MISO and independent power producers asked FERC on Wednesday to dismiss a complaint by transmission customers seeking to overturn the results of the RTO’s 2016/17 Planning Resource Auction (PRA).
The Sept. 8 complaint by the Coalition of MISO Transmission Customers claims MISO misapplied its Tariff, causing the South-North transfer limit to bind sooner that it should have, driving up prices in MISO North (EL16-112).
Prices in Zone 1 cleared at $19.72/MW-day and Zones 2, 3, 4, 5, 6 and 7 each cleared at $72/MW-day after MISO limited capacity imports from MISO South to 876 MW. MISO South cleared at $2.99/MW-day. (See MISO’s 4th Capacity Auction Results in Disparity.)
On Wednesday, MISO responded to the complaint, saying it is a “several-month-late challenge … and fails to demonstrate any Tariff violation.” MISO said it calculated the constraint properly and that the coalition raised no objections when the results were shared with stakeholders nearly a month before the auction.
The Independent Market Monitor filed comments backing MISO, saying the customers failed “to identify a single provision of the Tariff that MISO failed to abide by when MISO calculated” the constraint.
The Electric Power Supply Association filed a protest saying the complaint should be dismissed because it is based solely on the 2016/17 PRA results. “The [coalition] has not demonstrated any violation or wrongdoing as required under FERC Rule 206 that would support its request to unwind the results of the 2016/17 PRA,” the group wrote.
Dynegy also called for FERC to reject the complaint, which it said “ignores express provisions of the Tariff and the settlement” between MISO and SPP over the transfer limit.
Illinois Attorney General Lisa Madigan filed comments supporting the complaint. Eight state regulatory bodies are among the more than 35 intervenors as of this week. The Organization of MISO States also filed to intervene.
Excess Capacity Trapped?
The complaint was filed by McNees Wallace & Nurick, which represents industrial customers. The coalition said it is an ad hoc association of large industrial customers that consume more than 8 billion kWh of electricity annually.
The customers claim Entergy’s territories in Zones 8, 9 and 10 had excess capacity, but MISO’s transfer limit caused it to become trapped in the South, leading to the higher prices in the Northern zones. They argue the limit should have been increased by at least 206 MW, which would have led to north prices clearing at just $20/MW-day.
The coalition asked FERC to reset Northern clearing prices to $20/MW-day and order MISO to issue refunds from June 1, the beginning of the planning year. The customers also asked that FERC conduct an audit of the Monitor’s approval of offers in the PRA, alleging that the Monitor did not rein in unreasonably high going-forward costs.
Currently, MISO subtracts firm reservations from the 2,500-MW South-North limit negotiated with SPP. The customers argue those firm reservations are never going to be used in full.
“The firm transmission service reservations of 1,624 MW that MISO deducted from the available system capacity usage of 2,500 MW do not reflect actual power transfers from the MISO South to MISO Midwest region. Rather, the deductions reflect firm service that MISO has agreed to provide NRG Energy Inc. in order to allow NRG capacity resources located in the MISO South region to qualify as a capacity resource in PJM,” the complaint said. “There is no evidence that NRG is, in fact, using this firm transmission reservation during the 2016/17 planning year to actually flow energy from MISO South to MISO Midwest in such a way that NRG’s full transmission reservation should be deducted from the 2,500 MW total.”
The complainants say MISO “overstates the impact of firm transmission reservations” and does not consider “the actual or reasonably likely use of the firm transmission reservation.” The customers said the transfer limit problem was recognized in the IMM’s 2015 State of the Market report.
In its own filing Wednesday, NRG said that while “the MISO Tariff should expressly address how internal transmission constraints should be modeled, there is no evidence that MISO violated its existing Tariff.” If the commission grants the coalition’s request for relief, NRG said, it should require MISO to calculate the sub-regional constraints by only deducting pseudo-ties from the 2,500-MW limit.
The coalition asked FERC to fast-track its complaint, saying it wants a decision in time to implement changes before next year’s PRA.
Changes Being Discussed
MISO is already considering adjusting the South-North transfer limit in planning for next year’s auction. A draft proposal on the 2017/18 sub-regional limit is on the agenda for the Oct. 5 Resource Adequacy Subcommittee meeting. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
In its response to FERC, MISO said the “complaint raises more problems than it alleges to solve.”
“It also requires the assumption that market participants will act against their own economic interest in scheduling transmission,” the RTO said.
NextEra Energy and Energy Future Holdings have assured Texas regulators they won’t be constrained in their review of the NextEra’s agreement to purchase Texas utility Oncor, which includes a $275 million termination fee.
During an update hearing Sept. 26 on EFH’s emergence from Chapter 11 bankruptcy (14-10979-CSS), Judge Christopher S. Sontchi said he had filed a joint letter from EFH and NextEra addressing the Public Utility Commission of Texas’ concerns.
PUCT Commissioner Ken Anderson said during a Sept. 22 open meeting that the termination fee “appears to be an effort to really tie the commission’s hands in the proceeding,” as it would allow NextEra to cancel the deal if the commission imposed “overly burdensome” conditions. Anderson also called the fee an “improper attempt to constrain the commission.” (See Texas PUC Expresses Doubts over NextEra-Oncor Deal.)
NextEra has proposed buying Oncor, EFH’s transmission business, for $18.7 billion.
According to the letter, “NextEra is not entitled to a termination fee under the merger agreement if NextEra Energy terminates the merger agreement because the commission either approves the merger agreement transaction with ‘burdensome conditions’ … or does not approve the merger agreement transaction.”
NextEra and EFH said the termination fee would be triggered only if EFH or Energy Future Intermediate Holding Co., Oncor’s direct parent, terminate the merger agreement. The companies wrote they “would like to make clear that, in any event, NextEra will not seek to collect any portion of the termination fee contemplated by the merger agreement in the event it terminates the agreement.”
Sontchi opened Monday’s hearing by quoting from the transcript of the PUC meeting.
“I believe [the] letter addresses the concerns raised by Commissioner Anderson,” Sontchi said. He said any possible triggering of the termination fee is “an issue for the bankruptcy court, and not for the PUCT and ratepayers.”
The PUCT’s approval is just one of several favorable regulatory rulings NextEra and EFH must secure before closing the deal.
