MATS Challenge Too Late for Targeted Coal Plants

By Rich Heidorn Jr.

American Electric Power and FirstEnergy plan to shut down more than 9,200 MW of coal-fired generation and invest hundreds of millions to keep other plants operating under the Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS).

Those plans won’t change even if the Supreme Court throws out the standards, which are due to take effect April 16. (See related story, Supreme Court Shows Ideological Divide over MATS Rule.)

“We have been investing in, operating and staffing the generating units scheduled for retirement in a way that would not support their continued operation past their planned date of retirement,” AEP spokeswoman Tammy Ridout said Monday.

For those plants that AEP plans to keep, “the investments that we are making [to meet MATS] also satisfy other Clean Air Act requirements,” such as the Cross State Air Pollution Rule (CSAPR) and Regional Haze regulations, she added. “We are fully committed to those investments, and by the time a decision from the Supreme Court is expected, we will have completed or be well on our way toward completion with most of them.”

FirstEnergy has the same outlook. “The plants that we’ve announced for closure, we don’t have any plans to change those decisions,” said FirstEnergy spokeswoman Stephanie Walton. “We’re investing $370 million in upgrades to comply with MATS. Most of [the investments] will have been made by the time the Supreme Court rules.”

Indeed, about 90% of the capital expenditures needed to meet MATS compliance have already been spent, attorney Paul M. Smith, representing Calpine and other generators, told the justices last week.

AEP and FirstEnergy aren’t alone in downplaying the potential impact of the court’s ruling on the queue of coal plants headed for the gallows.

“We see little in immediate practical implications on power markets arising from a scenario where the Supreme Court overturns MATS,” UBS analysts said in a research note last week. “Rather, with the current gas price environment virtually ensuring limited run times on coal plants, particularly of the Appalachian variety which are primarily impacted by these regulations, we do not think many coal assets will elect to continue operations.”

“I think it’s pretty unlikely that anything like a majority of the plants announced for retirement could be backed off on,” agreed Anne Smith, co-chair of NERA Economic Consulting’s global environment practice.

Cost-Benefit Analysis

While the court’s ruling will be too late to provide a reprieve for most of the old, small plants targeted for retirement, it could have an impact on EPA’s efforts to reduce emissions from electric generation.

A ruling that requires EPA to take costs into account when it decides what to regulate — as opposed to when it sets the standards — could have broad implications.

Some environmental attorneys say the Supreme Court decision to hear the MATS challenge could indicate it is reconsidering its 2009 decision that held EPA had discretion on how to consider the cost of regulating large cooling water intake structures under the Clean Water Act, which doesn’t expressly authorize or forbid the use of cost-benefit analyses.

A ruling that found it was “arbitrary and capricious” for EPA not to consider costs could raise the bar for future regulations.

EPA claims MATS will cost $9.6 billion annually but produce total benefits of at least $37 billion to $90 billion per year, preventing as many as 11,000 premature deaths and 130,000 asthma attacks, while eliminating 5,700 hospitalizations and emergency room visits and 540,000 missed workdays.

However, only a fraction of the benefits — $500,000 to $6.2 million annually — are directly related to cuts in mercury emissions. The remainder are “co-benefits” that arise not directly from reducing toxic emissions, but from reductions in particulate matter and carbon emissions expected to result from the standards.

Critics say EPA has engaged in over counting, citing the same co-benefits to justify multiple EPA regulations.

Section 112 vs. 111(d)

The MATS case, which turns on an interpretation of section 112 of the Clean Air Act, also could have an impact on challenges already filed to EPA’s proposed greenhouse gas rule, which the agency is pursuing under section 111(d) of the act.

A suit by coal mining company Murray Energy argues that it is illegal for EPA to regulate generating plants under section 111(d) because power plant emissions are already regulated under section 112. If the Supreme Court rejects the mercury rule, it could remove that as a basis for a challenge on the carbon rule, some say.

PJM Impact

But MATS, 25 years in the making (see related story), will have a major impact regardless of the court’s ruling.

In PJM, 120 generating units totaling about 12,500 MW have indicated plans to retire by 2018. The plants average 48 years old, with some as old as 67. Only four of the units, totaling 425 MW (3.4% of total capacity at stake), are less than 40 years old.

At the end of last year, AEP had generating capacity of almost 37,600 MW, more than 23,700 MW of it coal-fired. It plans to retire 6,500 MW by the end of next year, including 5,400 MW in PJM.

AEP said a decision to remand or suspend the rule could impact certain aspects of the operation of environmental controls that are already installed or are currently under construction. “For example, there could be greater flexibility to operate selective catalytic reduction systems and SO₂ scrubbers if they are not needed to achieve the mercury and acid gas limits under the MATS rule, but are only required to achieve compliance with the market-based CSAPR programs,” Ridout said.

FirstEnergy cited MATS in announcing in January 2012 it would retire six coal-fired plants totaling 2,689 MW in Ohio, Pennsylvania and Maryland by September of that year. The closures were projected to affect about 529 employees. Retirements of three Ohio plants — Eastlake, Ashtabula and Lakeshore — have been delayed under reliability-must-run agreements.

The retirements will leave FirstEnergy with six coal-fired plants totaling 9,228 MW in Ohio, Pennsylvania and West Virginia. Most of those being retired are 500 MW or smaller and served as peaking or intermediate generators; those being retained are 1,000 to 2,500 MW baseload plants.

