Page 1774 – RTO Insider

March 31, 2015June 15, 2023

Union: Transmission a Critical Part of New York REV

By William Opalka

A labor council representing New York utility workers is worried that the state’s path-breaking initiatives in the smart grid, distributed energy resources and energy storage are taking attention away from overdue needs for transmission upgrades in the state.

A so-called Memorandum of Concerns, while endorsing the new “utility paradigm” of New York’s Reforming the Energy Vision, said that the program needs extensive transmission upgrades to succeed. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)

“While these initiatives have provided benefit to New York ratepayers and thrust New York state to the forefront of the electric industry, the transmission infrastructure these elements are connected to have been greatly neglected,” said Theodore Skerpon, chairman of the 15,000-member New York State International Brotherhood of Electrical Workers Utility Labor Council, in a March 20 filing with the PSC (12-T-0502).

“The primary foundation of REV is the ability to efficiently move electricity across the state to determine an accurate cost-benefit analysis for proposed local generators,” the memo adds.

The memo points out that 80% of the state’s high-voltage transmission lines are at least 35 years old and that 4,700 circuit miles will require replacement within the next 30 years. Upstate New York generation is needed to supply demand but is constrained by transmission bottlenecks.

New York Gov. Andrew Cuomo unveiled the New York Energy Highway to address those issues in 2012, building upon his administration’s own assessment and studies by NYISO and the Federal Energy Regulatory Commission. The initiative is envisioned as a public-private partnership to spur at least $2 billion in private investment to expand or upgrade transmission corridors from upstate generating plants to load centers in and around New York City.

PSC Spokesman James Denn said REV and the Energy Highway are proceeding in tandem, as the PSC in December said it will determine the need for relief of persistent transmission congestion along the Mohawk and Hudson Valley transmission corridors. A technical conference will be convened in mid-2015 to identify the scope of the problem. (See New York PSC Orders Study, Conference on Transmission Congestion.) New York has identified the need for about 1,000 MW of additional capacity but has not named specific projects (13-M-0457).

“Staff’s need report is expected to be issued on or before June 10, 2015, followed closely by the all-parties technical conference to ensure that all parties can raise questions about its recommendations. The proceeding remains very active, with parties, including staff, submitting well over 100 critically important documents since December,” he said.

March 31, 2015June 15, 2023

Congressional Meeting Fails to Sway LaFleur on Capacity Results

By William Opalka

A meeting last Tuesday among the New England congressional delegation, ISO-NE and Federal Energy Regulatory Commission Chairman Cheryl LaFleur ended the way that it started: with LaFleur and the RTO defending rising capacity prices and the delegation unhappy.

The delegation requested the meeting after its failed attempts to get FERC to reopen the results of last year’s Forward Capacity Auction. Total costs tripled to $3 billion in FCA 8, covering the 2017-2018 period.

The results became effective when a short-handed FERC deadlocked at 2-2 over whether they were “just and reasonable.” LaFleur, who voted to approve the results, stood by her decision in a letter to the delegation last month. (See LaFleur Rejects Further Review of 2014 ISO-NE Capacity Auction.)

FCA 9, held in February, saw costs rise another $1 billion, to $4 billion for 2018-2019. (See ISO-NE Files Capacity Auction Results; Comments due April 13.)

Last week’s meeting at the Capitol was organized by Massachusetts Democratic Reps. Joseph P. Kennedy III and Richard Neal, and included LaFleur, ISO-NE CEO Gordon van Welie, 14 other congressmen and three senators. Staff members of several other congressmen and senators also attended.

According to Kennedy’s office, LaFleur stated that the capacity market is working as intended, with rising prices drawing new generating resources into the region. Reopening a settled case would also set a bad precedent, she added.

Van Welie warned that prices could go even higher.

LaFleur also reportedly said she was satisfied with a staff investigation of the planned closure of the 1,510-MW Brayton Point generating station in Massachusetts, which concluded the closure was not an exercise of market power that would benefit the plant owner’s other assets, as critics have charged. Energy Capital Partners said Brayton Point would close in 2017 and prospective owner Dynegy has stayed with that plan.

“New England residents pay some of the highest electricity prices in the country and these capacity rates continue to climb. There is no way we can look at this system and say it’s working,” Kennedy said. “The markets are rewarding highly consolidated energy incumbents on the backs of consumers … FERC’s inaction around the results of FCA 8 have left ratepayers in legal purgatory with no means to contest skyrocketing rates. This is a regulatory shortcoming that must be remedied. … [Tuesday’s] meeting was the start of a conversation I expect will continue in the weeks and months ahead.”

ISO-NE spokeswoman Lacey Girard reiterated that until plant retirements were announced in 2013, New England had a capacity surplus. About 10% of the fleet is expected to leave the market in coming years.

“These are basic economic fundamentals — when there is excess supply, prices fall, and when there is a shortage of supply, prices rise. The higher prices coming out of last year’s auction helped spur investment in new resources in the most recent capacity auction, including more than 1,000 MW of new generating capacity, which will help address the region’s resource shortage and meet peak demand in 2018,” she said. (See Exelon, LS Power Join CPV in Adding New England Capacity).

“I appreciate Congressmen Kennedy’s and Neal’s work to gather together so many members of the New England delegation to talk about the interesting and complex energy issues facing the region. I welcomed the opportunity to hear the view of the congressmen and senators and feel it was a very productive meeting,” LaFleur said in a statement.

March 31, 2015June 15, 2023

External Constraint Vexing MISO, Market Monitor Says

By Chris O’Malley

MISO’s Independent Market Monitor says transmission loading relief requests attributed to a Tennessee Valley Authority constraint are causing price volatility within the RTO.

