Page 1835 – RTO Insider

May 27, 2014

Capacity Prices Jump Following Rule Changes

The 2017/2018 base residual auction exceeded expectations of analysts and generation company executives, with annual resources clearing at $120/MW-day in most of PJM following rule changes that limited demand response and generation imports.

Capacity Auction Clearing Prices 2017/2018 (Source: PJM Interconnection, LLC) — Click chart(s) to zoom.

Prices in Virginia, West Virginia, North Carolina and much of Ohio doubled from $59/MW-day in last year’s BRA. The east was essentially flat, with the PSEG zone falling to $215/MW-day and MAAC up by less than $1. ATSI rose 5%.

Unlike last year’s auction, which saw the PSEG, ATSI and MAAC zones separate from the rest of the RTO, only the PSEG zone cleared separately. The auction procured 167,004 MW for the delivery year beginning June 1, 2017, giving the RTO a 19.7% reserve margin.

Six new combined-cycle plants cleared for the first time, all of them located east of the west-to-east transmission constraints or in other areas with capacity needs. In total, more than 5,900 MW of new entry cleared.

Reasons for Increase

In a press conference late Friday, Executive Vice President for Markets Andy Ott said the increase in clearing prices resulted from the costs of compliance with state environmental regulations and new limits on generation imports and summer-only demand response. (See related story, Major Rule Changes Reduced Imports, DR)

“I think the changes that we have made … certainly had their intended effect,” Ott said. “Anytime you have an auction with competitive new entry with this kind of volume, we look at that as a success story.”

Demand Response Changes

About 11,000 MW of demand response cleared, a drop of 1,433 MW from last year’s auction. Annual DR increased by 1,400 MW and extended summer by almost 4,700 MW, while limited summer-only resources dropped by more than 7,500 MW. Limited DR cleared between $14 and $80 lower than annual resources, which include generation, annual demand response and energy efficiency.

Ott touted the “dramatic shift” in DR. “All in all we saw it as a positive result that we got higher value DR,” he said.

Imports dropped to about 4,500 MW, down from 7,500 last year. Unlike last year, all of the imports came with firm transmission. All but about 500 MW cleared after winning exemptions from the import limits, which required them to also be pseudo-tied.

Exceeding Expectations

In first-quarter earnings calls before the auction, executives of PJM companies said they didn’t expect a dramatic rise in prices following the rule changes.

FirstEnergy officials said they were encouraged by PJM’s “modest reforms” but sought additional changes such as a premium for having fuel on-site, which could boost nuclear and coal plants. PPL CEO William Spence said there were too many variables to make any prediction on prices.

AEP CEO Nick Akins said he expected RTO prices of $80 to $100, while UBS Securities predicted RTO prices of $80 with MAAC flat at $120. Barclays Capital analyst Dan Ford accurately predicted that only PSEG would separate from the RTO, but his $100/MW-day target for MAAC and the RTO was also low. His PSEG target was slightly high at $229.

Below is a detailed analysis of the auction results.

Prices

Clearing prices remained volatile, with prices doubling in much of the RTO. For the first time in seven years, the RTO and all of the MAAC zones cleared at the same price.

Increased supply from new generation and uprates was offset by the drop in imports and demand response, PJM said.

Although RTO prices rebounded from last year, they were still below the $136/MW-day for 2015/16 and the all-time high of $174, set in planning year 2010/11.

Capacity Offered & Cleared

The nearly 179,000 MW of unforced capacity offered was down 3% from the total offered a year ago. An additional 21,300 MW was eligible but did not offer because it was exported, included in Fixed Resource Requirement capacity or excused due to environmental restrictions or pending retirement.

Generation was responsible for 93% of the cleared capacity, with DR providing 6% and energy efficiency 1%.

Almost 7,150 MW of “incrementally new” capacity was offered this year, including new generation, capacity upgrades to existing generation and energy efficiency. Generation capacity deratings and a reduction in DR offers exceeded the new capacity, however, resulting in a net decrease of almost 5,700 MW of installed capacity.

The cleared capacity for 2017/18 includes 5,185 MW of generation that postponed or cancelled retirement and 1,224 MW of reactivations.

Demand Response & Energy Efficiency

Demand response offered dropped 22% and cleared DR declined 12%, the second year in a row of declines. In all, DR offers have declined by 43%, and cleared DR by 26%, since peaking for delivery year 2015/16.

The biggest declines in cleared DR this year came in ATSI (-792 MW), PSEG North (-242), BGE (-145) and DEOK (-112). APS (+244) and COMED (+242) showed the biggest increases with AEP also up (+49).

Energy efficiency offered has increased by 43% over the two years, albeit from a much lower base.

About 97% of the demand resources and virtually all of the EE offered cleared.

The new limits on the volume of summer-only (limited) DR and extended summer DR that was permitted to clear changed the mix of DR clearing and resulted in price separation among the products. The volume of limited DR clearing dropped by three quarters, while extended and annual grew dramatically. Extended summer now represents nearly two-thirds of all capacity DR, up from 20% in 2016/17.