PJM’s reliability concerns also led East Kentucky Power Coop. to delay retirements of Dale Station Units 3 and 4 until April 2016, a year later than planned. EKPC closed Units 1 and 2 of the Clark County, Ky., plant about a year ago.

EKPC said Units 3 and 4 would be maintained in case market and regulatory conditions allowed their retrofit or conversion. The plant, with a capacity of 196 MW, began operating in 1954, with the newest unit dating from 1960.

“If the Supreme Court makes a decision that changes the rules on MATS, our board would carefully look at that decision to assess whether our plans should change,” said EKPC spokesman Kevin Osbourn.

GHG Rule: Good for Regulated Gens, not Merchants

EKPC, which has invested nearly $1.5 billion in two new coal-burning units and retrofits to older units, said it fears those investments could become stranded as a result of EPA’s Clean Power Plan, which will require Kentucky to reduce its carbon emissions by 18% from 2005 levels by 2030.

But the additional regulations won’t necessarily be a bad deal for utility investors.

“To the extent we install additional controls on our generation plants to limit CO₂ emissions and receive regulatory approvals to increase our rates, return on capital investment would have a positive effect on future earnings,” AEP told investors in its 2014 annual report. “Prudently incurred capital investments made by our subsidiaries in rate-regulated jurisdictions to comply with legal requirements and benefit customers are generally included in rate base for recovery and earn a return on investment. We would expect these principles to apply to investments made to address new environmental requirements.

“However, requests for rate increases reflecting these costs can affect us adversely because our regulators could limit the amount or timing of increased costs that we would recover through higher rates. For our sales of energy into the markets, however, there is no such recovery mechanism.”

March 30, 2015

Dynegy Wins FERC OK for $6.25B Duke, Energy Capital Partners Generation Deals

By Ted Caddell

The Federal Energy Regulatory Commission on Friday approved Dynegy’s purchase of 12,500 MW of generation from Duke Energy and Energy Capital Partners, the final approval needed for both deals (EC14-141, EC14-140).

The $3.45 billion ECP deal is scheduled to close Wednesday, while the $2.8 billion Duke acquisition will close Thursday.

With the two deals, Dynegy — which emerged from bankruptcy less than three years ago — has boosted its total ownership to nearly 26,000 MW of generation.

Dynegy will own 11 Duke generating units in Ohio, Illinois and Pennsylvania totaling about 6,100 MW, as well as Duke Energy Retail Sales, its competitive retail business in Ohio. The ECP deal gives Dynegy 10 generators totaling 6,400 MW, primarily in the Midwest and New England.

Dynegy would gain about 9,000 MW in PJM, boosting it to more than 10,700 MW and eighth in generation share in the RTO.

A New Player in New England

The ECP deal also makes Dynegy a major player in the ISO-NE market, where it had been the owner of a single 540-MW natural gas plant in Maine. (See Dynegy Back in the Game with Duke, ECP Acquisitions.)

Dynegy expected to close the deal with Duke by the end of last year, but it missed that deadline while it was addressing market power concerns from PJM’s Independent Market Monitor. Those concerns were resolved in a settlement last month, with Dynegy agreeing it would not try to buy any of the plants that will come on the market as a result of the PPL-Riverstone Holdings deal to form Talen Energy. It also committed to offer all of its units into the PJM capacity market auctions and promised it wouldn’t retire any units unless they failed to clear. (See Dynegy, PJM IMM Reach Settlement on Duke, Energy Capital Partners Deal.)

No Market Power Concerns

In approving the deals, FERC said it saw no market power concerns in either ISO-NE or PJM. It said Dynegy’s share of New England’s energy market would rise as high as 17.7% and its share of the region’s capacity market would be 9.4%.

The commission also rejected a complaint by Utility Workers of America Local 464 that the transaction would enable Dynegy to raise New England capacity prices due to its acquisition of ECP’s Brayton Point Station, which is scheduled for retirement in 2017.

The commission said Brayton Point’s closure was beyond the scope of its review of the ECP transaction and that the union did not explain how it derived the price increases it claimed would result from the a reduction in offered capacity.

“As the commission has explained, its authority to condition [asset sale] authorizations is limited to addressing specific, transaction-related harm,” FERC said. “The issues raised by UWA Local 464 are related to the retirement of the Brayton Point Station, which the commission has already reviewed, rather than the proposed transaction.”

More Deals on the Way?

The Houston-based merchant generator has indicated it is looking to expand its fleet still further. A Dynegy executive told Columbus Business First last month that the company “would be very interested” in American Electric Power’s coal plants in Ohio. AEP, which failed in its initial bid to secure a power purchase agreement for one of its Ohio coal plants, has hired investment bank Goldman Sachs Group to investigate the sale of its coal-fired fleet. (See AEP Considering Sale of 8,000 MW in Ohio, Indiana.)

Those plants, with a combined capacity of 7,875 MW, are in Ohio, except for the 1,186-MW Lawrenceburg plant in Indiana. Some 2,100 MW of the plants Duke is selling to Dynegy are partially owned by AEP already, and Dynegy has said it would make sense to consider acquiring AEP’s share.

March 26, 2015

Supreme Court Shows Ideological Divide over MATS Rule

By Rich Heidorn Jr.

WASHINGTON — The Supreme Court’s ideological divide was on display Wednesday as justices sparred with attorneys over whether the Environmental Protection Agency should have considered costs before deciding whether to regulate mercury and other hazardous air pollutants from power plants.

