incoming members of Congress may have approval of the Keystone XL Pipeline in their sights, but the Public Service Commission still needs to grant a crucial approval, and that may not be too easy. More than 40 groups have filed to intervene in the commission’s approval process.
The PSC approved the pipeline in 2010, but that construction permit expired last June. TransCanada has filed for a new construction permit, but most of the groups who have filed with the PSC are against the project.
The commission has scheduled hearings in February, March and April to consider what can be heard and filed at the final hearings, which are scheduled for May 5-8.
LNG Terminal Plans on Hold Due to Falling Gas Prices
Excelerate Energy told the Federal Energy Regulatory Commission that it is putting its floating liquefied natural gas terminal project near Port Lavaca on hold, partly because of plunging natural gas prices.
“Due to the recent global economic conditions, the company has determined that, at this time, this project no longer meets the financial criteria necessary in order for us to move forward with the capital investment,” the company announced last week. The company asked FERC to put its project filings on the shelf until April 1.
The export facility was to have been built in Lavanca Bay, about 30 miles southeast of Victoria. The $2.5 billion project would have been the first floating LNG export terminal in the U.S.
Residents Question Need for Line: Dominion Short on Answers
Northern Virginia residents have questioned the need for a transmission line proposed by Dominion Virginia Power to serve an unnamed high-tech client near Haymarket in Prince William County, west of Manassas National Battlefield Park.
Although Dominion won’t identify the customer, rumors abound that a major Amazon data center is planned for the area. Dominion spokeswoman Le-Ha Anderson said the utility’s existing lines aren’t large enough to supply the prospective client’s needs. Dominion estimates the costs of the new line and a substation are about $65 million.
Residents of Haymarket and surrounding areas say the proposed line would be unsightly and impact property prices. A town hall meeting for residents is scheduled for tonight at Battlefield High School.
The Public Service Commission has approved American Electric Power’s $550 million sale of half of its Mitchell Power Plant to one of its subsidiaries, Wheeling Power.
The 1,600-MW coal-fired plant, on the banks of the Ohio River in Moundsville, is 43 years old, but it recently had its emissions-control systems upgraded.
Another AEP subsidiary, Kentucky Power, owns the other half of the plant. The entire plant had been owned previously by AEP’s merchant generation business.
PSC to Let Cheyenne LF&P to Fix $5.1 Million Mistake
Cheyenne Light, Fuel & Power made a mistake when doing the calculations for its most recent rate case – a $5.1 million mistake. Its 2014 rate case left out a monthly collection from its residential customers of about $8.88 a month. This resulted in a collection shortfall for November and December of $985,875, which would grow to $5.1 million over a full year.
The company asked the Public Service Commission for permission to make up the difference on an interim basis, pending approval of a new rate case. The commission ruled in late December it would allow the company to re-file the rate case, but that ruling is on hold pending an appeal by two of Cheyenne’s industrial customers.
The state collected $43.2 million more in sales and use taxes during the first five months of its fiscal year, ending November. That’s good news for state officials, but there’s bad news on the horizon.
State finance officials say the strongest counties – Campbell, Laramie and Converse – collected $26.1 million of that, and much of that was due to energy industry jobs and services.
“From an industry perspective, the mining [including oil and gas], retail trade and construction sectors have captured most of the collection gains to date,” said Jim Robinson, principal economist for the Economic Analysis Division of the state Department of Workforce Services. But the recent plunge in natural gas and oil prices means tax collections in those counties are almost sure to drop as well.
A Québec pension fund has agreed to spend up to $593 million to acquire up to 30% of Indianapolis Power & Light from AES, which is seeking to lighten its share of U.S. utilities as their coal-fired generation in MISO and PJM face increasing environmental pressure.
IPL on Dec. 23 filed for Federal Energy Regulatory Commission approval on the deal (EC15-56), which also needs an OK from the Committee on Foreign Investment in the United States, an interagency groupthat includes the U.S. Treasury, Department of Energy and State Department.
Caisse de dépôt et placement du Québec (CDPQ) will pay $244 million for 15% of AES Investments, an IPL parent company, and contribute up to an additional $349 million for up to 17.65% of IPALCO Enterprises, IPL’s direct parent, based on capital calls.
