SACRAMENTO — Members of California’s Senate and Assembly hastily passed a conference committee report Tuesday night intended to protect ratepayers and help utilities pay for wildfire damages.
Both utilities and ratepayer advocates were unhappy with the measure, leading the committee’s co-chairman to suggest he and his colleagues had done an OK job.
“It may be a little bit encouraging that utilities and ratepayers both have a problem with this,” said Sen. Bill Dodd, a Napa Valley Democrat.
Wildfires ravaged Santa Rosa, Calif., in October 2017. | Army National Guard, Capt. Will Martin
The final conference committee report on Senate Bill 901 was approved in a confused rush Tuesday night as a deadline approached to get the bill in print 72 hours before the legislature reaches the end of its two-year session at midnight Friday.
Earlier versions of the bill would have removed the strict liability that California imposes on utilities if electrical equipment is a substantial cause of a wildfire.
Under the legal doctrine, Pacific Gas & Electric potentially faces billions of dollars in damages for last year’s devastating wine country fires, which leveled a swath of the city of Santa Rosa. State fire investigators said the utility was at least partly to blame for a number of those blazes because trees or branches hit PG&E power lines.
The conference committee deleted the provision eliminating strict liability and replaced it with a procedure that would allow the utilities to issue revenue bonds to cover wildfire costs. Charges would be added to customers’ bills to pay off the bond debts. (See Bond Sales Eyed to Fund Utility Wildfire Costs.)
That didn’t make utilities happy. A lobbyist for San Diego Gas & Electric told the committee Tuesday it was a step backward from the prior version of the bill.
Ratepayer advocates were outraged.
“We strongly oppose this bailout for PG&E,” said Mark Toney, executive director of The Utility Reform Network. “Billions of dollars at stake should not be decided in such a rushed process.”
Other groups, including cities, counties and plaintiffs’ attorneys, supported the conference committee’s report because it left intact the strict liability standard, sometimes called “inverse condemnation,” which allows those harmed to be compensated without proving negligence.
The conference committee report also contains measures to prevent wildfires, including provisions governing forest management and tree removal. And it allows the California Public Utilities Commission to consider the reasonableness of a utility’s conduct in determining whether to allow it to recover wildfire costs from ratepayers.
The conference committee report will be incorporated into SB 901, which now goes back to the Senate and Assembly. Both houses must approve the bill by Friday if they want it to reach the desk of Gov. Jerry Brown.
Lawmakers have unveiled a new plan to help California’s investor-owned utilities cover the costs of wildfires sparked by transmission lines.
The new plan calls for the California Public Utilities Commission to authorize the IOUs to pay for wildfires by selling revenue bonds and passing on the costs to customers through charges on their utility bills. It would also direct the PUC to look at whether a utility acted unreasonably by disregarding fire risks, or whether outside factors such as extreme weather contributed to fires. The proposal includes provisions for managing vegetation near power lines and easing regulations for tree cutting.
The new plan was outlined Friday by State Sen. Bill Dodd, one of the co-chairmen of a legislative conference committee tasked with mitigating wildfire risks and addressing their costs.
A prior plan proposed by Gov. Jerry Brown would have lessened the legal liability of the companies but was tabled after critics called it a multibillion-dollar bailout. (See California Utilities Lose Bid to Reduce Wildfire Liability.)
Senate Bill 901, the vehicle for the governor’s wildfire proposals, will be amended to include parts of the governor’s original proposal and the new changes, which Brown’s office vetted, Dodd said. “We can all agree that the status quo is unacceptable,” he said.
The committee must decide soon on the final provisions of SB 901. The current two-year legislative sessions ends at midnight Friday, when bills not sent to the governor will expire.
State Assemblyman Chris Holden, the other co-chairman, said lawmakers faced a daunting job in trying to prevent wildfires, protect fire victims and ratepayers, and ensure the stability of the state’s utilities. “The ramifications and the stakes are clearly very high, no matter which way we go or how we go there,” Holden said during Friday’s hearing.
The governor’s initial plan would have done away with California’s unique system of holding utilities strictly liable for all damage caused by power-line sparked fires. Instead, it would have required courts to weigh the reasonableness of the IOUs behavior and factor in other causes that contributed to fires.
The new plan maintains strict liability but provides a clearer route for passing on the damages to ratepayers.
A wall of flame in Southern California. | Tim Walton, Photo One Productions, CAL FIRE
The details of the new plan remain sketchy, including whether it would cover the October 2017 fires in the Napa and Sonoma valleys, which caused death and urban destruction on a scale rarely seen in Northern California. Investigators for the California Department of Forestry and Fire Protection blamed nearly a dozen of the worst blazes on Pacific Gas and Electric power lines and equipment coming into contact with trees and branches. PG&E faces billions of dollars of damages in those cases.
Some critics, including ratepayer advocates, remain concerned that lawmakers are primarily focused on helping utilities, not fire victims or utility customers.
“The ratepayers are the ones that are number one on my list. I want to be sure that they are not the ones that suffer because of mismanagement,” Assemblywoman Eloise Gomez Reyes said.
But Sen. Hannah-Beth Jackson, an outspoken critic of the utilities, thanked her fellow conference committee members Friday for focusing more on residents and less on IOUs in the new outline. “This is a massive undertaking for a massive problem,” she said.
VALLEY FORGE, Pa. — A planned vote on a proposal to expand PJM stakeholder input on end-of-life (EOL) transmission projects was revised to a second “first” reading last week after it was agreed that revisions to the plan since it was initially discussed made it substantially different than originally proposed.
American Municipal Power and Old Dominion Electric Cooperative developed the proposal to give stakeholders “meaningful input” in transmission owners’ planning of baseline and supplemental projects for EOL facilities. It was introduced after members agreed, at AMP’s suggestion, to terminate the Transmission Replacement Processes Senior Task Force at the July Markets and Reliability Committee meeting. (See PJM Stakeholders End Tx Replacement Task Force.)
Since last month, however, proponents abandoned enough of the proposal that they agreed to reintroduce it. The proposal no longer requires alternative dispute resolution (ADR) before a project can go forward or that the stakeholder process occur prior to TOs finalizing their budgets. Also eliminated is the requirement for additional meetings outside the TOs’ approved processes, or detailed-criteria examples and how they would be applied.
