Page 1562 – 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

MISO Board Questions Execs on Entergy Out-of-Cycle Requests

By Chris O’Malley and Rich Heidorn Jr.

Under questioning from MISO board members, senior RTO officials last week defended their support for Entergy’s controversial requests to spend $200 million on out-of-cycle transmission projects.

General Counsel Steve Kozey and Clair Moeller, executive vice president of transmission and technology, told the Board of Directors System Planning Committee on March 17 that MISO planners had followed the RTO’s rules in recommending approval of the projects, the largest of which is a $187 million transmission upgrade near Lake Charles, La.

Committee Chairman Michael Evans did not ask the committee to endorse the projects to the full board, despite a request to do so from Phillip May, CEO of Entergy Louisiana and Energy Gulf States Louisiana. Evans said the goal of last week’s 90-minute meeting was to “ventilate the subject fully.”

Evans said the committee will invite the full board to take part in additional discussions in a conference call before their next face-to-face meetings beginning April 21.

At the Planning Advisory Committee meeting last month, the Transmission Developer and Independent Power Producer sectors voted against MISO staff’s conclusion that the Lake Charles project qualified as an out-of-cycle reliability project. As a result, MISO officials said, the full board will conduct a “full review” of the request. (See MISO Board to Review Entergy Lake Charles Project Following Stakeholder Pushback.)

In previous meetings and in letters to the board, critics have challenged Entergy’s load forecasts as speculative and say the project’s scale suggests benefits beyond that of a baseline reliability project, the only type of project permitted under MISO’s out-of-cycle procedure. They questioned why Entergy didn’t see large industrial growth coming early enough to include it in the MISO Transmission Expansion Plan (MTEP), instead of asking for out-of-cycle approval that deprives transmission developers an opportunity to compete.

The critics also said MISO failed to conduct a thorough review of the Lake Charles project as required under the RTO’s rules. The IPP sector said that the business practice manual for transmission planning (BPM-20) provides for up to six months of study for an out-of-cycle review and that it implies multiple Technical Study Task Force meetings are possible during the review. MISO conducted just one task force meeting before endorsing the proposal at the PAC meeting, the IPP sector said.

Jeffrey Webb, senior director of expansion planning, countered that the BPM does not require an “extended series of meetings.” Webb also said MISO had no authority to reject a transmission owner’s load forecasts.

Need Questioned

Kip Fox, representing the Competitive Transmission Developer sector, listed a series of industrial projects that have been shelved or delayed — evidence, he said, that much of the growth expected at Lake Charles is speculative.

“It is not speculative,” responded Charles Long, director of transmission planning for Entergy. “Certainly with any forecast there’s uncertainty. But I can tell you there’s enough need coming to Lake Charles to necessitate this project.” Entergy says more than 500 MW of new load is under contract with another 300 MW “probable” this year.

MISO presented an analysis showing the increased load would cause voltage problems and thermal overloads as high as 146% of line ratings. (See map.)

Board Chairman Judy Walsh expressed support for staff, saying she was “sort of skeptical that [MISO’s review was] not robust enough.”

She also voiced reservations over whether MISO should “become the validators of load” projections.

But she also expressed concern that while Entergy might save eight months by winning approval as an out-of-cycle project rather than submitting it for inclusion in the MTEP process, “you could lose that [time] in a dispute at FERC.”

Moeller said those skeptical of Entergy’s forecasts can challenge the company when it seeks approval from the Louisiana Public Service Commission. He also noted that Entergy was taking on financial risk. “It’s not in their interest to spend almost $200 million to serve load that isn’t there,” he said.

Attorney Noel Darce, representing the PSC, said the commission’s staff wants the MISO board to approve the requests without delay. He said the PSC “retains full authority to approve the certification and to review the prudence of the expenses incurred on this project.”

Scope Challenged

Director Evans asked staff to verify that MISO had met its obligations to follow its BPM and other procedures, wondering aloud: “How can you get a 700-MW load that’s a surprise?”

He also pressed staff on their conclusion that Lake Charles is a baseline reliability project, saying “it would appear from the letters [to the board] that there’s not universal agreement.”

In a March 12 letter, ITC Holdings Vice President Kristine Schmidt noted that Entergy’s request states that, in addition to addressing reliability concerns, the project “will also facilitate future economic development in the area.”

“Facilitation of future economic development is the definition of a market efficiency project, not that of a baseline reliability project. While there may be components of the [Lake Charles] project which are needed for reliability, the entire project possesses a much broader scope than what would be required to meet those reliability needs,” Schmidt said.

NRG Energy said MISO should determine whether the Lake Charles project includes upgrades that should be directly assigned to Entergy’s end users and not socialized across all users of the system. It noted that when one of NRG’s cooperative customers sought to bring new load onto the system, the costs of the “cut-in” for the load were directly assigned to the co-op.

NRG also noted Entergy’s plans to construct a large combined-cycle generator “in and around the same location as where the proposed upgrades are to be done.”

“Under FERC precedent, a new power plant must bear its own development costs and cannot be allowed to benefit from a deliberately timed, self-serving ‘reliability’ transmission project,” NRG said.

In his own letter on March 16, Entergy’s May said that the project is “the optimal and most efficient solution to the identified need.” Construction of smaller, incremental upgrades would be inefficient and difficult to manage and would threaten Entergy’s ability to meet its required June 2018 in-service date, he said.

May said if the Lake Charles project were designated as a market efficiency project, and underwent the full competitive bidding process — “not to mention any litigation that may flow from the process” — it’s likely the in-service date of upgrades would be pushed out to at least 2020.

