FERC last week denied a request to reconsider its decision to revoke the license for a small Michigan hydroelectric project over significant safety concerns.
The commission also rejected Boyce Hydro’s motion to transfer the license for its 4.8-MW Edenville Dam to another operator, Wolverine Hydro, calling the request moot in light of the revocation (P–10808).
FERC ordered Edenville closed in February 2018, then revoked the dam’s license the following month after finding it had insufficient spillway capacity and that Boyce had a longstanding history of noncompliance with other safety measures. The commission denied Boyce’s request for rehearing on the closure early this year. (See Closed Michigan Dam Loses Rehearing Bid.)
Edenville Dam spillway
In the order issued Thursday, FERC said it only entertains motions for reconsideration when a party can assert the commission “may have erred by overlooking or misunderstanding facts or arguments set forth in the party’s rehearing request.” Boyce didn’t pose that argument in its request for rehearing over the license, and its other arguments were “unconvincing,” the commission wrote.
“Here, Boyce Hydro does not claim that the commission misunderstood or misinterpreted its prior arguments. Thus, its pleading is not a proper request for reconsideration and we will not consider it as such. … To the extent that Boyce Hydro seeks to introduce new facts and arguments into the record, it is making an untimely, collateral attack on the now final revocation order.”
FERC made clear that revocation of the license was not up for negotiation and that Boyce’s only recourse now is to seek a new license.
“In any event, we have no ability to grant the relief that Boyce Hydro seeks. We have revoked the license for the Edenville Project, in orders that are now final. Accordingly, we currently have no jurisdiction over the Edenville project works. Should Boyce Hydro or any other entity wish to operate the project to generate electricity, they would need to seek a license to do so,” FERC said.
And because it could not reinstate the Edenville license, FERC said it also could not grant the request to transfer the license to Wolverine.
Boyce had claimed that it could secure a new power purchase agreement with Consumers Energy at a higher rate that would have allowed it to obtain a loan to “fund construction of auxiliary spillway capacity sufficient to pass the entire [probable maximum flood]” requirement, then pass the license to Wolverine.
But FERC said Boyce brought no “firm proof” that such a situation will play out.
FERC last week rejected separate rehearing requests from both sides in a dispute between the Louisiana Public Service Commission and System Energy Resources Inc. (SERI) over the return on equity rate for the company’s Grand Gulf Nuclear Station (EL18-142).
Entergy subsidiary SERI’s rehearing request centered on the question of whether FERC could legally probe the Grand Gulf ROE in two separate proceedings and set two separate 15-month refund periods.
FERC last August set to settlement procedures the Louisiana PSC’s complaint that the ROE in the unit power sales agreement (UPSA) formula rate for calculating the Grand Gulf costs billed to Entergy’s operating companies is unjust and unreasonable. The Louisiana regulator contested SERI’s capital structure and the depreciation rates included in the ROE. (See FERC Sets La. Entergy Complaint for Settlement.)
Grand Gulf Nuclear Station | Entergy
SERI owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy’s Arkansas, Mississippi, Louisiana and New Orleans subsidiaries under the UPSA.
Regulators in Arkansas and Mississippi also claimed in 2017 that the 10.94% ROE used by SERI in its formula rate for energy sales from Grand Gulf is outdated and overcharges customers (EL17-41). (See FERC Opens Proceeding over Entergy Nuclear Power Sales.)
FERC put both complaints to settlement proceedings in order to reset SERI’s ROE, equity ratio and depreciation rates to just and reasonable levels. Because of the complaints’ similarities, the commission eventually consolidated them into one settlement process.
But SERI contended that FERC was in breach of the Federal Power Act because it set a second refund date for the Louisiana complaint, saying the law “precludes refunds for more than a 15-month period absent dilatory behavior on the part of the utility.”
The commission pointed out that it has yet to make any final determinations in the case and could dismiss a request for rehearing on that detail alone.
But it offered a deeper explanation for its denial of the premature challenge, saying “even if we were to consider SERI’s request for rehearing on the merits, we would deny it.”
The commission said it was not circumventing the 15-month refund period requirement because the two complaints were filed separately and, as such, the limitation applies separately to each complaint.
It also noted it is free to investigate the same ROE in two different proceedings and that SERI was incorrect in its assumption that the commission should have dismissed the Louisiana PSC complaint because it didn’t contain “new claims or changed circumstances sufficient to justify an additional proceeding.”