The revised proposal presented to the MRC would require TOs to explain their criteria for determining EOL projects, provide details about the asset and its condition, and make them available for PJM to post 30 days before the first applicable meeting of the Regional Transmission Expansion Plan cycle. It would also define the EOL processes and offer three choices for where to include TO-specific procedures in PJM’s governing documents.
“We are concerned about the transparency … as well as the ability once we have that transparency to comment in a timely manner,” AMP’s Ed Tatum said. “We think [TOs] are doing a pretty good job when it comes to assessing your systems.”
In response to a question from LS Power’s Sharon Segner, he acknowledged that the proposal could “not really” halt a project.
“If a TO is bent on getting a project built, I’m not sure how any of this could stop it,” he said. “I think what it does is it gives the opportunity to fully discuss the need for a project.”
TOs “may not wish to respond” to input on a project and “we honor that,” he said.
The opportunity for ADR before projects are finalized was removed, he said, because “it’s very clear to me that PJM did not want that part of our proposal to be memorialized.”
It was proposed as manual changes, he said, because he felt that he wouldn’t be able to get the two-thirds majority approval necessary for including it in the Operating Agreement.
“We think this is the best we can do. That’s all I got,” he said.
“While we would like to get it in the OA, we’re not sure that it’s necessary,” AMP attorney Lisa McAlister said.
Consensus
PJM’s Ken Seiler said the RTO is optimistic that TOs and their opponents may be reaching consensus after a nearly two-year stalemate created by FERC ruling that TOs weren’t properly complying with their obligations under Order 890 to provide stakeholders with adequate information on supplemental projects — transmission expansions or enhancements not required for compliance with reliability, operational performance or economic criteria. PJM and its TOs submitted compliance filings in March, which they are implementing now, and refused to engage AMP and others in additional negotiations on the issues.
“We’re certainly committed to transparency around the entire process, and that’s including supplementals,” Seiler said.
AMP and PJM “have certainly moved much closer to where we think we need to be,” and they’ve also “closed the gap” with the TOs, he said. “We’re not there yet.”
PPL’s Frank “Chip” Richardson asked for patience as TOs implement their plan for complying with FERC’s show cause order earlier this year requiring them to increase stakeholder engagement in the development of supplemental projects. (See “TO Supplementals Discussion,” PJM PC/TEAC Briefs: Aug. 9, 2018.)
TOs plan to initiate stakeholder processes in the first and third quarter next year to review the implementation of the TOs’ new M-3 Tariff attachment, an outline of TOs’ responsibilities that had formerly been in the Operating Agreement. He suggested that the “appropriate place” to continue analyzing the process is in the Planning Committee, although a special session of the MRC was announced for Sept. 13 to discuss transmission replacement processes.
Seiler confirmed that the new processes under M-3 will begin their transition into the RTEP in September, but that it will take some operating experience with it before integration can be improved. He noted that supplemental, aging infrastructure and EOL projects are often incorrectly used interchangeably, which obscures meanings.
“We’ve got to get a little tighter with the words, a little more consistent with the words,” he said.
Exelon’s David Weaver reiterated calls for consensus. “We really got into a stalemate in the TRPSTF, [but] the TOs really do want to provide additional transparency,” he said.
Despite Weaver’s conciliatory words, not all TOs appear ready to support the AMP-ODEC proposal.
Duquesne Light’s Tonja Wicks criticized the proposal as having “a number of flaws” and said it’s “inappropriate to ask stakeholders to vote on specific language rather than concepts when the language isn’t defined.”She took issue with what she saw as the proposal imposing additional requirements and obligations on TOs through the manuals and outside of the OA, the latter of which she noted would require FERC approval to be implemented.
She accused Tatum of “forum shopping” for the proposal, a remark he dismissed as “a pejorative comment.”
“And it was,” she shot back.
Can High-voltage Still be Supplemental?
PJM Vice President of Planning Steve Herling indicated the potential for supplemental projects involving high-voltage lines to go through the RTEP analysis because they will likely become eligible for regional cost-sharing. (See DC Circuit Court Rejects PJM Tx Cost Allocation Rule.)
“It doesn’t tell us what to do, so we have to wait until FERC decides,” he said of the D.C. Circuit Court of Appeals’ decision to remand back to the commission its denial of cost sharing for high-voltage lines in PJM’s territory. “I believe that’s been FERC’s general direction, and we do whatever FERC tells us to do.”
FERC last week approved portions of a Louisiana Public Service Commission complaint against Entergy subsidiaries System Energy Resources Inc. (SERI) and Entergy Services, denied and dismissed other portions, and set the remainder for settlement proceedings (EL18-142).
The PSC filed the Section 206 complaint in April, contending that the return on equity in the unit power sales agreement (UPSA) formula rate for calculating the costs of the Grand Gulf Nuclear Station billed to Entergy’s operating companies is unjust and unreasonable. The state regulator contested SERI’s capital structure and the depreciation rates currently incorporated into its rates, and it asked FERC to set the complaint for hearing and reset SERI’s ROE, equity ratio and depreciation rates to a just and reasonable level.
The commission’s Aug. 24 order granted the PSC’s complaint about the ROE element, establishing hearing and settlement judge procedures and setting a refund effective date of April 27. It denied the capital structure elements and dismissed the depreciation rate elements.
Louisiana regulators charged that SERI’s ROE of 10.94% was calculated based on a record “developed in the mid-1990s,” saying that conditions have changed significantly since then, as investor return requirements, interest rates and inflation have decreased. They argued that SERI’s equity investor and shareholders faced almost no risk because the company sells Grand Gulf’s entire output to four utilities that are wholly owned by Entergy and are obligated by the UPSA to buy the power regardless of the amount delivered.
FERC found the Louisiana commission raised issues of material fact that it couldn’t resolve, and it set the complaint for investigation and a Section 206 trial-type evidentiary hearing. It encouraged the parties to make every effort to settle their disputes before hearing procedures begin.
