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.
SANTA MONICA, Calif. — Attendees at last week’s Infocast California Distributed Energy Summit received a crash course in the complexity of developing policies on distributed energy resources in a state that already boasts nearly 5,000 MW of rooftop solar.
The takeaway: Conflicting regulatory drivers and misaligned utility business models must be addressed to ensure the value of DERs is maximized and that consumers aren’t saddled with the costs of stranded assets.
Moderating a panel on regulatory issues, Brandon Smithwood, California state affairs manager at the Solar Energy Industries Association (SEIA), let panelists weigh in on the “alphabet soup” of agency proceedings intended to foster the integration of DER.
“To us, DER is anything that’s connected to the distribution level,” said Tom Flynn, storage and DER policy manager at CAISO. “Any resource of any type, any technology. It doesn’t matter to us whether it’s in front of the meter, behind the meter — but it’s connected to the distribution grid, connected to the grid below the ISO’s grid.”
A few years ago, DER advocates expressed interest in aggregating those resources to participate in CAISO’s wholesale market, which requires participating resources to be at least a half-megawatt in capacity, Flynn said.
In response, the ISO allowed DERs to aggregate as a “virtual resource” distributed across multiple pricing nodes within the ISO’s system. That program, known by the acronym DERP — or Distributed Energy Resources Provider — was approved by FERC in June (ER16-1085). (See CAISO Tariff Change Would Extend Market to DER.)
Since then, the ISO has started another initiative called Energy Storage and DER — or ESDER. Among other things, that effort would allow developers to use storage to offset load behind the meter. Unlike other DERs such as rooftop solar, that storage could then bid demand response into the wholesale market.
Storage, “in effect, creates one of the first multiple-use applications,” Flynn said, noting that it can simultaneously participate as a supply- and demand-side resource.
Flynn noted that the California Public Utilities Commission has initiated a proceeding that explores similar issues, such as multiple-use applications; the ability to provide services to multiple entities; station power for storage; and interconnection processes and metering rules for DERs participating in wholesale markets.
Will Speer, director of electric system planning at San Diego Gas and Electric, tossed a few more letters into the regulatory alphabet soup, bringing up the CPUC’s Integrated Resources Plan and Distributed Resources Plan.
The goal of the DRP is to determine the ability of a utility’s distribution system to accommodate DER, Speer said.
“The first requirement was to complete an integration capacity analysis,” he said. “The next big piece of this is a locational net benefits analysis. It’s really looking at — for the locations of feeders — what is the locational net benefit of DERs in those spaces?”
Another component of the plan: demonstration projects to examine the locational benefits of DER and the use of microgrids.
Jim Baak, director of grid integration at nonprofit policy advocacy group Vote Solar, said the number of acronyms indicates the complexity of the regulatory landscape.
“In typical public utility code fashion … we’re very good at parsing issues into siloed proceedings and programs,” Baak said.
To provide a sense of the complexity, Baak listed the topics being treated under separate and overlapping proceedings: electric vehicles, DR, energy efficiency, interconnection rules, the renewable portfolio standard, time-of-use rates, net energy metering, general rate cases, integrated resources planning and energy storage.
That creates a lot of “conflicting drivers” for DER, Baak said.
One of those drivers is the traditional utility planning process, which focuses on loads, resources and forecasting.
Another driver is state policy objectives, which seek to reduce GHG emissions, support jobs and enhance customer choice in energy supply.
And then there’s yet another layer: customer demand and the market forces responding to it.
Although the industry recognizes consumer demand in terms of forecasting and deployment of DER, the planning process is not fully factoring in long-term changes in consumer behavior, Baak contended.
New industry entrants such as Google, Microsoft, General Electric and ADP are seeking to provide services to consumers about how they “consume, produce and think about energy,” Baak noted, asking how that development fits with the traditional utility planning structure and business model.
“If you think about it for a while … there’s not a real good fit,” he said. “We’re sort of trying to overlay this existing infrastructure that we have in the regulatory process with market forces that are happening.”
DER is comparable with the “disruptive” technologies and processes that gave rise to businesses like Uber and Airbnb, and something that can’t be forced into traditional utility structures, Baak said.
“And the one piece that I feel is missing in California is the vision for this,” he said.
Baak acknowledged that the technical proceedings seeking to identify ideal locations for implementing distributed resources are necessary for maintaining reliability. But he also wondered how well equipped they are for meeting state policy objectives and consumer needs.
“What happens when a customer wants to put in an electrical vehicle or solar system in an area of the grid where there are not necessarily grid benefits for doing so?” Baak asked.