Instead, FERC pointed out, the two complaints are based on financial data from different time periods, and as such, are based on different factual records. According to the Louisiana PSC, the 2017 docket did not reflect more recent discounted cash flow data now available.
“Although the two complaint proceedings have been consolidated for purposes of hearing and settlement judge procedures, the commission may or may not reach the same conclusions regarding SERI’s ROE with respect to each complaint,” FERC said.
It also noted it has “previously allowed successive complaints when presented with new analysis.”
In the same order, FERC also denied the Louisiana PSC’s request to rehear the federal commission’s dismissal of the PSC’s complaint regarding SERI’s use of its own capital structure — rather than that of its parent Entergy — for setting the ROE for Grand Gulf to put the issue to settlement proceedings.
The PSC had conceded that its original complaint failed to apply FERC’s three-part test for determining the independence of an affiliate’s capital structure from that of its parent or to show that the test was inapplicable in SERI’s case. But it argued that its amended complaint was sufficient to support SERI’s adoption of Entergy’s capital structure or a structure appropriate for a utility with low risk.
In response, FERC pointed out the PSC admitted the commission did not err in its August 2018 order.
“There is thus no basis upon which to grant rehearing,” FERC wrote. “Moreover, the commission has already issued an order in response to the Louisiana commission’s amended complaint, establishing additional hearing and settlement judge procedures. We decline to address that matter further here.”
NERC CEO Jim Robb returned to his former workplace at the Western Electricity Coordinating Council last week for the first time since he took the nation’s top reliability job 15 months ago.
NERC CEO Jim Robb addresses the WECC board for the first time since he left the regional entity about 15 months ago. | WECC
His four years in Salt Lake City have proven useful in Atlanta and D.C., Robb told the WECC Board of Directors at its quarterly meeting. Many of the reliability challenges facing the U.S., including the shift to renewable energy and a major reliability coordinator transition, are centered in the Western Interconnection, which WECC oversees.
“The good news and the bad news, depending on how you feel about living in interesting times, is that almost all of these [challenges] have some amount of epicenter here in the West,” Robb said. “My training and experience here have served me very well in my new role on the Eastern seaboard.” (See New NERC Chief Not ‘Smartest Guy in the Room’.)
The RC transition that starts July 1, when CAISO takes over the role from Peak Reliability in CAISO’s California service territory, is a big concern for those whose job is to make sure the lights stay on, he said.
“The RC transition here in the West … I’ve described that as the single biggest reliability risk in the country over the next 18 months,” Robb said.
Robb’s replacement at WECC, Melanie Frye, listens intently to his presentation with other board members. | WECC
The new RCs taking over from Peak include CAISO’s RC West, SPP, BC Hydro and Gridforce. The transitions are planned on a staggered schedule through December. (See New RCs Tell WECC Transition on Schedule.)
Robb recognized the “tremendous amount of work going on” within those entities and at WECC to ensure a smooth handover, but he said people shouldn’t let their guard down. The new RCs “have to work together as seamlessly as one RC given the way the region is structured here,” he said. “That needs to continue to be a laser focus.”
Communications between multiple RCs in the Eastern Interconnection haven’t always met the “level of seamlessness and transparency” required, Robb said. In the West, lax performance would have even more of an impact on reliability, he said. (See RC Transition Fraught with Pitfalls, WECC Hears.)
Another major challenge is the pace of change in the mix of Western resources, he said. Traditional coal and nuclear baseload generation is being replaced by variable resources, such as wind and solar, with natural gas plants serving as backstops.
The switchover is “changing how we think about serving load,” Robb said.
Consolidated Edison’s Anthony Natale has summarized what he’s learned about substation fires over two decades in several bullet points. But the biggest lesson, he says, is one of humility.
“These are low-frequency, high-hazard events. We don’t do them often enough to get good at them,” he said Wednesday during a NERC lessons-learned webinar.
That’s all the more reason, he said, for setting up a framework for responding to fires. It starts with identifying appropriate response techniques; memorializing the techniques into a policy; and then using the policy as a platform for training — training that includes the fire department.
“You cannot meet the fire department for the first time at the command post,” he said.
Firefighters arrived before utility workers at this 2010 transformer fire in Denver, making matters worse by using water that may have spread burning transformer oil.
Natale joined representatives from Georgia Power, Florida Power & Light and the Midwest Reliability Organization for the webinar, which was hosted by Richard Hackman, NERC’s senior event analysis adviser for reliability risk management.