Commission Approves Settlement Between Entergy, Parties
The commission last week also approved a settlement among SERI, the Arkansas, Louisiana and Mississippi commissions, Cooperative Energy, and New Orleans City Council, addressing issues regarding the depreciation rates to be applied under SERI’s UPSA (ER17-2219).
SERI amended the agreement between itself and its operating companies in 2017 to revise the depreciation rates used to calculate Grand Gulf’s depreciation and amortization expenses and update the depreciation rates for use in calculating the plant’s annual revenue requirement for decommissioning costs.
VALLEY FORGE, Pa. — PJM members are grappling with a gambler’s dilemma in one of their markets: accept a heavy loss or keep rolling the dice and hope to get lucky. The difference could cost millions of dollars.
In responding to GreenHat Energy’s potentially record-setting default in its financial transmission rights market, PJM has asked the members who will pay for the loss to decide whether to liquidate the portfolio now and stomach hefty bills in the short term, or potentially let the positions run their natural course over the coming months and live with the slow bleed and constant risk that a position might go exceptionally bad.
PJM was left to contend with the issue after GreenHat defaulted on a $1.2 million payment in June. (See PJM Reeling from Major FTR Default.)
“We’ve been handed a pig’s ear to manage. I’m not sure how one does that,” said Susan Bruce, who represents the PJM Industrial Customers Coalition.
Neither option is optimal, but stakeholders have preferences generally based on their market interests. Their differences emerged at last week’s meeting of the Markets and Reliability Committee. After stakeholders approved a problem statementand issue charge to reconsider PJM’s plan for mitigating future defaults, Exelon representatives presented a motionto suspend any liquidation of the portfolio through November.
PJM rules require staff to attempt to liquidate the defaulted positions as quickly as possible by offering them in the monthly FTR auctions. However, staff found that the bids received to take the positions were roughly four times what the clearing prices on those paths had been prior to the default. Staff anticipate the liquidated positions could cost more than $24 million in August alone.
Cumulatively, the default has already cost members $42.5 million in three months, and the portfolio includes positions into the 2020/21 planning year.
Proposed Delay
At the MRC meeting, Exelon proposed directing PJM to request FERC approval to waive its rules requiring liquidation of the positions through Nov. 30, instead letting any that come due during that time period to go to settlement and accepting whatever the real-time cost turns out to be. FTR traders argued against the delay, saying it would allow the market to continue to be indefinitely bogged down by the defaulted positions.
“The purpose of our motion is to facilitate choice,” Exelon’s Jason Barker said. “Both paths have risks.”
While liquidation would quickly eliminate the risk, members would have no control over their costs and the liquidation results for August indicate that they “will be pretty high,” he said. Forestalling any potential liquidation until members have agreed on a plan “offers both choice and control” because it allows market participants time to take other positions in the FTR market to hedge against the likely losses. He offered to help advise members who don’t trade FTRs and said other experienced traders would likely offer the same.
“While we bear a big share of the default burden, we are also in a position to hedge our risks,” he said.
Bob O’Connell, with Panda Power Funds, pointed out that the plan requires retroactive FERC approval. PJM wouldn’t be following its Tariff until then, and “we can’t presume that FERC will accept the Tariff language,” he said. PJM attorney Chris O’Hara acknowledged the risk but was confident FERC would grant the waiver request.
“That is not unique to this position and not something that PJM hasn’t done before,” he said.
Bruce described the situation as “trying to choose what is the least-bad option among a suite of bad options” and asked how energy suppliers planned to handle passing the loss allocations on to their customers. Barker said it would likely vary from contract to contract, but he assured her that, “as the holder of one of the largest pig’s ears,” his company’s interests are “aligned” with its customers. Bruce asked for the process to be “very transparent” and ensure auditability.
Greg Carmean, executive director of the Organization of PJM States Inc., asked whether state regulators would have any authority over suppliers who choose not to take any proactive steps.
Barker declined two suggested friendly amendments to the proposal, the second of which would have given PJM the authority to analyze the FTR market and determine whether it would be best to offer positions into each monthly auction.
“We would prefer that the members have the choice about how to mitigate the risk, not PJM,” Barker said.
CFO Suzanne Daugherty said staff wants clarity on what the members want and that giving staff discretion would create “more ambiguity” and “might be something members end up regretting.”
Alternative
Greg Pakela of DTE Energy offered an alternative that he said would avoid putting “all of your eggs in one basket” by offering for liquidation half of every position that would otherwise go to settlement in the current month. Many FTR traders preferred DTE’s proposal, but other stakeholders felt it left many unanswered questions.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he could not vote on the measure “even if he wanted to” because it had been posted too late for him to poll his members prior to the meeting.
The MRC approved Exelon’s proposal with 4.04 in favor in a sector-weighted vote, which precluded a vote on DTE’s proposal. From there, the proposal was moved to the Members Committee for an uncommon same-day vote. Several stakeholders expressed frustration at being required to consider the measure so quickly, but they also understood the need for expediency. PJM staff noted they had delayed closing the current FTR auction until after the MRC in order to confirm member preferences for how to handle the current positions.
James Ramsey with Suffolk Fund objected to the vote, which appeared to trigger a rule in PJM’s procedures that would block the vote from being taken. Staff confirmed Ramsey’s objection needed to occur in the MRC when the intention was announced to bring it for a vote at the MC, but Ramsey pointed to an example in the rules that appeared to allow a participant to level an objection in the MC. With the interpretation of the rule in question, Gabel Associates’ Michael Borgatti, who chairs the MC, called for a vote on whether the rules should be waived to allow for the vote. That motion received 4.43 in favor, surpassing the necessary 3.34 threshold in the sector-weighted vote.
The proposal was then approved by acclamation, with five votes in opposition and one abstention.
VALLEY FORGE, Pa. — PJM generators have had enough of a yearlong dispute between the RTO’s staff and its Independent Market Monitor that they say has put generators at risk of regulatory reprisals.