Moeller noted that often a customer will reveal the need for load at the last minute “and then you can’t move fast enough to meet their needs.”

Moeller said the Lake Charles dispute — the first out-of-cycle project to face any stakeholder opposition, he said — is an example of friction between the traditional monopoly business model and the emerging, competitive developer segment resulting from the Federal Energy Regulatory Commission’s Order 1000. “It’s those two business models that are colliding in many of these comments,” he said.

On this, finally, there was consensus.

“This is an entirely different world,” agreed George Dawe, vice president of Duke-American Transmission Co. The old world was “transmission owners nodding their heads at each other’s transmission owner projects.”

March 24, 2015

Dunkirk Plant Chronology

1950: Dunkirk units 1 and 2, each 75-MW simple-steam coal plants, go into operation on Lake Erie, 55 miles southwest of Buffalo, N.Y.

1959-1960: Dunkirk adds units 3 and 4, 185 MW coal-fired, simple-steam units.

1999: NRG Energy acquires Dunkirk from Niagara Mohawk Power. NRG later converts the plant to use low-sulfur Powder River Basin coal and installs controls on mercury and nitrogen oxide emissions.

March 2012: NRG says it will mothball Dunkirk effective Sept. 10, 2012.

August 2012: The New York Public Service Commission approves a reliability support services agreement between NRG and Niagara Mohawk parent National Grid to keep Dunkirk operating to maintain system reliability. National Grid agrees to pay NRG $2.9 million per month for the nine-month period of Sept. 1, 2012, through May 31, 2013, with additional cost adjustments for taxes and coal costs, and credits for capacity market revenues earned by Dunkirk.

May 2013: The PSC approves a new RSSA between NRG and National Grid through May 31, 2015, at a cost of $2.1 million per month, with the same cost adjustments as the original RSSA.

February 2014: The Federal Energy Regulatory Commission accepts and suspends National Grid’s proposed rates to cover the cost of the RSSA. FERC accepts the changes subject to refund and further order, saying it was not convinced the changes were just and reasonable.

June 2014: The PSC approves a $140 million plan to upgrade three Dunkirk units from coal to natural gas, with a capacity of 435 MW. The PSC selected the repowering over a plan to invest up to $76 million in transmission upgrades, which would have addressed reliability concerns and allowed the plant to close. Closing the plant, Chautauqua County’s largest taxpayer, would have reduced the city’s property tax revenues by more than 40%. The repowered plant is expected to pay about $8 million in property taxes annually.

October 2014: The Sierra Club files suit against the PSC over the repowering plan.

January 2015: National Fuel Gas and NRG announce a settlement allowing National Fuel to build a 9.3-mile pipeline to supply Dunkirk. National Fuel and Dunkirk Gas, an NRG affiliate, had originally offered competing pipeline proposals to the PSC.

February 2015: Entergy sues the PSC, alleging it infringed on FERC authority by approving the repowering plan.

March 2015: Niagara Mohawk informs PSC it will exercise its option to extend the RSSA for seven months through Dec. 31, 2015.

September 2015: Projected completion date of Dunkirk repowering.

March 24, 2015June 15, 2023

FERC Approves NERC Risk-Based Registry

By Rich Heidorn Jr.

About 500 organizations will be relieved of some grid reliability regulations and another 200 exempted entirely under the North American Electric Reliability Corp.’s new method for classifying entities under its jurisdiction.

The Federal Energy Regulatory Commission last week approved NERC’s Risk-Based Registration (RBR) initiative, with a few modifications and caveats (RR15-4).

The order approves NERC’s proposals to:

Remove purchasing-selling entities and interchange authorities as functional registration categories. Because these entities’ activities are commercial in nature, their removal poses little or no risk to reliability, NERC said. FERC rejected a proposal to also remove load-serving entities from registration, ordering NERC to provide more information to ensure that there are no reliability gaps.
Raise the threshold for registering entities as distribution providers to those with loads of 75 MW or more, up from 25 MW. NERC also will provide a subset list of reliability standards to distribution providers that are subject to NERC rules solely due to their operation of underfrequency load shedding protection systems. The change is expected to affect about 100 entities, representing less than 1% of load served by NERC-registered distribution providers.
Align five functional registration categories with the 2012 revised definition of the bulk electric system.
Make procedural changes to its registration process, including the introduction of a “materiality” test for registration.

NERC’s Compliance Registry currently lists more than 1,600 organizations responsible for about 4,300 reliability functions under 15 functional entity categories.

The commission said the changes would allow regulators to focus resources on entities with the greatest potential impact on reliability.

NERC said the changes will reduce regulation of about 700 organizations, with about 200 exempt from all NERC rules, and another 500 removed from some registrations while remaining regulated under others. For example, interchange authorities, which verify and communicate interchange schedules, are also registered as either a balancing authority or reliability coordinator.

FERC Chairman Cheryl LaFleur called the changes “another significant step in the evolution” of the mandatory reliability standards ordered by the Energy Policy Act of 2005.

In February, FERC approved NERC’s risk-based approach to reliability compliance monitoring and enforcement, which will reduce the kinds of reliability violations subject to NERC enforcement, with “minimal”-level risk issues subject to less oversight (RR15-2). (See New NERC Enforcement Methods Allow Self-Logging Minor Risk Issues.)

Commissioner Norman Bay said that it is “incumbent on NERC to show that reliability is in fact being enhanced” as a result of the changes.