FERC rejected for a second time Arizona Public Service’s proposed rules over how external resources can use dynamic scheduling to participate in the Western Energy Imbalance Market (EIM).
The commission ruled that APS’ tariff changes failed to comply with an April 29 directive to “clarify that dynamically scheduled external resources are not required to enter into commercial contracts with APS in order to participate in the EIM” (ER16-938).
FERC’s Sept. 26 order affirmed that APS could require dynamically scheduled external resources to have the technical capability to provide load-following and regulation services, but it said APS could not condition eligibility on their provision of the services.
“Consistent with the April 29 order, we affirm that APS may not condition a dynamically scheduled external resource’s participation in the EIM on its contracting to provide load-following or regulation service to APS,” the commission wrote.
Arizona Public Service’s Hassayampa-Gila 500 kV line serves the utility’s Phoenix load center. Photo Source: AECOM
EIM members PacifiCorp and NV Energy currently restrict external EIM participation to only those resources pseudo-tied into their respective balancing areas. While APS will allow EIM transfers via pseudo-ties, the utility elected to further extend market participation to those external resources equipped to dynamically schedule into its transmission network.
But APS required that dynamically scheduled resources meet the tariff-defined qualifications of a Balancing Authority Area Resource (BAAR).
Under the EIM’s rules, a BAAR designation denotes a resource’s eligibility to contribute to an EIM participant’s “available balancing capacity” — the verifiable operating reserves a market participant carries to ensure that it isn’t leaning on the EIM to meet its capacity requirements.
APS’ tariff proposal included requirements that a BAAR resource be unit-specific rather than an unspecified system resource and be able to provide regulation and load-following services to help the utility to meet its resource adequacy criteria.
The proposal also required that a BAAR either be owned by APS or under contract with the utility for energy, ancillary services or capacity.
In its April order, the commission objected to that last provision and directed the utility to clarify that external resources do not have to qualify as a BAAR in order to transact with the EIM.
Instead of inserting a new provision covering dynamically scheduled resources, APS’ compliance filing redefined BAARs to exclude the ownership and contracting requirements. The utility expressed concern that removing the BAAR provision could enable resources to circumvent operational and technical specifications applicable to all resources participating in the EIM — specifications already approved by FERC. APS also contended that, by revising the definition to eliminate the commercial relationship requirement, it had complied with FERC’s directive.
The commission disagreed, saying that “APS has failed to comply with the directive to remove the requirement that an external resource qualify as a BAAR to be eligible to participate via dynamic scheduling.”
The BAAR qualification is “commercial in nature,” given that APS’ tariff still required any resource designated as such to provide load-following and regulation service, the commission found.
Market participants’ transactions in the EIM are expected to be voluntary and not subject to such obligations, FERC said. While an external resource participating in the EIM can enter a contract to provide ancillary services to APS, it cannot be required to do so, the commission said.
The commission ordered APS to restore the original commercial language to the BAAR qualification in order to ensure that APS and CAISO, the EIM’s operator, can identify those resources that contribute to the utility’s EIM capacity requirement.
“In the context of the available balancing capacity mechanism, it is crucial that APS either own or have a contractual right to call upon the capacity for regulation or load-following services from a designated resource,” the commission wrote.
Other elements of the ruling include:
FERC affirmed APS’s requirement that external resources participating in the EIM via dynamic scheduling be capable of responding on a unit-specific basis. “As APS notes, requiring that resources be unit-specific, will ensure that APS can distinguish an external resource’s dynamic schedule from an intertie bid,” FERC wrote.
The commission denied a rehearing request by the Southwest Public Power Agency (SPPA) over its approval of APS’s proposal to adopt EIM pricing of transmission losses without giving transmission customers the option of self-supplying losses within the same hour. The commission said FERC precedent does not “preclude the use of a financial settlement mechanism to the exclusion of in-kind replacement of losses.”
The commission directed APS to submit a compliance filing providing more details about the timing and duration of its evaluation of operating reserve obligation payments and credits from CAISO. SPPA contended that APS has not committed to ensuring that customers will share in the benefits of reduced reserve costs resulting from EIM participation.
CAISO’s Board of Governors has approved a proposal to extend most of the temporary Tariff provisions the ISO implemented in June in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility.
The ISO will now seek expedited approval from FERC to extend the measures through Nov. 30, 2017 — a year beyond the original sunset date.
While the region weathered the summer without grid emergencies, the ISO has identified a continued risk of gas shortages for generators in the face of limited operations at Aliso Canyon during the winter, according to Cathleen Colbert, senior market design and regulatory policy developer at CAISO.
“The goal [of the extension is] to determine what provisions were needed for winter reliability,” Colbert said during a Sept. 26 call to discuss a draft final proposal to renew the measures.
The Aliso Canyon gas storage facility was closed last October after inspectors discovered a massive methane leak. Photo Source: California Department of Emergency Services
The provisions were geared to helping Southern California gas-fired generators manage their gas burns to avoid system-balancing penalties and enable them recover gas costs after the fact, while providing the ISO the flexibility to move energy into the region during periods when gas supplies became constrained.
During winter, electric load is not the “primary driver” of gas imbalances, as the bulk of gas demand shifts from “non-core” gas customers such as electric generators to “core” residential heating customers, Greg Cook, CAISO director of market and infrastructure policy, told the board during an Oct. 3 call.
“It’s good to note that the non-core generators are the first to be curtailed in the event that we do not have sufficient on-system gas to meet the core and non-core demand,” Cook said.
Among the measures CAISO proposes to extend:
The release of advisory schedules by CAISO two days ahead of an operating day to help scheduling coordinators plan for gas procurement further in advance.
The ability of generators to reflect gas cost expectations into day-ahead bids by using an approximation of next-day gas prices, which are published after the ISO’s morning day-ahead market runs. ISO rules typically require generators to incorporate the previous day’s next-day gas prices into energy bids.
A gas adder and an after-the-fact cost recovery mechanism for generators connected to the Southern California Gas system to tie cost recovery and penalties to same-day gas prices rather than day-ahead gas indices.
Authority of the ISO to manually override its “dynamic competitive path” assessment when it determines that the transmission path is no longer competitive in the face of a gas constraint.