Bob O’Connell of Panda Power Funds led the charge at last week’s meeting of PJM’s Markets and Reliability Committee, introducing a proposal that would require the RTO to accept opportunity cost adders calculated by the IMM, Monitoring Analytics. PJM had announced in an Aug. 7 letter to generators that it would no longer accept adders developed by the Monitor’s calculator if they exceed the value developed by the RTO’s calculator because “PJM has not approved the methodology used by the Monitoring Analytics calculator.”
“I didn’t pick this fight. PJM did. All I’m trying to do is restore what existed before they picked this fight,” O’Connell said.
The adder allows generators who have operating limitations to remain revenue neutral if they are required to forego running at financially optimal times because they were dispatched by PJM at some other time.
PJM’s and the Monitor’s calculators use different methodologies and sometimes arrive at different results. PJM staff didn’t have “concrete proof” of the different results until two months ago, the RTO’s Stan Williams said. Generators are concerned the ban puts them in regulatory limbo because there is no option that is universally approved.
Old Dominion Electric Cooperative’s Adrien Ford said there’s “a lot of appeal” to the Monitor’s method, which provides a single number based on inputs provided by the generator, but that “it’s useless to us” if PJM won’t accept it. PJM’s method requires generators to use their discretion to choose which result they believe is most accurate.
O’Connell said he forced the vote because he needs a “safe harbor” from a FERC enforcement referral.
“We cannot continue in an environment where if I use Joe’s calculator, I’m at risk of being referred to FERC by PJM, and if I use PJM’s calculator, I’m at risk of being referred by Joe,” he said, referring to Monitor Joe Bowring.
O’Connell’s proposal had been up for introduction at the MRC meeting, but John Rohrbach, who represents ACES on behalf of the Southern Maryland Electric Cooperative, motioned for it to be up for voting consideration. He argued the immediate vote was necessary because PJM’s ban disrupted years of reliance on being able to use either calculator and “effectively short-circuited” an ongoing stakeholder process to review the calculators. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)
O’Connell seconded the motion but said that he would withdraw the proposal if PJM lifted the ban. He also suggested creating comparative tests using identical inputs to determine why results are different and identify the best practice.
“As long as that memo is out there, I have a commercial responsibility to my team to try to get that resolved,” he said, adding that he couldn’t accept a general agreement to continue looking at the issue without definitive timelines. “I’ve got to be able to negotiate with somebody; I can’t just concede the point.”
He stressed in his presentation that he was not simply shopping for the calculator that offers the higher price, offering to provide evidence to stakeholders. PJM attorney Chris O’Hara asked that O’Connell not do so because the evidence he was planning to provide could also create a competitive advantage for other generators by publicizing confidential details about Panda’s Stonewall plant.
O’Connell said he would be willing to “take the Market Monitor’s number and live with that” if PJM would accept it. He and Rohrbach agreed to add a friendly amendment that would require picking a calculator and sticking with it for at least a year at a time.
Other stakeholders were also displeased with the standoff, expressing surprise that the entities are able to share information on so many other issues but can’t come to agreement on this one.
“The two of you work hand in glove on so many issues it seems impossible to me that you can’t sign some [nondisclosure agreement] and work something out,” GT Power Group’s Dave Pratzon said.
They reiterated the offer of removing the vote if the two parties could commit to working out their differences.
“If somebody would back down from a position, we could be in a position to not force this [Operating Agreement] language. I think there’s an opportunity here that’s being missed,” said Carl Johnson, who represents the PJM Public Power Coalition.
PJM and Bowring refused to budge.
“We have the ultimate authority to say whether an opportunity cost is valid or not,” Williams said, adding that “this issue goes away once we have a chance to dig into the calculations” Bowring’s calculator provides.
Bowring accused PJM of “changing the rules” and said the ban “came as a surprise to us as well.” He said he was willing to submit his calculator to an independent audit because “we’re not saying ours is perfect,” but that he couldn’t provide PJM access to the code for the algorithm because it’s protected intellectual property.
Williams acknowledged that “it was a surprise from the standpoint that we put it into writing, but it is a consistent message that PJM has been telling participants for two years.”
Stakeholders generally supported generators’ desire for a risk-free calculator, endorsing the proposal at the MRC with 47 abstentions but no objections.
The proposal then moved to the Members Committee meeting that followed the MRC, where it required a two-thirds endorsement vote to be added to the agenda for voting. Several stakeholders became hesitant to vote on the proposal again at another senior committee on the same day.
The measure to take a vote on the issue received a 2.87 on a sector-weighted vote, which failed the necessary 3.34 threshold. However, FirstEnergy’s Jim Benchek noted that the end results didn’t add up to five, as the sector-weighted vote is designed to do. PJM staff explained that was because all six End-Use Customer sector members in attendance abstained, which was considered participation but recorded as a 0 for the purpose of the reaching the approval threshold.
Stakeholders warned PJM and Bowring that the measure would be on the agenda for the September meeting of the MC if the two parties hadn’t found agreement by then. At a previously scheduled special session of the Market Implementation Committee on the issue on the following day, Johnson said the avoided vote was a “conscious gift” to allow the parties to work out their differences.
He warned that his frustration is “growing” because IMM staff at the special session were unable to corroborate statements Bowring made at the MRC.
“I appreciate all of the frustration and history that goes into this, but we’ve got to get past it,” Johnson said.
Bowring later explained that the special session was billed as a discussion of technical topics rather than broader policy issues, so he did not attend and the staff that did were only familiar with the technical aspects of the issue. Monitoring Analytics’ John Hyatt said at the meeting that the Monitor has explained to PJM how its calculator works. It’s optimized to maximize profit while PJM uses “an ad hocestimate” to solve an optimization problem, he said.
It “baffles us” why PJM doesn’t use “more sophisticated mathematics,” Hyatt said. “We don’t know why you would want to do that. We’ve just taken it to the next level.”
Williams disputed Hyatt’s understanding of PJM’s methodology, saying that confusion is “part and parcel” to the disagreement. Hyatt acknowledged that PJM staff have “been very generous with sharing data and we have reproduced the results of the PJM calculator, and we know what the PJM calculator is doing.” PJM’s Tom Hauske acknowledged the RTO’s calculator hasn’t changed since 2010.