The case combined what began as three challenges to EPA’s Mercury and Air Toxics Standards (MATS), which are due to take effect in less than three weeks. After an appellate court upheld the rule in a 2-1 ruling in April 2014, the Supreme Court agreed to consider a single question: Did EPA act unreasonably because it refused to consider costs in determining whether it is “appropriate and necessary” to regulate hazardous air pollutants emitted by electric utilities?

The 90-minute oral arguments saw the court’s liberal wing, led by Justices Elena Kagan and Sonia Sotomayor, defending EPA’s stance that it should consider costs only after a cost-blind determination that the pollutants pose a public health risk and therefore should be regulated.

The regulations were initiated 25 years ago, when Congress amended the Clean Air Act in 1990. The amendments ordered EPA to regulate 189 hazardous air pollutants (HAPS), including mercury, arsenic and cadmium, which had not been previously controlled. (See related story, MATS: 25 Years in the Making.)

Conservatives, led by Justice Antonin Scalia, expressed sympathy for the challenge by Michigan and other coal-dependent states, some electric utilities and the coal mining industry.

As in many past decisions, the ruling may turn on the opinion of centrist Anthony Kennedy. In contrast with his colleagues, who appeared to have staked out firm positions, Kennedy’s questions suggested he was leaning toward EPA but willing to consider the challengers.

‘Capacious’

Early in the argument by Michigan Solicitor General Aaron D. Lindstrom, Kennedy observed that “‘appropriate’ is a capacious term.”

“It is a capacious term,” Lindstrom agreed. But he said that “cuts against the government because one of the things that’s encompassed within the term ‘appropriate’ is that it looks at all of the circumstances in … determining whether or not you’re going to regulate. Costs [are] relevant.”

Justice Kagan said Congress would have explicitly required EPA to consider costs if that was its intent. For sources other than electric generating plants, Congress expressly forbade EPA from considering costs when deciding whether to regulate. “To get from silence to this notion of a requirement seems to be a pretty big jump,” Kagan said.

Scalia said he disagreed with the premise that EPA could ignore costs because Congress did not give explicit instructions to the contrary. “I would think it’s [a] classic arbitrary and capricious agency action for an agency to command something that is outrageously expensive, and in which the expense vastly exceeds whatever public benefit can be achieved. I would think that that’s a violation of the Administrative Procedure Act.”

Uncertainty over Acid Rain Program

Among the issues in dispute is the significance and rationale for Congress’ decision to treat power plants differently from other air pollution sources.

Some provisions of the 1990 Clean Air Act amendments specifically targeted power plants, including the acid rain program that required regulations on sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from the largest coal-fired generators.

Congress ordered EPA to perform a study evaluating whether the acid rain and other programs had addressed all public health concerns from generators. It ordered EPA to develop additional regulations if the agency determined it was “appropriate and necessary.”

“So what, if anything, can we infer from” Congress’ decision to treat power plants differently from other HAPS sources? Justice Samuel Alito asked. Lindstrom was in the middle of his answer when Justice Kagan jumped in.

“They were trying to create a different regime because they thought that the acid rain program might have a real impact on what these electric utilities were doing,” she said. “So they said, wait and see and let’s see how the acid rain program works, and let’s see if we still have a problem to solve. And that’s the reason why they put the electric utilities in a different category, isn’t it?”

Later, Justice Kennedy said that EPA’s emission threshold — equal to the emission rates of the top 12% of generators in their class — was an “implicit cost consideration.”

Lindstrom said that wasn’t enough. “The fact that some utilities were able to impose things doesn’t mean it would be cost effective for other ones to do it,” he said.

Utility Air Regulatory Group

Attorney F. William Brownell, representing the Utility Air Regulatory Group, an ad hoc association of electric generating companies and industry trade associations, spoke second.

Brownell focused on the cost of the regulation — by some accounts the most expensive EPA regulation in history at an estimated $9.6 billion annually. In addition to controlling mercury emissions, it is also designed to control emissions of non-mercury metals and acid gases.

The rule sets separate standards for different types of oil-fired generators and separates lignite coal generators from others.

“Most of the costs here — the majority, about $5 billion annually — are associated with the acid gas regulation, which the agency has concluded presents no public health risk,” Brownell said.

Kagan said Brownell’s position that EPA consider costs before it decides how to categorize emission sources, was unworkable. “EPA … can’t even figure out the costs until it makes those categorization decisions,” she said.

Solicitor General Defends EPA

Solicitor General Donald Verrilli Jr., representing EPA, said the court should uphold the EPA’s rulemaking because “it is the most natural and certainly a permissible reading of the statutory text, which directs EPA to focus on health concerns and doesn’t mention costs.”

Chief Justice John Roberts pressed Verrilli to concede that EPA “could have interpreted the statutory language to allow them to consider costs.” When Verrilli declined to answer directly, Justice Kennedy repeated the question.

Verilli refused. “I think EPA … read the best interpretation of the statute was [that] it didn’t provide for the consideration of costs at the” stage where it was determining what pollutants to regulate.

Alito said there was no reason for Congress to treat power plants differently except “to hold open the possibility that power plants would not be listed even if their emissions exceeded the levels that would result in listing for other sources.”

Verrilli said he refused to accept Alito’s premise. “The argument that your honor just posed is not in the legislative history, and it’s not in the text,” he said.

Justice Stephen Breyer, who usually votes with the liberal wing, indicated he was looking for a rationale to support EPA. But he said he was concerned that “it begins to look a little irrational to say, ‘I’m not taking [cost] into account at all.’”

Verrilli said the cost consideration comes after EPA identifies the pollutants and classifies the sources into peer groups. “Once EPA lists and defines the category for listing, then the automatic requirement that is applied is that everyone in the category has to match the performance of the best 12%,” he said.