Annual DR cleared at the same price as generation, $120 in all but PSEG ($215). Extended summer DR also cleared with the annual products except in the PPL locational deliverability area, where it priced at $53.98/MW-day. Limited DR cleared at $40 in PPL, $201 in PSEG and $106 in the rest of the RTO.

New Generation

The auction received offers from almost 6,600 MW of what PJM terms “new” generation capacity, including new facilities, uprates at existing facilities and reactivations of plants scheduled for retirement that will be switching fuels.

Of the generation that was offered into the auction, 95% cleared.

The auction cleared 6,267 MW of new generation, the highest ever. Of that, 340 MW was in uprates to existing generation. The remaining 5,927 MW of new generating units included about 4,800 MW of gas-fired combined-cycle plants clearing for the first time. All of the new generation is located east of west-to-east transmission constraints or in LDAs that needed capacity.

Wind offers dropped 8% to 804 MW while solar increased 30% to 116 MW. All of the offers cleared.

The new generation helped prices in MAAC converge with the rest of RTO, PJM said.

Imports

Cleared generation imports dropped by nearly 3,000 MW to 4,526 MW, a reduction of almost 40% from last year.

Of the 4,526 MW, nearly 4,000 MW met the requirements for an exception from the capacity import limit (CIL).

The majority of the imports came from west of the RTO. PJM will export 1,223 MW of capacity. Before it began the capacity auctions, PJM was a net exporter of capacity.

The zones and their caps are:

North (New York ISO & ISO New England): 1,598 MW (Light green on the map).
West 1 (MISO East, MISO West & Ohio Valley Electric Corp.): 2,301 MW (orange).
West 2 (MISO Central + MISO South): 767 MW (salmon).
South 1 (Tennessee Valley Authority & LG&E Energy Transmission Services): 1,278 MW (orange-yellow).
South 2 (VACAR — non-PJM): 2,493 (creamsicle).

Long-Term Impact

PJM credits the implementation of the Reliability Pricing Model for a net of 62,464 MW in capacity since its implementation.New generation and generation upgrades have contributed more than half of the increased capacity since the start of RPM, with demand response, imports and cancelled retirements making up the rest.

The 11 base residual auctions to date have procured almost 29,100 MW of new generation, more than replacing the 20,700 of de-ratings and retirements. Demand response to date has totaled almost 11,300 MW with energy efficiency adding almost 1,300 MW.

Combined-cycle plants have been by far the biggest source of new generation since the capacity market began with a total of more than 19,000 MW. Steam units and combustion turbines have each added almost 6,000 MW. Additions among other fuel sources were each less than 2,000 MW.

May 23, 2014

Capacity Prices Double in Western PJM, Flat in East

[Editor’s Note: Click here for an updated and expanded version of this story.]

The 2017/2018 base residual auction cleared at $120/MW-day in most of PJM as restrictions on demand response and imports doubled prices in Virginia, West Virginia, North Carolina and much of Ohio.

Prices were essentially flat in the east, with the PSEG zone falling to $215/MW-day and MAAC up by less than $1. ATSI rose 5%.

Unlike last year’s auction, which saw the PSEG, ATSI and MAAC zones separate from the rest of the RTO, only the PSEG zone cleared separately.

The auction procured 167,004 MW for the delivery year beginning June 1, 2017, good for a 19.7% reserve margin.

Six new combined-cycle plants, totaling 4,800 MW, cleared for the first time, almost all of it located east of the west-to-east transmission constraints or in other areas with capacity needs. In total more than 5,900 MW of new entry cleared.

In a press conference late this afternoon, Executive Vice President for Markets Andy Ott said the increase in clearing prices resulted from the limits on imports, summer-only demand response and the costs of compliance with state environmental regulations.

About 11,000 MW of demand response cleared, a drop of 1,433 MW from last year’s auction. Annual DR increased by 1,400 MW and extended summer by almost 4,700 MW, while limited summer-only resources dropped by more than 7,500 MW. Energy efficiency rose to a record 1,339 MW, up by more than 200 MW.

Ott touted the “dramatic shift” in DR. “All in all we saw it as a positive result that we got higher value DR,” he said.

Rule Changes

In last year’s auction, RTO prices dropped 56% to $59.37/MW-day, while prices in ATSI dropped more than two-thirds (to $114/MW-day) and MAAC fell 29% ($119). Prices in the Public Service zone rose 31% to $219. Generation imports nearly doubled, leading some to question their deliverability. (See Capacity Auction: New Generation, Imports Up, Prices, DR Down.)

In April, the Federal Energy Regulatory Commission approved PJM’s plan to create five import zones with a combined limit of 6,499 MW for this year’s base auction (ER14-503). (See FERC Clears Capacity Import Limits.)

FERC also recently approved most of PJM’s proposal for making demand response an “operational resource.” However, the commission rejected a proposal requiring DR providers to respond to sub-zonal dispatch. The commission also rejected PJM’s proposals for eliminating financial speculation in the auction, instead scheduling a technical conference to develop a solution. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

FERC previously approved rules requiring DR providers to give more assurances in their offers (ER13-2108), as well as limits on the clearing of limited demand response (ER14-504).

