State Briefs

State Holds Delayed Hearing on PSEG New Nuke Plans

The state’s Congressional delegation arranged for a public comment session on a possible new reactor at Public Service Enterprise Group’s Artificial Island site in New Jersey after lawmakers realized that only Garden State residents had been given the opportunity to talk. A session was held Thursday in Middletown to let residents speak out about the Nuclear Regulatory Commission’s draft environmental impact review. Although PSEG has not made firm plans for a new reactor at the site – home of the Salem and Hope Creek reactors – it is pursuing NRC site approval.

Richard Cathcart, manager of Delaware City and a former state representative, said he supports construction of a new reactor on the Artificial Island site across the state line. “We know that the construction workforce could grow to over 4,000 jobs, many of which could go to Delawareans,” he said, noting that he was speaking as a private citizen. “And we know new construction could bring a much-needed and major boost to the economy.”

But environmentalists question how an early site approval can be given when PSEG hasn’t even determined what type of reactor design it would deploy.

More: The News Journal

DISTRICT OF COLUMBIA

New Office of Consumer Services Chief Named by Public Service Commission

The Public Service Commission appointed a program analyst as the interim Director of the Office of Consumer Services.

Susan Nelson, who started as an analyst in the PSC’s Office of Technical and Regulatory Analysis in May, was elevated to fill the position after Linda Jordan retired earlier this month. The Office of Consumer Services handles consumer complaints and inquiries and operates outreach programs. Nelson held numerous customer care and billing positions in the telecommunications industry before joining the PSC.

More: PSC

ILLINOIS

Grand Prairie Gateway Wins ICC Approval

The Commerce Commission approved Commonwealth Edison’s Grand Prairie Gateway Project, a 70-mile transmission line running across four Illinois counties. Construction of the $251 million project is scheduled to begin next year and be completed in 2017.

The 345-kV line “would allow greater access to renewable energy west of Illinois, which should enhance competition in the electricity markets,” a commission news release said. Terence Donnelly, ComEd executive vice president, said the line will relieve congestion that impedes the flow of low-cost energy, and reduce costs for delivering energy to customers.

The line would start from a substation near Byron Nuclear Generation Station and continue to a substation near Wayne. Byron is owned by ComEd’s parent company, Exelon.

More: Kane County Chronicle

INDIANA

Vectren Customers See Big Spike in Energy Bills

Droves of Vectren customers have applied for energy assistance after many complained about dramatically higher bills to make up for underpayments in previous months.

The Utility Regulatory Commission is monitoring Vectren’s action plan after hundreds of customers complained. Vectren officials say that the problem stems from inaccurately estimated bills. The company has been swamped with requests to meet with customer service representatives, and community service organizations say they’re experiencing record numbers of requests for emergency energy subsidies.

A single mother of three children said her Vectren bill was around $11 for three straight months then jumped to more than $700.

More: WTVW

KENTUCKY

LG&E/KU Adjusts Generation Construction Plans

Louisville Gas & Electric and Kentucky Utilities updated plans with the Public Service Commission, telling the PSC they will need to build between 368 MW and 737 MW of natural gas generation starting in 2020. The PPL subsidiaries filed the updated resource assessment report with the PSC last week.

The companies said they plan to retire two units at the E.W. Brown coal-fired plant and still plan to go forward with a 10-MW solar project on the plant site. Uncertainty about the effect of the recent Environmental Protection Agency emissions rules make it difficult to be more specific, the utilities said. Further load growth studies could force them to consider building more natural gas-fired generation before 2020.

More: UtilityDive

MARYLAND

PSC Holding Public Sessions on BGE’s Rate Increases

Baltimore Gas and Electric is asking for its fourth rate hike in four years. The Public Service Commission has scheduled several public hearings.

The company wants to raise distribution charges to both gas and electric customers by about $15 a month. BGE says it needs the increase to pay for infrastructure upgrades. If approved, the rates would go in effect in January.

More: The Baltimore Sun

MICHIGAN

Senators Ask Feds to Delay We Energies Rate Hike

Sens. Carl Levin and Debbie Stabenow have asked the Federal Energy Regulatory Commission to reconsider its decision to force We Energies customers in the state to absorb a $97 million rate increase to pay for the company’s power plant in Marquette.

We Energies wanted to shut its Presque Isle Power Plant after its largest industrial companies switched to another provider. But MISO determined the plant was crucial to system reliability and ordered that it stay in operation. The Wisconsin Public Service Commission later ruled that a large number of Wisconsin customers should be freed from paying the plant’s costs, shifting the bill to Michigan customers. FERC upheld its ruling.

Levin and Stabenow said the rate impact on customers in the Upper Peninsula is unjustified.

More: WTAQ

NEW JERSEY

Report: Utilities Need to Give BPU More Storm Info

The Board of Public Utilities needs more information on storm responses to determine how to best improve resiliency, according to a consultant’s report.

The report, prepared by GE Energy Consulting, says the state fails to get enough information before and during storms to help it determine the most cost-effective solutions.

It also called on utilities to harden portions of the grid, especially substations. During Superstorm Sandy, 40% of Public Service Electric & Gas substations were shut down by flooding. Since then, the company has started a program to raise substations above the 100-year flood zones or to protect them with walls.

More: NJSpotlight

Utilities Spent $1.25B on Storms in 2011 and 2012, Study Shows

The Board of Public Utilities said utilities in the state spent $1.25 billion to restore and repair systems after the storms of 2011 and 2012, including Superstorm Sandy. The tally was part of the board’s review of storm costs to determine what should be recovered from ratepayers.

The board approved a New Jersey Natural Gas request to recover $48.7 million, including the costs to replace sections of natural gas distribution mains washed away by Sandy. Jersey Central Power & Light said it spent $736.1 million in storm costs. Public Service Electric & Gas said it spent $366.3 million. Atlantic City Electric put its costs at $70 million.

ACE has already received permission to increase rates to cover its costs. JCP&L has a request pending. PSE&G hasn’t asked to raise rates.

More: Asbury Park Press

NORTH CAROLINA

Duke Won’t Charge Customers for Corporate Taxes it Doesn’t Pay

Duke Energy said it will not charge customers $19 million for corporate income taxes that it doesn’t actually have to pay, even though the Utilities Commission approved the practice.