Calpine, Exelon, PSEG, National Grid Support EPA

The final speaker, attorney Paul M. Smith, representing Calpine, Exelon, National Grid Generation and Public Service Enterprise Group, supported the EPA.

“It’s important to recognize that something like 90% of that $9.6 billion — 90% of the capital cost, which is most of that $9.6 billion — has now already been spent,” he said. “And the industry has not experienced the kinds of upheavals that are being described. The rule takes effect in the middle of April, and so the idea that the result here was somehow ludicrous or outlandishly expensive is belied by the fact that the industry is bringing itself into full compliance.”

Significance

Sanne H. Knudsen, assistant professor of law at the University of Washington School of Law, said the significance of the court’s ruling, expected by June, will depend on its breadth.

One scenario is that the court defers to EPA’s judgment under the longstanding Chevron doctrine. “One would wonder, however, if that were the outcome, what inspired the court to take the case,” she wrote in a preview for the American Bar Association.

A second possibility, she said, is that the court vacates the rule in a broadly written opinion that mandates cost-benefit analyses in all public health regulations when Congress is silent.

A third scenario is that the court requires the cost-benefit analysis but upholds the rule on the grounds that a remand would lead to the same result.

March 24, 2015

FERC Nixes SPP Plan to Review TO Revenue Requirement Filings

The Federal Energy Regulatory Commission last week rejected SPP’s proposal that the RTO review the information that transmission owners include in their initial revenue requirement filings after joining the RTO (ER15-859).

SPP filed the proposal with FERC in January as a result of a 2014 settlement reached with Southwestern Public Service Co. in a dispute over whether the transmission facilities of Tri-County Electric Cooperative were eligible to be included in SPP transmission rates (EL13-15, EL13-35).

SPP said the review process, which was unanimously approved by the SPP Members Committee, was intended to identify issues that might result in challenges to the initial rate filings. The RTO said it would have no authority to prevent a transmission owner from overriding SPP’s concerns in its filing with FERC.

The Missouri Joint Municipal Electric Utility Commission, the Kansas Power Pool and South Central MCN, a competitive transmission company that plans to partner with electric cooperatives and municipal utilities in SPP, filed protests in February.

The commission said the proposed review process, which could take as long as six months after a new transmission owner’s execution of the SPP membership agreement, was unreasonable.

“We agree with protesters that SPP’s proposed six-month review process could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs,” the commission said.

The commission said it recognized that SPP was attempting to create a consensus solution based on the 2014 settlement. “However, we find that the review process SPP proposes to mandate here could unjustly and unreasonably impair a new transmission owner’s ability to recover its costs for transmission service it provides under the SPP Tariff.”

March 24, 2015June 15, 2023

MISO, PJM Ponder List of ‘Quick Hit’ Upgrades

By Chris O’Malley

Faulted by some stakeholders for not approving cross-border transmission projects under terms of their joint operating agreement, MISO and PJM have identified what lower-voltage flowgate projects could be done quickly and cheaply on their own sides of the seam.

The RTOs have jointly identified more than two dozen flowgate projects that could relieve market-to-market congestion.

The list of upgrades includes at least 14 projects totaling more than $45 million on the PJM side and 12 totaling $59.5 million on the MISO side.

Eric Laverty, MISO’s director of sub-regional planning, told his RTO’s Planning Advisory Committee on March 18 that the projects were not identified as the result of complicated modeling but through simple analysis of congestion history during 2013 and 2014.

Flowgates that showed significant day-ahead and balancing congestion in 2013 and 2014, and M2M flowgates that caused auction revenue rights infeasibilities, were included. Solutions had to be completed and provide a payback on investment quickly. Greenfield projects were not considered.

“We didn’t run these through a full set of futures for market efficiency-type analysis,” Laverty said, sharing information from a recent PJM/MISO Interregional Planning Stakeholder Advisory Committee.

“Here’s the cost. Here’s what the congestion has been over the past couple years. Does this [upgrade] make sense?”

PJM engineers have been using production cost simulations to study issues on their side of the seam. Both RTOs modeled special transfer conditions, such as those resulting from high wind production and increased Michigan imports.

Smaller ‘Quick Hits’

Laverty said the upgrades didn’t amount to high-dollar projects, with the largest potential MISO project an $11.9 million upgrade at the Burnham-Sheffield 345-kV flowgate.

Also, “they’re not rising to a reliability project yet,” he said, but could grow more costly over time.

George Dawe, vice president of Duke-American Transmission Co., asked if the upgrades would be eligible for competitive solicitations if they were delayed and became reliability projects. Laverty said no. Later, referring to a potential southwest Michigan project, he added, “We don’t know yet.”

For now, PJM and MISO need “to get a pulse” of transmission owners to see if they have an appetite for making improvements. “It’s a matter of building the business case for these projects,” Laverty said.

These “quick hit” projects will be the subject of additional review at the April IPSAC meeting, with conclusions and recommendations likely in May.

The extent to which the projects improve conditions for utilities on the seams is yet to be seen.

Last December, Northern Indiana Public Service Co., a MISO member flanked by PJM in eastern Indiana and Illinois to the west, complained to the Federal Energy Regulatory Commission that the RTOs haven’t approved a single cross-border transmission upgrade project under the JOA (EL13-88). FERC ordered a technical conference on the issue.