Hackman noted that although some utility substations are enclosed, most are outdoors, and many are in rural areas with volunteer fire departments with limited resources.
“We’re trying to help get that addressed by … getting these lessons learned out and getting the discussion going,” Hackman said. The webinar recording and slides are available for utilities to present to their fire departments.
Although the presentation included specific lessons from individual fires, Hackman said the “generic [lessons] are the most valuable.”
“The primary one is before any substation fire occurs, we need to have a working relationship between the electric utility and the fire department. [The utility needs] to describe the hazards in the substation to the fire department. The fire department needs to be able to explain their needs to the electric utilities.”
Because not all fire departments have foam, Georgia Power has equipped small trailers with 5-gallon containers of foam concentrate and an oil spill response kit that it can deploy to fires. | Georgia Power
“Basically, everything in a substation is a hazard,” said Michael Bocovich, principal systems protection engineer for MRO, citing energized equipment, PCBs, toxins from burning plastics and metals, and porcelain that is extremely sharp when broken. Ground rods can be trip hazards, and “anything that’s in the air is a hazard for falling: bus section switches, insulators, conductors,” he continued.
“Some other hazards you may not think of also can include angered animals. I know racoons have been the source of many substation faults. They’re tough, mean animals. They can survive a fault, and they’re not very happy after that happens. I’ve also heard reports of bears in substations.”
Because of the hazards, utilities must train firefighters not to enter a substation without a utility escort, who can ensure equipment has been de-energized.
“You have to establish a policy up front because they’re going to employ their everyday tactics,” Natale said. “They’re going to get in and they’re going to search.”
Con Edison posted these signs outside every point of access to its substations to remind firefighters not to enter without a utility worker escort. | Con Edison
To prevent that, Con Ed has posted signs outside its substations with the logos of both the utility and the New York Fire Department. “That sign is essentially a stop sign, and this is what keeps them from forcing entry,” Natale explained.
Bocovich described a 2010 transformer fire at a Denver substation that was captured on video. The substation was next door to the firehouse, so firefighters arrived immediately and began spraying water on the blaze before utility personnel arrived.
That was not a good idea. NERC says water should never be used on a transformer fire. It will sink below the transformer oil that is heated above the boiling temperature of water, causing a “boil over.”
“Water may have allowed burning oil to spread to other equipment,” Bocovich said. “There was another transformer on site that was destroyed by this fire also.”
Foam is the preferred firefighting technique for transformer fires and their oil. Because not all fire departments have foam, Georgia Power’s Scott Cox said, his utility has equipped small trailers with containers of foam concentrate and an oil spill response kit that it can deploy to fires.
“No water,” Natale emphasized. “You don’t want to sustain a boil-over because you’ll end up burning down the entire substation. Water is fine to use if you’re going to protect exposures. But you’re not knocking down a transformer fire with it.”
FERC on Thursday expanded NERC’s cyber incident reporting requirements, closing what it said was a gap in the critical infrastructure protection (CIP) reliability standards.
The new standard, CIP-008-6 (Cyber Security – Incident Reporting and Response Planning), revises the definitions of “cybersecurity incident” and “reportable cybersecurity incident.”
Simon Slobodnik, of the Office of Electric Reliability, and Leigh Anne Faugust, of the Office of General Counsel, gave a presentation on the revised CIP reliability standard.
It requires reporting of incidents — now classified as “cybersecurity incidents” — that compromise, or attempt to compromise, electronic security perimeters (ESP), electronic access control or monitoring systems (EACMS) or physical security perimeters associated with high- and medium-impact bulk electric system (BES) cyber systems and attempts to disrupt operation of a BES cyber system (RD19-3).
A “reportable cybersecurity incident” refers to an action that actually compromises or disrupts one or more reliability tasks on the BES.
The new standard is a response to a July 2018 FERC ruling in which the commission criticized the existing reporting threshold, which only required reporting cyber incidents that have “compromised or disrupted one or more reliability tasks.” Noting that NERC did not identify any reportable incidents in 2015 and 2016, FERC said the threshold understated the risks and could lead to bigger, more successful attacks. (See FERC Orders Expanded Cybersecurity Reporting.)
The new rule would require, for example, reporting on malware installed on a BES cyber system that performs one or more reliability tasks even if the system still operates.
The rule will apply to EACMS that perform authentication; monitoring and logging; access control; interactive remote access; and alerting.