The NCUC ruled earlier this month that utilities can continue to charge customers a 6.9% tax, even though the state legislature recently cut the corporate tax from 6.9% to 5%. Duke said it could have extracted $19 million a year more from Duke Energy Carolinas and Duke Energy Progress customers under the ruling.

“Duke Energy supports the NCUC’s Oct. 9 decision that explains the state of the law in North Carolina,” Duke said. “However, in this case, we have already reduced rates to reflect the decrease in corporate income taxes.”

The ruling gave utilities the option to adjust rates and set an Oct. 24 deadline for them to decide. Republican commission members said the over-collections are negligible for individual bills, but the Democrats said the state’s four utilities would generate an additional $21 million a year.

More: The News & Observer

OHIO

PUCO Drops In-State Renewables Requirement

Utilities in the state no longer have to find in-state sources for half of their renewable energy supply, the Public Utilities Commission ruled.

While making it easier for companies to reach renewable targets, the decision is another blow to the state’s solar industry, which is already feeling a downturn after legislators froze renewable targets earlier this year. “Pure financial projects are on hold right now,” said Geoff Greenfield, president of Third Sun Solar.

More: Columbus Business First

PENNSYLVANIA

PUC Eyes Extension of Utility-Based Energy-Efficiency Conservation

The Public Utility Commission opened a study to consider extending state-directed energy-efficiency and conservation targets for utilities beyond 2016.

The current programs, authorized by a 2008 law called Act 129, set targets for reductions in consumption and peak demand. The targets expire in May 2016. The law requires the PUC to re-evaluate the costs and benefits of energy-efficiency and conservation programs every five years and to consider extending the goals.

More: PUC

EDCs to Provide Customers Look at What Info is Given to Suppliers

The Public Utility Commission directed the state’s electric utilities to reach out to customers every three years to give them the opportunity to review the marketing information being provided to third-party electric generation suppliers. The information includes historic usage and customer addresses.

The PUC’s order directs electric distribution companies to allow customers to access the information and to restrict it if they want. The commission’s action calls on all distribution companies to remind customers of their right to access the information.

More: PUC

PUC’s Audit of PECO Shows Possible Millions in Savings

A Public Utility Commission audit of PECO’s management and operations suggested ways the company could save up to $5.7 million a year and up to $3.1 million in one-time savings. The commission’s Bureau of Audits report was made public by a 5-0 vote of the commission.

The report provided 28 recommendations for the company to improve performance and save money, including reducing non-storm response overtime, improving the mapping of its natural gas lines to cut down on gas line hits and improving oversight of contractors. PECO has agreed to implement all of the recommendations by the first quarter of 2017.

More: The Philadelphia Inquirer; PUC

VIRGINIA

Appalachian Power Files for 6 Energy-Efficiency Plans

Appalachian Power has filed with the State Corporation Commission for approval for four residential energy-efficiency programs and two programs for commercial and industrial customers.

The residential programs include home energy assessments, incentives for customers to give up second refrigerators or freezers, new construction energy-efficiency standards and retail rebates for high-efficiency lighting and appliances. The C&I plans provide incentives for high-efficiency lighting and heating and cooling equipment, and rebates for larger energy-efficiency projects.

The programs are designed to help the company reach mandated energy reduction targets.

More: Bluefield Daily Telegraph

WEST VIRGINIA

Possible to Meet EPA Standards with Mix of Methods, Report Says

The state could meet the Environmental Protection Agency’s proposed carbon emissions standards with a combination of more renewable generation, power plant modification and energy-efficiency programs, according to a report released last week.

The report identified several areas necessary to meet the targets, including modifying existing power plants; dispatching low-emitting plants first; increasing renewable energy generation; expanding energy-efficiency programs; and building lower-emitting, natural gas-fired plants to take advantage of the state’s shale gas production. The report was prepared by the West Virginia University College of Law’s Center for Energy and Sustainable Development, the Morgantown-based consulting firm Downstream Strategies and the Appalachian Stewardship Foundation.

Given the available options, the report said the state can develop a plan to meet its emission targets while also enhancing social, economic and environmental benefits.

More: The Charleston Gazette

October 27, 2014

MRC/MC Preview

The contentious $1,000/MWh energy offer cap is likely to be the subject of some of the most vigorous debate at Thursday’s Markets and Reliability and Members committees meetings.

The MRC deadlocked over the issue Sept. 18 with none of three proposals to lift the cap winning a two-thirds majority. (See Members Deadlock on Change to $1,000 Offer Cap.)

An Oct. 10 task force meeting failed to bridge the gap between generators and load interests. As a result, PJM will ask the MRC to sunset the task force. (MRC agenda item # 3.)

Meanwhile, despite the lack of consensus, Bob O’Connell of J.P. Morgan Ventures Energy will attempt to win MC approval to effectively eliminate the cap from the Operating Agreement as of June 1, 2015. (MC agenda item #4.)

O’Connell’s proposal also suggests that cost-based offers below $2,250/MWh – equivalent to a 15,000 Btu/kWh generator burning gas purchased at $150/Btu -– be allowed to set LMPs. Cost-based offers above $2,250 would be reimbursed through uplift and not set the clearing price. Price-based offers would be permitted to equal cost-based offers when the latter is more than $1,000/MWh.

At the April MRC meeting, O’Connell said that if stakeholders refused to approve a problem statement considering changes to the cap, as few as five members could create a user group to push for the change “through an alternative stakeholder process that may disenfranchise certain members.” (See Effort to Lift Offer Cap Advances After Debate.)

Below is a summary of the other issues scheduled to be brought to a vote at the MRC and MC meetings. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:30)

Members will be asked to endorse the following manual changes:

Revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 28: Operating Agreement Accounting that will set the default Tier 1 synchronized reserves estimates to zero MW for nuclear, wind, solar, batteries and hydro generators. The change means those resources will not receive compensation unless they actually produce during a spinning event.
Changes to Manual 1 to comply with a revised reliability standard given preliminary approval by the Federal Energy Regulatory Commission last month. COM-002-4 (Operating Personnel Communications Protocols) requires the use of a three-part communications process when issuing operating instructions. (See FERC Backs NERC, NAESB Standards.)
Revisions to Manual 14A: Generation and Transmission Interconnection Process that create a pre-application process for new and existing generation resource additions of 20 MW or less in compliance with FERC Order 792. Potential interconnection customers will have to submit a formal written request and a $300 processing fee. PJM is requesting these changes be effective beginning Nov. 1. (See PC Starts Work on Small Generator Interconnection Changes.)
Revisions to Manual 19: Load Forecasting and Analysis clarifying process for adjusting load forecasts due to significant load changes. The changes, which do not reflect any change in the procedures, were endorsed by the Planning Committee Sept. 2.
Conforming changes to Manual 18: PJM Capacity Market in response to members’ requests for details of the process for requesting and cancelling demand response maintenance outages and a FERC order allowing Annual, Extended and Limited products for DR (ER11-2288). The changes detail what qualifies for the maintenance outage, timeframes for the notification window, length of outage, extensions, cancellations, impacts to compliance calculations and resource testing.