At the end of the two-step process, CDPQ will have indirect ownership of 15% to 30% of IPL and will be able to nominate two IPALCO directors. AES Investments would nominate nine of the directors.
Environmental Pressures
IPL, which owns about 2,623 MW of coal-fired generation (83% of its total), is scrambling to comply with the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS), and may face compliance expenses under the EPA’s proposed carbon emissions rule. In its earnings report for the second quarter, AES said it was too soon to determine what impact the carbon rule, and state plans for implementing it, will have on the company.
From 2014 to 2016, IPL plans to spend $326 million on MATS compliance alone.
At least half of IPL’s capital spending plan involves replacement of coal-fired units. The biggest project, at $600 million, is the construction of a 671 MW gas-fired generating station to replace aging coal units at its Eagle Valley plant, 30 miles south of Indianapolis.
AES’ Second Thoughts About U.S.
Although it is based in Arlington, Va., three-quarters of AES’ pre-tax income from continuing operations comes from its international investments.
AES, which bought IPL in 2000 for $2.15 billion, would see its stake in IPALCO fall to 70% under the deal.
Earlier this year AES tried to sell its Dayton Power & Light’s generation fleet rather than spinning it off into an unregulated subsidiary by 2017, as the Public Utility Commission of Ohio had ordered.
AES bought DPL in 2011 for $3.5 billion, about a 9% premium to DPL’s stock price. But AES later expressed regrets about the purchase, saying it hadn’t received the benefits it expected. In its 10-K filed last February, AES cited Ohio’s market-based pricing and low wholesale prices.
In July, however, AES said it had dropped its plan to sell DPL. “In light of the potential recovery of power prices, as well as PJM capacity prices, AES believes that this business has additional value that can be captured by continuing to own and operate these generation assets,” AES said in a statement.
Moody’s Likes Deal
Moody’s Investors Service said in a Dec. 15 report that the sale would help the credit rating of IPALCO, which is in the midst of a $1.4 billion capital spending plan.
“CDPQ’s contractual commitment is credit positive for IPALCO and its wholly owned subsidiary Indianapolis Power & Light … particularly considering CDPQ’s strong credit quality compared to AES,” Moody’s analyst Natividad Martel wrote.
Moody’s did not change its ratings for IPL, IPALCO or AES, however, which are Baa1 stable, Baa3 stable and Ba3 stable, respectively.
IPL has a current capital structure of 45% equity and 55% debt.Virtually all of the utility’s profits are returned to AES as dividends, which has left the utility thinly capitalized. In the first nine months of 2014, IPL paid $78 million in dividends to AES.
Map of AES’ US businesses (Click to zoom)
Over the last two years, AES contributed $156 million in additional equity to IPL, said Moody’s.AES and CDPQ will contribute another $62 million on top of CDPQ’s $349 million.
Although it would ultimately receive less in dividends from IPL, AES would enjoy a reduction in requirements to make equity contributions to IPL. That will “enhance AES’ parent only free cash flow position,” said Moody’s.
That’s notable because AES recently announced it would double dividend distributions starting in the first quarter of 2015.
As of Sept. 30, IPL had an available borrowing capacity of $249.3 million under its $250 million unsecured revolving credit facility after outstanding borrowings and existing letters of credit.
CDPQ
The purchase is being made by CDP Infrastructure Fund GP, a New York-based investment fund and a wholly-owned subsidiary of CDPQ.
CDPQ has a controlling interest in Gaz Metro Limited Partnership, the biggest natural gas distributor in Quebec and the 100% owner of Vermont’s Green Mountain Power.
In MISO, in which IPL operates, CDPQ has a 24.7% interest in Invenergy Wind, whose projects include Bishop Hill Energy III, in Henry County, Ill.
IPL is asking FERC for expedited approval of the CDPQ deal. Even with Invenergy Wind’s current and proposed projects, Invenergy and IPL would own or control on a combined basis 2% of MISO’s installed generation capacity, IPL said in its filing. IPL noted that FERC recently accepted market-based rate filings by affiliates of Invenergy Wind based in part on the passive nature of the CDPQ interests.
New Source Review Liability
IPL, meanwhile, could find itself facing other environmental costs outside of its $1.4 billion capital program.
Although not mentioned in the context of the CDPQ deal, IPL remains haunted by the specter of a 16-page Notice of Violation the EPA handed the utility in 2009.