It also specifies the minimum information that must be reported: the functional impact that the incident achieved or attempted to achieve, the attack vector used and the achieved or attempted level of intrusion.
The reports will be sent to the Electricity Information Sharing and Analysis Center (E-ISAC) and the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT).
Initial reports must be made within one hour of the responsible entity’s determination of a “reportable cybersecurity incident” and by the end of the next calendar day after determination of an attempt to compromise a BES cyber system, an ESP or an EACMS — or a “cybersecurity incident.”
FERC Chair Neil Chatterjee praised NERC’s speed in revising the standard and noted that no comments were filed in opposition.
Commissioner Cheryl LaFleur said the increased requirements will allow entities to learn from near misses and help the commission “identify emerging issues where we may need to enhance” standards.
“There is a well-documented statistical relationship — documented first as a safety pyramid in the industrial safety area, but applied to reliability in all kinds of industrial systems — between near misses and actual events. So, it’s very important that we learn from experience,” she said. “The expanded reporting will promote a culture of attention to cybersecurity, including all the details that make a network secure.”
Commissioner Cheryl LaFleur
Commissioner Bernard McNamee said cybersecurity “is so important that it has yet to be politicized in this town.”
“[It] is clear that everybody realizes that there are real threats out there [and] that industry and government … need to work together, and that constant vigilance is important to ensuring the security of our grid,” he said.
FERC estimated that 288 of the 1,414 unique NERC registered entities as of May 24, 2019, will be affected by the increased reporting requirements.
Single Points of Failure
The commission also issued a Notice of Proposed Rulemaking to adopt reliability standard TPL-001-5 (Transmission System Planning Performance Requirements), NERC’s proposal for addressing single points of failure of protection systems. It also responds to the commission’s directives on planned maintenance outages and stability analyses for spare equipment (RM19-10).
But the NOPR also would direct NERC to modify the standard to require corrective action plans for protection system single points of failure in combination with a three-phase fault if planning studies indicate the potential for cascading outages.
NERC’s proposal would require planning authorities and transmission planners to perform annual planning assessments considering a variety of system conditions and contingencies. For scenarios considered likely, known as “planning events,” the planning entity must develop a corrective action plan if it determines its system would experience performance issues. For scenarios considered to be less likely that could result in severe impacts such as cascading outages (“extreme events”), the planning entity must conduct an analysis to understand the potential impacts and identify potential mitigation measures.
Commissioner Bernard McNamee
FERC said the proposed standard will require more comprehensive study of the potential impacts of protection system single points of failure — nonredundant components of a protection system whose failure would affect normal clearing of faults.
“In particular, the modifications reflected in proposed reliability standard TPL-001-5 address the commission’s concern that the exclusion of known outages of less than six months in currently effective reliability standard TPL-001-4 could result in outages of significant facilities not being studied,” the commission said.
Not Extreme?
But the commission disagreed with NERC’s categorization of protection system single points of failure in combination with a three-phase fault as an “extreme event” that only requires study and not a corrective action plan. The NOPR would direct NERC to modify the standard to require corrective action plans for such events if planning studies indicate the potential for cascading.
NERC told FERC that its review of more than 12,000 protection system misoperations since 2011 showed that only 28 involved three-phase faults (10 breakers that failed to operate and 18 breakers that were slow to operate). NERC said none of the 10 failure-to-trip scenarios resulted in events that required reporting.
FERC, however, said the 10 incidents average to about one event every eight months. “Although we recognize that three-phase faults constitute a relatively small subset of all protection system operations, under the following measure of one protection system single point of failure every eight months, the occurrence of three-phase faults with misoperations could reasonably be viewed as regular occurrences.
“Based on the present record, it is unclear whether such contingencies are as rare as NERC maintains,” FERC continued. It cited a 2009 NERC Industry Advisory on three system disturbances over five years that were initiated by a protection system single point of failure in combination with a single-line-to-ground fault. “According to the Industry Advisory and supporting documentation, all three events evolved into either a multiphase fault or a three-phase fault with cascading,” FERC said.
It also cited a 2012 informational filing in which NERC “reported that it is not uncommon for a single-line-to-ground fault to evolve into a multiphase fault and … stated that studies solely on single-line-to-ground faults may understate the reliability risk of single points of failure of protection systems.”
The commission said the first draft of proposed standard TPL-001-5 included a requirement would have addressed protection system single points of failure in combination with a three-phase fault, but that the proposal was dropped because the team said, “industry comments . . . were particularly negative.”