3. Cap Review Senior Task Force (CRSTF) (9:30-9:50)

The committee will be asked to approve sunsetting the task force. (See above.)

4. Energy / Reserve Pricing & Interchange Volatility update (9:50-10:20)

Members will vote on whether to approve new rules to reduce uplift and ensure energy prices better reflect operator actions. The changes would increase synchronized and primary reserve requirements under emergency conditions when additional intraday resources are scheduled. The committee also will be asked to approve limits on interchange during emergency conditions. The limit would be used when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load for the hour. The changes were approved last month by the Market Implementation Committee. (See MIC Briefs.)

5. Transmission Owner (TO) Data Feed (10:20-10:30)

Members will be asked to approve Operating Agreement and manual changes to make it easier for transmission owners to access real-time generator data. The changes are intended to improve situational awareness and emergency response. The Operating Agreement would be revised to include a universal non-disclosure agreement, eliminating the need for a separate data confidentiality agreement. Transmission owners will be able to obtain data from generators in their zone without justification. For generators outside its zone, the TO must confirm that the plant is in the current TO energy management system (EMS) model or will be included in an expanded model. The changes were approved by the Operating Committee last month.

6. Cold Weather Resource Improvement (10:30-10:45)

Members will be asked to approve rules for voluntary winter testing of seldom-used generators. The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit. (See Winter Testing Could Cost $15.9M.) The Operating Committee approved the changes earlier this month.

7. 2014 IRM STUDY RESULTS (10:45-11:00)

Members will be asked to approve a recommendation to leave PJM’s Installed Reserve Margin at 15.7% for planning year 2018/19, unchanged from 2017/18. The Planning Committee approved the recommendation earlier this month. (See Planning Committee Briefs.)

8. Reactive Supply and Voltage Control Service from Deactivating Resources (11:00-11:15)

The MRC will be asked to approve on first read a proposed problem statement and issue charge seeking to prevent generation fleet owners from collecting payments for reactive power and voltage control service from generators that are no longer running.

9. Manual 29 Revisions – Billing Adjustments (11:15-11:30)

The committee will be asked to approve a proposed problem statement and issue charge on first read regarding revisions to Manual 29: Billing, regarding treatment of underpayments of miscellaneous items or special adjustments. The changes are intended to prevent cost shifting when miscellaneous items or special adjustments are underpaid.

10. Regional Planning Process Senior Task Force (RPPTF) – Window Proposal Fee (11:30-11:45)

Members will consider a proposal by the RPPTF to charge a nonrefundable $30,000 fee for “greenfield” transmission proposals submitted during project proposal windows as a result of FERC Order 1000.

Members Committee

2. CONSENT AGENDA (1:20-1:25)

The MC will be asked to endorse revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 15: Cost Development Guidelines to correct a typographical error. The words “mileage ratio” will be replaced with “mileage” in Section 3.2.7 of Manual 11 and Section 2.8 of Manual 15, where the calculation of adjusted regulation performance cost is described. There is no change in PJM’s calculations, which have been correctly using mileage as it is defined by PJM.
Members will consider revising its conflict of interest policy to reflect the increasing number of consumer product companies, manufacturers and technology companies becoming involved in the electric industry. (See PJM Revising Policy on Prohibited Investments.)

3. Nominating Committee (1:25-1:30)

The MC will elect members of the 2015 Nominating Committee.

4. Energy Market Offer Price Cap (1:30-2:00)

Bob O’Connell of J.P. Morgan Ventures Energy will attempt to win approval for Tariff and Operating Agreement revisions eliminating the $1,000/MWh energy market offer price cap effective June 1, 2015. (See above.)

October 27, 2014

FERC Removes 10% Adder from Generators’ Make-Whole Payments

By Michael Brooks

The Federal Energy Regulatory Commission said Tuesday that PJM should not have included a 10% adder in its calculation of make-whole payments to generators whose costs exceeded the $1,000/MWh offer cap last winter.

FERC granted a rehearing request to PJM’s Independent Market Monitor, agreeing that including the adder — typically included in cost-based offers to account for the uncertainty of calculating operating costs for combustion turbines under changing ambient conditions — was a mistake.

FERC said that the generators subject to their Jan. 24 waiver of the offer cap would still “receive make-whole payments by documenting the cost and volumes of natural gas needed to generate electricity.”

But the commission said that because the generators’ actual costs are now known, including an adder meant to cover uncertainty was inappropriate.

“This type of ex post determination does not contain any inherent uncertainty that would warrant an adder whose purpose in ex ante offers is solely to enable resources to recover uncertain or difficult-to-quantify costs,” FERC said.

The Monitor had argued in a March report that the adder portion was “not an actual cost and the generation owners did not pay it.” (See Stakeholders Preview Offer-Cap Debate.)

Denied

In its rehearing request, the Monitor also argued that non-capacity natural gas-fired generation resources should receive relief so as not to deter them from participating with PJM. FERC, however, disagreed.

“PJM’s filing requested a temporary waiver only for generation capacity resources and, therefore, we will not extend the waiver to other generators,” FERC said. “Further, no party in this proceeding has presented evidence that natural gas-fired generators other than generation capacity resources had documented costs above the market-clearing price.”

FERC also denied requests for rehearing from the Maryland Public Service Commission and the PJM Industrial Customer Coalition.

The coalition said customers shouldn’t be forced to pay higher prices due to generators’ decisions not to hedge against price spikes in the natural gas market. The coalition also said the waiver should have been limited in scope to specific PJM zones rather than the entire footprint.

FERC countered that the events of late January amounted to an emergency that harmed confidence in the wholesale markets and threatened reliability. “Delaying the issuance of the order could have threatened reliability by discouraging generators from making their units available,” FERC said, adding that its broad waiver was consistent with past orders during emergencies.