When asked whose intellectual property was at issue based on Bowring’s comments from the previous day, Hyatt said “my understanding is it’s the [Monitor’s] intellectual property,” which Bowring later confirmed.
As the tension continued, PJM staff appeared to back away from their demands.
“We’re just looking for reasonable assurance that the Market Monitor’s calculator is doing what they told us it does,” Hauske said.
“I could also live in a world where” the Monitor showed the outputs for a particular set of inputs, PJM’s Jeff Schmidt said.
“This whole situation is very dysfunctional, wasting stakeholder time and imposing compliance risk on members,” said Exelon’s Sharon Midgley, who asked if it could be included in the Monitor’s contract renewal, which is currently being considered by PJM’s Board of Managers.
The Trump administration’s replacement for the Clean Power Plan is likely to mean limited and localized relief for the coal industry while increasing nuclear retirements and premature deaths, according to EPA and outside analysts.
The Affordable Clean Energy (ACE) rule announced by EPA last week will seek heat-rate efficiency improvements at individual plants, in contrast with the CPP, which set state emissions limits and encouraged switching to natural gas and renewables. (See related story, EPA:CPP Replacement Could Boost Coal-Fired Power by 6%.)
The new plan, which will cover about 600 coal-fired generating units at 300 facilities, also proposes for the coal industry long-sought relief from New Source Review (NSR).
President Trump celebrated the new rule at a campaign rally in Charleston, W.Va., last week, extolling “clean, beautiful West Virginia coal.”
Observers agree the changes will keep some coal plants running longer than they would have under existing law or the CPP.
But few, if any, analysts believe the administration’s proposal will be enough to overcome economic trends and state and local policies favoring natural gas and renewables. Some say EPA is exaggerating the coal plant efficiency improvements likely to result.
“Killing the Clean Power Plan will not bring coal back, because the Clean Power Plan did not kill coal. It’s still economics,” West Virginia University law professor James Van Nostrand told the Charleston Gazette-Mail.
“It’s unfortunate, because I think peoples’ hopes were raised in a cruel way by Trump,” Van Nostrand said. “But I don’t think our politicians have done a service to our citizens either by continuing to blame the EPA, because they know it’s broader forces at issue. They know we need to transition away from coal to other sources.”
EPA’s Regulatory Impact Analysis (RIA) predicted that, assuming a 4.5% average heat rate improvement at $50/kW, coal production for power sector use will be 5.8% higher than under CPP by 2025, rising to 9.5% by 2035. A scenario assuming the same heat rate improvement at a cost of $100/kW would see coal’s use increase 4.5% in 2025, rising to 7.4% in 2035.
But a Brattle Group analysis last week said that EPA’s assumption that coal plants in all states would see heat rate improvements (HRI) of 2 to 4.5% is unlikely.
“Some states will likely adopt lower HRI requirements for many plants and none at all for some plants, since the states have the discretion to set unit-specific emissions standards. In addition, the potential HRIs may be overstated, since they appear to be based to some extent on potential improvements at inefficient plants that have already retired,” Brattle said. “If so, the surviving fleet may have already employed some or most of the BSER [best system of emission reductions] measures and therefore don’t have as much room for improvement.”
An analysis by Resources for the Future released earlier this month said that while EPA’s “at-the-source” enforcement plan would reduce coal units’ emissions per megawatt-hour by 4%, it would result in only a 2.6% cut in national power sector CO2 in 2030 compared to the no-policy scenario. “This modest change is due in part to the emissions rebound effect, with coal generation estimated to be 1.1% higher in 2030 relative to the no-policy reference case … with potential increases in CO2 emissions in eight states.”
New Source Review
EPA proposes to change the NSR rules under the Clean Air Act so that only projects that increase a plant’s hourly rate of pollutant emissions would face a full NSR analysis that could trigger additional pollution controls.
Miles Keogh, executive director of the National Association of Clean Air Agencies, said the NSR change is likely to be most significant in vertically integrated states.
By exempting any projects improving efficiency from NSR, plant operators could extend their units’ lives by five to 10 years rather than being replaced by cleaner generation, Keogh said. “In restructured states, you take your chances in the market earning a return on an upgrade. But where you can rate-base an improvement, you earn a return on the investment,” Keogh tweeted, adding that many state regulators may favor saving coal plants and their jobs.
“Ten years is a big deal. Ten years ago, we had hundreds of coal plants in the pipe, gas was $15/MMBtu, there was one-fifth as much installed wind and no [electric vehicles] on the market.”
Utility Plans
There is no indication that utilities that have announced targets for decarbonizing will change their plans based on the new rule.
In February, American Electric Power, the largestCO2 emitter in the power sector, announced plans to reduce carbon emissions by 60% below 2000 levels by 2030 and 80% by 2050. AEP’s projected CO2 emissions for 2018 are about 90 million metric tons, 46% below 2000. In its 10-K, AEP said its strategy is based on “economics, customer demand, regulations, and grid reliability and resiliency.” Coal currently represents almost half of its generating capacity.
Less than 2 GW of new coal plants were built between 2013 and 2017. In contrast, 60 GW of new combined cycle gas generation was completed, under construction or had cleared regulatory approvals since 2012. Wind added 29 GW and solar added 23 GW over the same period with a combined 12 GW under construction or in post-permitting development. | Bipartisan Policy Center
Duke Energy, the No. 2 carbon emitter among generators, has said it hopes to cut its coal- and oil-fired power generation to 16% by 2030, from 33% in 2017. Coal and oil accounted for 61% in 2005.
No. 3 emitter Southern Co. has reduced coal’s share to 28% in 2017 from more than 70% in 2005.
The Edison Electric Institute was noncommittal on the plan, saying in a statement that it was still evaluating it.
Impact on Nuclear
The new plan could also undermine the Trump administration’s efforts to prolong the lives of at-risk nuclear plants because it doesn’t provide emission-reduction credits to low-CO2resources, Brattle said. “Unlike CPP, the ACE rule does not provide a mechanism (either through credits or higher energy prices) to benefit any low-CO2generation technologies, including nuclear, natural gas and renewables. This may result in greater risks for nuclear retirements and contradict the administration’s efforts to prevent retirements of ‘fuel secure’ baseload plants including nuclear.”