Market Congestion Projects

MISO’s Planning Advisory Committee also received an update Wednesday on potential “high-benefits-to-cost” solutions involving 14 congested flowgates in four areas: southern Indiana, southern Illinois, northern Indiana/southeast Wisconsin and Iowa/Minnesota.

Seventeen transmission developers submitted 45 solutions, including 10 carried over from the 2014 market congestion planning study. Twelve of the 45 proposals passed the benefit-cost threshold.

The projects identified in southern Illinois and southern Indiana show particular promise as “those two areas have been hammered by congestion,” said Digaunto Chatterjee, senior manager of economic studies.

Chatterjee said MISO has been studying some areas of the grid “over and over and over” enough to know they stand out as particularly problematic.

“These are real problems with real market participants that have real pain,” he said.

March 24, 2015

FERC Dismisses NY Generators’ ‘Price Suppression’ Complaint

By William Opalka

The Independent Power Producers of New York failed to persuade federal regulators that out-of-market payments that keep financially strapped generation operating to maintain system reliability suppress capacity prices.

IPPNY had claimed that NYISO’s Market Administration and Control Area Services Tariff — which allows de minimis offers from capacity resources that would have left the market without reliability-must-run agreements or repowering agreements — disadvantaged other generators.

“We find that IPPNY has failed to show that NYISO’s tariff is unjust and unreasonable,” the Federal Energy Regulatory Commission wrote last week in denying the complaint over the Cayuga and Dunkirk generating stations (EL13-62). (See related story, FERC: Hearing or Settlement on Dunkirk RSSA Charges.)

Owners of Cayuga and Dunkirk had notified state officials that the plants would be mothballed because they were not economic to operate. Both negotiated reliability support services agreements (RSSA) with transmission owners that were approved by the New York Public Service Commission.

IPPNY sought to have those resources excluded from the capacity market or required to offer at levels no lower than the resources’ going-forward costs.

FERC said competitive capacity offers should reflect going-forward costs minus other sources of revenue. “If going-forward costs adjusted for revenues are very low, then it would be reasonable to expect a low capacity market offer that reflects the low going-forward costs,” the commission said. “We agree with the New York commission that, when RSSA revenues are taken into consideration, the Cayuga and Dunkirk units’ going-forward costs would likely be low.”

Although FERC rejected IPPNY’s complaint, it ordered NYISO to establish a stakeholder process to consider whether there are circumstances that warrant the adoption of buyer-side mitigation rules in the rest-of-state zone, and whether mitigation measures would need to be in place to address any price suppressing effects of repowering agreements.

“While we find that IPPNY has not satisfied its burden under section 206, we recognize that IPPNY’s [complaint] raises concerns regarding whether changed circumstances in the rest-of-state may necessitate the prospective adoption of market power mitigation rules for the rest-of-state,” FERC wrote.

Chairman Cheryl LaFleur further addressed that aspect in news conference after Thursday’s commission meeting. “The commission has drawn a distinction in its orders between new resources and existing resources. Where repowering falls is somewhere in the middle, which is one of the reasons we asked questions about that,” she said.

March 24, 2015June 15, 2023

State Briefs

PSC Approves Increase in Bloom Energy Subsidy

The Public Service Commission has approved an increase in the subsidy that Delmarva Power customers pay to fuel cell manufacturer Bloom Energy. The surcharge, adjusted periodically, will cost a typical customer about $4.34 a month.

Bloom Energy enjoys a 21-year deal under a 2011 law that guarantees revenue for power generated from its 30-MW fuel cell operation. In exchange, Bloom has to guarantee jobs and an ongoing operation in Delaware. Bloom currently receives about 16.687 cents/kWh, more than Delmarva’s 10.75-cent/kWh advertised rate.

More: The News Journal

ILLINOIS

ComEd Unveils 11th-Hour Clean Energy Bill

Commonwealth Edison supporters have introduced another clean-energy bill into the mix as state lawmakers spar over conflicting visions of renewable power legislation.

ComEd’s bill, introduced by Sen. Kimberly Lightford (D-Maywood) and Rep. Bob Rita (D-Blue Island) aims to foster growth in clean energy for households, such as solar power, and for microgrids to provide greater reliability and resiliency.

The utility also proposes a $100 million program to build 5,000 Chicago-area electric vehicle charging stations.

Some suspect the bill is intended to build support for other legislation backed by ComEd parent Exelon, which would create a ratepayer surcharge to subsidize carbon-free nuclear power. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.) Environmentalists and green energy advocates are supporting a third bill they say would create tens of thousands of new jobs by boosting state goals for renewable power and energy efficiency.

More: Crain’s Chicago Business

IOWA

Senate Likely To Allow IUB Selection to Stand Without Investigation

Senate Democrats say they won’t challenge the appointment of Geri Huser to chair the Utilities Board.

Gov. Terry Brandstad picked Huser, identified as a business-friendly former state representative, to succeed Republican Libby Jacobs as board chairwoman. Jacobs will remain on the three-person board. Sheila Tipton, a Democrat with a legal background in utilities regulation, was not reappointed.

Huser’s appointment came a month after the board ordered MidAmerican Energy to refund $2 million to customers. A MidAmerican Energy executive confirmed that the company recently met with the governor and criticized the refund decision. (See MidAmerican’s Fingerprints on Shakeup of Iowa Utilities Board?)

More: The Des Moines Register

KANSAS

Renewables’ Tax Exemption to be Limited to 10 Years

A bill before the Senate Assessment and Taxation Committee would put a 10-year limit on property tax exemptions for renewable power projects.