FERC’s denial of the PSC’s request was mostly procedural: the PSC had requested a detailed report from the Monitor explaining the basis for determining make-whole payments. The PSC filed its request on Feb. 21; one month later, the Monitor filed its report.

October 27, 2014June 15, 2023

EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans

PJM officials are developing contingency plans for their 2015 capacity auctions in the wake of last week’s stay of the D.C. Circuit Court of Appeals’ EPSA ruling.

PJM General Counsel Vince Duane said it will be at least next spring before the Supreme Court decides whether to review the D.C. Circuit’s ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) throwing out the Federal Energy Regulatory Commission’s Order 745.

On Monday, the D.C. Circuit granted a stay until Dec. 16 on its ruling in order to give U.S. Solicitor General Donald B. Verrilli Jr. time to file a petition for certiorari on FERC’s behalf. If Verrilli files the petition, the stay will remain in effect until the Supreme Court rejects the request, or accepts it and decides the case on its merits.

Although the D.C. Circuit’s May 23 ruling explicitly concerned FERC’s jurisdiction over demand response in energy markets, some believe it also jeopardizes the inclusion of DR in FERC-regulated capacity markets. To avoid legal vulnerabilities, PJM on Oct. 7 proposed eliminating DR as a capacity supply resource and instead having load-serving entities offer DR and energy efficiency to reduce their capacity obligations.

Duane said the stay does nothing to provide additional certainty regarding the May 2015 Base Residual Auction.

“If [the Supreme Court justices] take the case, you have another year of not knowing what the rules for DR participation are,” Duane said in an interview last week.

“If cert isn’t granted, that’s the walk-off home run. That’s the end of it. There’s no more appeals,” he added. “And we are right on the eve of a capacity auction and the question then is what rules can apply now that EPSA is the law of the land and we have Tariff sheets that are kind of antiquated.”

As a result, Duane said, PJM is considering contingency plans, based on the Oct. 7 ‘Poof’ Goes the Demand Response?)

EPSA Response

Electric Power Supply Association CEO John Shelk responded to the stay with a statement calling on PJM to assume the D.C. Circuit’s ruling stands.

“EPSA remains confident that the D.C. Circuit’s decision will stand and that Order 745 will eventually be vacated,” Shelk said. “The key now is moving forward on plans for an orderly transition that take into account not only what the decision requires with respect to demand response participation as supply in the energy markets but also its implications for the capacity markets. Even lawyers who disagree with the court’s conclusion that FERC lacks jurisdiction agree that the ruling’s legal rationale logically means that demand response cannot be a supply-side resource in capacity markets.”

ISO-NE Response

ISO-NE spokeswoman Marcia Blomberg said Friday that the ISO is continuing with its plans to seek FERC approval for rules allowing DR to provide operating reserves and participate in the Forward Reserve Market effective June 2017.

“However, given the legal uncertainty regarding the future of Order 745, and the fact that the full integration of demand response into energy and reserve markets will require two years of work to modify software and system infrastructure, the ISO will decide in early 2015 whether to begin devoting resources to meet the June 1, 2017, implementation date, or to ask for a delay until the legal questions are resolved,” Blomberg said.

FirstEnergy Complaint

The court ruled that Order 745, which required PJM and other RTOs to pay DR resources market-clearing prices, violates state ratemaking authority.

FirstEnergy Solutions filed a complaint with FERC within hours of the May 23 ruling, demanding that PJM throw out the DR that cleared in the May BRA for delivery year 2017/18.

On Wednesday, PJM filed a response in opposition to the FE complaint, saying that FE’s demand that PJM recalculate the 2014 auction results without DR would be “extremely damaging to the market certainty that is critical to sustaining investment in electricity infrastructure.” (EL14-55)

Instead, PJM said it will submit Tariff revisions around New Year’s that will seek to minimize litigation risk by proposing that:

Load-serving entities be permitted to submit price-responsive bids into the capacity auction beginning with the May 2015 BRA, as outlined in the white paper;
Demand response capacity commitments already made for the 2014/15 through 2017/18 delivery years be honored “subject to an orderly, voluntary exit path for capacity demand resources that anticipate losing their energy market compensation as a result of EPSA”; and
Changes be made to incremental capacity auction rules to support a transition, including a provision precluding any new demand resource offers in RPM auctions by retail end users or by aggregators of retail customers.

“PJM expects to ask the commission to accept these changes to serve at least as a ‘stop-gap measure,’” the RTO wrote, “perhaps to be effective only until such time as the commission and industry stakeholders have had an opportunity, once jurisdictional questions are finally resolved, to consider and develop generic and more considered options for demand response participation in organized wholesale electricity markets.”

In its own response, PJM’s Independent Market Monitor told FERC it opposed recalculating the 2014 auction but “generally supports the objective of” the FE complaint.

“Granting this objective as it pertains to future [capacity] auctions would permit the correction of faulty rules that have interfered with the efficient performance of the PJM capacity market design,” the Monitor wrote.

Praise from LaFleur

Because FERC’s direct authority to initiate legal action ends at the D.C. Circuit, FERC Chairman Cheryl LaFleur said that the decision whether to seek a Supreme Court hearing will be made by Verrilli. “That office has the exclusive authority to make that decision for the U.S. government — all the agencies. As with other agencies, we work behind the scenes with them,” she said during a keynote address at PJM’s Grid 20/20 conference Tuesday.

LaFleur said she was unable to talk about the pending FirstEnergy complaint. But she praised PJM’s “very thoughtful” white paper.

“I appreciate your contributing to the discourse on this,” she said. “Because we have a pending complaint before us on how we treat demand response in the markets right now, I haven’t been able to be a part of that discourse, but I’m glad it’s going on.”

October 27, 2014June 15, 2023

Michigan Gov.: Wisconsin Energy-Integrys Merger Could Stifle Competition

By Chris O’Malley

Wisconsin Energy Corp.’s proposed $9.1 billion acquisition of Integrys Energy Group has generated some notable opposition — including Michigan Gov. Rick Snyder.

On Oct. 17, Snyder and Michigan Attorney General Bill Schuette asked the Federal Energy Regulatory Commission to reject the merger, which would create one of the Midwest’s largest electric and natural gas utilities (EC14-126).

Wisconsin Energy and its subsidiaries already control most of the generation in Michigan’s Upper Peninsula. Michigan officials say the merger would give Wisconsin Energy a 60% ownership interest in the area’s only transmission system operator, American Transmission Co. (ATC).