Suspension of virtual bidding in circumstances when CAISO determines the practice could produce market inefficiencies.
CAISO also seeks to refine a provision allowing it to enforce a market constraint that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of restricted gas supply. The refinement would set a limit on the maximum burn only.
One key provision from the original Aliso Canyon plan is on the chopping block: a measure that allows the ISO to reserve transmission capability on the Path 26 transmission line linking the Pacific Gas and Electric and Southern California Edison service territories in order to ensure adequate delivery into the southern part of the state during gas restrictions.
CAISO says it no longer needs that capability because Peak Reliability, the reliability coordinator for most of the Western Interconnection, recently modified its system operating limit (SOL) methodology to allow Path 26 to exceed its capacity rating under emergency conditions.
One board member expressed concern that the expanded limit would provide the ISO with only a short timeframe in which to respond to a gas-driven grid emergency before being required to return the line to its SOL.
“Why wouldn’t it be prudent to retain the internal capability?” asked board member Dave Olsen. “Are we giving up flexibility it would be prudent to retain?”
Cook responded that the new SOL methodology provides CAISO with the reliability protections it was seeking when it originally proposed the Path 26 provision — which had prompted concerns from some market participants about the impact on the ISO’s congestion revenue rights market.
“Now that we have this increased flexibility provided by Peak [Reliability] that helps deal with the reliability concern, it’s probably best to retire that provision so that those market concerns could go away,” Cook said.
The ISO plans to file the updated Aliso Canyon proposal with FERC in mid-October.
WASHINGTON — Obama administration lawyers squared off with opponents of the Clean Power Plan last week, as oral arguments scheduled for less than four hours stretched over seven.
We won’t know for months how those whose opinions count — 10 judges of the D.C. Circuit Court of Appeals — scored the arguments. And whatever they decide will inevitably be reviewed by the Supreme Court.
But based on the judges’ questions and comments, four of the five challenges — a Constitutional issue; a bill drafting error; EPA’s alleged failure to provide sufficient notice of changes between the original and final plan; and a claim that it relied on dubious assumptions on the growth of renewables — appeared to have little chance of prevailing.
‘Beyond the Fence Line’
For opponents, the best hope of overturning the CPP is likely the argument that was presented first, led by West Virginia Solicitor General Elbert Lin.
Lin contended that EPA overreached its authority by creating CO2 emission limits that coal-fired generators can’t meet, forcing a “generation switch” to natural gas and renewables.
“Ninety-six percent of [West Virginia’s] power comes from coal,” he said. The rule, he said, was “clearly designed to make us change our generation source.”
Judge Brett M. Kavanaugh evidenced the most sympathy for the “beyond-the-fence-line” argument.
The CPP seeks to cut the power sector’s carbon emissions by 32% by 2030, compared with 2005 levels. It uses two different CO2 emission rates to define the “best system of emission reduction,” one for coal-steam and oil-steam plants and a second for natural gas plants. The agency said compliance can be achieved through improving generators’ efficiency (Building Block one) and shifting generation from coal to lower-emitting natural gas plants (Building Block two) and zero‐emitting renewables (Building Block three).
Citing what he said was at least three decades of Supreme Court precedent, Kavanaugh said EPA needed explicit Congressional approval for the magnitude of the changes contemplated by the CPP. “This is a huge case,” he said. EPA is “fundamentally transforming the industry.”
Justice Department attorney Eric Hostetler, speaking for EPA, insisted the agency is entitled to deference under the Supreme Court’s Chevron decision, which held that courts should defer to agencies’ interpretations of the laws they are charged with enforcing unless the court finds their actions unreasonable.
“This is far from the first time EPA has relied on generation-shifting,” he said.
EPA’s rule is a “proper and sensible” response for the “most urgent threat that our country has ever faced,” Hostetler said.
Judge Thomas B. Griffith also expressed concern over EPA’s strategy. “It doesn’t help that the president said, ‘If Congress doesn’t act, I will,’” he said.
Judge Janice Rogers Brown asked why EPA wasn’t regulating under Clean Air Act Section 115 instead of going through “linguistic gymnastics” under Section 111(d).
While his questions indicated he may vote to overturn the CPP, Kavanaugh made clear he is no climate denier. He called EPA’s policy “laudable,” saying “I understand the climate is warming.”
He added that “I understand the frustration with Congress,” which has not been able to reach agreement on climate policy.
But he also expressed sympathy for coal states such as West Virginia, saying that national policy, authored by Congress, could incorporate a safety net such as public assistance and job training.
“Whole communities are going to be left behind,” he said, addressing EPA’s lawyers. “If you do it, all the people who will be left back will [remain] left back.”
It’s questionable that Kavanaugh will be able to carry a majority in overturning the rule, however. Less than a minute into Lin’s argument, Griffith interrupted to challenge his claim that the rule would be “transformative.”
He noted that EPA estimates that the amount of coal-fired generation will still be 27.4% of total generation in 2030 — only 5.4% less than projected without the rule. “That hardly sounds transformative,” Griffith said.
Judge David S. Tatel also expressed skepticism. The term “best system of emission reduction” is “an awful broad grant” from Congress, he said. “It says best system of emissions reduction,” he repeated twice, emphasizing “system.”
Emission Limit a ‘Lever’
Judges Cornelia T.L. Pillard and Patricia A. Millett also appeared sympathetic to EPA’s case.
Pillard asked how the CPP is that different from previous EPA rulemakings, which required coal-fired generators to add equipment such as scrubbers.
Peter D. Keisler, representing industry and labor challengers, said EPA failed to take into account the remaining useful life of coal plants. He insisted EPA’s authority is limited to “operation of the source” and doesn’t “extend to the investment decisions of the owner.”
“The emission limit here is a lever” to force subsidization of renewables, Keisler said. Renewables, he said, are not “sources.”
Millett asked whether EPA could force dual-fuel plants to make gas primary. Yes, Keisler responded.
Three judges nominated by President Obama to the D.C. Circuit Court of Appeals in 2013 are among 10 that will rule on the EPA Clean Power Plan. From left are Robert Leon Wilkins, Cornelia “Nina” Pillard and Patricia Ann Millett. Source: The White House
Judge Sri Srinivasan cited the Supreme Court’s 2011 ruling in American Electric Power v. Connecticut, which he said gave EPA a guide to how to regulate CO2 from power plants. But Srinivasan also saw a distinction between requiring coal plants to add scrubbers and requiring them to seek aid from other generators.