In first-quarter earnings calls before the auction, executives of PJM companies said they didn’t expect a dramatic rise in prices following the rule changes.

[Editor’s Note: RTO Insider will have a full report on the auction results Tuesday.]

May 23, 2014

Court Throws Out Demand Response Rule

A Federal Energy Regulatory Commission rule requiring PJM and other RTOs to pay demand response resources market clearing prices violates state ratemaking authority, a federal appeals court ruled today.

The Court of Appeals for the D.C. Circuit ruled 2-1 to void FERC Order 745, backing a challenge by the Electric Power Supply Association and others.

The commission’s 2011 order (RM10-17) required DR participating in the day-ahead and real-time energy markets to be paid locational marginal prices identical to those for generation. The order applied when DR was capable of balancing supply and demand and lowered the market-clearing price.

FERC said it had authority for the order under sections 205 and 206 of the Federal Power Act because reducing retail consumption through DR can aid reliability and lower wholesale prices.

The commission made a distinction between “price-responsive” DR, which it acknowledged was a retail product subject to state regulation, and DR response to incentive payments, which it called “wholesale demand response.”

Not a Wholesale Sale

Judges Janice Rogers Brown and Laurence H. Silberman disagreed. “A buyer is a buyer, but a reduction in consumption cannot be a `wholesale sale,’” they wrote in a 16-page opinion authored by Brown (11-1486). “FERC’s metaphysical distinction between price-responsive demand and incentive-based demand cannot solve its jurisdictional quandary.”

The commission “went far beyond removing barriers to demand response resources,” as Congress had ordered in the Energy Policy Act of 2005, the judges ruled.

In addition, the judges said, FERC’s reasoning had “no limiting principle,” agreeing with petitioners who said it would allow the commission to regulate the steel, fuel and labor markets because they also impact wholesale prices.

Windfall

Even if Order 745 did not encroach on state authority, it would have failed anyway because paying DR the LMP is not just and reasonable, the judges said, siding with Commissioner Philip Moeller, who dissented in the order. Moeller argued Order 745 overcompensates DR because it requires that it be paid the full LMP plus “be allowed to retain the savings associated with [the provider’s] avoided retail generation cost.”

The judges said this “potential windfall to demand response resources seems troubling, and the Commissioner’s concerns are certainly valid.”

Dissent

In a 28-page dissent, Judge Harry T. Edwards disagreed with the majority both on the jurisdictional question and on the propriety of paying DR at LMP.

Edwards said FERC deserved deference in its interpretation because the FPA is “ambiguous regarding whether forgone consumption constitutes a `sale’” and whether “a rule requiring administrators of wholesale markets to pay a specified level of compensation for such forgone consumption constitutes `direct regulation’ of retail sales” that would encroach on state jurisdiction.

Edwards noted that the compensation requirement built on the commission’s 2008 Order 719, which required that ISOs and RTOs accept bids from DR “unless not permitted by the laws or regulations of the relevant electric retail regulatory authority.”

Moreover, Order 745 was not the type of “direct regulation” of retail sales that would violate state prerogatives, Edwards said.

“All Order 745 says is that if a State’s laws permit demand response to be bid into electricity markets, and if a demand response resource affirmatively decides to participate in an ISO’s or RTO’s wholesale electricity market, and if that demand response resource would in a particular circumstance allow the ISO or RTO to balance wholesale supply and demand, and if paying that demand resource would be a net benefit to the system, then the ISO or RTO must pay that resource the LMP,” Edwards said. “That is it.”

Edwards also disagreed that upholding the order would leave FERC with unfettered authority, noting the restrictions the court had imposed in the California ISO case (372 F.3d 395), in which it ruled that FERC exceeded its jurisdiction in replacing the ISO board members on the theory that the composition of the board affected wholesale rates.

The court held that FERC’s authority was limited to matters “that directly affect the rate or are closely related to the rate, not all those remote things beyond the rate structure that might in some sense indirectly or ultimately do so.”

Edwards said requiring DR be paid the full LMP was reasonable to overcome barriers to entry.

Impact of Ruling

Before Order 745, ISOs and RTOs differed in the level of compensation paid to DR, with some underpaying demand resources in some circumstances, the commission ruled.

FERC’s response to the court’s rejection will be affected by the change in the composition of the commission since it issued the order. Order 745 was approved on a 4-1 vote that included two commissioners no longer on the panel: former Chairman Jon Wellinghoff, a strong proponent of DR, and Mark Spitzer.

Commissioner Tony Clark, who often sides with Moeller, replaced Spitzer, noted attorney Carolyn Elefant in a recent blog post.

Elefant said that an adverse ruling could affect FERC’s enforcement action against Lincoln Paper Co. for allegedly manipulating the ISO New England’s DR program. The Maine-based company filed a motion to dismiss in February that challenged the enforcement action on jurisdictional grounds.

Wellinghoff, now strategic counsel for the Advanced Energy Management Alliance (AEMA), said if the decision survives an appeal it will “lead to increased electricity costs for consumers by putting more money in the pockets of power generators.”