The order noted a disagreement over whether mitigation measures addressing the issue could be costly.
“While we are aware of the potential for increased cost under this proposal, we understand that there are likely cost-effective actions. … For example, a corrective action plan … could add a redundant lockout relay in the control circuitry of a protection system, which would eliminate occurrence of those events reported in the 2009 NERC Industry Advisory. As another option, an entity could add control center monitoring and reporting functions to a DC battery bank or to a communication system of a communication-aided protection scheme so that system operators are aware of their failure.”
The commission asked for comments on the issue. Comments will be due 60 days after publication in the Federal Register.
FOLSOM, Calif. — A carbon workshop hosted by the Western Energy Imbalance Market’s Regional Issues Forum on Tuesday underscored how West Coast and Intermountain states can be uneasy partners in CAISO’s real-time energy market.
California has a well-established cap-and-trade program. Oregon is poised to adopt one.
Washington voters rejected a carbon fee bill last year, but the state has pursued aggressive carbon-reduction policies much like California’s, including a 100% clean-energy mandate. (See Western States to Tackle Wildfires, Renewables, EIM Told.)
Some states between the Sierra Nevada and Rocky Mountains, however, have no official carbon policies and continue to burn coal as a significant power source.
Carl Zichella, Western transmission director for the Natural Resources Defense Council, said the EIM has consistently proven its economic benefits since it started in 2014. Its diverse members — eight participants across eight Western states — are “like dogs and cats lying down together,” he said, referring to the fact that investor- and publicly-owned utilities with different business models are working together to capture the benefits of a regional market under the EIM’s framework.
But notable regional differences emerged during a daylong discussion of how to reconcile disparate carbon policies in a centralized energy market such as the EIM. CAISO’s largest meeting room was unusually crowded for the event.
While Californians worried about accounting for carbon leakage in interstate transfers, representatives of Mountain states urged their coastal counterparts to keep politics out of a market that so far has produced more than $650 million in benefits for its voluntary participants.
“I think that adding policy into an economic universe, when you’re bringing in more and more states with diverse policy interests, makes the system more fragile,” said Idaho Public Utilities Commissioner Kristine Raper, a frequent critic of California trying to export its environmental policies to other parts of the West. (See Overheard at Transmission Summit West.)
She said adding politics into the EIM was like stretching a rubber band thinner and thinner until it’s at the snapping point.
“The EIM is clearly an economic benefit to its customers,” but the more policy that is added on, the “more tenuous it gets,” she said.
Utah Public Service Commissioner Jordan White said he thought trying to incorporate carbon policy into the market runs the risk of undermining its ability to optimize energy use among states with and without carbon-reduction goals.
“I hope we don’t erode the efficiency we’ve achieved so far,” he said.
Neither Utah nor Idaho have cap-and-trade or carbon-reduction programs. Some Mountain states are becoming more progressive, however. New Mexico recently joined the growing list of states, including California and Nevada, to adopt goals of relying on 100% clean energy by midcentury. (See Washington, Nevada Join 100% Clean Energy Movement.)
Sarah Cottrell Propst, New Mexico’s secretary of energy, minerals and natural resources, said that under Democratic Gov. Michelle Lujan Grisham, the state is pursuing environmental policies like those farther west. They include providing financial support to utilities that close coal plants and reducing methane emissions from natural gas and oil production.
Public Service Company of New Mexico, the state’s largest utility, has committed to achieving the state’s 100% clean-energy mandate five years ahead of schedule, in 2040, she said. The state’s ample wind and solar production, which exceeds the needs of its relatively small population, will be a major export commodity in the EIM, she said.
“New Mexico is really roaring back in terms of policy and creativity,” Propst said.
California Public Utilities Commissioner Clifford Rechtschaffen took issue with the idea that the energy market would be undermined by policy directives. The CPUC has been dealing with legislative mandates for the past decade without undue problems, he said.
CAISO Vice President Mark Rothleder agreed it would be optimal to have a united carbon policy across the West but said the obstacles may be too difficult to overcome, especially with the EIM expected to add day-ahead trading to its current real-time-only market.
“We need to coordinate on what the overall objectives are,” Rothleder said. “Let’s move forward in a thoughtful way.”
TRAVERSE CITY, Mich. — MISO on Tuesday acknowledged that it might be forced to change course on its second-ever competitively bid transmission project after the passage of a Texas law giving incumbent utilities right of first refusal (ROFR) for any projects built in the state.