The incentive has been in place since 1999, but the proposal would modify the tax breaks so that they would expire 10 years after the launch date of each project. The Kansas Division of the Budget estimates that existing renewable power projects would pay about $18 million annually in taxes in 2025, which could be used for school funding.

The proposal to end the unlimited tax break amounts to “bait and switch,” said Jeff Riles, manager of regulatory of affairs for Enel Green Power North America. Supporters say the incentive attracted many wind, solar and other renewable energy projects to Kansas.

More: Associated Press

MAINE

Missing “And” Cuts Efficiency Investments by $36 Million

The Public Utilities Commission has reduced the amount utilities are required to pay into a fund that subsidizes energy efficiency programs by about $36 million — and it’s all because of a missing “and” in the statute.

The early version of the bill that created the Efficiency Maine Trust stated that funding would be determined by “total retail electricity and transmission and distribution sales.” The adopted legislation stated funding would be based on “total retail electricity transmission and distribution sales.”

The result is that electricity supply sales are not included, decreasing funding from $59 million to $23 million. Two of the three PUC members say the program should be funded exactly as the legislation stated. Energy efficiency advocates are contemplating a legal challenge to restore the $36 million “and.”

More: Bangor Daily News

MANITOBA

Manitoba Man Can’t Stop Tx Lines Across Property

A Manitoba man who bought 50 acres outside the small town of Richer, Manitoba, is upset that Manitoba Hydro is planning to erect 200-foot transmission towers on his property, part of its proposed Manitoba-Minnesota transmission line.

“It never would have dawned on me that Manitoba Hydro could just come and say, ‘Hey, we’re cutting your property in half and taking some of it and there’s absolutely nothing you can do about it,’” Conrad Thiessen said. A company spokesman said he understood Thiessen’s frustration but that “if it’s moved from his property, it may impact four others down the road, and is that any fairer?”

Thiessen said he has contacted his elected officials but so far hasn’t had any luck.

More: CBC News

MARYLAND

Opposition Growing for Proposed 45-Tower Wind Power Project

Opposition is mounting to the proposed Mills Branch Wind Project, which would place 500-foot-tall wind turbines near the Eastern Shore town of Kennedyville.

Opponents to the project, which developer Apex Clean Energy of Charlottesville, Va., said would include 35 to 45 turbines, gathered for an organizational meeting last weekend. They have also launched a website, Keep Kent Scenic.

“With a forest of wind turbines visible up to 25 miles away, Kent County tourism will no longer enjoy its scenic resource, and historic properties and homeowners can expect a big hit on property values,” the organization stated.

More: The Star Democrat

MINNESOTA

Regulators Defer Decision on Xcel’s Request on Solar Gardens

The Public Utilities Commission has denied a request from Xcel Energy to limit the size of community “solar gardens.”

Xcel, which is required under the state’s net-metering law to buy electricity produced by the small solar cooperatives at a set price, argued that solar gardens more closely resemble utility-scale operations, whose output would be put out for a bid at a lower price competitive with wholesale markets.

The commission said it has decided “at this time” not to limit the size of solar gardens. “Potential adjustments, if any, to the program will be fully evaluated” in a few months, said a PUC official.

More: Minneapolis Star-Tribune

MISSOURI

City, Coalition Want to Revisit 40-year Prairie State Contract

Columbia officials and a pro-competition advocacy group want to review the municipal utility’s 40-year power purchase contract with Prairie State Energy Campus in Illinois.

Columbia Water and Light procures about a quarter of its power from the coal-fired Prairie State complex under a 2006 contract. But concerns about energy costs and climate change have caused some advocates to rethink the wisdom of the long-term commitment.

“In addition to locking us into burning fossil fuels for the next 40 years, thereby undermining our ability to transition to clean energy, this contract gives us no ability to negotiate the price of the energy we purchase,” City Councilman Ian Thomas said.

More: KOMU

NEW JERSEY

JCP&L Announces Refund Finally – but Storm Costs Eat it Up

The Board of Public Utilities approved a refund from Jersey Central Power & Light for overbilling its customers, but it offset the reduction by allowing the company to recoup expenses from repairing damage from major storms. The decision has taken two years to settle.

The BPU ordered the utility owned by FirstEnergy to refund $115 million for overbilling the costs of transmission system maintenance. But it cut the proposed rebate to about $35 million to allow the utility to recover costs from storms in 2011 and 2012, including Hurricane Sandy.

“I was happy the board upheld their rate decrease, but I was hoping for more,” said Stefanie Brand, director of the Division of Rate Counsel. Monthly bills for residential customers will decrease by about $1.68 a month.

More: The Record

Henkels & McCoy Agrees to Pay $600,000 in Ewing Gas Explosion

Giant utility contractor Henkels & McCoy will pay a $600,000 penalty to the Board of Public Utilities to settle claims about its role in a fatal gas explosion in Ewing last year.

The company was repairing a power outage for utility Public Service Electric & Gas when its workers drilled through a mismarked PSE&G natural gas main. The crew did not notify emergency responders about the incident, and hours later an explosion killed the resident of a nearby house where the stray gas had migrated underground.

PSE&G has already agreed to pay $1 million in fines.

More: The Princeton Packet

NORTH CAROLINA

Coal Ash I: Groups Urge Supreme Court to Uphold Duke Ash Cleanup Ruling

North Carolina environmental groups last week urged the state Supreme Court to uphold a 2014 lower court ruling that they say requires Duke Energy to immediately halt groundwater pollution from its coal ash pits.

