The SPP Regional Entity’s Board of Trustees on Thursday officially terminated the RE’s regional delegation agreement, shutting it down effective 5 p.m. CT Friday.
The trustees approved a motion to terminate the agreement during a brief phone call that was delayed until Trustee Steve Whitley could join Chair Dave Christiano and create a quorum. Staff patched Whitley in over a speakerphone from SPP headquarters. Trustee Mark Maher was unable to attend.
The meeting was a formality, as FERC in May approved the RE’s dissolution, effective Aug. 31 (RR18-3), and the transfer of its 122 registered entities to the Midwest Reliability Organization and SERC Reliability Corp. (See FERC Approves Dissolution of SPP RE.) The order ended a reliability oversight role that had been a source of concern at the commission and NERC and revised the delegated agreements among NERC, MRO and SERC to reflect their new geographic footprints.
The RE has been working since then to transfer data and files to its members’ new REs and purging its own files.
“We have absolutely nothing left, other than a bank account,” RE President Ron Ciesiel told the trustees. He said the RE’s books will be closed in about a week, and the remaining funds transferred to NERC, MRO and SERC.
“We’re ready to close the doors,” said Ciesiel, noting he and remaining RE staffers Kevin Perry and Joe Gertsch would be “mustered out” of SPP following the conference call. Ciesiel said the rest of the RE’s original staff have been placed elsewhere within the RTO or “made other decisions.”
MRO CEO Sara Patrick joined with Ciesiel, Christiano and Whitley in complimenting staff and the entities for their work during the transition.
“I know this was an unprecedented development, and certainly not something anyone anticipated,” she said. “I appreciate it’s gone as smoothly as it has.”
“I think our registered entities are in good hands,” Christiano said.
NERC will assume the compliance monitoring and enforcement of the RTO for two years following the delegated agreement’s termination date, after which it will determine a successor.
Christiano closed the call by uttering “sine die” — business adjourned, with no appointed date for resumption.
SPP Files for Cancellation of WAPA Operating Agreement
SPP filed with FERC on Aug. 28 to cancel its joint operating agreement with the Western Area Power Administration (ER18-2326).
The JOA was rendered moot by SPP’s integration of the Integrated System in October 2015, when the WAPA-Upper Great Plains Region transferred functional control of its transmission facilities to the RTO.
The agreement, which dates back to 2012, expired by its own terms on June 21. SPP filed a three-year extension in 2015 that was accepted by FERC.
SACRAMENTO — A bill that would require California to get 100% of its power from renewable and other zero-carbon resources by 2045 is headed to the desk of Gov. Jerry Brown.
Senate Bill 100 — the 100 Percent Clean Energy Act — passed a major hurdle Tuesday, clearing the state Assembly by a narrow margin, then sailed through the Senate Wednesday. Brown hasn’t said if he will sign or veto the measure, but it dovetails with his ambitious environmental agenda with regard to renewable power.
“This bill will continue California’s energy revolution,” said Sen. Ben Hueso (D), who voted for the measure.
Some Republicans argued against the measure, saying it would raise energy bills, while Democrats said wind and solar were now cheaper alternatives to fossil fuels.
In the Assembly Tuesday, the bill needed a majority vote in the 80-member lower house but remained on call, without the votes for passage, much of the day. It passed in the early evening by a vote of 44-32.
Other measures being weighed this week — the last of the legislature’s 2017-18 session — include a bill that would start CAISO on the road to being an RTO for Western states, letting California tap into wind power from Wyoming and solar power from New Mexico, for instance, while those states could buy California’s clean energy during times of low in-state demand. (See CAISO Regionalization Bill Set on Uncertain Course.)
CAISO’s leadership strongly supports Assembly Bill 813, which is currently being held in the Senate Rules Committee as a deal is worked out to bring it to the Senate floor. The legislature has until midnight Friday to send measures to Brown or watch the bills expire.
SB 100’s fate was unknown until the last minute Tuesday. Sen. Kevin de Leon (D), the bill’s author, had to work his Assembly colleagues on the Senate floor to get the last votes needed to pass the measure before the lower house adjourned for the day. There were a number of Democratic holdouts who had to be persuaded. Former Gov. Arnold Schwarzenegger, former Vice President Al Gore and others weighed in to encourage lawmakers to pass the measure.
In addition to requiring investor-owned utilities, publicly owned utilities and community choice aggregators to obtain 100% of their energy from renewables by 2045, the bill sets milestones along the way: 40-44% by 2024; 45-52% by 2027; and 50-60% by 2030.
The Long Island Power Authority’s proposal to exempt “beneficial electrification” from carbon charges received a mixed reaction Monday at a meeting of the Integrating Public Policy Task Force (IPPTF).