EPA’s RIA projects ACE will result in an additional 5,000 MW of nuclear retirements by 2030 compared with the CPP.
The Nuclear Energy Institute was noticeably silent on the proposal last week, issuing no statements. NEI declined RTO Insider’s request for comment on Monday.
Cost Claims and Trading
Brattle also questioned EPA’s claim that ACE could reduce compliance costs versus the CPP by up to $6.4 billion, saying it is based on inconsistent assumptions about the cost of heat rate improvements. “Under consistent assumptions for cost of HRIs ($100/kW), EPA’s analysis shows the compliance cost under ACE would be $1.7 billion to $3.0 billion higher than the costs under CPP. This somewhat counterintuitive result is likely due to the ability under CPP to trade emissions allowances through emission-reduction measures (such as dispatch switching) that are less expensive than implementing HRIs at $100/kW.”
ClearView Energy Partners analyst Christi Tezak told clients last week that the EPA proposal “appears to strongly disfavor compliance through trading beyond averaging emissions between units located at the same plant.”
At a press briefing last week, Assistant EPA Administrator Bill Wehrum acknowledged a “tension” between the Trump administration’s interpretation of its authority under the Clean Air Act and its desire to limit compliance costs. Wehrum acknowledged that trading programs, such as the acid rain program, can be more cost effective and “more effective over all.”
“We believe that BSER should be focused on emission controls and measures that can be implemented at the plant or applied to the plant. We … think certain aspects of the CPP, like consideration of how electricity grids are managed and how the various power plants are dispatched into the grid … goes beyond our authority and states’ authority.”
Wehrum said the agency is seeking comments on “how we could actually allow [trading] to be implemented in a way that’s consistent with what we think BSER needs to be. We’re really looking forward to getting public comment to help us think through that question.”
Health Impacts
EPA’s RIA predicts ACE will result in 400 to 1,400 additional premature deaths annually from fine particulate matter (PM) by 2030 compared with the CPP.
Wehrum was unapologetic about the impact, saying ACE is an effort to reduce greenhouse gases, not other pollutants.
“We care very much about the amount of pollution that’s emitted in the country and power plants are a significant source of certain types of air pollution. We’re the Environmental Protection Agency. This is what we do.
“We’re not dealing with SO2. We’re not dealing with NOX. We’re not dealing with particulate matter,” he said. “We have abundant legal authority to deal with those other pollutants directly, and we have very aggressive programs in place that directly target emissions of those pollutants. So our view is, if we want to regulate PM, we regulate PM straight up. If we want to regulate SO2, we regulate SO2straight up.”
Legal Challenges
ACE, like the CPP, will make only small reductions in carbon emissions over those expected based on current trends. But it is unlikely to be rejected by the courts, according to Tezak, who said EPA could finalize the rule in the first half of next year, setting up court reviews likely to continue into 2020.
“Critics of ACE may have difficulty proving, as a legal matter, that the rule guarantees [nationwide emissions increases],” Tezak said, noting that cheap natural gas and state policy preferences for renewables and nuclear energy “seem likely to deliver emissions reductions in line with ACE targets. It may be hard to argue that ACE is a failure if emissions continue declining.
“The D.C. Circuit [Court of Appeals] may agree with the new plan’s opponents that climate change is a problem that demands a response from policymakers, but we are not yet convinced that the courts will direct EPA to stretch interpretation of the existing statute when the agency declines to do so,” she said. “This matters. Even if voters elect a new president in 2020, should federal courts uphold ACE, it may take Congress (rather than a regulatory pendulum swing by a greener president) to replace or otherwise strengthen the rule.”
Tezak said EPA may revise ACE’s proposal to extend the implementation period, however. 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.
“Under this scenario, a state could be without an enforceable carbon limit program for coal-fired units as late as five years after ACE finalization,” Tezak said.
SEATTLE — NERC CEO Jim Robb said last week his organization is sidestepping Washington’s fuel war politics and striving to maintain its independence from industry while still collaborating to identify best practices and emerging threats.
Robb has had no shortage of issues to address in the four months since he joined NERC from Western Electricity Coordinating Council (WECC). In his keynote address at last week’s third biennial NAES-NERC conference, Robb said the organization is focused on making sure its reliability standards evolve in response to the changing generation mix and the growth of electric vehicles and distributed generation. (See related story, Overheard at the NAES-NERC Conference.)
“Do [the standards] need to be evolved in particular ways to be compatible with the industry as it’s evolving?” Robb asked. “Are we keeping our eyes far enough down the road on reliability issues to make sure that we have a good sense of how this new restructured industry is going to work — and going to work reliably? If we don’t have a sense of what we need to have in the ground 10, 15 years from now, we may have lost the battle, and that’s becoming particularly clear on issues like gas infrastructure.”
Relationship with Industry
Robb, who replaced longtime CEO Gerry Cauley, said the organization is seeking to balance its role as enforcer of reliability standards with the need to work closely with industry to respond to new threats, such as cyberattacks.
“We are an independent authority; however, we are very tightly linked with industry in terms of being able to leverage technical expertise and capability in order to do our work,” Robb said. “Our work is much better because of the relationship we have with industry, but we can never be viewed as not being independent from industry.”
Robb said NERC and its Regional Entities face the challenge of “how to manage the yin and yang of independence and partnership in a way that gets us to the right answer from an oversight perspective.”
Other speakers at the three-day conference also discussed that balance.
Midwest Reliability Organization CEO Sara Patrick emphasized that “authority should defer to expertise” with respect to reliability issues. NERC and the REs must be sensitive to actual operations, “understanding how things work, not just how they’re supposed to work.”
Patrick said her organization has changed from its early focus on enforcement of standards. “Enforcement is only one of the tools in our toolkit and it may not be the most effective,” she said, encouraging companies to self-report violations and devise strategies for avoiding them in the future.
Jeff Craigo, vice president of reliability assurance and monitoring at ReliabilityFirst, cautioned against companies adopting practices that superficially achieve compliance without actually improving grid security, often the product of organizational silos and inadequate communication among different departments.