“The word ‘system’ is a capacious term,” responded Hostetler. He rejected opponents’ complaint that the agency was relying on a rarely invoked section of the Clean Air Act.
“You might not use a fire extinguisher until your house is burning down,” Hostetler said. “That doesn’t mean you shouldn’t use it.”
He also insisted the rule “doesn’t require any subsidies,” noting other compliance methods such as co-firing with natural gas.
Brown asked several questions but staked no clear position in the arguments. Judge Karen LeCraft Henderson said little and Judge Robert L. Wilkins was silent.
Although the D.C. Circuit’s decision is likely to be reviewed by the Supreme Court, its ruling would prevail if the high court — currently shorthanded following the death of Justice Antonin Scalia — deadlocks 4-4.
Mutually Exclusive? Section 111(d) vs. 112
One curious wrinkle in the legal questions concerning the CPP is a drafting error that resulted from the House of Representatives and Senate approving two different versions of Section 111(d) when it amended the Clean Air Act in 1990.
The section has long been used to regulate pollution from existing sources that is not covered under other sections of the CAA.
Opponents say the House’s version of the amendment barred EPA from using the section if the agency was already regulating power plant emissions under another section of the CAA. The Senate’s version, however, included no such prohibition. The two were never reconciled and President George H.W. Bush signed the revision into law with both amendments.
EPA regulates power plant emissions such as mercury, acid gases and other hazardous air pollutants (HAPs) under Section 112.
Lin said he believes the House version was the “substantive amendment” and the Senate’s was a clerical error. But he said the challengers should succeed even if the court decided to give the House and Senate versions equal weight. “The way to reconcile them … is to give both amendments maximum effect,” he said.
Judge Kavanaugh sided with the plaintiffs, saying he believed the House amendment applies.
But the other judges who spoke on the matter expressed no support for the opponents’ interpretation.
Srinivasan said that if both amendments were considered, EPA would be given the right to regulate under 111(d). “It seems like it’s inclusive and not exclusive,” he said.
Allison D. Wood, representing the non-state plaintiffs, also insisted the House exclusion should prevail. She said most, if not all, coal plants are already regulated under Section 112.
“Under your theory you can’t regulate existing sources [for CO2] at all,” responded Judge Tatel.
“I just don’t see the logic of that,” added Judge Pillard.
Justice Department attorney Amanda S. Berman said a “contextual reading is the best reading of this ambiguous text,” asking the judges to side with EPA’s “reasonable middle course.”
Adopting the House version would be a “dramatic downsizing ” of 111(d), she said.
“I don’t think Congress intended something so drastic,” she said, adding that electric generators are already regulated under “at least five sections” of the CAA.
Sean Donohue, representing environmental and public health intervenors, said the plaintiffs’ arguments were an attack on the Supreme Court’s 2007 ruling in Massachusetts v. EPA, in which the court ruled that the CAA applies to CO2 emissions from automobiles.
The court followed that up in 2011 with its ruling in American Electric Power v. Connecticut, in which the court barred common law nuisance complaints over power generators’ carbon emissions, saying it was EPA’s response to regulate the emissions under section 111(d).
Constitutional Issues
After lunch, the judges returned to hear plaintiffs’ constitutional challenge, with petitioners’ attorney David Rivkin Jr. complaining that the CPP “commandeers” state officials to implement the rule in violation of states’ rights under the separation of powers clause of the 10th Amendment.
Judges Griffith and Tatel challenged Rivkin, with Griffith asking how the CPP differed from any other federal regulation that requires state action.
Tatel, who is blind, said Rivkin’s logic would also void the Americans with Disabilities Act. Compliance with the ADA, he said, requires local governments to exercise their police powers to issue building permits for wheelchair ramps and curb cuts.
Harvard University constitutional law professor Lawrence H. Tribe supported Rivkin’s argument on behalf of the non-state petitioners. Tribe noted that the Senate had rejected cap-and-trade legislation in 2010. EPA’s supporters “are asking you to bail out Congress,” he said.
Judge Millett challenged Tribe, appearing sympathetic to EPA’s argument that rejecting the CPP would amount to a “bait and switch” after the AEP ruling.
Justice department attorney Berman called the CPP “bread and butter cooperative federalism,” saying the plaintiffs’ arguments would “take down much of the Clean Air Act.”
She said there was nothing in the record to suggest the “parade of horribles” opponents have predicted: price spikes, blackouts and jails being forced to release prisoners.
Throughout the afternoon’s arguments, only Kavanaugh consistently expressed support for the challengers. Several times, he cited the Supreme Court’s 2014 ruling in Bond v. U.S., which he said established limits to the deference granted executive agencies under Chevron. The court ruled unanimously that a woman who attempted to poison a romantic rival could not be prosecuted under Section 229 of the Chemical Weapons Convention Implementation Act of 1998. The court said there must be “a clear indication that Congress intended to reach purely local crimes before interpreting Section 229’s expansive language in a way that intrudes on the states’ police power.”
‘Notice’ Issue
Plaintiffs also complained that EPA failed to provide sufficient notice of its proposal because the final rule, issued in August 2015, included provisions not mentioned in the draft rule a year earlier.
The plan uses two different CO2 emission rates to define the best system of emission reduction, one for coal-steam and oil-steam plants and a second for natural gas plants. The draft rule had proposed a blended rate. (See Revised Clean Power Plan Allows More Time, Sets Higher Targets.)
John Campbell Barker, representing state petitioners, said EPA should be required to withdraw the rule and restart the process, as it did in withdrawing its 2012 draft rule on CO2 emissions from new electric generators.
The Justice Department’s Norman L. Rave said EPA changed the way it calculated state targets because it was “inundated” with comments objecting to state-by-state rates. Critics said the original plan would mean states that had done nothing to curb greenhouse gas emissions would have less stringent rates than those that had already taken action.
Rave said there was no shortage of opportunities to comment on the rule, noting the more than 600 meetings EPA held with stakeholders. The agency said it received more than 4.3 million comments in total.