It alleges IPL updated three generating plants over 23 years without adding the most modern pollution controls. The EPA’s New Source Review (NSR) requires utilities to undergo a pre-construction review for new plants and whenever existing plants are modified in a way that involves “non-routine” physical changes resulting in a significant increase in emissions.
IPL contends that the maintenance projects were routine.
In its third-quarter earnings report, AES said it has met with EPA officials to resolve the NOV and noted that in other NSR cases the EPA has “required companies to pay civil penalties, install additional pollution control technology on coal-fired electric generating units, retire existing generating units, and invest in additional environmental projects.” Such an outcome could have a “material impact” on IPL and AES, the company said.
One such case involving similar allegations cost American Electric Power $75 million in penalties and environmental projects as part of a 2007 settlement with the EPA. AEP agreed as part of the settlement to make $1.2 billion in additional sulfur- and nitrogen-control upgrades at its Rockport and Clinch River generating plants.
AEP’s settlement came after almost eight years of litigation.
NYISO said last week that its new capacity zone has convinced generation owners to reopen several shuttered power plants, delaying potential reliability concerns to beyond 2019.
The RTO said 1,900 MW not counted in its September Resource Needs Assessment — mostly mothballed coal plants whose owners are converting them to natural gas — have been added to the expected generation fleet. Based on these additions, NYISO said it has withdrawn its request seeking additional capacity.
The revived resources include the 495-MW Danskammer Generating Station in Newburgh and the 557-MW Bowline Generating Station in Haverstraw.
“Earlier this year, we identified reliability needs that would begin in 2019. Fortunately, the new capacity zone in southeastern New York encouraged power producers to revitalize significant generating resources in the region. These investments address the identified reliability needs and are expected to produce $400 million in savings next year,” NYISO President and CEO Stephen G. Whitley said in a statement.
In its RNA, NYISO said that New York’s electric system would violate resource adequacy criteria beginning in 2019 due to inadequate resource capacity in southeastern New York. (See NYISO Sees Capacity Crunch by 2019; Tx Problems in 2015.)
The returning capacity includes Danskammer, which previous owner Dynegy in 2013 said was headed to the scrap yard. New owner Danskammer Energy, which was formed after the creation of the capacity zone, said the facility would be converted to natural gas, with fuel oil as a backup. The company expects the facility to be in operation by the end of this year.
NRG Energy, the owner of the Bowline facility, said the new capacity zone had created pricing signals that justify the restoration of the Bowline Unit 2 to full service by summer 2015.
Other plants that have announced plans to return to service include the 348-MW Selkirk Cogeneration Project, the 185-MW Astoria 20 Power Plant in Queens and the 435-MW Dunkirk Generating Station in western New York, NYISO said.
News of the restored generation provides vindication for the RTO, which received heavy criticism after proposing the new capacity zone. (See New Yorkers Upset over NYISO Capacity Zone.)
The New York Public Service Commission ordered a study and technical conference to identify fixes for persistent transmission congestion along the Mohawk and Hudson Valley corridors.
“After carefully considering comments from stakeholders and members of the public, and in light of other proceedings related to improving energy efficiency and modernizing the grid, we will carefully reexamine the need for transmission upgrades to address existing transmission congestion problems,” PSC Chair Audrey Zibelman said in a statement. The congestion has increased consumers’ costs and raised reliability concerns, the commission said.
Transmission developers have until Jan. 19 to submit proposed upgrades. The commission ordered staff to issue a report addressing the needs and potential solutions by June 10, which will be followed by a technical conference (13-E-0488).
In its order the commission said the technical conference will allow “a full airing and discussion among the stakeholders of the basis of the need for transmission facilities and the viability of potential alternatives.”
A commission decision on preferred projects is expected in August or September.
The Environmental Protection Agency last week issued the first-ever federal regulations on the handling and storage of coal ash, pleasing utilities and disappointing environmentalists by declining to classify the material as hazardous waste.
Utilities generally welcomed the rule, with FirstEnergy calling EPA’s decision to regulate coal combustion residuals (CCRs) as solid waste “appropriate.”
The Sierra Club called it “a modest first step,” while environmental group EarthJustice — which had won a court order forcing EPA to act — blasted the result.