“The key is that you’re coordinating your compliance program across your organization,” Craigo said.
“You can be minimally compliant, but that won’t get you security,” said David Godfrey, WECC vice president of entity oversight.
Curtis Crews, director of compliance assessments for Texas Reliability Entity, talked about the “circle of competence” between oversight agencies and plant operators.
“I audit; you do maintenance. We need each other,” Crews said.
James Merlo, NERC vice president of reliability management, warned against the tendency for companies to drift from reliability standards.
“You can’t see drift in your own organization” in the same way that “you can’t smell your own room,” Merlo said, referring to the phenomenon of “sensory adaptation.”
“I believe NERC standards are the floor, not the ceiling, so the work of [NERC] is critical,” FERC Commissioner Neil Chatterjee said.
The Politics of Resilience
Robb also acknowledged the highly charged debate over resilience and the Trump administration’s push to protect coal and nuclear generation.
“There’s a tremendous amount of political influence in place right now, whether it’s ‘Can we survive without coal plants?’ or ‘What are we going to do if we don’t have our nuclear fleet?’ ‘How much renewable can we really put on the system?’
“Many of these issues are important technical issues for the industry and NERC and the REs to deal with, but they’re also highly politicized, and our job is to stay out of the political fray and be ideologically independent,” Robb said.
Mark Lauby, NERC’s chief reliability officer, told the conference that resilience has always been part of his agency’s mission.
“It’s our definition of reliability,” he said. “Resilience is something we have to keep our eye on, particularly as the risks change.”
EVs, Behind-the-Meter Generation
Robb also pointed to uncertainties stemming from the increased adoption of EVs and how they will interplay with solar generation.
“We used to always operate the system on a very simple, straightforward baseload, mid-merit peaking array, with a fairly well-known load curve,” he said. “We have to kind of ’fess up. We don’t even know what the load curve looks like. So much [generation] is masked by behind-the-meter generation.
“We’ve learned a tremendous amount over the course of the last two years around how inverter-based resources respond to disruptions on the system, and it’s been a little bit like following a ball of yarn through a house,” Robb told conference participants. “One issue you think you’ve corrected, and then another one appears, and so forth.”
“It’s an industry issue because inverters will be highly central to the deployment of batteries, which we’ll see in multiple jurisdictions,” Robb said, adding that solar will also continue to be “one of the resources of choice” over the next 10 to 15 years. He also noted that inverters have “pretty extraordinary capabilities” to promote reliable operations. “We need to be ahead of that.”
Robb also said the industry needs to shift its operating model to one that is “just more stochastic in nature.”
“Policies in general need to be rethought,” Robb said. “Most of our frameworks and rules of thumb around things like resource adequacy were based on largely coal and liquid fuel resource mix and a metal-bending [heavy manufacturing] economy, and that’s not what we have anymore.”
SEATTLE — “Buckle your seatbelts; it’s going to be an interesting ride,” NAES CEO Bob Fishman said as he kicked off last week’s third biennial NAES NERC conference, where nearly 140 power plant operators, engineers and back-office professionals spent three days being schooled in the finer points of complying with NERC standards.
Fishman | NAES
Fishman wasn’t so much referring to the nature of the conference — billed “Sustaining Reliability: Balancing Operations and Compliance” — as the changes forcing the electricity sector to re-examine its approach to reliability.
“To look at the market, we’re entering an era of unprecedented change,” said Fishman, whose company helps generators, transmission owners and others comply with NERC reliability standards. “In my career, I’ve seen the rise of the gas turbine and the combined cycle plant. During my stint at Calpine, we were building 8,000 MW a year for a while, and that was a big shift. But this shift is different and very fundamental.”
Demonstrating his point, Fishman listed several concurrent developments: the decline in electricity demand relative to economic growth; growing reliance on renewables and efficiency; plant retirements; and persistently low power prices driving an increasing number of bankruptcies by generators.
What do those changes mean for compliance, grid operations and the future of the industry? Fishman posed rhetorically.
“The good news is that people can’t live without electricity, so the grid’s not going away soon,” he said. “But we are going to see a very different grid infrastructure and operation than we’ve seen before. The integration of renewables into the grid has and is causing a dramatic shift in where power is generated, how it’s generated and how the grid copes with the intermittency of renewables.”
The three-day conference, which featured NERC CEO Jim Robb and FERC Commissioner Neil Chatterjee, touched on EPA’s replacement for the Clean Power Plan, the politically charged debate over grid resilience, cybersecurity, and the impact of electric vehicles and solar generation. (See related story, NERC Seeks to Balance Oversight, Collaboration.)
Here’s more of what we heard.
FERC Discusses Resilience
Mark Hegerle, director of the Division of Compliance in FERC’s Office of Electric Reliability, pondered the meaning of resilience: “Is it encompassed by reliability? Is it part of reliability? Is it something separate from reliability? Does it mean fuel security? Does it mean hardened transmission? Cybersecurity? Recovery from thunderstorms or distribution outages?”
Hegerle noted that FERC in January rejected the Department of Energy’s Notice of Proposed Rulemaking to provide price supports for coal and nuclear plants. Instead, FERC opened its own resilience proceeding setting out three goals: to develop a common understanding of resilience, understand how each region assesses resilience, and use that information to evaluate potential commission actions (RM18-1). (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)
“We wanted to actually think before acting. I know that’s a rarity in Washington,” he said.
“FERC has a lot of responsibilities, but protecting the reliability of the bulk power system is among the most important,” Chatterjee said. “It’s a point that I made during my Senate confirmation hearing, and one year into my time at FERC, I remain committed to this mission.”
Chatterjee said he has “gotten under the hood of the system” as commissioner, helping him understand even more what it takes to maintain the high level of reliability enjoyed by the U.S. He also cautioned that historically low natural gas prices and technological innovation are driving “unprecedented changes” in the country’s resource mix.
“These trends promise tremendous benefits to consumers through lower prices and great choice, but they also highlight a need for vigilance to ensure that reliability is not adversely impacted,” Chatterjee said. “Ten years from now, I do not want to regret not having asked the hard questions about the effects of these changes in resource mix.”