The alliance, a trade group for DR providers, noted a report by PJM’s Market Monitor that estimated DR saved consumers $11.8 billion in 2013.

Environmental groups also lamented the ruling. “As the U.S. advances into the clean energy economy, demand response should play an increasingly larger role in how our electricity is produced, delivered and consumed,” the Environmental Defense Fund said in a news release. “This order stymies that growth.”

If the jurisdictional ruling stands, “it could severely limit FERC’s ability to create a level playing field in wholesale markets and even planning for energy efficiency, demand response and other technologies,” said John Moore, senior attorney for the Natural Resources Defense Council’s Sustainable FERC Project.

“At a time when the transmission grid and our electric resource portfolio are changing rapidly — think more solar and wind power, rooftop solar, electric cars and two-way grid communications — the court’s decision could seriously constrain FERC’s ability to reform grid rules to accommodate these new dynamics, effectively cementing the agency into a 20th century approach to addressing 21st century challenges,” Moore said.

PJM Response

PJM noted that the ruling will not take effect immediately. The court told its clerk of the court to withhold issuance of the mandate on the order until seven days after disposition of any petitions for rehearing.

“Therefore, PJM hereby advises that it will continue to abide by the terms of its Tariff and Operating Agreement as relates to demand response in its markets,” the RTO said in a statement. “In other words, PJM will continue to operate business as usual.”

“At this point, it’s business as usual,” Andy Ott, executive vice president for markets said in a press conference today on capacity market results. If the order stands, he said, “FERC will have to [provide] some clarification on our Tariff.”

May 21, 2014

Analysis: LaFleur Cruises, Bay Bruises in Confirmation Hearing

By Rich Heidorn Jr.

WASHINGTON — Federal Energy Regulatory Commissioner Cheryl LaFleur sailed through her Senate confirmation hearing Tuesday while Norman Bay was forced to defend his limited policy experience and his running of the commission’s enforcement division.

Cheryl LaFleur and Norman Bay being sworn in to the Senate hearing.

Bay also found himself having to negotiate a gender politics minefield resulting from President Obama’s decision to appoint him directly into the chairmanship — leapfrogging him over LaFleur, the acting chair and the only woman on the panel.

Based on the senators’ comments at the Energy and Natural Resources Committee hearing, Bay will likely need every Democrat — or will have to pick off a Republican or two — to win confirmation.

LaFleur’s reappointment to a second five-year term, by contrast, seems assured.

No one criticized LaFleur, and some of the Republicans, including ranking member Lisa Murkowski of Alaska, said they would like to see her retain the chairmanship.

Heavy-Handed Enforcement?

It was clear well before the hearing started that Bay would face strong headwinds.

Two days earlier, The Wall Street Journal published an op-ed by former FERC general counsel William Scherman, along with a piggybacking editorial by FERC antagonist Paul Gigot, accusing Bay of driving Wall Street banks out of energy trading with heavy-handed enforcement tactics.

It continued an attack that Scherman, now a well-compensated attorney representing FERC targets, had begun at the National Association of Regulatory Utility Commissioners conference in November. (See FERC Pick a Blank Slate.)

Norman Bay, with Richard Gates looking on, responding to questions on his handling of the Gates case.

When Bay stood up to be sworn in, Richard and Kevin Gates — the twin hedge fund managers whose case Scherman cited as exhibit A — were sitting in the row behind him. Richard was on camera, over Bay’s shoulder, during the entire two-hour hearing. (See PJM Trader Calls FERC on Manipulation Probe.)

Murkowski made it clear that Bay had failed his job interview when he met her in her office the previous week.

After praising his “impressive personal story and resume,” Murkowski said she judged his energy policy experience as “recent and limited.”

“I did feel that our discussions had raised questions about your qualifications not just to be a sitting commissioner but to serve as the next chairman of FERC,” she said.

Bay, a first-generation Chinese American who attended Dartmouth and Harvard before becoming a U.S. attorney for New Mexico, has served as director of FERC’s Office of Enforcement since 2009. But unlike most FERC commissioners in the last decade, Bay has never served as a state utility regulator. (See table.) In addition, the last five chairmen served a median of 30 months before becoming chair.

Other Republicans joined in the attack, citing the Wall Street Journal articles and Scherman’s accompanying May 13 article in the Energy Law Journal. The latter — a 49-page, 28,000-word article — alleged a “widespread view that the FERC enforcement has become lopsided and unfair” and called for reforms.

“I find this very troubling,” Sen. John Barrasso (R-Wyo.) told Bay. “I believe this raises serious questions about your fitness to be on the commission. I also believe that these tactics have contributed to driving investors out of the electric market and that means a less reliable grid and higher costs to consumers.”

Sen. Mike Lee (R-Utah) also pressed him on Scherman’s allegations, asking him, “Is this true? Do we need reforms?”

Bay noted that the commission had adopted the “Brady doctrine,” which requires prosecutors to provide targets exculpatory evidence in the government’s possession, at his suggestion. Scherman alleges that FERC officials have failed to abide by the doctrine.