“Today’s rule doesn’t prevent more tragic spills like the ones we are still trying to clean up in North Carolina and Tennessee,” the group said, referring to the Tennessee Valley Authority’s 2007 spill of 5 million cubic yards of contaminated coal ash in Kingston, Tenn., and last winter’s failure of a pipe at a Duke Energy impound pond that dumped 39,000 tons into the Dan River.
The Duke incident led North Carolina legislators to impose stricter rules on how coal ash storage sites can be operated.
But until Friday, there were no federal regulations governing the storage and use of coal ash, a byproduct of burning coal. There are an estimated 1,000 coal ash storage sites in the U.S., primarily under the control of electric generating companies. The industry produces an estimated 140 million tons of coal ash per year.
A “hazardous waste” designation would have resulted in a bigger increase in storage costs and prohibited any beneficial use for coal ash. By some estimates, about 40% of coal ash is used for highway construction, concrete manufacturing and fill material at construction sites.
The EPA proposed coal ash rules in 2010 but, under political pressure from industry groups, the White House sent the rules back for rewriting. It took a court-ordered consent decree to set Friday’s deadline. The final rule will take effect six months after their publication in the Federal Register.
EPA: ‘Common Sense, Pragmatic Rules’
Although the rules were issued by the EPA, it will be up to states to enforce them. “The rule requires that power plant owners and operators provide detailed information to citizens and states to fully understand how their communities may be impacted,” the EPA said.
The EPA called the rules “common sense, pragmatic rules to protect against structural failure, water and air pollution.”
EPA Administrator Gina McCarthy said the rules are intended “to help prevent the next catastrophic coal ash impoundment failure, which can cost millions for local businesses, communities and states. These strong safeguards will protect drinking water from contamination, air from coal ash dust and our communities from structural failures, while providing facilities a practical approach for implementation.”
The rules:
Require closure of impound sites that fail to meet engineering and structural standards;
Require regular inspections of the structural safety of surface impoundments;
Prohibit construction of new sites in sensitive areas such as wetlands and earthquake zones;
Require monitoring of groundwater near sites and closing unlined sites that are polluting groundwater;
Mandate liners for new sites;
Close sites that are no longer receiving coal ash; and
Mandate control of air-blown coal ash.
Utilities: Rules Are Workable
Utilities generally viewed the rules as workable.
American Electric Power spokeswoman Tammy Ridout said the company was pleased the EPA allowed for “continued application of important beneficial uses of these materials. Where closure of impoundments will be needed under this rule, the EPA is providing adequate time to implement the closures safely.”
Ridout said the company has already taken many of the steps outlined in the rules.
“AEP already has ground-water monitoring systems in place at most of our ash impoundments. We have developed a plan to close, dewater and permanently cap all but two of our existing eight fly ash ponds and will close a total of 20 ash ponds. Many of these pond closures will be at plants that will be retiring in the next year.”
PPL spokesman George Lewis said his company is reviewing the rules to see how it will affect it. Lewis said classifying coal ash as hazardous wastes “could have had a devastating impact on future beneficial uses, including concrete, cement and wallboard manufacturing.”
“PPL has not been opposed to EPA regulation that keeps beneficial uses as an option. We believe beneficial uses are a common-sense environmental solution, and we’ve pursued them for several years under strict and effective state regulations,” he said. “With appropriate measures to protect human health and groundwater quality, beneficial uses are better for the environment than landfill or basin disposal.”
In a research note yesterday, UBS Securities said the rule could hurt merchant generators with coal portfolios such as NRG Energy and Dynegy, which can’t turn to state regulators for rate increases. The analysts also cited FirstEnergy, saying the company may have to retire its giant Mansfield plant if it is unable to continue using its Little Blue Run coal ash site.
FirstEnergy spokeswoman Stephanie Walton said the company already complies with strict state regulations in Pennsylvania, West Virginia and Ohio. “FirstEnergy has extensive groundwater monitoring in place at all of our coal ash disposal facilities,” she said. “We are currently reviewing the rule to better understand whether there will be any implications for our operations.”
Duke: $3.4 Billion Cleanup
Duke spokesman Dave Scanzoni said the company is engaged in a review of the lengthy set of rules and its final position wouldn’t be known until early next year. But he noted that Duke is already in the midst of a $3.4 billion coal ash remediation effort in North Carolina. (See Duke Sees $3.4B Coal Ash Cleanup Bill; Who’s Next?)