Speaking at a June 18 meeting of the MISO Board of Directors’ System Planning Committee, Executive Director of System Planning Aubrey Johnson confirmed that the new Texas statute applies to Hartburg-Sabine, although it’s still unclear how the law will affect the project.
Hartburg Sabine project | MISO
Johnson said staff are reviewing the new law and the Tariff to determine how the rules might interact “in accordance with regional transmission plans and state laws.”
Committee Chair Mark Johnson noted the status of the project is undoubtedly causing some “burning questions right now” among stakeholders and said it would be discussed in the committee’s closed session immediately following the meeting.
MISO in November selected NextEra Energy Transmission Midwest’s $115 million bid to construct the 500-kV Hartburg-Sabine project in East Texas, which would include a new 23-mile 500-kV transmission line, four short 230-kV lines and the new Stonewood 500-kV substation. NextEra’s proposal beat 11 other competitors, scoring 97 out of a possible 100 points under the RTO’s selection criteria. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)
Meanwhile, MISO continues to hold monthly meetings with Republic Transmission, developer of the RTO’s first competitive project, the $62.4 million Duff-Coleman 345-kV transmission line in southern Indiana and western Kentucky, Johnson said. That project is so far going off without a hitch, she added, and is on track to be in service by January 2021 — or possibly earlier.
During sector introductions at MISO’s June 19 Advisory Committee meeting, Competitive Transmission Developers Sector representative Steve Rowley touted the cost benefits that competitive developers offer through lower bids and project cost caps.
An April report released by The Brattle Group found electricity customers could save $8 billion over five years if competitive transmission planning processes expanded to cover a third of all transmission investments, compared with just 3% today. But another study published by Concentric Energy Advisors this month questioned that conclusion, claiming incumbent transmission owners’ initial cost estimates for projects generally prove to be accurate. (See Study Findings Clash on Value of Competitive Tx.)
The Trump administration on Wednesday finalized its repeal of the Obama administration’s Clean Power Plan, saying its replacement will correct its predecessor’s overreach of the Clean Air Act and restore power to the states.
Under the Affordable Clean Energy (ACE) rule, EPA has determined that the best system of emissions reductions (BSER) is heat-rate efficiency improvements that can be achieved at individual coal plants, not the “beyond the fence line” generation-shifting, fuel-switching and state emission caps required under the CPP.
EPA Administrator Andrew Wheeler said in a statement that U.S. power sector CO2 emissions will fall by as much as 35% below 2005 levels after ACE’s full implementation. But most of the reductions will result from industry trends toward renewables and natural gas and away from coal.
The agency outlined the proposal at a press briefing Wednesday, insisting the briefing leader be referred to only as a “senior EPA official.” The official said EPA rejected carbon capture and sequestration as “not technically feasible and not cost effective,” although it said states could impose such requirements on their own.
The official dismissed comparisons with the CPP as “fictitious” because it was never implemented and was stayed by the Supreme Court.
“It’s a fantasy to say there’s any real comparison here. But even if you were to try and compare … even if we were to implement CPP beginning today, it would produce no real change in the glide path that the industry is on right now,” he said.
That’s because the CPP’s implementation was blocked, the official acknowledged, and because “the world keeps changing around us. There are fundamental changes occurring in the power sector that have nothing to do with our regulation and have everything to do with market economics and the shale gas boom. There’s a pronounced move out of coal and into gas; there’s a pronounced move into renewables for reasons unrelated to the price of gas.”
The official said the ACE rule is, in part, a recognition of state’s rights.
Trimble County 1, a 514-MW coal-fired unit between Louisville and Cincinnati | LG&E-KU
“The Obama administration actually imposed emission-reduction obligations on each and every state. We think that’s not EPA’s role,” he said. “We’re revising the framework regulations primarily to make it abundantly clear that we, as the federal government, identify [the] best technology; states … develop the emissions limits … and then we review and approve. The Clean Power Plan was way too federal-heavy, and this part of the ACE final rule is going to rebalance the relative role of the states and federal government.”
The new plan will cover about 600 coal-fired generating units at 300 facilities.
States will have three years from the date of the final rule to submit their plans for EPA approval, compared with nine months under the CPP. EPA will have 12 months to approve or reject state plans, up from four months under CPP. For states that fail to submit an approvable plan, EPA will have two years to develop its own plan, up from six months.