He also cited the notice of data availability EPA issued between the draft and final rule, which signaled that it was considering factoring in states’ ability to tap out-of-state renewable resources to meet their targets. (See EPA Signals Flexibility on Interim Carbon Targets, Coal-Gas Shift.)
Rave said the petitioners had failed to clear any of the three tests needed to overturn the rule on notice grounds and had not identified any data they would have offered to EPA had they received more notice.
Record-Based Issues
The final arguments dealt with plaintiffs’ claims that EPA failed to demonstrate that its proposed compliance measures are achievable.
William Brownell, representing the non-state petitioners, said the agency failed to provide “real-world proof” that generation-shifting will work, saying the CPP envisioned “something entirely different in terms of magnitude and character” than current utility operations under least-cost security-constrained economic dispatch.
He challenged the rule’s reliance on combined cycle plants operating at 75% capacity factors, saying only 15% of them currently run that often. He also mocked EPA’s projections for the growth in wind generation, saying the agency assumed seven years of growth at the rate seen in 2012, when growth spiked because of the impending expiration of the Production Tax Credit.
Brett Kavanaugh is sworn in as a D.C. Circuit Court judge by Supreme Court Justice Anthony Kennedy in 2006, as his wife, Ashley, and President George W. Bush look on. Source: The White House
Millett said EPA was projecting from existing trends. “They didn’t pull these numbers out of thin air,” she said.
Wisconsin Solicitor General Misha Tseytlin said the court must determine whether the plan is achievable under the “most adverse circumstances.” That means, he said, considering the possibility that California and other states with excess renewables will “lock out” states that need them by setting onerous requirements.
“If that happens, all of EPA’s numbers break,” he said.
Justice Department attorney Brian Lynk responded that EPA was conservative in “multiple ways” in its projections, citing its assumptions on heat rates and renewable growth.
Millett asked how the agency would respond if the rule was unachievable for some states.
“I have no doubt that EPA would be amenable to consult with that state,” Lynk said. And if states were not satisfied with EPA’s response, Rave said, “I’m sure there would be an opportunity for them to come to court.”
Kevin Poloncarz, representing Calpine and other power companies supporting the rule, said the 75% capacity factor for combined cycle plants was “eminently reasonable.”
The reason such dramatic fuel switching hasn’t happened in the past, he said, is because the cost of carbon hasn’t been included in economic dispatch calculations.
EPA shouldn’t be required to take a Balkanized state-by-state approach to regulating the industry, he insisted. “Electricity,” he said, “doesn’t observe state boundaries.”
WASHINGTON — After four years, Commissioner Tony Clark’s last day at FERC will be Sept. 30, he said at his last, and 47th, open meeting Thursday.
Tony Clark received parting gifts from each of his fellow commissioners, including a lookalike bobblehead from Chairman Norman Bay. Source: Norman Bay
Clark said that given the date would be the end of a week, pay period, quarter and the federal fiscal year, “this may be God’s way of telling me that that’s probably the right day to move on.”
The remaining days of his tenure will be mostly spent emptying his office, he said, though he would be available in case a quorum (a minimum of three commissioners) is needed for decisions in which another commissioner could not participate. Chairman Norman Bay recuses himself from issues he dealt with as head of the commission’s Office of Enforcement, and Commissioner Colette Honorable recuses herself from matters that were before her as a regulator in Arkansas.
Bay said he did not foresee any quorum problems following Clark’s official departure. “I feel like we’re on top of that. We’ve known for some time that Commissioner Clark would be leaving, and so we’ve been planning for the completion of any orders where his vote would be required.” Clark indicated in January that he would not seek another term.
A former North Dakota regulator, Clark is the lone Republican on the commission after the departure of Philip Moeller last year.
Clark’s three Democratic colleagues praised him for his meticulous thinking and ability to work through disagreements civilly.
“You’ve been an outstanding public servant,” Bay said. “I know that every place you’ve gone to, you have made [it] better with your thoughtfulness, your encyclopedic knowledge of policy, your reasonableness and your collegiality.”
Commissioner Cheryl LaFleur joked about her disappointment at not being able to influence Clark more after he joined the commission. “From the very first day you walked in, you were always on top of the issues, crystal clear in your thinking, pragmatic and very, very decisive,” she said.
“I have enjoyed working with him very much, even though we come from different places,” Honorable said. “But in many ways, we have been quite a lot alike, I would say, in terms of … our commitment to serving.”
Honorable joked that they agreed on many things, but not on their favorite president. Her parting gift to him was a mug featuring the Democratic nominees for president and vice president, Hillary Clinton and Tim Kaine. Clark promptly hid the mug behind his name plate.
“Hopefully at FERC, people see an agency in a town that is sometimes dysfunctional, but an agency that I think is very functional,” Clark said. “Although we don’t agree on every item — that’s to be expected — … where we do disagree, we can do so without being disagreeable.”
Clark was nominated by President Obama after Sen. Mitch McConnell (R-Ky.) forwarded his name to the White House. He said he has not heard anything about Obama nominating replacements for the two GOP vacancies. He speculated that new commissioners may be among a group of nominees submitted by the next president.
The best chance for a nominee to get confirmed by the Senate would be during the lame-duck session after the November elections as part of a package of nominees, said Dan Blair, CEO of the National Academy of Public Administration, a Congressionally chartered think tank that provides advice to public officials.
But there are many different permutations of what could happen based on the results of both the presidential and senatorial elections. For example, Blair said, if Republican presidential nominee Donald Trump wins the White House, McConnell, the majority leader, could defer to him on who should go to FERC.
Many federal agencies suffer member shortages while the White House and Senate negotiate over nominations. Obama may be holding out on nominating anyone to FERC until he can reach an agreement on a Democratic nominee for a different agency, Blair said. “There’s a lot of horse trading that goes on behind the scenes. You have to look outside the commission.”
When asked if he had heard anything about reinforcements, Bay said only, “The nomination process I leave to the White House and to the Senate.”
Nicole Daigle, communications director for the Senate Energy and Natural Resources Committee, said Chairman Lisa Murkowski (R-Alaska) “is concerned that FERC will be down to three commissioners.”
“It is important that we have a full complement of members on the commission,” Daigle said in a statement.