“The level of concentration in both generation and transmission in the Upper Peninsula by one company as a result of this merger is a major concern for Michigan. This concentration will provide the [utilities] market power in the region that could negatively affect competition and rates,” Snyder and Schuette wrote.

Milwaukee-based Wisconsin Energy, parent of We Energies, and Chicago-based Integrys, whose holdings include Wisconsin Public Service and Michigan Gas Utilities, announced the merger June 23.

If the merger is approved, the combined companies will serve more than 4.3 million gas and electric customers in Wisconsin, Illinois, Michigan and Minnesota.

Most of the merging utilities’ generation is in the so-called Wisconsin and Upper Michigan region, or WUMS.

In their request to intervene, the Michigan officials said Wisconsin Energy and Integrys failed to analyze the relevant geographic market in determining market power, significantly understating “both the horizontal and vertical market power that the merged utility will have,” including the adverse impact such market power could have on rates and competition in Michigan’s Upper Peninsula.

Wrong Market Studied

The officials assert that the relevant geographic market is not the entire MISO footprint but WUMS, which includes the Upper Peninsula.

“Michigan contends that it is completely inappropriate to use MISO’s footprint, which includes parts of 16 states and one Canadian province, as the geographic market for assessing market concentration,” the state wrote.

Michigan pointed to findings by MISO’s Independent Market Monitor, as of the start of energy markets in April 2005, as identifying WUMS and North WUMS as narrow constraint areas (NCAs). “In designating submarkets as NCAs, the commission has effectively recognized these areas as separate and distinct geographical markets,” Michigan said.

Michigan says the merger could shift 93% of the cost of retiring the Presque Isle generating plant — $90.2 million — from Wisconsin ratepayers to a “much smaller set” of ratepayers in Michigan’s Upper Peninsula.

Great Lakes Utilities Protest

The proposed merger is also problematic for some utilities, including Wisconsin-based Great Lakes Utilities.

GLU’s members include municipal electric utilities in 12 Wisconsin and Michigan cities that are neighboring utilities to Wisconsin Energy and Integrys. GLU is a wholesale power customer of both.

GLU’s protest complains that the merger is likely to result in “substantial” increases to the cost of wholesale power. GLU also asserts that the merger will “strengthen Wisconsin Energy’s hand in transmission planning and cost allocation issues at the expense of other entities.”

In particular, GLU said the acquisition of Integrys will consolidate the ownership of ATC. Wisconsin Energy controls 26% of the voting shares in ATC while Integrys controls 34%.

“Without diversity of opinion and perspective, ATC’s function as an independent entity will be less certain,” GLU said.

A spokeswoman for Wisconsin Energy, Cathy Schulze, said the utility will respond to the protests soon.

October 24, 2014June 15, 2023

PJM, IMM Post Capacity Performance Cost-Benefit Analysis as Members Form Battle Lines

[Editor’s Note: This article was amended Oct. 28 to put FERC Chairman Cheryl LaFleur’s comments in context. See clarification below.]

PJM’s proposed Capacity Performance product would cost ratepayers as much as $6 billion over the next four years, with long-term costs of as much as $700 million annually, the RTO and Independent Market Monitor Joe Bowring said in a joint paper Thursday.

The cost-benefit analysis was released two days after Federal Energy Regulatory Commission Chairman Cheryl LaFleur indicated support for PJM’s efforts in a speech at PJM’s Grid 20/20 conference in Washington and stakeholders announced 15 coalitions that will argue for changes in the plan.

Almost 80 stakeholders joined at least one of the coalitions, which include two load groups and seven representing generators (including gas, hydro, renewables and independent power producers). Other groups represent project finance interests, storage developers and companies specializing in energy efficiency and demand response.

The largest group is the Transition Coalition, with 19 members led by Michelle Gardner, director of regulatory affairs for NextEra Energy Power Marketing. It is concerned with rules that will apply for delivery years 2015/16 through 2017/18.

PJM Gains Allies

The release of the joint cost-benefit paper indicates that PJM will have the Market Monitor on its side in the debate before FERC. Bowring, who had expressed skepticism about PJM’s original proposal, said the RTO’s amended Oct. 7 plan addressed his major concerns. (See Revised Capacity Performance Plan Wins Bowring’s Support.)

The proposal also received an unofficial boost from LaFleur in her keynote address Tuesday at the Grid 20/20 conference. LaFleur said she agreed with PJM’s goals of finding a way to “value base load properly without losing sight of the other resources and how to assure that the fuel will be there for reliability.”

“We certainly will look closely at any proposal that comes in. But I think the purpose of understanding what it is we want the market to do and really trying to refine the definition — while not easy — is exactly what we should be doing,” she said.

[Clarification: FERC spokesman Craig Cano said Oct. 28 that while LaFleur “is supportive of [PJM’s] goals,” she wants to make clear that she has not prejudged the proposal.]

Cost-Benefit Analysis

The analysis released by PJM and the IMM projects both the increased capacity costs and energy market savings based on an assumption that the new Capacity Performance product, with its higher expectations and penalties for non-performance, will reduce outage rates by 6 percentage points in winter and 3 percentage points in summer.

Had the product been in place in 2014, it would have reduced energy load payments by 8.7% in January and February ($975 million) and 8.5% in June-August ($725 million), according to the analysis.

The proposal’s requirement that generator dispatch parameters reflect their physical characteristics during Hot and Cold Weather Alerts would have reduced January’s uplift payments by 83% ($500 million), the analysis says, resulting in total energy cost savings for the year of $2.2 billion.

The analysis uses the $2.2 billion savings in future projections, beginning with delivery year 2016/17.

Over the long term, PJM and the Monitor say, the changes will have a net cost of $300 million to $700 million, with net savings in years with extreme weather.

Next Steps

The coalitions have until 5 p.m. Oct. 28 to submit briefing papers to the Board of Managers, which will decide on the final proposal submitted to FERC.

The coalitions will make oral presentations to the board at an “Enhanced” Liaison Committee meeting at the Cira Centre in Philadelphia Nov. 4. The meeting will be teleconferenced for PJM members and state commission and FERC representatives, but no members of the media will be permitted.

October 20, 2014June 15, 2023

Federal Briefs

A Nuclear Regulatory Commission staff report says that the Yucca Mountain nuclear waste repository in Nevada would, “with reasonable expectation,” meet safety requirements.