Bay’s response to the criticism was curiously unemphatic. He did not say the allegations were false. He said he didn’t “believe” them to be accurate.

LaFleur provided Bay only limited cover, acknowledging she had dissented on several orders over application of penalty guidelines and investigative procedures. “This is a relatively new area of our work,” she said. “It’s to be expected that we would have debates about how the rules are to be applied … but I haven’t dissented on any of the settlements or the substance of the orders to show cause.”

Negative Pricing and Market Manipulation

Sen. Lamar Alexander (R-Tenn.) tried to corner Bay with a long series of cross examination-style questions in which he attempted to link FERC’s enforcement practices with wind farms, the production tax credit, negative energy prices and nuclear power’s financial woes.

Democrat Joe Manchin and Republican Rob Portman, of the coal-dependent states of West Virginia and Ohio, spent their time on the clock asking what FERC could do to stop the EPA’s pending greenhouse gas rules.

Manchin, who helped sink the bid of Obama’s previous nominee, Ron Binz, did not indicate whether or not he would support Bay. He has previously expressed doubts about Bay’s experience. (See Senators Weigh in on Bay Nomination, PTC, Nuclear Waste.)

Portman offered perhaps the best news Bay heard all day, saying, “I assume you are going to be confirmed.”

Republican Ally

Bay had one notable Republican ally, a frail former committee Chair Pete Domenici, a fellow New Mexican, who introduced him in a rambling defense.

“He’s done everything right to entitle him to try this, try this job on …” Domenici said. “I’m not a great fan of the president of the United States. People know that. But this is a great appointment.”

Current New Mexico Sen. Martin Heinrich, a Democrat, also sponsored Bay. He praised Bay as “fair, balanced [and] consensus-oriented” and said he had used the enforcement tools that Congress granted FERC in 2005 to provide “$300 million in relief to consumers.” Heinrich dismissed Scherman’s attack as “sour grapes,” noting the attorney had represented “the losing side in a number of cases.”

Sen. Maria Cantwell (D-Wash.) also gave a spirited defense. She noted that Congress gave FERC expanded penalty powers in response to the Western energy crisis, during which traders at Enron and other companies boosted profits by manipulating the electricity market.

“The energy markets cannot be a tool for those who want to invest just for their own manipulation of the market. We have to have policemen on the beat,” she said. “… I want to remind everyone that the policeman has been on the beat and has done a lot of great work.”

Gender politics

But for most of the session Bay and his supporters found themselves playing defense, not only over his experience and FERC record but for his gender and Obama’s decision to appoint him as chairman. In addition to having one of five votes on the bipartisan commission, the chairman serves as FERC’s chief executive, responsible for managing staff and setting policy initiatives.

Murkowski said she was troubled by “the fact that our lone female commissioner, who has certainly demonstrated her leadership, would be moved down from the position that she currently holds as chairman.”

Barrasso also said Bay’s qualifications paled in comparison to LaFleur’s, who came to FERC after more than two decades of experience in the electric and natural gas industries, including roles as chief operating officer, general counsel and acting CEO of National Grid USA and its predecessor.

“Given the wide gap in experience between you and chairwoman LaFleur, why should we demote chairwoman LaFleur to make room for you?” Barrasso asked. “And what specific qualifications do you have to be chairman of FERC?”

Bay responded by talking about his “great respect” for LaFleur and professing his confidence that they would work well together.

As to the president’s decision to pass over a seemingly more qualified woman?

“You would have to ask the White House that particular question,” Bay responded. “But I would like to think that the White House might have considered a number of factors. First that I’ve done work – and good work – to protect consumers and the integrity of the marketplace and to ensure that there’s a level playing field for all market participants.”

Bay also cited his “bipartisan record of commitment to public service and good government,” a reference to his work with the State and Justice departments during Republican administrations. Bay also said his experience in the energy industry began before he joined FERC, citing his work as counsel to Sandia National Laboratory and two summers in college during which he worked at a Department of Energy research facility.

Finally, Bay got to what may be the realpolitik answer for why the White House could have bungled the politics of the FERC chairmanship for a second time: “Geographical diversity,” Bay said.

Bay was backed for the post by former FERC chair Jon Wellinghoff, an ally of Senate President Harry Reid of Nevada.

“I do come from New Mexico,” Bay said. “It’s a Western state and it’s a producer state. And Westerners and Pacific Northwesterners have always cast a long shadow, not only on this committee but also on FERC as well.”

Maybe LaFleur, an unapologetic Boston sports fan, shouldn’t have worn her Red Sox jersey to the commission meeting last October.

May 20, 2014

Industry Happy, Environmentalists Outraged by EPA Rule

The EPA’s cooling water rule resulted from a settlement following years of litigation with environmental groups including Riverkeeper Inc., Natural Resources Defense Council and the Sierra Club. Based on environmentalists’ reaction yesterday, the legal battles may not be over.

Reed Super, legal director for the Waterkeeper Alliance, said the EPA abdicated its responsibility “to state agencies that are simply not equipped to make these decisions alone.