Ground source heat pumps are cited as a type of “beneficial electrification” which causes a net reduction in carbon emissions. | EPA
LIPA’s David Clarke said beneficial electrification (BE) — load growth that improves load factors and results in net reductions in carbon emissions — could increase generator margins while reducing fixed costs and should be supported by policymakers. Clarke cited as examples vehicle electrification and switching from oil-fired boilers to ground source heat pumps.
Clarke acknowledged the complexity of carving out BE loads for separate rate treatment but said it could be accomplished without skewing dispatch. He proposed treating BE load growth as having no marginal carbon impact, meaning it would not pay the carbon component of the LBMP.
“I think the question here is: Is there a consensus … around the idea of trying to include beneficial electrification in this proposal?” Clarke asked. “I’m willing to at least try to illustrate that it might benefit large groups of stakeholders.”
Kevin Lang, representing New York City, said Clarke had proposed an “interesting concept.”
But other stakeholders indicated no appetite for including the issue in their current deliberations, saying it should be delayed or handled by retail regulators rather than in the wholesale market.
One stakeholder who asked not to be named said the proposal raised numerous issues. “If you include extensive switching to heat pumps, a utility can very quickly become a winter peaking operation rather than a summer peaking operation. This then raises the question of forward capacity markets and so forth. How much does it cost to have the extra capacity in place for winter weather?”
Because thermal loads tend to be very “peaky,” resulting in more start-up operations, adding such loads raises issues of environmental justice, the stakeholder said.
“Any policy maker who gets into the subject of electrification should be able to stand up in front of a crowd of people like this and draw a curve of carbon monoxide, unburned … carbon emissions during the startup of even a natural gas turbine, and be able to comprehend how ugly that start-up process is during the first hours of operation and where that exhaust is going. We need to be very careful about increasing peaky types of grid loads.”
Mark Younger, of Hudson Energy Economics, said measuring carbon savings from beneficial electrification is very complicated.
“We would be going through a huge amount of complication to try and address something that realistically should lower the average carbon cost … fairly little,” he said. “I look at this and I say this seems like a perfect thing to not try and address at all at the wholesale level. … If someone wants to put together a retail rate design that is targeted to beneficial electrical uses and therefore has some degree of savings on maybe some of the fixed costs, the distribution costs … that’s a perfectly appropriate thing certainly for DPS [Department of Public Service] to consider.”
Clarke recommended awarding the social cost of carbon offsets through load-serving entities, which he said would allow for continued funding of LSE carbon abatement programs and incent LSEs to encourage BE load growth. The state Public Service Commission would retain its jurisdiction over how offset revenues are treated at the retail level.
Erin Hogan, director of the state Utility Intervention Unit, agreed with Younger, saying “it’s premature to try and address this now.”
She said the issue could be revisited once policymakers develop criteria for BE and once the NYISO develops its bottom-up forecast.
“The issue that I take issue with is that all beneficial electrification is good. To the extent there’s low penetration, the fixed costs could be spread over more megawatt hours. However, if the penetration is so high that the utilities then have to revamp their systems, all those little transformers in neighborhoods might have to be resized. Those costs could go up exceptionally high,” she said, noting that her office filed comments in the “New Efficiency New York” docket asking the PSC to develop criteria for defining BE.
Under Clarke’s proposal, loads qualifying as BE would have to improve load factors and prevent increases in regulated natural gas customers’ fixed costs. Policymakers should consider offsetting increases in fixed costs to electric customers resulting from load growth at sub-transmission feeders and distribution lines, he said.
Lang said New York City “is looking closely” at beneficial electrification, predicting it “will be bigger” than Younger suggested.
“If [the impact is] tiny, it’s tiny,” said Clarke. “That’s not the issue. I’m thinking down the road this is going to be big. Beneficial electrification, especially if [carbon emissions] were only monetized in the electric sector, is going to be a huge thing. And we’re going to be penalizing — if we keep doing what we’re doing — load growth that reduced carbon … by charging it a carbon charge even though its net effect on carbon is negative.”
Import Carbon Pricing
Clarke also gave a presentation on addressing imports from grid operators that already incorporate carbon prices. NYISO staff have suggested treating imports as if New York had no carbon policy, saying it may be too complicated to use the actual hourly marginal energy rate [MER] of external RTOs.
Clarke said the ISO’s proposal “gives neither an efficient carbon-free dispatch nor efficient dispatch when damage costs are considered” using the social cost of carbon.
Under Clarke’s proposal, the ISO would back out the price of carbon in each external zone and compare it to the New York price, less its carbon price based on the New York MER. “If MERs are similar, why not get more power from ISOs/RTOs where the cost of power absent carbon charges is lowest?” he asked.
The draft assumes the status quo — known as Option 1 — of treating imports as if New York had no carbon policy.
NYISO’s Mike DeSocio said, “I haven’t heard compelling arguments” for considering ways to value clean resources outside New York, known as Option 2.