The 781-page report was ordered when the license for the facility was still under consideration, back in 2008. Since then, the Obama Administration halted work on the project, about 100 miles northwest of Las Vegas.

The National Association of Regulatory Utility Commissioners welcomed the report and urged the administration and Congress to support the continued review of the facility’s license application. NARUC noted that consumers of nuclear energy have contributed billions of dollars over the past 30 years to fund a repository. “Our government owes it to them to finish the job.”

But opponents said the report did not fully consider all the probabilities that could affect safety. “It’s a pretty meek endorsement,” said Robert Halstead, director of the Nevada Agency for Nuclear Projects.

More: Las Vegas Review-Journal; NARUC

Duke Files for FERC Approval of NCEMPA Asset Purchase

Duke Energy Progress has asked the Federal Energy Regulatory Commission to approve its $1.2 billion buyout of the North Carolina Eastern Municipal Power Agency’s shares of several Duke power plants.

NCEMPA is selling its stakes in four Duke Energy Progress power plants — about 700 MW at two coal-fired plants and three nuclear units. If the deal is approved, Duke will be the sole owners of the Roxboro Unit 4 and Mayo Unit 1 coal plants, and the Brunswick Units 1 and 2 and Harris Unit 1 nuclear stations. All of the plants are in North Carolina.

Duke also entered into a 30-year power-purchase agreement to supply wholesale power to the 32 municipalities represented by NCEMPA. The terms of that agreement were not released.

Duke will also need regulatory approval from North Carolina, South Carolina and the Nuclear Regulatory Commission.

More: Market Watch

Lockheed Martin Claims Breakthrough in Fusion Power

The magnetic coils inside the compact fusion (CF) experiment are critical to plasma containment, as pictured in this undated handout photo.

Defense contracting giant Lockheed Martin made big waves last week when it announced it had made a technological breakthrough in creating a power source based on nuclear fusion. It said the first reactors — small enough to fit in the back of a truck — could be ready in a decade.

The Lockheed research team, headed by Tom McGuire, has been working on the project at the company’s Skunk Works, its top secret research facility in California. McGuire told Reuters that its designed 100-MW reactor would be about 10 times smaller than current reactors.

The company said it planned to build and test a fusion reactor in the next year, and then construct a prototype within five years. The method, long sought after by researchers, attempts to capture the energy released during nuclear fusion, rather than nuclear fission. Nuclear fusion occurs when atoms combine into more stable forms and is inherently safer. Fusion reactors would use a deuterium-tritium fuel and not produce any radioactive waste.

More: Reuters

EPA Fines DOE for Missing Hanford Cleanup Deadlines

The Environmental Protection Agency is fining the Department of Energy up to $10,000 for every week it fails to start removing radioactive sludge at the Hanford Nuclear Reservation on the Columbia River in Washington state.

The DOE had agreed to start the storage basin clean-up by Sept. 30 at the nation’s most contaminated nuclear site, where plutonium was produced. But it missed the deadline, blaming federal budgeting issues. The EPA said it will start the fine at $5,000 for the first missed week before fining the department $10,000 for each additional week of delay.

The DOE had requested a deadline extension but was denied by the EPA.

More: The Seattle Intelligencer

Last 44M Acres in Gulf Opened to Energy Exploration

The Bureau of Ocean Energy Management is opening the last unleased areas in the central Gulf of Mexico to oil and gas exploration, it announced last week.

The lease sale, to take place in New Orleans in March, will mark the seventh such sale under the Obama Administration’s five-year Outer Continental Shelf Oil and Gas Leasing Program. The first six sales offered more than 60 million acres and produced $2.4 billion in federal revenue.

The blocks to be leased off Louisiana, Mississippi and Alabama run from 3 to 230 miles offshore, in water from 9 feet to 11,000 feet deep. The bureau estimates the 44 million acres could produce 460 million to 894 million barrels of oil and 1.9 trillion to 3.9 trillion cubic feet of natural gas.

More: Bureau of Ocean Energy Management

Baran Sworn in as New NRC Commissioner

Jeff Baran is sworn in as a NRC commissioner by Chairman Allison M. Macfarlane (right) as his wife Michelle Yau looks on. (Source: NRC)

Jeff Baran was sworn in as a member of the Nuclear Regulatory Commission and will serve until June 30, 2015, the remainder of William Magwood’s term. Magwood accepted a position with the Paris-based Nuclear Energy Agency.

NRC Chairman Allison M. Macfarlane administered the oath of office. “We have substantial work ahead of us and I am confident that Jeff will make a valuable contribution to our mission,” she said. Baran was staff director of Energy and Environment for the U.S. House Committee on Energy and Commerce, and had NRC oversight duties in that position.

More: PennEnergy

Cove Point Opponents File Rehearing Request with FERC

A group of environmental and customer advocates filed a motion seeking a rehearing of the Federal Energy Regulatory Commission’s approval of the Cove Point LNG export terminal, saying the agency’s OK was based on an inadequate environmental review.

Earthjustice, representing groups such as the Sierra Club, Lower Susquehanna Riverkeeper and the Chesapeake Climate Action Network among others, also filed a motion to stay, hoping to stop initial construction at the site on the Chesapeake Bay in southern Maryland.

“In neglecting to prepare a thorough review of the environmental impacts of Dominion’s controversial project, FERC is prioritizing the desires of a powerful company over the health and safety of the people of Calvert County, Marylanders and communities throughout the Marcellus Shale region,” Earthjustice Associate Attorney Jocelyn D’Ambrosio said.

More: Earthjustice

TVA Builds First U.S. Nuclear Backup Facility

The Tennessee Valley Authority has completed the nation’s first nuclear backup facility built in response to the 2011 disaster at Japan’s Fukushima Daiichi facility.

The fortified facility, serving the TVA’s Watts Bar Nuclear Plant in Spring City, Tenn., is an $80 million bunker protecting pumps and generators. It was built on bedrock with 18-inch concrete walls and designed to withstand earthquakes, fires and even a missile attack.

The TVA is the first U.S. utility to finish a backup center. Many other nuclear sites in the U.S. are either planning such facilities or already building them, in response to orders from federal regulators.

More: Chattanooga Times Free Press

DOE Funds Combined Heat, Power Project at Aberdeen

The Department of Energy is helping to fund a 7.9-MW combined heat and power (CHP) project to replace the aging steam plant at the Army’s Aberdeen Proving Ground in Maryland. CHP, also known as cogeneration, uses a single station to provide both electricity and heat, usually in the form of steam.