And Baak pointed to the elephant in the room: the need to reform the utility business model, an effort that requires regulatory input and oversight.
“We do need to recognize that there’s a misalignment between the utility’s financial objectives and the policy objectives that we have here for DER,” Baak said. Utilities are being asked to defer investment in infrastructure on which they could earn a rate of return for shareholders and instead procure third-party DERs.
In May, New York regulators approved an order revamping their utility business model, creating new revenue streams tied to utilities’ willingness to become “distribution system platform providers” that plan, operate and administer markets for distribution-level services. The order creates incentives based on how well utilities meet goals for GHG reductions, system efficiency and energy efficiency. Customer satisfaction surveys of DER providers also will be a factor. (See NY REV Order Revamps Utility Business Model.)
California has put no such mandate in place, just a set of incentives and “a vague idea of where we think this should go,” Baak said.
“We have to make sure the utilities are structured in a way, and financially awarded in a way, that they support the policy goals of the state as well as the market forces that are driving this,” Baak said.
Speer concurred with Baak up to a point, contending that the state’s support of DER is focused on a goal.
“It’s not just to promote DER to promote DER, it’s to achieve reductions in GHGs,” Speer said. “I do think that vision’s out there, but there is a lot of work to be done.”
“I get a sense in everywhere that we go that we want it to happen today,” Speer continued, adding that customers will suffer without proper planning.
Baak said Vote Solar feels “a sense of urgency,” both because of the state’s climate goals and an anticipated increase in consumer demand for DER as prices decline.
CAISO’s Flynn acknowledged that “evolving customer preferences” — and not just public policies — are driving the adoption of DER.
DER owners’ desire to maximize their investments led the ISO to begin developing ways for DERs to access its wholesale markets.
The ISO is starting to see DER as a more significant supply resource, something that can both offset and serve more load.
Keeping Distribution in the Loop
But with that trend comes increased effects on the utility distribution system, which “are going to more and more affect the transmission system — and vice versa,” Flynn said.
Distribution utilities are developing the capabilities to manage those effects, but increased participation by DER in wholesale markets will require improved data transfers between CAISO and utilities, he said.
Flynn pointed out that an ISO dispatch order to a DER market participant — which puts power on the distribution grid hosting the resource — leaves the distribution utility “completely out of the loop in terms of information.”
“They don’t know what that DER is offering to provide us in the wholesale market,” Flynn said. “They don’t know that we’ve issued a dispatch instruction to them.”
That has alerted CAISO to a “major gap” in its processes: the need to improve data exchange with utilities — something just as important to the ISO, which needs to ensure a predictable response by a DER.
“I think everyone’s goal here is to optimize the use of DER,” Flynn said. “We don’t want to leave value on the table.”
Baak brought the consideration of that value into the context of the regulatory process, noting that Southern California Edison has submitted a rate case proposing more than $2 billion in distribution grid investment to facilitate increased deployment of DER.
While Baak acknowledged the need to modernize the grid, he contended that some of that investment could be displaced by using DERs more cost-effectively.
His organization is concerned that without a utility business model reformed to accommodate DER, regulators will sanction unnecessary investment in utility infrastructure that will remain as a fixed cost in the rate base for 20 years. As the growth of DER allows more customers to supply their own energy, the utility rate base will decline.
“Well, what happens to that fixed-cost recovery?” Baak asked. “Now you’re exacerbating the problem of fixed-cost recovery over a diminishing rate base. What happens to rates?”
Those issues will have to be resolved in a way that supports the state’s energy and environmental goals, Baak contended.
“We’re concerned that, because these proceedings are moving forward independently without that vision, we’re going to end up with a solution in the end that’s less cost-effective for consumers.”
The Nuclear Regulatory Commission wants to know more about NextEra Energy’s plans to respond to the degradation of concrete at its Seabrook nuclear generating station in New Hampshire. An alkali-silica chemical reaction is causing the plant’s concrete walls to break down.
NextEra’s amended license proposal did not contain sufficient details on how it would address the issue, according to a NRC spokesman. The company has until Oct. 3 to provide more details on how it is going to stop, or counter, the chemical reaction. NextEra is seeking a 20-year extension to the plant’s operating license, which is currently set to expire in 2030.
The commission has not deemed the degradation a safety issue, but it wants to know how the company is going to tackle long-term preventative measures.
The Tax Court has ordered Exelon to pay as much as $1.45 billion in back federal taxes, penalties and interest.
The bill resulted from a tax strategy that Commonwealth Edison used after its $4.8 billion sale of coal-fired power plants in 1999. To shield itself from the potential tax bill, ComEd sunk much of the proceeds in long-term leases of power plants in other parts of the country and leased the plants back to the owner-operators.