On Cybersecurity
“It’s no secret that America’s critical infrastructure is under threat from foreign actors,” Chatterjee said, referring to the potential for cyberattacks on the grid. “Could the grid hold up against a cyberattack that take out a [gas] pipeline? What about a cyberattack that takes down a substation?”
Joseph Baugh, senior compliance auditor for the Western Electricity Coordinating Council (WECC), addressed the need for “low-impact” facilities — such as smaller power plants — to be hardened against cyberattacks, a new requirement under a NERC’s CIP-003 standard.
“Smaller sites can become a vector for attacks on more critical facilities,” Baugh said.
“If you just own a single generation location, that’s a low-impact [bulk electric system] asset — but you still communicate,” Baugh said. “You probably communicate with either a [generation operator] or a [balancing authority] somewhere. And if you have someone providing transmission services for you, you [are] probably communicating with a [transmission operator]. Know where those communications paths lie, know what they look like, know what they use, and develop the protections necessary and applicable to those communication paths.”
“Cyber is a rapidly evolving threat. It’s a threat that morphs day in, day out,” Robb said. “Your ability to protect yourself from a security perspective is much, much more complex than operating a system reliably and securely.”
On the Demise of Peak Reliability
Robb said the single most important reliability issue facing the U.S. over the next two years is Peak Reliability’s announcement that it will end operations as the Western Interconnection’s reliability coordinator as soon as the end of 2019. Peak will be replaced by “at least three, maybe four [RCs], depending on how you do the math,” Robb said. “The Western Interconnection is structured very, very differently than the East. It really operates as one integrated machine and has had the benefit of Peak Reliability being the reliability coordinator for the entire interconnection.”
The CEO noted that CAISO, SPP and Canada’s BC Hydro could all be functioning as Western RCs within the next two years and would require NERC certification.
“Most importantly for the West are [that] seams agreements are going to need to be put in place to make sure those RCs operate seamlessly and effectively as one,” Robb said.
Chatterjee said FERC is “closely monitoring” the transition from Peak.
“While I appreciate the desire for greater participation in markets and reduced costs that prompted this change, moving away from a single reliability coordinator in the West reintroduces many of the difficult seams issues that prompted the formation of Peak in the first place,” he said.
Maury Galbraith, executive director of the Western Interstate Energy Board (WIEB), expanded on the potential seams issues in a post-Peak West, listing concerns over outage coordination, system operating limits, awareness of remedial action schemes, data sharing and overall communication.
Galbraith acknowledged that CAISO was likely to become the RC for most of the interconnection and said WIEB was concerned about governance under the ISO — or any other RC that is stood up in the region.
“We think the decision-making of the RC needs to be transparent. It needs to be independent. There ought to be a role for the states and provinces to provide input into that decision-making process,” Galbraith said.
Chatterjee said his staff gets annoyed when he refers to energy storage as a “gamechanger.”
“They say it’s too cliche of a comment, but there’s truth in that cliche,” Chatterjee insisted. “Storage will be the transformative technology. But for us to be able to realize storage’s full value, we must ensure communication between the customer, the distribution utility, the transmission utility and the RTO in a way that’s never been done before.”
Galbraith pointed to the “explosion” of distributed solar in the West, which is expected to double in the next 10 years. That development is coupled with the significant retirement of coal resources, with about 15,000 MW being shuttered between 2010 and 2025.
A major implication of those two developments: “We are seeing, with all of the renewable generation, a premium placed on flexible operation of other generators,” Galbraith said.
Galbraith noted that Western Interconnection coal units that in 2001 on average operated at near capacity for 52% of their operating days are now functioning as baseload just 22% of the time. In 2016, coal units were offline for 22% of operating days, compared with 9% 15 years ago.
“So one big question for [WIEB’s Western Interconnection Regional Advisory Board] and its members are, ‘Where are we going to get ancillary services, not next winter or summer, but five, 10, 15 years down the road when those coal units are retired or offline?’” Galbraith said.
MISO’s Steering Committee last week approved an expanded role for the Energy Storage Task Force — with the proviso that the task force doesn’t impede on discussions in other stakeholder forums.
The committee allowed the task force more authority by approving a charter that allows it to evaluate energy storage issues instead of simply identifying them for committee assignment, and to recommend approaches directly to MISO and stakeholders, without first approaching the committee. The group can also provide subject matter expertise to committees that have been assigned storage policy issues. The task force has been seeking an expanded role for a few months. (See MISO Energy Storage Group Seeks Expanded Role.)
However, Steering Committee members removed proposed charter language that would have allowed the task force to evaluate proposed storage solutions that have already been assigned to other stakeholder committees. The committee made the decision based on MISO’s two-year-old stakeholder redesign, which discourages duplicate discussion topics across stakeholder committees.
Energy Storage Task Force Chair John Fernandes, of Invenergy, said some members of the task force have become frustrated by its previous charter’s limitations on discussion.
“When the conversation veers to market structures, hands go up and they say, ‘you shalt not go there,’” he said. “The Energy Storage Task Force is getting a little punchy not being able to talk about market structures.”
Fernandes warned that if task force members continually hit limitations in discussion, they might convene privately and put together nonpublic proposals for MISO staff.
“It will go against everything you want to protect in the stakeholder process,” Fernandes told Steering Committee members.
But some on the Steering Committee said task force members should simply track storage topics in the stakeholder committees to which the Steering Committee assigned them. “I’m really not appreciating that it’s an implied threat, either black or white,” said Planning Advisory Committee Chair Cynthia Crane. She said stakeholders could simply attend other stakeholder committees rather than resorting to nonpublic meetups.
Fernandes also said the task force must be allowed to consider topics outside of the scope of FERC Order 841.
He said the order also places a “really tight fence around which storage issues” can be discussed in the organized markets. He said that’s in contrast to member companies currently developing storage for use beyond Order 841 rules.
“Really what industry is doing is out-of-scope; industry is going beyond Order 841,” Fernandes said.
Steering Committee Chair Tia Elliott said she didn’t see anything in the task force’s current charter that would preclude it from discussing matters beyond Order 841.