The DOE will replace the facility’s steam plant, which is being decommissioned in 2016, with a CHP plant that will provide 86% of the site’s steam needs and 50% of its electricity. The project will also develop standard protocols — including design, air permitting and electrical interconnection — that can be replicated at other defense facilities.

Other projects included in the DOE’s $2 million in funding are a 13.7-MW plant at NASA’s Johnson Space Center in Houston and the National Science Foundation’s Arctic Program at Thule Air Force Base in Thule, Greenland.

More: Air Conditioning, Heating & Refrigeration News

Low-Carbon Energy System Could Save Trillions, Study Says

Transitioning to a low-carbon energy system could free up trillions of dollars of investment capital, spurring economic growth, according to a report by the Climate Policy Initiative.

The report estimates the worldwide cost of building and maintaining low-carbon energy systems and transportation systems. A second section of the report calculates the economic costs of decommissioning existing fossil fuel assets. It concludes the transition could free up $1.8 trillion for investment between 2015 and 2035.

It said concentrating the phase-out on coal assets could provide the largest emissions cuts with the least financial loss.

“Our analysis reveals that with the right policy choices, over the next 20 years governments can achieve the emissions reductions necessary for a safer, more stable climate and free up trillions for investment in other parts of the economy,” CPI senior director David Nelson said. “This is even before taking into account the environmental and health benefits of reducing emissions.”

More: Climate Policy Initiative

October 20, 2014June 15, 2023

Company Briefs

Xcel Energy says changing environmental regulations are forcing it to shut down the 232-MW coal-fired units at Black Dog power plant in Burnsville, Minn.

Xcel told MISO last week that the Black Dog plant has been a cost-effective, reliable energy resource for more than 60 years. “But there is a cost associated with the modifications needed to operate these coal units under new federal air emission rules. Retiring the units will benefit our customers by not only avoiding those costs but also reducing emissions.”

A 300-MW natural gas-fired plant at the site will remain in operation. The two coal units will go dark in April.

More: Energy Central

Dynegy Picks Right Time for $5.1B Bond Offering

Dynegy issued $5.1 billion in debt just before bond yields increased to their highest levels in a year, lifting the prices of the underlying notes.

“They priced the deal in the middle of the carnage and prices popped right after the sale,” Andy DeVries, a CreditSights analyst said the day of the offering.

September saw a sell-off of junk-rated bonds – investors pulled $2.3 billion from funds that buy high-yield bonds in the week ending Oct. 1, according to Lipper data. Dynegy offered its bonds in three tranches, or sections: five-, eight- and 10-year notes.

More: Bloomberg

FirstEnergy Disputes Dark View of IEEFA Report

FirstEnergy says a recent report that contends the company is struggling to remain viable is “misleading and biased.”

The Institute for Energy Economics and Financial Analysis’s report said the company is too dependent upon aging coal generation and is relying upon ratepayer subsidies to “reverse a deepening spiral of debt service and revenue declines.”

But FirstEnergy spokesman Doug Colafella said last week that the company “has taken significant actions —particularly in the past 12 months — to improve our financial position, lower our cost structure and position the company for more stable and predictable growth through our regulated holdings, and overcome the lingering effects of the recession as well as challenging capacity and energy markets.”

“We believe the strategies we have put in place, together with our commitment to operational excellence and financial discipline, will provide long-term value and predictable, sustainable growth to our investors,” Colafella said.

More: Midwest Energy News

PJM to Sierra Club: You Don’t Understand

The chief planning official for the grid operator took issue with an environmental group’s claim that continued operation of a generating plant in New Jersey would be a threat to the system.

At issue is the planned switch from coal to natural gas for the B.L. England plant in South Jersey. New Jersey Sierra Club Director Jeff Tittel, citing a PJM report, told area reporters that continued operation of the plant would be a threat to system reliability.

Just the opposite, PJM’s Steven R. Herling, vice president of planning, told Tittel in a letter.

“Recent media statements attributed to you about reliability and cost impacts associated with the B.L. England generating units remaining in service are based on a misunderstanding of PJM Interconnection’s planning process,” Herling wrote. “Simply put, the continued operation of existing generating units at the B.L. England site, absent the addition of significant amounts of new generation, is not projected to result in reliability problems.

“Our transmission-planning process is very complex, dynamic, and — as a consequence — can be misunderstood,” Herling continued. “I would have been very happy to explain the process and underlying facts to help you avoid confusion and would be willing to clarify PJM’s study results at any time.”

Tittel stands by his group’s claims and said PJM was changing its story at the behest of utilities. “They’re trying to spin it any way they can,” he said.

More: The Philadelphia Inquirer

Dominion’s Surry Plant Shuts Down Due to Malfunctioning Sensor

Dominion Resources’ Surry Unit 2 tripped and shut down unexpectedly last week after a sensor mistakenly detected a problem in the reactor protection system, the company announced. The reactor, in operation since 1973, went offline at about 8 a.m. Oct. 13.

“It did just what it was supposed to do,” Dominion spokeswoman Bonita Harris said. “Nuclear plants are designed to shut down automatically when that happens.”

The plant returned to service two days later. The plant last had an unscheduled shutdown in April 2011 after it was hit by a tornado.

More: The Daily Press

Farley Unit 2 Goes Offline After Lightning Strike

Operators of Southern Co.’s Joseph M. Farley Nuclear Plant in Alabama shut down Unit 2 after a lightning strike on a transmission line Oct. 14. The plant was already in the process of going offline for a refueling outage.

Each of the two Farley units requires refueling every 18 months, a process that takes about a month. About 900 Southern employees and 800 contractors will be involved in the effort. Farley Unit 1 remains in service, the company said.

More: Power Engineering

Top 25 US Companies Continue to Increase Solar Installation

The top 25 companies in the U.S. for embracing solar power installed 28% more capacity last year as equipment and installation prices continued to drop, according to the Solar Energy Industries Association.

Since 2012, the 25 companies — including Target, General Motors, Kohl’s and Walgreens — have doubled the amount of photovoltaic capacity installed on their facilities, from 279 MW in 2012 to 569 MW as of August, according to the trade group’s annual report.

SEIA spokesman Ken Johnson said the 30% Solar Investment Tax Credit helped maintain an impetus for the industry’s growth.