“Unfortunately, EPA’s rule will perpetuate the unacceptable status quo that has allowed antiquated plants to withdraw nearly 100 trillion gallons of fresh and sea water each year, and indiscriminately kill fish and wildlife instead of recycling their cooling water or use dry cooling technology, as modern plants have done for the past three decades,” Super said. “We are beyond disappointed with this new rule.”

The energy industry’s initial review was more positive. “The Environmental Protection Agency, to its credit, has taken into account many viewpoints and made improvements to this rule based on the scientific data and procedural analysis that has been brought to its attention,” the Nuclear Energy Institute said in a statement. “We’re hopeful those improvements are included in the final rule.”

NEI said enforcement must recognize the impacts on electric reliability and include cost-benefit analyses to balance increases in electricity costs against environmental benefits.

“Cooling towers consume twice as much water from the aquatic habitats we want to protect compared to once-through cooling systems,” NEI continued “This fact is very important given projections that much of our country will face a water-constrained future. Technology-based solutions at a power plant’s cooling water intake structure can be highly effective in protecting fish and can accommodate the ecological diversity of the various sites. As the EPA has pointed out previously, solutions like traveling screens, with a collection and return system, are comparable to cooling towers in protecting aquatic life in water bodies used for cooling power plants.”

Tom Kuhn, president of the Edison Electric Institute, said the association was “pleased that EPA had avoided imposing a categorical one-size-fits-all approach to compliance; has embraced significant elements of flexibility; and has acknowledged the importance of weighing costs with environmental protection.”

May 20, 2014

Cooling Water Rule: 7,000 MW Lost in PJM?

By David Jwanier and Rich Heidorn Jr.

WASHINGTON — PJM could lose as much as 7,000 MW of generation by 2018 under long-awaited cooling-water regulations approved late yesterday by the Environmental Protection Agency.

The rule will require steam generators in PJM to take steps to reduce the volume of fish and other aquatic life sucked into their cooling water intakes.

The final rule affects about 544 power plants, including nuclear-, coal-, gas- and oil-fired steam generators. More than 500 industrial sites, including pulp and paper mills; chemical, iron, steel and aluminum manufacturing plants; refineries; and food processors, are also covered by the rule.

The EPA said about 40% of affected units are already using the “best available technology” as required by the regulations, which were issued under section 316(b) of the Clean Water Act.

The EPA estimates that 2.1 billion fish, shrimp and crabs are killed annually by being pinned against cooling water intake structures (impingement) or being drawn into cooling water systems (entrainment).

Industry officials were relieved in 2011 when the EPA announced its proposed rules, which did not include a requirement that all generators install expensive closed-loop cooling systems employing cooling towers. The EPA is also delegating enforcement largely to state environmental officials. (See related stories, What’s Covered by EPA Cooling Water Rule?)

PJM spokesman Ray Dotter said the RTO has not done any studies to evaluate the potential impact of the regulations but will review the final rule. “We did look at the proposed EPA rule and believe it provided flexibility to the states to conduct unit-specific determinations, which would minimize the impact to generation,” Dotter said.

The North American Electric Reliability Corp. published an analysis of the proposed rule in November 2011, which projected at least 25,000 MW of retirements or deratings nationwide by 2018 under a “moderate” regulation, including about 7,000 MW in PJM (1,300 MW of deratings and 5,700 MW of retirements).

The moderate case is estimated to cost $170 to $440 per gallon per minute (GPM).

The moderate case assumed only “more aggressive” states would require closed-loop systems. NERC said those states — including Delaware and New Jersey in PJM — are home to three-quarters of affected generation.

NERC projected PJM generators installing cooling towers would lose an average of 1.6% of their energy output.

NERC’s analysis, and a 2011 analysis by ReliabilityFirst Corp., assumed no nuclear plants would retire as a result of the rule, although RFC said retrofits would cut nuclear capacity by 3.5%. That, however, was before nuclear operators began threatening to shutter units because of low capacity and energy revenues.

Oyster Creek Generating Station (Source: Exelon)

PJM is already losing Exelon’s Oyster Creek nuclear plant by the end of 2019 — 10 years before its license expires — under a settlement with the New Jersey Department of Environmental Protection.

NERC predicted PJM would need more generation or additional demand response by 2018 under the moderate case and by 2015 under the “strict” case. The strict case, which would have required closed-loop systems and boosted generators’ costs by 25%, could have caused 35,000 MW in retirements and deratings nationwide, NERC estimated.

In its 2013 10-K filing, Public Service Enterprise Group said it was “unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations, although such impacts could be material.”

Exelon’s 2013 10-K filing, issued in February, said that under a final rule that did not require cooling towers, and allowed states’ permitting agencies to apply cost-benefit tests and consider site-specific factors, “the impact of the rule would be minimized even though the costs of compliance could be material.”

Exelon said its generators without closed-cycle recirculating systems include the Clinton, Dresden, Peach Bottom, Quad Cities, Salem, Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna nuclear plants in addition to Oyster Creek. Also affected in PJM are the Eddystone, Gould Street, Riverside and Schuylkill fossil fuel plants as well as the Fairless Hills plant, which burns landfill gas.