“Duke Energy will adjust its existing ash management plans, as necessary, to comply with all state and federal regulations,” he said.
EEI: Door Left Open to ‘Hazardous’ Designation
Edison Electric Institute President Tom Kuhn said the group supports the EPA’s decision, but he added “we still have concerns with the self-implementing nature of the rule and the way in which EPA has left the door open to one day regulate coal ash as a hazardous waste, creating additional uncertainty for electric utilities.”
“Passing legislation that establishes state-enforced federal requirements for the disposal of coal ash would address many of our concerns and help eliminate uncertainty,” he said. “EEI will continue to advocate for such legislation in the next Congress.”
The Utility Solid Waste Activity Group, an industry organization, voiced similar concerns, saying it was “disappointed with the agency’s suggestion that it is still evaluating whether to reverse this determination and regulate coal ash as a hazardous waste at some point in the future.”
Enviros: Not Enough
Some regulation is better than none at all, environmental groups said, but some expressed disappointment that the rules aren’t stringent enough.
Mary Anne Hitt, director of the Sierra Club’s Beyond Coal campaign, said the Obama administration did “not go far enough to protect families from this toxic pollution.”
“The Sierra Club has significant concerns about what has been omitted from these protections and how they will be enforced in states that have historically had poor track records on coal ash disposal,” she said.
EarthJustice also was critical. “It won’t stop the slower moving disaster that is unfolding for communities around the country, as leaky coal ash ponds and dumps poison water,” EarthJustice attorney Lisa Evans said.
“While EPA’s coal ash rule takes some long overdue steps to establish minimum national groundwater monitoring and cleanup standards, it relies too heavily on the industry to police itself,” said Eric Schaeffer, executive director of the Environmental Integrity Project. “Companies like Duke Energy, First Energy and TVA have already learned that spills and leaking ash ponds add up to billions of dollars in cleanup costs.”
PSEG Nuclear last week called on PJM’s Board of Managers to prevent planners from using what the company said is unproven technology in the stability fix for Artificial Island.
The company, operators of the island’s Salem and Hope Creek nuclear plants, said a proposal by Dominion Resources could result in damage to turbine generator shafts and widespread outages.
Thomas Joyce, chief nuclear officer, said in a letter that Dominion plans to use “FACTS” devices, “for which there is limited knowledge of potential failure modes and their frequency of occurrence.”
Dominion is one of four finalists for the Artificial Island project; PSEG Nuclear’s sister company, Public Service Electric & Gas, is also in contention.
“PJM staff had previously represented that it consulted with the [Nuclear Regulatory Commission] and the NRC was unconcerned with any of the proposals,” Joyce wrote. “At the Dec. 9 TEAC meeting, we learned for the first time that the ‘consultation’ consisted of only informal discussions during two telephone calls. This is a far cry from anything close to an official licensing position on the part of the NRC.”
Joyce said that “by proposing to install these devices in close proximity to the second largest nuclear facility in the United States, PJM is creating the potential for a series of events that can not only cause harm to the multiple nuclear units at AI but also potentially impact a substantial portion of the EMAAC/Mid-Atlantic system.”
On Thursday, CAISO became the first region to fully comply with the regional requirements of the Federal Energy Regulatory Commission’s Order 1000.
Now, the commission is starting the process of arbitrating interregional compliance filings, beginning last week with PJM and MISO.
It’s clear the RTOs still have work to do.
FERC conditionally accepted the RTOs’ proposed revisions to their joint operating agreement (JOA), finding that they only partially complied with the requirements of Order 1000. It directed them to modify their interregional cost allocation method for cross-border transmission projects and develop identical language in their Tariffs to describe their interregional transmission coordination procedures (ER13-1944).
Cross-Border Project Cost Allocation
The RTOs filed their own revisions separately last year, mainly because of disagreements over the cross-border project cost allocation issue. While PJM proposed relying on the existing cost allocation methods in the JOA, MISO wanted to remove them for cross-border baseline reliability projects, arguing that tie lines between MISO and PJM transmission owners be designated as reliability projects, with each RTO recovering costs in accordance with its own Tariff. (See PJM in Standoff with MISO, NYISO on Order 1000 Filing.)