Daigle did not respond when asked whether Murkowski had suggested anyone to McConnell or whether McConnell had forwarded any names to Obama.
A spokesman for McConnell said the senator would not comment until the president submitted a nomination. The White House did not respond to a request for comment.
Clark said he was going to take some time to relax before spending the remainder of October thinking about his next job.
WASHINGTON — FERC said last week it is considering changing how it evaluates market power in electric utility mergers and applications for market-based rate authority (MBRA).
Most of the changes the commission is considering in its Notice of Inquiry (RM16-21) would affect merger reviews.
The commission noted that its market power evaluation for mergers, which are regulated under Section 203 of the Federal Power Act, differs from that used in MBRA applications under Section 205.
“While some of those differences may be appropriate, others may not be,” the commission said, adding that it was seeking to “harmoniz[e]” the two.
The commission asked for comment on whether it should make the following changes in Section 203 reviews:
Use a simplified analysis for transactions that typically don’t raise market power issues;
Add supply curve and market share analyses;
Modify how capacity under long-term power purchase agreements is attributed;
Require submission of documents already required by other federal antitrust regulators; and
Develop a more precise definition or test of de minimis in determining when a full competitive analysis screen is unnecessary in merger reviews.
The commission also is considering improving its single pivotal supplier analysis in MBRA applications and adding one to Section 203 evaluations.
Chairman Norman Bay said the proposed changes were not the result of concerns over a specific merger.
“There certainly have been a number of mergers over the last few years in the electric industry, but I don’t think there was any one specific act that led us to review the screens that we use in conducting our reviews under Section 203 of the FPA,” he said in a press conference after Thursday’s commission meeting. “I think more it’s a matter of continually striving for improvement as an organization or as an agency. And in order to do that, from time to time, you have to take a step back and examine what you’ve been doing and … ways to improve what you’re doing.”
Comments will be due 60 days after the notice’s publication in the Federal Register.
Adding Pivotal Supplier Screen
The commission said it is looking for new tools to ensure the effectiveness of its market power reviews, including the use of wholesale market share and pivotal supplier screens currently used in Section 205 MBRA reviews.
Merger applicants are currently required to perform a competitive analysis screen unless they can show that the acquisition does not increase their generation capacity in the relevant geographic markets or that the increase is de minimis.
The screen includes a delivered price test, which has been essentially unchanged since its introduction in 1996 and generally focuses on the short-term energy market “with far less detail and attention given to the other relevant products,” FERC said.
In contrast, the pivotal supplier screen measures a seller’s ability to exercise market power based on its uncommitted capacity at the time of annual peak demand in the relevant market. A seller passes the screen if wholesale load can be served without any of the seller’s capacity participating.
Although pivotal supplier tests are usually applied to energy-only markets, the commission said they could be applied to capacity and ancillary service markets under both sections 203 and 205. “Adding a pivotal supplier test to the commission’s review of a Section 203 application could make the commission’s analysis more effective because it would take into account the ability to meet demand, in addition to supply conditions, in screening for potential market power,” FERC said.
But the commission said it also seeks to improve the test because MBRA applicants “rarely fail” it.
“In many cases, the results of the pivotal supplier analysis indicate that the study area’s wholesale load can be met solely by remote suppliers, a result that is unlikely in practice,” FERC said. “The commission intended that the indicative screens would serve as a conservative threshold. However, with experience, this does not seem to be the case.”
As a result, the commission said it is considering whether to replace the current wholesale load proxy, defined as the average of the daily peak native load during the month in which the annual peak load day occurs.
FERC is considering replacing that input with the study area’s annual peak load — peak load not reduced by the proxy for native load obligation.
Market Share Analyses
The commission said its current merger analysis is a forward-looking review focused on how a transaction changes market concentration “and not an examination of market share changes or accumulation of market share over time.”
Thus, the commission said it is considering adding a market share analysis measuring the size of the applicant relative to other suppliers, allowing it to “determine if a seller has obtained a significant share in a specific market either through a series of transactions or a combination of transactions and construction, allowing for the accumulation of market power without one particular transaction triggering concerns.”
The MBRA wholesale market share screen determines whether a seller has a dominant market position by analyzing the number of megawatts of uncommitted capacity it controls relative to the uncommitted capacity of the entire market. Sellers with less than a 20% market share during all seasons pass the test.
Supply Curve Analysis
The Herfindahl-Hirschman Index of market power is calculated by squaring the market share of each firm competing in the market and then summing the resulting numbers. In 2012, FERC declined to adopt the 2010 Horizontal Merger Guidelines by the Department of Justice and the Federal Trade Commission, choosing to continue its reliance on the more conservative HHI thresholds in the 1992 guidelines.
The commission said it also is weighing whether to incorporate into its merger review a supply curve analysis to determine whether the acquisition would give the purchasing company the ability and incentive to exercise market power by withholding output from some generators to benefit other units and increase its overall profits.
The analysis would be more granular than the delivered price test, which measures aggregate capacity but not the breakdown by baseload, intermediate and peaking units.
“A supply curve analysis would enable the commission to identify situations that typical [Herfindahl-Hirschman Index] analyses do not capture, including situations where mergers that result in changes in market concentration below the thresholds that merit further scrutiny from an HHI perspective may still have the ability and incentive to raise prices above competitive levels,” the commission said.
Capacity Associated with Power Purchase Agreements
FERC also sees a need to change how it accounts for capacity subject to long-term firm power purchase agreements.
If a utility signs a long-term firm PPA for the output of a generating facility before filing an application to purchase that generator, the commission has usually attributed the generator’s capacity to the purchasing utility. That means the company’s acquisition of the plant would not be seen as increasing its market share.
“While the current approach of attributing the capacity of the facility to the purchaser is appropriate in the context of the market-based rate market power analysis, in the Section 203 context the change in market concentration may extend beyond the terms of the PPA,” FERC said. “For example, if a transaction conveys ownership over a generation facility where a PPA is expiring in two years, the transaction may prevent competitive supply from re-entering the market.”
Applicant Merger-Related Documents
FERC noted that merger applicants are required to submit to the Department of Justice and Federal Trade Commission both internal reports and those of consultants that concern the competitive effects of an acquisition.