More: Midwest Energy News

October 20, 2014

FERC Orders ROE Hearing on MISO TOs

By Chris O’Malley

MISO industrial customers will get a full hearing on their bid to reduce transmission rates by $327 million a year.

The Federal Energy Regulatory Commission Thursday ordered an evidentiary hearing on the industrials’ complaint that the 24 MISO transmission owners’ base return on equity (ROE) — 12.38% except for ATC, which has a base ROE of 12.2% — is unjust and unreasonable.

The complaint “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures,” the commission ruled (EL14-12).

The commission rejected an attempt by the transmission owners — including Ameren, Duke Energy and Entergy — to dismiss the complaint on procedural grounds.

FERC opened the door to fights over the maximum allowable ROE in June, when it changed the way it sets return on equity rates for electric utilities that’s now more akin to the process it uses for natural gas and oil pipelines. Ruling in a case involving New England transmission owners, FERC tentatively set the “zone of reasonableness” at 7.03-11.74%. (See related story, New England TOs to Pay Refunds in ROE Case.)

MISO’s industrial customers say the base ROE for MISO TOs should not exceed 9.15%, citing “significantly changed economic circumstances since the base ROEs were first established.”

The commission rejected the industrials’ challenge to the use of capital structures that include more than 50% common equity.

“Complainants have not demonstrated that MISO TOs, individually or collectively, do not meet the requirement of the commission[’s] three-part test, failure of which would call into question the justness and reasonableness of using their actual capital structures for ratemaking purposes.”

The plaintiffs are six groups of industrial customers, including Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.

October 20, 2014

Va. SCC Staff Blasts EPA Carbon Rule

By Michael Brooks

The Environmental Protection Agency’s proposed regulations on carbon emissions would increase electric bills and harm reliability, Virginia State Corporation Commission staff members said in comments filed last week.

SCC staff said EPA’s “arbitrary, capricious, unsupported and unlawful” plan could cost Dominion Virginia Power customers alone between $5.5 billion and $6 billion. “Contrary to [the EPA’s] claim that ‘rates will go up, but bills will go down,’ experience and costs in Virginia make it extremely unlikely that either electric rates or bills in Virginia will go down,” staff said.

The EPA’s proposed regulations, announced in June, call for a 30% reduction in carbon emissions from the country’s existing power plants’ 2005 levels by 2030, with individual targets for each state. (See Carbon Rule Falls Unevenly on PJM States.) Virginia would be required to reduce its generating plants’ emissions to 884 lbs./MWh by 2020 and to 810 lbs./MWh by 2030.

Stranded Investments

The EPA’s modeling predicts that Virginia utilities will have to retire 2,851 MW of fossil-fuel generation and build 351 MW of wind power before 2020, “a timeframe that compromises reliability,” staff said.

The retirements threaten “several billions of dollars of recent investments in existing coal-fired facilities in Virginia and West Virginia that Virginia ratepayers have only begun to pay off. Much of this investment has been constructed to comply with EPA consent decrees on which the ink is hardly dry,” staff wrote.

Staff also claims the regulation would impose more stringent emission requirements on existing generators than the EPA is requiring in a separate standard for new generation.

While existing plants in Virginia will eventually be limited to 810 lbs./MWh, new coal plants, built with the best available carbon-capture technology, are limited to 1,000-1,050 (depending on the size), while new natural gas plants are limited to 1,100.

“It would be hard to imagine the EPA advancing such a proposal in areas that are more familiar to everyday life,” SCC staff said. “Would it be rational to require the current owners of automobiles or lawnmowers throughout Virginia, for example, to meet an emission standard that is 26% more stringent than required for the production of new cars or lawnmowers that must use the best available technology?

“Turning regulation on its head in this way — requiring older, but still useful equipment to meet a standard that the EPA admits cannot be achieved even by entirely new equipment — is a recipe for stranding prior investments and requiring significant additional investment.”

Reliability Impact

SCC staff said that they analyzed Dominion’s 2013 integrated resource plan as a reference to estimate the cost of complying with the EPA’s rule. One of two scenarios in the IRP, the Fuel Diversity Plan, calls for the addition of a third unit at the utility’s North Anna nuclear plant. (See SCC: Dominion IRP Lacks Analysis of Nuclear Plans.)

This plan would allow the state to meet its 2030 goal, the SCC staff said, but they altered it to include 69 MW of wind generation and more coal plant retirements than originally called for to meet the interim 2020 goal.

“These retirements are of grave concern because the power plants involved are used today to ensure reliable service to Virginia customers, have years of useful life remaining and cannot be replaced overnight or without regard for impacts on the electric system,” staff said.

Staff said the regulations set “generic and unsupported expectations of levels” of renewable generation and energy efficiency that “are extremely ambitious, almost certainly unachievable and uneconomic under traditional standards.”

Enviros: SCC Staff ‘Playing Politics’

Several environmental groups, however, criticized SCC staff’s assertions as inaccurate.

“The SCC staff analysis is just plain wrong,” said Glen Besa, director of the Sierra Club’s Virginia Chapter. “They’re playing politics with climate change science and they have no business doing that, and they’re bringing discredit on the commission.”

“The SCC staff crossed the line in their hastily submitted comments to EPA and I think they’ll ultimately regret that mistake,” said Dawone Robinson, the Chesapeake Climate Action Network’s Virginia policy director. “I think they misread the rule.”

Specifically, Robinson questioned the use of Dominion’s Fuel Diversity Plan as a way to comply with the regulations.

“SCC staff seems to suggest that in order to comply with the Clean Power Plan, Virginia needs to invest in a third nuclear reactor at North Anna, and that simply isn’t the case,” Robinson said. “Additionally, many of the coal plant retirements and natural gas conversions that the SCC staff suggests will hamper the state … were proposed by the utility before the Clean Power Plan was even released.”

Robinson’s comments echo those made by Cale Jaffe, director of the Southern Environmental Law Center’s Virginia office, to The Richmond Times-Dispatch.

“It appears the staff has misread the rule,” Jaffe said. “Analyses that we have reviewed show that Virginia is already 80% of the way to meeting Virginia’s carbon pollution target under the Clean Power Plan.

“Almost all of those reductions are coming from coal plant retirements and natural gas conversions that the utilities put in place long before the Clean Power Plan was even released.”

The EPA, which will be accepting comments on the proposed rule through Dec. 1, will issue the final rule in June 2015.