New Source Review
In its ACE proposal last year, EPA also proposed allowing states to adopt an hourly emissions increase test for determining whether power plant upgrades are a “major modification” triggering a new-source review under CAA Section 111d. Only projects that increase a plant’s hourly rate of pollutant emissions would need to undergo a full NSR analysis, which could result in additional pollution controls.
emissions were already decreasing without the Obama administration’s Clean Power Plan. | EPA
Under current rules, an NSR review can be triggered if annual emissions increase because of increased dispatch even if hourly emissions drop — putting it in conflict with the ACE plan, the official said.
“Our projection is that the cost of having to go through the permitting process and the cost of corresponding emission controls and measures would make an otherwise viable efficiency project not viable and not sustainable under a state plan.”
The official said EPA will be back within several months with a final revision to the NSR regulations. “We fully intend to finalize the new-source review fix, but frankly with everything we have in the final [ACE] rule, we’ve bitten off as much as we can chew.”
The official was asked about studies predicting that up to 28% of coal plants will increase their total emissions because the efficiency improvements will improve their competitiveness.
“We project at full implementation that emissions from the sector are going to decrease,” the official said. “It’s entirely possible that for some individual [plants], emissions may go up. But even if they go up based on greater utilization, the emissions rate will go down because that’s what this regulation would require.”
Reaction
Reaction to the plan was unsurprisingly split.
Coal lobbying group ACCCE called it a “sensible and legally sound approach to regulating carbon dioxide emissions from the nation’s coal fleet.”
“We are especially pleased the ACE rule provides flexibility to set reasonable carbon dioxide standards that do not force the premature retirement of more coal-fired generating units,” ACCCE CEO Michelle Bloodworth said. “For that reason, we commend EPA for not attempting to use environmental regulations to drive energy policy.”
U.S. Rep. Bill Johnson (R-Ohio) said the rule shows President Trump making good on his promise to end “the War on Coal.”
“The current leadership at the EPA understands we can have smart environmental regulations and protect coal jobs and our economy at the same time,” he said in a statement.
Rhea Suh, president of the Natural Resources Defense Council, vowed to fight the plan in court. “President Trump’s dirty power scheme would do nothing to address the rising economic costs and the increasing dangers wrought by climate change,” she said. “Instead, it would give polluters free rein and doom future generations to a dangerously hostile world.”
Coal heat rates by state | EIA
Analysts at ClearView Energy Partners noted that parties will have 60 days from the rule’s publication in the Federal Register to appeal, meaning the Trump administration would still be in office to defend the rule. “If there are significant delays to the pace of the appeal, the potential that a differently minded administration (should one be elected in 2020) could mount a less aggressive defense or reconsider the rulemaking (as the EPA under the Trump administration did) could grow.”
ClearView said the rule does not prevent states from enacting higher renewable portfolio standards or other climate measures. “Indeed, we think the less stringent replacement for CPP may further galvanize subnational decarbonization efforts,” they said.
NextEra Energy on Monday filed a federal lawsuit challenging the constitutionality of a recent Texas law giving incumbent utilities the right of first refusal (ROFR) to build transmission projects in the state.
The suit argues that Senate Bill 1938, which was signed into law May 16, causes “injury” to NextEra’s subsidiaries by preventing their entry into Texas’ transmission development marketplace as regulated utilities. It said the bill also interferes with the companies’ ability to plan, invest in and conduct business operations in the ERCOT, MISO, SPP and Western Electricity Coordinating Council regions of the state (1:19-cv-00626).
“This case is about the very type of economic protectionism the Constitution was designed to prevent,” NextEra wrote, contending that SB1938 violates the U.S. Constitution’s Commerce and Contracts clauses.
NextEra Energy Transmission could find itself locked out of the Texas market. | NextEra Energy
Filed in the U.S. District Court for the Western District of Austin by NextEra Energy Capital Holdings (NEECH), the suit names Texas Attorney General Ken Paxton and Public Utility Commissioners DeAnn Walker, Arthur D’Andrea and Shelly Botkin as defendants. They have 21 days to file a response.
The lawsuit also calls out state lawmakers for caving to the interests of incumbent transmission owners and reversing a “long and successful history of holding itself as open for business” to new transmission entrants that didn’t already own transmission or hold PUC certificates of convenience and necessity (CCNs) to provide service.
“Despite this history, after facing competition, several of Texas’ traditional transmission and distribution utilities successfully lobbied the Texas Legislature to effectively close the border to further new entrants,” NextEra wrote. “The resulting law is discriminatory on its face, by preserving the opportunity to invest in and provide service over new transmission facilities in the state solely to entities that already own facilities and hold a certificate.” The law is intended to benefit local entities that already hold “the sole right to build transmission lines … in Texas, even when those transmission lines deliver power in interstate commerce,” the company said.