MISO based its argument on the fact that FERC had previously accepted the RTO’s proposal in its regional Order 1000 compliance filing to remove regional cost allocation for its baseline reliability projects and assign all of the costs to the pricing zone where the project is located.
FERC rejected MISO’s argument, however. “To the extent that a conflict exists between the existing cross-border baseline reliability project cost allocation in the MISO-PJM JOA and the cost allocation requirements for interregional transmission facilities in Order 1000, that conflict results from MISO’s decision to no longer regionally allocate the costs of MISO baseline reliability projects, not the requirements of Order 1000,” FERC said.
Similar, but not Identical, Language
In their compliance filings, PJM and MISO said they were in agreement over interregional transmission coordination procedures. But owing to their separate filings, the RTOs included language and terms based on their own individual Tariffs. Order 1000 requires neighboring planners to use the same language in their filings.
“Although MISO and PJM state that these minor differences in their respective filings are needed to reflect whether the
discussion is from the perspective of either MISO or PJM, we find that some of the differences do not serve this purpose and therefore are not necessary,” FERC said. The commission directed the RTOs to adopt identical terms in new compliance filings due in two months.
FERC also said that the RTOs’ cost allocation proposals do not explicitly refer to an interregional transmission facility as defined by Order 1000: “a transmission facility that is located in two or more transmission planning regions.” The RTOs’ JOA refers to cross-border baseline reliability projects and cross-border market efficiency projects, but it does not explicitly state that these projects must be located in both PJM and MISO. FERC wants a definition that matches Order 1000’s in the next filing.
“I guess it’s no secret that the somewhat convoluted seams between those two regions have a complicated and lengthy history at the commission, and I’m hopeful that today’s order on the interregional compliance filing will help improve … [the] interregional coordination of transmission across the seams,” FERC Chairman Cheryl LaFleur said. “It does look so far like … interregional coordination [and] cost allocation … will be the [issues] that we have to devote some attention to.”
NIPSCO Complaint
In a separate but related order, FERC addressed a complaint from Northern Indiana Public Service Co. against PJM and MISO regarding the interregional transmission planning provisions in the JOA. NIPSCO, a MISO member, is flanked by PJM in eastern Indiana and Illinois to its west.
The company complained that the MISO-PJM seams there are highly congested and that the RTOs have not approved a single cross-border transmission upgrade project under their JOA.
In response, FERC ordered staff to conduct a technical conference to explore the issues NIPSCO raised (EL13-88).
The Federal Energy Regulatory Commission last week upheld its 2011 rate order for the RITELine transmission project over the opposition of Commissioner Philip Moeller, who opposed the panel’s decision to reduce an incentive adder for risks.
The RITELine Project, a joint venture by Exelon and American Electric Power, is a proposed $1.6 billion 765-kV transmission line stretching from northern Illinois, through Indiana and into Ohio. The companies say it would allow the integration of 5,000 MW of wind generation.
The companies had sought an ROE of 12.7%, which included a base ROE of 10.7% plus certain incentive adders.
FERC’s 2011 order approved a total rate of 11.43%, including some adders and a base rate of 9.93%.
FERC granted only a 100-basis-point adder “to compensate for the risks and challenges associated with investing in new transmission,” rather than the 150 basis points it had previously granted for such risks. The commission said a reduced adder was justified because the incentives it had included reduced the project’s financial risks.
In their rehearing request, the companies argued that this represented a substantial change in how FERC grants incentives for transmission projects, and that the commission had failed to adequately explain it.
In last week’s order denying rehearing (ER11-4069), the commissioners rejected the companies’ contention that reduction of the risk adder “represents a departure from commission policy; there is no policy guaranteeing a project 150 basis points, but rather any ROE adder depends on the risks and challenges of that particular project.”
In a partial dissent, Moeller said the commission had made “a significant policy change without justification for that change.” “If we are going to produce less carbon dioxide when generating electricity, we’ll need more transmission lines to move cleaner sources of power to those who need it,” Moeller continued. “This action thus sets up a collision between two federal agencies that regulate the energy industry. That is, while the Environmental Protection Agency is moving to limit carbon dioxide, which will require more transmission lines, this commission is changing its policies on transmission incentives in a manner that actually discourages the very transmission that will be needed to satisfy EPA requirements.”