Duke, which is appealing the ruling, says the lower court decision became moot after the legislature created a statewide Coal Ash Management Commission that will prioritize the cleanup of four of Duke’s ash pits. But environmental groups say the decision covered all of Duke’s 14 identified pits and required an immediate total cleanup.

The coal ash issue has been front and center in North Carolina. Duke agreed to pay a $100 million fine related to a massive ash leak last year into the Dan River and a $25 million fine for groundwater contamination from its Dutton plant near Wilmington.

More: News & Observer

Coal Ash II: Judges Back McCrory in Coal Ash Commission Make-up

A three-judge Superior Court panel ruled that the General Assembly erred when it created a commission charged with overseeing the cleanup of Duke Energy’s coal ash pits, ruling that the appointment of the commission’s membership was an executive function, not a legislative role.

The judges said lawmakers ignored the mandate for separation of legislative and executive powers when they formed the commission and appointed six of its nine members. House Speaker Tim Moore and Senate leader Phi Berger said they would appeal the ruling.

If it is upheld, the ruling could mean that Gov. Pat McCrory, a former Duke Energy executive, would choose most or all of the commission’s members.

More: Citizen-Times

NORTH DAKOTA

Company that Spilled 2.2 Million Gallons of Brine Proposes New 14-Mile Oil Pipeline

Summit Midsteam, whose wastewater pipeline leaked 2.2 million gallons of oil-drilling brine in January, is seeking permits to build a new pipeline, this one for oil.

Summit subsidiaries Meadowlark Midstream and Epping Transmission asked the Public Service Commission to approve a plan to convert an existing 10-mile “gathering” pipeline to a transmission pipeline. The company said the oil pipeline is made of stronger materials than the water pipeline and would have increased safety systems, including pressure and flow sensors monitored in a control center. The water pipeline was supposed to be monitored by regular patrols, but that system failed to detect the brine leak for several days.

“I think right-of-way patrolling is something we’ve learned to do probably better,” Meadowlark spokesman John Millar said. “We’re still trying to figure out why with the patrols we did have in place we didn’t see this spill. We think that’s going to be a more prominent part of our surveillance.”

More: Prairie Business Magazine

OHIO

Lawmakers Join to Preserve State Parks from Fracking

Democratic and Republican lawmakers collaborated to prohibit oil and gas development in state parks in draft legislation designed to speed up state permitting for hydraulic fracturing operations.

As a result of last-minute discussions, state parks will be protected, but fracking will be allowed in state wildlife areas and in state forests, although surface disturbances will be prohibited. Nature preserves will continue to be protected.

The General Assembly approved fracking on state lands in 2011, but Gov. John Kasich imposed a moratorium by declining to name anybody to the governing authority, the Oil and Gas Commission. The new legislation will enable the commission to be activated again.

More: Columbus Dispatch

Historic Low Prices Don’t Slow Oil and Gas Drilling in State

The Utica Shale region in Ohio continues to be a hotbed of oil and gas production, despite the plunge in energy prices.

According to the federal Energy Information Administration, the Utica region, along with the Marcellus region to the east and north, will continue to show increased production of gas and oil in the coming months.

“The biggest thing that differentiates Utica from the other regions is Utica is relatively young,” said Jozef Lieskovsky, an analyst for the EIA. Younger wells typically produce at a higher rate than mature wells.

More: Columbus Dispatch

PENNSYLVANIA

PUC Judges Recommend Lower Rate Hike for Met-Ed Customers

Administrative law judges have recommended a 10.9% rate increase for Met-Ed customers. The FirstEnergy subsidiary is seeking a 17.8% increase.

The recommendation was part of a larger rate proceeding dealing with FirstEnergy’s four Pennsylvania utilities. The judges recommended increases ranging from 7.4 to 13.1% for West Penn, Penelec and Penn Power.

The Public Utility Commission is set to consider the recommendations at a meeting in May.

More: York Daily Record

VIRGINIA

DEQ Approves NRG’s Cleanup Plan for 17,000 Gallons of Oil at Plant

The state Department of Environmental Quality last week approved NRG’s plan to recover fuel oil and to clean up tons of contaminated soil at a former Pepco power plant in Alexandria on the Potomac River.

Officials estimated that 17,000 gallons of fuel oil leaked from the plant’s tanks. NRG said it plans to complete the cleanup over the next three years, and monitor soil and groundwater for two years after that.

The deputy director of Alexandria’s transportation and environmental services said the contaminated groundwater is not near any wells and poses no health threat.

More: The Washington Post

— Ted Caddell

March 24, 2015

After Delay, Split FERC Accepts ISO-NE Order 1000 Filing

By William Opalka

A divided Federal Energy Regulatory Commission last week accepted ISO-NE’s second regional compliance filing to implement Order 1000, a filing that had languished for more than a year while the commission had only four members (ER13-193, ER13-196).

FERC largely affirmed its May 2013 order accepting ISO-NE’s regional planning and cost allocation process. It found proposed revisions, filed by ISO-NE and the Participating Transmission Owners Administrative Committee in November 2013, largely complied with the directives in its first order, requiring the parties to make additional filings on some provisions.

In a post-meeting news conference, Chairman Cheryl LaFleur was asked if the delay meant the commission had been deadlocked at 2-2 in the time it awaited replacements for former Chairman Jon Wellinghoff, who resigned in November 2013, and John Norris, who stepped down last August. Norman Bay replaced Wellinghoff in August but the commission remained short one member until Colette Honorable was sworn in Jan. 5.