Exelon must now decide whether it wants to pay or appeal. Even if it to decides to appeal, it still must pay the Internal Revenue Service or post a bond, the company said in a Securities and Exchange Commission filing. “Exelon is still evaluating the Tax Court’s decision and considering next steps,” the company said.
A coalition of environmental groups asked the D.C. Circuit Court of Appeals last week to stay construction of Spectra Energy’s Algonquin Incremental Market natural gas pipeline project while its appeal of FERC’s approval is pending. The pipeline project is designed to transport natural gas from shale-gas fields in the Mid-Atlantic region to markets in the Northeast and Canada.
The groups noted that the court reprimanded FERC for approving a similar project in 2014, but that by the time it had reached its decision, construction was almost complete.
An offshore wind developer has begun surveys off the Massachusetts coast, where it leases about 160,000 acres from the Bureau of Ocean Energy Management.
OffshoreMW is conducting the work south of Martha’s Vineyard in preparation for the possible construction of offshore wind facilities in the area. Seafloor and sub-seafloor surveys will be taken by the crew of the Shearwater research vessel. The company was the successful bidder for the lease area in 2015.
The Idaho National Laboratory has developed a ballistic barrier system designed to protect substations against threats such as bullets, explosives and tornadoes.
The lab started working on the patent-pending Transformer Protection Barrier after a substation in California was targeted by a marksman who fired up to 150 rounds at it, causing an estimated $15 million damage to 17 transformers.
“We are trying to be proactive and provide solutions to threats when they emerge,” said Chad Landon, head of INL’s Defense Systems Materials Technology and Physical Analysis department. “Based on the 2013 incident and similar situations, we decided to come up with a solution.”
FERC is considering changes to its Electric Quarterly Report (EQR) rules, including requiring data on ancillary services transactions and changes to how financially settled trades are reported.
In its Sept. 22 notice of the proposed changes, the commission said it will accept comments on the proposals for 60 days following their publication in the Federal Register (RM01-8, RM10-12, RM12-3 and ER02-2001).
Ancillary Services
Transmission providers currently report ancillary services such as reactive supply and regulation in the EQR’s Contract Data section. FERC is proposing that transmission providers also report information about transactions made under their ancillary services agreements in the EQR’s Transaction Data section.
FERC said the information will “help the commission, the public and the industry determine the actual rates being charged for service under these agreements [and] increase price transparency into the wholesale ancillary services markets.”
Booked Out Transactions
The commission also is seeking to clarify the reporting of “booked out” trades — those settled financially without any transmission of power.
FERC said EQR submissions relating to book outs frequently contain inconsistent or inaccurate information, making it difficult to determine how much power is being traded compared to how much is actually being delivered.
“We find that, based on the current EQR database configuration, it is not possible to differentiate book outs of energy or capacity because EQR filers do not have the option to distinguish between the two products,” FERC wrote.
To create a distinction, FERC proposed amending its data dictionary to replace “booked out power” with the product names “booked out energy” and “booked out capacity.”
FERC also seeks to clarify that booked out transactions must be reported in the EQR regardless of the number of parties involved. The notice provides examples of how booked out transactions should be reported when:
two companies sell physical energy to each other for the same delivery period;
one company sells energy to another company and, in real time, the company buying the energy signals the seller to reduce the amount of energy it is providing; and
at least three companies are in a chain of energy sales and one company appears twice in that chain.
Tariffs and Time Zones
FERC also proposed that filers submit into the EQR’s tariff reference fields tariff-related information that they currently submit in the e-Tariff system and that they include time zone information for transmission capacity reassignment transactions.
NextEra’s amended license proposal did not contain sufficient details on how it would address the issue, according to a NRC spokesman. The company has until Oct. 3 to provide more details on how it is going to stop, or counter, the chemical reaction. NextEra is seeking a 20-year extension to the plant’s operating license, which is currently set to expire in 2030.
The Tax Court has ordered Exelon to pay as much as $1.45 billion in back federal taxes, penalties and interest.
A coalition of environmental groups asked the D.C. Circuit Court of Appeals last week to stay construction of Spectra Energy’s Algonquin Incremental Market natural gas pipeline project while its appeal of FERC’s approval is pending. The pipeline project is designed to transport natural gas from shale-gas fields in the Mid-Atlantic region to markets in the Northeast and Canada.
The Idaho National Laboratory has developed a ballistic barrier system designed to protect substations against threats such as bullets, explosives and tornadoes.