Attempts to restart the Yucca Mountain Underground Nuclear Waste Repository have hit another snag: the government does not have the necessary water rights to operate at the Nevada site.
A staff report by the Nuclear Regulatory Commission said that despite decades of study and construction, the Department of Energy allowed land-use agreements for the site to expire and would need an act of Congress to renew them.
Sen. Harry Reid, D-Nev., a leading opponent of Yucca Mountain, said the report underscored major weaknesses in the project. “This is just one reason why the Yucca Mountain project will never be built,” he said in a statement.
NRC Puts Callaway’s License Renewal Decision on Hold
Ameren Missouri expected the Nuclear Regulatory Commission to rule by the end of this month on its application for a 20-year license renewal for its Callaway Energy Center, but the company heard last week that the decision is on hold while the commission considers a legal challenge.
The Missouri Coalition for the Environment, which on Dec. 8 requested to intervene in the case, wants to challenge the “legal adequacy” of the commission’s newly revised Continued Storage of Spent Nuclear Fuel rule. Callaway was to be the second nuclear plant to get a license renewal under the new spent-fuel rule, which the commission adopted in October, ending a two-year moratorium on license renewals.
Columbia Gas’ $268.5 million Eastside Expansion Project, which includes 19 miles of new transmission line from Chester County, Pa., into New Jersey, received approval from the Federal Energy Regulatory Commission.
The expansion includes plans to upgrade a compressor station in Forks Township, Pa., to support the pipeline’s added capacity. FERC determined that the upgrade would not have an adverse impact on air quality.
Another NJ Pipeline Expansion Project Approved by FERC
The Leidy Southeast line, an addition to the Transcontinental Pipeline designed to bring Marcellus Shale natural gas to southern markets, was approved last week by the Federal Energy Regulatory Commission.
The $738 million project, a 30-mile series of loops in both Pennsylvania and New Jersey, won the commission’s approval despite objections from environmentalists who said it would cross farmlands and wetlands.
The Great Northern Transmission Line, a 220-mile, 500-kV line being built by Minnesota Power and Manitoba Hydro, has received approval from the Federal Energy Regulatory Commission.
The line will bring power to Minnesota from two hydro stations in northern Manitoba. MISO also voted to include the line in its Transmission Expansion Planning report for 2014.
FERC Grants Native American Hydro Project Exempt Status
The Federal Energy Regulatory Commission exempted a Montana hydro project from having to comply with reporting requirements, the first time such an exemption has been granted. The project will come under the full ownership of Native American tribes next year.
The Confederated Salish and Kootenai Tribes of the Flathead Reservation, which already owns part of the Kerr Hydroelectric Project, are buying the remaining shares from PPL. The tribes and their company Energy Keepers Inc. asked FERC for an order declaring them exempt public utilities under section 201(f) of the Federal Power Act, which would relieve them of obligations to maintain or make available their books and records to the commission.
FERC found that the tribes and their holding company are performing an inherent government function and were exempt. The ruling will allow the tribes to engage in forward power sales before assuming full control of the project.
DOE Releases Environmental Study on 720-Mile Tx Line
A proposed $2 billion transmission line designed to bring wind energy from Oklahoma to Tennessee passed an important regulatory hurdle when the Department of Energy released the draft environmental impact study.
Clean Line Energy Partners, the project’s developer, said the final environmental impact study should be completed next year. Construction on the Plains & Eastern project is expected to begin next year and to be completed in 2018. The line is designed to deliver 3,500 MW of wind energy to its final customer, the Tennessee Valley Authority.
Secretary of Energy Ernest Moniz has given the OK for the Savannah River Site in South Carolina to begin cleaning up radioactive tanks that stored chemicals when the site was part of the nation’s nuclear weapons production system.
Moniz’s decision came after a long study of hazards and preliminary work at the site. The underground tanks of H Tank Farm will be emptied and their interiors will be coated with a cement grouting to stabilize any remaining materials.
“We are now able to move forward to safely, effectively and efficiently clean up and close these tanks in the H Tank Farm, as we work to achieve the key mission of cleaning up the environmental legacy of the Cold War,” Moniz said.