“That’s a reasonable inference,” LaFleur responded. “It was 3-to-2 the first time and it was 3-to-2 this time so it took five people to vote it out,” she said.

Dissents over ROFR

The order affirms the commission’s prior findings that ISO-NE must remove right-of-first-refusal provisions and that the Mobile-Sierra doctrine does not preclude that requirement. The Mobile-Sierra doctrine presumes that freely negotiated wholesale energy contracts are just and reasonable unless they are found to seriously harm the public interest.

Commissioners Phillip Moeller and Tony Clark partially dissented from the order, saying the majority did not adequately address concerns regarding the Mobile-Sierra doctrine.

“On rehearing, the commission again declines to provide the actual quantitative or granular analysis of public interest harm that is required to overcome the Mobile-Sierra protection previously granted. The result in the instant case is thus legally suspect,” Clark wrote. “Moreover, the decision has the unfortunate side effect of calling into question the commission’s commitment to upholding the regulatory certainty provided under our Mobile-Sierra decisions.”

The majority wrote that “the commission must determine whether the instrument or provision at issue embodies either (1) individualized rates, terms or conditions that apply only to sophisticated parties who negotiated them freely at arm’s length; or (2) rates, terms or conditions that are generally applicable or that arose in circumstances that do not provide the assurance of justness and reasonableness associated with arm’s-length negotiations.”

In granting a partial rehearing, ISO-NE is permitted to restore certain provisions that recognize the transmission owners’ rights to retain use and control of their existing rights of way.

The commission found just and reasonable the proposal to allocate costs of public policy transmission upgrades 70% to the region based on load-ratio share and 30% to those states whose public policy necessitated the project. FERC gave ISO-NE 60 days to file additional modifications.

Additional Filings Required

The commission also required ISO-NE and the Participating Transmission Owners Administrative Committee to make additional compliance filings that:

Specify a process for transmission providers to enroll in the transmission planning region;
Describe the process through which participating transmission owners will identify transmission needs driven by federal public policy requirements that will be evaluated in the local transmission planning process and how they will be evaluated;
Revise the definition of a nonincumbent transmission developer in the ISO-NE Tariff to require that a participating transmission owner that proposes to develop a transmission facility not located within or connected to its existing electric system enter into a nonincumbent agreement;
Modify study deposit provisions to provide a description of the costs to which the deposit will be applied, how those costs will be calculated and an accounting of the actual costs; and
Revise the ISO-NE Tariff and Operating Agreement to provide a consistent definition of the term “backstop transmission solution” and remove language that would require a Participating Transmission Owner to continue developing a backstop transmission solution beyond what was originally proposed.

March 24, 2015

FERC Accepts Formula Rate Protocols from MISO, SPP, PJM Utilities

The Federal Energy Regulatory Commission last week accepted revised transmission formula rate protocols by four SPP and MISO utilities that had deficient protocols.

The commission also accepted a new protocol from Louisville Gas & Electric and Kentucky Utilities, a PJM member in Kentucky and Virginia.

While accepting the filings, FERC required further compliance filings within 60 days from Black Hills Power, which serves parts of South Dakota, Wyoming and Montana; Empire District Electric Co., with territory in Missouri, Kansas, Oklahoma and Arkansas; Kansas City Power & Light and KCP&L Greater Missouri Operations, with customers in Missouri and Kansas; and Westar Energy, which serves parts of Kansas.

The commission ordered the revisions for the SPP in July 2014, saying the existing protocols had impeded the ability to review and appeal transmission owners’ cost claims. The commission ordered similar revisions for MISO transmission owners in 2013. (See FERC OKs MISO, TO Rules on Formula Rate Challenges.)

The commission found that the provisions related to rate challenge procedures and transparency in all of the filings generally comply with directives in the July 2014 orders, but they required some additional modifications.

March 24, 2015

FERC Rejects Dominion Rate Request

By Michael Brooks

The Federal Energy Regulatory Commission last week rejected Dominion Virginia Power’s request to push back the effective date for a rate revision by more than year, a change that would have cost transmission customers $11.1 million (ER15-856).

Dominion had asked FERC to change the effective date of revised transmission depreciation rates from April 1, 2013, to Jan. 1, 2012. FERC approved the revised rates last April.

FERC said changing the date would violate its rule against retroactive ratemaking, a charge the North Carolina Electric Membership Corp. made in a February protest to the request. (See NCEMC: Dominion Request is ‘Retroactive Ratemaking’.)

“The filed rate and retroactive ratemaking doctrines both bar a public utility from charging a rate other than the rate properly filed with the commission, and similarly bar the retroactive imposition of an increased rate for service already provided,” FERC said. “However, this is precisely what Dominion proposes to do in the instant filing … by now proposing to charge customers an additional $11.1 million from Jan. 1, 2012, through March 31, 2013.”

Dominion said it requested the extension because of a Virginia State Corporation Commission ruling that increased its depreciation expense and accumulated depreciation effective Jan. 1, 2012 — the date of a depreciation study commissioned by Dominion. The SCC told FERC it supported Dominion’s request, saying it is standard practice to use the date of the study as the effective date for changes in depreciation rates.

FERC responded that “we are not suggesting that a Jan. 1, 2012, effective date would be inappropriate for retail rates, which is within the purview of the states. In this case, however, Dominion will receive all of its transmission operations and maintenance expenses through its formula rate, and its allowed rate of return and associated income taxes on all unrecovered plant balances. Furthermore, the commission has previously accepted rates that reflect regulatory differences from what this commission requires for accounting purposes and what state commissions require for state rate purposes.”