“We believe these merger-related documents could be useful in the commission’s understanding of an applicant’s competitive analysis screen by providing additional information regarding, for example, the relevant geographic market definition or anticipated unit retirements,” it said.
Blanket Authorizations
FERC also is taking another look at its use of blanket authorizations — waivers of commission review for certain Section 203 transactions. The commission said it is considering canceling blanket authorizations for some types of deals and extending them to others.
“Since these blanket authorizations were granted, industry has undergone substantial change, including continued market development and expansion of RTOs/ISOs [and] consolidation among utilities, such that the conditions that gave rise to the blanket authorizations currently in effect may no longer be appropriate,” FERC said. “For example, it may no longer be appropriate to grant blanket authorizations to holding companies that only hold exempt wholesale generators, as is granted in 18 CFR 33.1(c)(8), as exempt wholesale generators now make up a significant portion of supply and any transaction involving these generators could affect wholesale rates by impacting competition.”
Exempt wholesale generators, a category created under the Energy Policy Act of 1992, are independent units that sell exclusively to wholesale customers and were exempt from some requirements of the Public Utility Holding Company Act of 1935. PUCHA was repealed in 2005.
NYISO CEO Brad Jones said he is not convinced by any argument that the DER Roadmap pits the strength of a large grid against the resiliency of a small grid, as the system needs both to be robust. “Our goal is to find a way to bring both of those together to allow each of those different parts of the grid to provide efficiency for our operations and reliability for the overall grid.”
Audrey Zibelman, chair of the New York Public Service Commission, said, “We want the distribution markets to be optimizing distributed energy resources and optimizing load and co-optimizing that with the wholesale market, so that way will have a two-way seamless grid that is vertically coupled, that allows us to have a system that is more reliable, more dynamic, more efficient and more environmental.”
Cristin Lyons, partner at consultant ScottMadden, discussed the difficulty grid operators and utilities face in gaining visibility into the volume of distributed generation and how and when it is producing. There also are questions about whether they can be aggregated and how they will be compensated, she said. “Can you verify when they’ve operated? Do you even know if they are coincident with peak? Are they dispatchable? … At the end of the day, how do all these resources get paid? I think if we’re ever able to figure out the money, everything else will follow. We’re not there yet.”
Nick Tumilowicz, who manages the Electric Power Research Institute’s DER integration effort, discussed Consolidated Edison’s Brooklyn-Queens project, which is using battery storage and distributed generation to delay construction of a $1.2 billion substation. EPRI is performing a life-cost analysis. “What does it look like when we deploy battery storage in the field … to support peak demand and efficient transmission and distribution deferral?”
Kelli Joseph, director of market and regulatory affairs for NRG Energy, considered how uncertainty in the markets currently limits how different technologies could participate. “There’s a lot of uncertainty … about what rate design they’re going to have on the distribution side. For some projects, without a wholesale participation, they probably don’t pencil out.”
Mike DeSocio, NYISO’s senior manager of market design, devised what he said is a simple way to look at how generation assets can be classified as distributed. “If you have an asset that’s large enough to participate in the [wholesale] market today, you’re not a DER. If you have an asset that’s too small to participate in the market today and you think you’re going to need to aggregate it to participate, that’s a DER, whether it’s in front of the meter or behind the meter.”
The Brattle Group last week endorsed MISO’s proposed Competitive Retail Solution, conditioned on the RTO adopting a wider demand curve that the consulting firm developed.
Brattle’s demand curve, revealed in its latest analysis of MISO’s proposed forward auction, is capped at 140% of the net cost of new entry (CONE). The foot of the curve lands at 115% of MISO’s planning reserve margin requirement and a $0 net CONE.
Brattle said the net CONE cap is “slightly above” MISO’s requested $195/MW-day figure for Zones 4 and 7 and the $185/MW-day price elsewhere.
Brattle analyst Samuel Newell said the analysis concluded that MISO’s separate forward auction solution will address reliability concerns while inviting merchant investment. It projects volatility will be reduced by 6 to 15% compared to a status quo case Brattle researched.
Volatility
Newell said the wider curve Brattle recommends seeks to “absorb more structural volatility than other markets,” and the curve’s shift to the right is needed to accommodate a lower CONE price cap than what’s in use at other RTOs. Brattle said the curve “allows some shortage at high prices.”
He said Brattle has recommended caps ranging from 1.5 times to two times net CONE in other regions. The recommended sloped demand curve is less steep than other regions’ and extends farther to the right.
“A reason to have a higher cap is to put more money in the market, and it helps protect against the risk of under-procurement if you’ve underestimated CONE,” Newell said. “Yes, the pricing is going to be volatile because of all that uncertainty that goes into the system. But as long as you have enough money built into the curve and the curve is shifted far enough right, you will attract enough megawatts.”
Brattle’s analysis predicts the new capacity structure would meet or exceed the one-day-in-10-years loss-of-load expectation (LOLE) and attract an additional 1,800 MW of merchant supply. Brattle also said the forward auction on average is predicted to clear an extra 120 MW. The analysis results will be included as testimony in MISO’s FERC filing to win approval of the forward auction.
The firm also said use of the sloped demand curve in the long run should result in average forward prices that spur merchants to build; however, Newell said the analysis didn’t forecast prices under the new auction construct. “The reason we’re here isn’t to forecast prices. It’s to address the widespread belief — that I think is right — that current prices won’t support merchant supply meeting need.”
Status Quo Falls Short
Brattle did find that in the long run, use of the demand curve under the forward design reduces the instances of auction prices clearing at the demand curve cap to 39% of years. When Brattle tested a status quo scenario in retail-choice zones, clearing at the demand curve cap amount happens 65% of the time in Zone 4 and 67% of the time in Zone 7. Brattle maintains some capacity prices clearing at the cap is needed to keep average clearing prices closer to net CONE.
Newell said Brattle tracked enough merchant supply to assume a one-in-10 standard with the curve, but MISO can also assume its utilities own supply averaging 3% more than their individual requirements. Brattle found that continuing with the status quo would result in MISO falling 891 MW short of its planning reserve margin requirement in the long term in MISO North. The status quo auction, Brattle said, also results long-term in a one-in-5.2 LOLE “with frequent severe shortage” events and a majority of auction offers clearing at the price cap.