SB 1938 grants CCNs to build, own or operate new transmission facilities that interconnect with existing facilities “only to the owner of that existing facility.” (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
As written, the legislation endangers a pair of transmission projects previously awarded to NextEra subsidiaries.
NextEra Energy Transmission (NEET) Midwest last November won a competitive bid from MISO for the Hartburg-Sabine project in East Texas, which would consist of a new 500-kV line, four 230-kV lines and a 500-kV substation. MISO executives acknowledged Tuesday that the congestion-relieving project “may face challenges as a result of recent Texas legislation,” casting its future into doubt. (See related story, Uncertainty Deepens for Hartburg-Sabine Project.)
NEET Southwest has a CCN application pending before the PUC to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s region of East Texas.
In contesting the bill before its passage, NextEra had countered concerns by legislators that out-of-state transmission companies might be less reliable than in-state companies by pointing to the Texas’ Competitive Renewable Energy Zone buildout, a $7 billion effort that resulted in 2,800 miles of new transmission facilities. NextEra said the “small number” of out-of-state companies brought into ERCOT to run CREZ lines has “successfully shown that out-of-state new entrant transmission service providers are just as reliable as in-state traditional transmission and distribution utilities.”
Joining NEECH as plaintiffs in the lawsuit are NEET, NEET Midwest, NEET Southwest and Lone Star Transmission, which built 330 miles of 345-kV transmission lines for ERCOT as a part of CREZ.
FERC on Thursday upheld NYISO’s decision to deny a New York energy service company’s application to join the ISO until its predecessor pays its outstanding debt (EL19-39).
Light Power & Gas of NY told FERC in January that NYISO had violated its Tariff and the Federal Power Act in treating it as the successor to North Energy Power, a bankrupt ESCO kicked out of the ISO in October after it filed for Chapter 11 bankruptcy and its unpaid obligations exceeded its collateral.
NYISO noted — and LPGNY did not dispute — that though the two companies are separate, both share Abe Leiber, Jack Klein and Hindy Gruber as principals, and that LPGNY “apparently seeks to serve the very same customers as North Energy.”
The ISO also noted that, though formed in 2014, LPGNY only became active a week after North Energy filed for bankruptcy, when one principal contacted the ISO about joining. LPGNY also filed its application to join exactly one week after North Energy’s membership was terminated, NYISO said.
A screenshot of (the now bankrupt) North Energy Power’s website | North Energy Power
LPGNY argued that NYISO’s Tariff has no “successor liability” policy and that, even if it and North Energy were the same company, the ISO failed to follow its bad debt and re-entry provisions for defaulting transmission customers.
FERC sided with NYISO. “We find that NYISO’s decision to treat LPGNY as the same entity as North Energy is reasonable in light of the record, particularly the close overlap in not only those entities’ relevant personnel, but also their business activities,” the commission said. “Namely, both entities have the same contacts and administrators, similar addresses, are engaged in the same business in the same territory and seek to serve the same customers.”
The commission has previously found that it “may disregard the corporate form in the interest of public convenience, fairness or equity.”
It also found that the Tariff “neither explicitly supports nor prohibits NYISO’s decision,” though it urged the ISO to file Tariff revisions spelling out the factors it will consider when deciding whether to treat two separate entities as the same. Moreover, it emphasized that its decision “does not rely on the application of ‘successor liability’ that LPGNY alleges is the basis of NYISO’s actions.”
Finally, FERC found that NYISO did not violate its bad debt procedures, saying the Tariff gives the ISO “wide latitude in pursuing cost-recovery measures that may minimize or avoid a bad debt loss.”
PJM and a group of New York transmission owners intervened in NYISO’s defense. PJM said the case “implicates broader and common policy issues regarding whether [RTO/ISO] tariff rules” allow for denying a new member’s application based on prior enforcement history.
The Maryland Public Service Commission also intervened, though without taking a position, saying it was interested in the case because of its potential impact on PJM. The RTO is dealing with the effects of being burned by financial transmission rights trader GreenHat Energy and its principals Andrew Kittell and John Bartholomew, who were identified as lieutenants in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012.
In an unusual move, LPGNY asked FERC to dismiss the interventions, a request the commission dismissed.