May 20, 2014

What’s Covered by EPA Cooling Water Rule?

The North American Electric Reliability Corp.’s 2011 review of EPA’s cooling water regulations had assumed that the rule would affect 1,200 generators with once-through cooling systems. EPA’s announcement of the final rule yesterday said it would affect less than half as many plants, however.

Covered are:

Existing facilities that withdraw more than 2 million gallons per day (MGD) of water from waters of the U.S. and use at least 25% of their withdrawals exclusively for cooling. They are required to reduce fish impingement using one of seven options.
Facilities that withdraw at least 125 MGD, which must conduct studies to determine whether controls will be required to reduce entrainment.
New units at an existing facility that are built to increase its generating capacity of the facility. They will be required to reduce the intake flow to a level similar to that of a closed-cycle system.

May 20, 2014

Consumer Advocates to PJM: No More Changes, Please

CAMBRIDGE, Md. — Consumer advocates asked the PJM Board of Managers last week to assess the impact of recent capacity market changes before making any new ones and criticized what they called the RTO’s new “inflexibility.” Environmental groups, meanwhile, asked PJM to become “proactive” in addressing climate change and to do more to capture the role of energy efficiency in its planning.

The comments came at the board’s yearly meeting with consumer advocates and public interest groups on the first day of the PJM Annual Meeting here. The tone was a bit less rancorous than 2013’s meeting, with several activists praising PJM for its work maintaining electric service during January and for its response to generator retirements.

Still, the participants weren’t going to let their one shot to talk to the board — and it was almost entirely a one-way conversation — go to waste.

“Five major proposals in the capacity market in the last 12 months is a lot to digest,” said Assistant Pennsylvania Consumer Advocate Dave Evrard, who cited four changes that were approved by FERC and one that was rejected. Evrard noted that PJM had provided cost estimates on only one of the four proposals, a restriction on how demand response clears in the auction. (See PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings.)

“We watch somewhat nervously to see what the results of the current base residual auction will be,” Evrard said, noting that demand response offers dropped by 27% between the 2012 and 2013 base residual auctions. The question is whether the recent DR changes “[exacerbate] the decline or if that was simply an aberration,” he said.

Wil Burns, an attorney who represents environmental groups, echoed Evrard’s concerns, saying the board should not make any additional changes until it has analyzed the impact of the recent changes.

PJM’s `Inflexibility’

Brian Lipman, litigation manager at the New Jersey Division of Rate Counsel, criticized PJM for failing to discuss with stakeholders its position on a crucial capacity market rule before filing comments with the Federal Energy Regulatory Commission. PJM sided with FirstEnergy, which petitioned FERC on April 7 to change how the RTO calculates the maximum price generators can offer into capacity auctions (EL14-36).

“We didn’t find out about PJM’s position until it was filed,” he said. “That is concerning to us that we didn’t have any input into that decision.”

PJM’s “recent inflexibility” regarding rule changes “makes stakeholders worry about the future of consensus-building,” he added.

Lipman said PJM should take more time in stakeholder discussions, such as in the current discussions on the use of the Handy-Whitman building cost index in the calculation of the Cost of New Entry (CONE). “We could have been discussing that for a year now,” he said. “Decisions are happening before we have a chance to participate.” (See related story, PJM Proposes Changes to Capacity Auction Parameters for 2015.)

Role of DR, EE

Environmentalists, meanwhile, asked the board to incorporate demand response and energy efficiency into more of its planning efforts. DR and energy efficiency are “factored into one of your eight planning estimates only,” Burns said.

Yorktown Power Station (Source: Dominion Virginia Power)

For example, PJM should consider whether increased DR might allow Dominion Virginia Power to retire its Yorktown coal-fired generators as planned at the end of 2014 rather than continuing to operate temporarily to address reliability problems, Burns said.

Alison Clement, of the Sustainable FERC Project, said PJM could learn from ISO New England, where at least 90% of energy efficiency bids into the capacity market.

Rob Marmet, of the Piedmont Environmental Council, called on PJM to help states find the most effective ways to comply with pending EPA rules on greenhouse gas emissions for existing generators.

PJM Chairman Howard Schneider offered some brief remarks at the end of the session. “We value the issues you bring to us and the way you bring them to us,” Schneider said. “The relationship has improved vastly over the last several years.”

PJM CEO Terry Boston was the only other board member to offer feedback to advocates, saying he liked Burns’ idea of giving DR a bigger role in PJM’s winter reliability plans.

May 20, 2014

Monitor Suggests Price Gouging by Generators

Some generators may have taken advantage of January’s weather to boost their prices, the Market Monitor said in its quarterly State of the Market report Friday.

“The behavior of some participants during the high demand periods in January raises concerns about economic withholding,” the monitor said. “In particular, there are issues related to the ability to increase markups substantially in tight market conditions.”