Bill Booth of the Mississippi Public Service Commission asked if Brattle did its own analysis of MISO’s CONE value. Newell said his firm did not test the accuracy of MISO’s net CONE. But even if MISO does revise its CONE values, Newell said, results wouldn’t be affected much, as Brattle’s higher, 1.4-times CONE cap “mitigates reliability risk of administrative error in estimating net CONE.”
“This aspect is exactly the same as the one we went through for PJM and New England. This aspect of it is very established ground,” Newell said.
Newell said the bigger issue is whether Brattle’s assumptions regarding cap and foot values and utilities’ ownership is correct. Brattle analyst David Oates said a lot of the modeling, including the Monte Carlo-style analysis, is similar to what was done in PJM and ISO-NE.
Brattle maintained the omission of MISO South was inconsequential, saying the 876 MW available for imports from the South is covered in varying megawatt amounts that utilities offer in the Monte Carlo analysis.
The company also modeled capacity import limits but not export limits and assumed utilities have a preference to build their own capacity instead of purchasing it from other utilities.
Zone 2 in Wisconsin and Michigan, which holds a small amount of participating demand, was initially included in the analysis, but Brattle found that it didn’t meet MISO’s materiality threshold.
In response to a question from Madison Gas and Electric’s Megan Wisersky, Newell said Zone 2 was initially included because it contains some competitive load. But MISO’s Mike Robinson said the inclusion was a relic of the RTO’s earlier work with Brattle and could be omitted altogether.
“It would be nice not to see that ever,” Wisersky joked.
The long saga of the Duke Energy coal ash spill that coated the Dan River with up to 39 million tons of toxic coal ash from a retired coal-fired plant in February 2014 came to an end Friday when the company agreed to pay a $6 million fine to the North Carolina Department of Environmental Quality. The company already settled federal pollution violations with a $102 million settlement in 2015.
The state first fined the company a $6.8 million civil penalty, which Duke called “entirely arbitrary and capricious.” The company did not say why it was now agreeing to a fine that is only slightly lower than the original, as it agreed with the DEQ not to make any public statements that were not mutually cleared.
The two sides did say that it is “in the best interest of the parties, the environment and the citizens of North Carolina that they enter into a compromise to avoid the time and expense of prolonged litigation.”
FERC granted American Electric Power’s request that its AEP Texas North and AEP Texas Central affiliates be combined into a single organization. The companies will operate under the name AEP Texas, with AEP Utilities, an AEP subsidiary, as its direct parent.
The commission dismissed the Oklahoma Municipal Power Authority’s request that it not address FERC’s jurisdiction over AEP Texas’ wholesale transmission service, finding “no evidence that either state or federal regulation will be impaired.”
AEP told the commission it expects the organizational changes to take place by year-end.
FERC on Friday approved ITC Holdings’ acquisition by Canadian utility operator Fortis and a Singapore-based investment fund. ITC, the largest independent transmission operator in the U.S., agreed to the $11.3 billion sale in February. (See Fortis to Acquire ITC Holdings for $11.3B.)
Fortis, which owns New York’s Central Hudson Gas and Electric and Tucson Gas & Electric, is purchasing most of ITC. GIC Ventures, an affiliate of an investment company that manages the government of Singapore’s foreign reserves, is purchasing the remaining 19.9%. ITC will remain a standalone transmission company.
FERC said the transaction raised no competitive concerns because ITC does not control any generating assets, and neither Fortis nor GIC own generation or natural gas assets in MISO, home to much of ITC’s transmission network. The deal, which the companies expect to close by the end of the year, had already been approved by state regulators in Wisconsin and Missouri.
Construction of NextEra Energy’s 87-turbine Brady Wind I project is 65% complete and concrete is being poured for the foundations of Brady Wind II, a nearby 72-turbine wind farm, according to the company.
Both projects are slated for completion by the end of the year. An 18.2-mile transmission line that will transmit the power to Basin Electric Power Cooperative, which signed a power purchase agreement with NextEra, will be completed in a few weeks.
PG&E last week announced the election of Eric Mullins to its board of directors and to the board of its Pacific Gas and Electric subsidiary.
Mullins is the managing director and co-CEO of Lime Rock Resources, a private equity fund specializing in the acquisition and operation of oil and natural gas properties. Before cofounding Lime Rock, Mullins worked for 15 years in the investment banking division of Goldman Sachs, where he served as managing director in the company’s energy and power group.
“As we position PG&E for continued long-term success, we welcome Eric’s expert counsel around our strategy and audit functions,” PG&E CEO Tony Earley said. “Eric’s deep financial background and familiarity with the energy sector will be invaluable assets for us.”
Alliant Energy has started construction of a 700-MW natural gas-fired generating station near Beloit, Wis., that will combine the power plant with an adjacent solar farm in the largest paired generation station of its type in the state.
The company’s Riverside Energy Center is already home to one solar farm. The $700 million project includes a second solar installation designed to offset power used by the new gas-fired plant, company officials said. When the second solar farm is completed, there will be 8,000 panels generating solar power.
The gas-fired plant is scheduled to be in service by 2020.
Xcel Announces Expansion of Wind Energy in Midwest
Xcel Energy says it is planning to invest $2 billion to build eight to 10 wind farms in Minnesota, the Dakotas, Wisconsin and Michigan, with an eye toward generating about 1,500 MW of electricity.
The company said it will own and operate some of the proposed wind facilities and enter into power purchase agreements with the operators of others.
“We believe this is one of the largest wind acquisitions in the country,” said Chris Clark, president of Xcel’s Upper Midwest Operations. He said the wind farms should come online between 2017 and 2020. Xcel is looking to renewable energy — primarily wind — to offset its planned retreat from coal-fired generation.
Dynegy was chosen as one of the winners of the Illinois Power Agency’s MISO Zone 4 capacity procurement auction for 2017/2018 and 2018/2019.
The company’s share of the auction was not announced, but the weighted average price was $143.20 and $137.25/MW-day, respectively. The total capacity from winning bidders was for 1389 MW for the first period and 465 MW for 2018/2019.
Construction of NextEra Energy’s 87-turbine Brady Wind I project is 65% complete and concrete is being poured for the foundations of Brady Wind II, a nearby 72-turbine wind farm, according to the company.