David Patton, CEO of Potomac Economics, told the Markets Committee of the Board of Directors he was concerned MISO is taking costly actions to manage a constraint that is not binding and that TVA may be relying excessively on external relief.

“We have a relatively unfavorable set of provisions that obligate us to model the constraint in our market, as if this is our constraint, and then obligates us to provide what appears to be an oversized amount of relief on the constraint,” Patton said during a presentation to the committee March 25.

Patton cited a TLR event on Feb. 20 in which TVA called for curtailing non-firm commitments toward managing the Volunteer-Phipps Bend constraint. He explained that when a TLR is called, MISO activates the constraint in its market, causing its generators to move and provide the flow relief requested.

The price effects on MISO’s market “can be dramatic,” Patton said, citing the price volatility that occurred in Michigan between 1 a.m. and 1 p.m. on Feb. 20.

Real-time prices at the Michigan Hub that were fluctuating around $50/MWh without the constraint began “bouncing up and down” to as high as $450/MWh with the effect of the constraint. “When prices do this we’re ramping generators up and down,” Patton said.

That one day’s price volatility raised the average price in February by more than 5%, Patton told the committee.

Uneconomic Flows

Besides causing price volatility, the TLRs affect the dispatch of MISO’s resources, Patton said, pointing to flows between MISO South and MISO Midwest regions.

Without the TLR constraint, transfers from MISO South to MISO Midwest were economic because of relatively high natural gas prices in the Midwest.

But the February constraint caused flows to frequently change direction and flow uneconomically from Midwest to South, Patton said.

On Feb. 20, MISO was virtually the only entity re-dispatching to reduce the flow on the constraint, “yet we’re incurring tremendous costs in our dispatch to provide relief, so there’s a couple of problems there.”

“One is that the amount of relief we’re being asked for is overly aggressive,” Patton continued, and the other is that MISO’s flows aren’t considered firm even though it is dispatching its own generation to serve its load.

“We also have concerns about other entities around us that are being overly aggressive in their use of the TLR process and we’re not sure there’s any oversight of what entities are doing.”

Board Chairman Judy Walsh asked Patton what MISO can do about the problem and how much it is costing the RTO.

Patton said he believes there are provisions that would allow MISO to categorize its day-ahead dispatch as firm. That would allow the RTO not to have to provide relief unless entities around MISO, including TVA, are curtailing services or redispatching their own systems. “At this point we’re carrying all the water on a day like this.”

As for cost, “it’s costing us tens of millions [of dollars] in congestion. It’s hard to quantify what it costs us” insofar as ramping generation up and down.

On the upside, Patton said the biggest concerns MISO has had historically with TLRs involved SPP, but the market-to-market process the RTOs now use to cooperatively manage each other’s constraints has virtually eliminated those TLRs.

Working on Congestion Management

Todd Ramey, who manages MISO’s real-time operations, told the committee that the TVA constraints are “interregional transfer constraints that bind infrequently but predictably.”

Typically this occurs when there are high loads to the north and east of the interconnection and lower and more moderate loads to the south and west.

The weather was particularly cold in the north on the day cited by Patton.

Ramey said he has no doubts that reliability concerns of the TVA reliability coordinator in the flow gate “were legitimate” during the period in February, but he said he concurred with Patton’s concerns.

Since the Feb. 20 constraint, MISO has been working with TVA to improve joint administration, Ramey said. “Efforts are underway. We’ve had conference calls with TVA” and plan additional meetings to go over data for joint congestion management, Ramey added.

Winter Performance Improved

At the meeting, Patton also summarized market conditions for February and noted a stark contrast from a year earlier, when the RTO struggled with extreme cold during the polar vortex.

This February, energy prices were down almost 40% — and natural gas prices down 57% compared to the year before.

“Market conditions were quite a bit more stable this year,” Patton said, noting fewer fuel supply issues, more available generating units and milder weather.

Ramey said while this past winter has been referred to as relatively mild, there were some parts of the MISO region that experienced cold temperatures reminiscent of the winter of 2013-14. Ramey cited a much-improved performance of peaking units and continued coordination with gas pipeline operators in the most recent winter.

March 31, 2015

FERC Interfering with Reliability Order, NYPSC Says

By William Opalka

New York regulators say the Federal Energy Regulatory Commission’s recent order on reliability-must-run agreements “interferes” with state authority as they try to address generation shortages in the state (EL15-37).

The New York Public Service Commission last week asked for a rehearing of FERC’s Feb. 19 order, which said the state must adopt uniform rules to prevent the need for protracted proceedings to ensure generators received compensation for continuing to operate. FERC said the lack of uniform rules created uncertainty that could compromise system reliability. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

“The commission must reconsider the RMR order because it ignores the fact that the NYPSC has already exercised its authority to ensure the availability of generation facilities needed for reliability, and interferes with the NYPSC’s ongoing exercise of this authority in approving reliability support services agreements,” the PSC wrote.

The PSC has relied on RSSAs to delay the retirements of generating facilities needed for reliability, such as the Dunkirk plant outside Buffalo and the Cayuga plant in Lansing, near Ithaca.

The PSC said FERC “failed to provide evidence that the NYPSC-approved RSSAs were inadequate to the task of addressing the reliability concerns cited in the RMR order.”

The PSC also objected to a FERC proposal to require what it termed an excessive full cost-of-service rate. “Full COS rates are neither required, nor just and reasonable, where the provider of a public service intends to abandon that service,” the PSC wrote. “Indeed, it has long been a well-accepted regulatory principle that a public service provider may not abandon service and must continue service even at less-than-COS rates until the abandonment is authorized.”

FERC ordered NYISO to create a process for determining which generation resources seeking to deactivate are needed for reliability; how they should be compensated, including accelerated cost recovery for generators that require upgrades; and how RMR costs should be allocated.

March 31, 2015June 15, 2023

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

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.”