The Monitor’s report cites the “markup index,” a measure of participant offer behavior. In the real-time energy market, 58% of marginal units had an average markup index at less than or equal to zero in the first quarter. But 14% of marginal units had average markups at or exceeding $150/MWh, compared to only 4% in the first three months of 2013.

In the day-ahead energy market, almost 87% of marginal units had average markups less than zero and an average markup index less than or equal to 0.03. “Nonetheless, some marginal units do have substantial markups,” the report said. Markups increased on days in January when demand was highest.

The markup index is calculated as (Price – Cost)/Price. The index ranges from -1.00, when the offer price is less than marginal cost, to 1.00, when the offer price is higher than marginal cost.

Competitive Offers Required

The Monitor said capacity resources should be required to make “competitive” offers into the energy market, an obligation that is not clear under current Tariff language.

“Selling capacity into the PJM capacity market but making energy offers daily of $999 per MWh would not fulfill the requirements of a capacity resource to make a competitive offer but would constitute economic withholding,” the Monitor explained in the 2013 State of the Market report. “This is one of the reasons that the rules governing the obligation to make a competitive offer in the Day-Ahead Energy Market should be clarified for both internal and external resources.”

The Monitor’s suggestion of economic withholding came a day after Federal Energy Regulatory Commissioner Tony Clark told PJM members that the commission had seen no evidence that market manipulation played a role in the high natural gas and electric prices in January.

In an interview yesterday, Market Monitor Joe Bowring said his staff will be interviewing generators with high markups and may refer the matter to FERC’s enforcement unit if it doesn’t receive satisfactory answers. “The Tariff requires us to refer potential enforcement matters to the commission,” he said.

January 2014 Outage Rates, Morning Peak (Source: PJM Interconnection, LLC)

Bowring said his staff is also investigating whether any generators engaged in physical withholding by improperly claiming outages. PJM saw as much as 22% of its generation out of service in early January, three times the normal winter outage rate.

Bowring said some gas-fired units took losses to operate in January. “We want to make sure that others also followed through” on their obligations, he said.

Inadequate Incentives

The Monitor’s report said the high generation outage rate in early January was an indication that the current balance of incentives and penalties is inadequate. “At present only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days,” the report said.

The obligation of capacity resources to offer into the day-ahead energy market “exists regardless of whether gas procurement is difficult, regardless of whether gas prices are high and regardless of whether gas procurement is risky,” the Monitor said.

Stakeholders this month began work on developing potential winter testing requirements for generators. Consideration of incentives for generator performance and penalties for failures will be considered in a separate initiative, PJM said. (See PJM Seeks Action on Winter Lessons.)

Day-Ahead Scheduling Reserves

The Monitor also reported withholding in the day-ahead scheduling reserve (DASR) market, a problem it has cited before which worsened in 2014.

PJM uses the market to acquire supplemental, 30-minute reserves. Because the direct marginal cost of providing DASR is zero, offers greater than zero constitute economic withholding, the Monitor said.

In 2013, 12% of offers in the market exhibited evidence of withholding. The clearing price in the first three months of 2014 was $0.06 per MW, double the price for the first quarter of 2013.

About 74% of resources offered at less than $1 in the first quarter, with 11.5% of resources offered at more than $5 per MW.

The 2013 SOM report recommended incorporating the “three pivotal supplier” test in the market to prevent the exercise of market power during times of system stress, ranking it as a low priority item. PJM said it does not believe the change is warranted given the minimal impact of the market on consumer costs.

May 20, 2014

Exelon Sells Its Share of Safe Harbor Hydro

Exelon last week sold its 67% interest in Safe Harbor Hydroelectric Project, one of four run-of-the-river hydro facilities on the lower Susquehanna River, to Brookfield Renewable Energy Partners, L.P. for $613 million.

Brookfield operates 6,000 MW of generation, primarily hydro, in the United States, Canada and Brazil. It will be sole owner of the facility when the deal closes.

The deal is supposed to be finalized by the third quarter of this year, subject to regulatory approval.

Exelon inherited two-thirds ownership of Safe Harbor when it bought Constellation, parent company of Baltimore Gas & Electric. It still owns and operates Conowingo Hydroelectric Generating Station, the last dam on the Susquehanna River before it empties into the Chesapeake Bay, and Muddy Run Pumped Storage Facility, which is perched on the banks of the Susquehanna upstream from Conowingo.

Safe Harbor went into operation in 1931. It was a joint project of the two companies that would become PPL and BG&E. An affiliate of the LS Power Group purchased PPL’s share in 2011, and Brookfield bought it from LS Power in March of this year.

There are three other power-producing dams on the lower Susquehanna in Pennsylvania and Maryland. Furthest upstream is York Haven Dam, a small, 20-MW facility south of Harrisburg, Pa., owned by Olympus Power. Next is Safe Harbor followed by Holtwood Hydroelectric Plant, both between Lancaster and York Counties in Pennsylvania. Originally a 108-MW plant, PPL completed an expansion of Holtwood in 2013 that added another 125 MW.

The Conowingo dam is a 630-MW facility on the Susquehanna, between Harford and Cecil Counties in Maryland.