Pallas LeeVanSchaick, of the ISO’s Market Monitoring Unit, challenged the “premise that Option 2 is complicated and hard to implement, and Option 1 is straightforward. … I don’t think it’s as straightforward as you think it is.”
Jordan Grimes, of Morgan Stanley, said beginning with Option 1 and later switching to Option 2 would be “untenable for markets.”
He asked whether the ISO had considered how the decision would be viewed under the U.S. Constitution’s Interstate Commerce Clause.
“The courts could say … you guys looked at two options, and Option 2 was the less discriminatory option — and that’s on record — and the ISO decided to go with Option 1 because it was easier.”
He said NYISO could learn from CAISO. “The way they tax imports largely works,” he said.
ISO attorney James Sweeney responded, “We haven’t identified anything from the interstate commerce area that would be a deal breaker for either option.”
Mike Mager, representing the Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, said the draft is missing many details that must be decided before NYISO stakeholders vote on any proposal. “It’s problematic to expect people to [vote] to implement one of the most significant market rule changes in the history of the NYISO without any clarity on what the social cost of carbon would be and how and when it would be updated,” he said.
NYISO’s DeSocio said “it’s difficult to foreshadow the kind of process the Public Service Commission would undertake” to set the cost of carbon. “We would hope they would be consistent with other [PSC] programs. From an efficiency standpoint, having different costs of carbon doesn’t seem like a good path forward.”
HOUSTON — The long transition between incoming Mexican President Andrés Manuel López Obrador’s July 1 election and his Dec. 1 inauguration has provided an early glimpse into how the new administration will approach the country’s energy reforms.
Unfortunately, the competing messages have left many observers confused, said political scientist and long-time Mexico watcher Tony Payan.
Members of López Obrador’s administration “don’t seem to have full agreement on what they want to do,” Payan told the International Society for Mexico Energy Monday night.
Payan, fellow and director of the Baker Institute’s Mexico Center at Rice University, said one official will call for NAFTA to stay in place, another will say, “No NAFTA is good NAFTA.” Another official will say the new government will review the 107 energy contracts signed with mostly foreign companies, then somebody else will say, “No, we’re not.”
“Then somebody says, ‘Put the energy reform to a referendum,’ and someone else says, ‘No, we’re not,’” Payan said. “The reality is there’s a lot of chaos. The incoming administration is spending too much time deliberating in public. They should put together the entire team, lock themselves in a room, agree on what they want to do, then come out and provide details to the public on what they want to do.”
Payan said the resulting confusion is “wearing them out” and reducing the Obrador administration’s political capital.
“The public debates is one of the worst things they can do, and they’re doing it,” he said. “Just two months after the election, and there’s already too many things up in the air.”
Most of the early focus has been on Mexico’s floundering petrochemical industry, which produced 1.88 million barrels of oil per day in the first half of 2018, compared to 3.4 million barrels per day in 2005. López Obrador has announced a $16 billion investment plan to increase the country’s oil production and refinery capacity.
Payan said Pemex, Mexico’s state-owned petroleum company, will take precedent over other companies and industries. Many in Mexico hold the ideological belief the country’s petroleum resources belong to the Mexican people. (See Opening of Mexico’s Market at Risk from New President.)
In the meantime, Payan said, the electric industry could very well continue to work on flexing its newly deregulated muscles.
“My guess is the electricity production landscape and markets are changing so quickly, and the technology is moving so fast, that it will be harder to restore any type of centrality to the state,” he said. “I think electricity is a little bit easier because it’s not wrapped in all that nationalism like oil is. Regulatorily, technologically, that market is so different. It’s a completely different ballgame. It’ll be hard to set them back.”
James Fowler, a senior Americas energy analyst for the ICIS Mexico Energy Report, agreed with Payan that the incoming government is sending mixed messages to participants in the electricity sector.
“On the one hand, they are talking about supporting private investments in the country and its infrastructure, whereas, on the other hand, they have talked about strengthening the role of state utility [Comisión Federal de Electricidad],” Fowler said. “Until energy market participants have a clear idea about where the new government’s energy policy is headed, we expect to see a slowdown in both new investment and the entrance of new companies into the Mexican power market.”
The Goodness of Competition
López Obrador’s $16 billion investment package includes plans to build more hydro facilities. However, he has also called for reducing the consumption of imported natural gas for power generation and cancelling a proposed retirement of 12 GW of inefficient and outdated power plants to boost the country’s energy independence, Fowler said.
“In reality, the new government will find it very hard to achieve these goals, while at the same time encouraging private investment in much needed new infrastructure, so something will have to give,” he said.
“When I look at the numbers, I can’t figure out how they’re going to do it,” Payan said, noting the disconnect between reduced taxes and increased infrastructure spending.
Renewable energy could also face some obstacles, Payan said. He pointed out López Obrador, a left-wing populist who emphasized social inequality on his way to a resounding victory, “wants to give a greater voice for farmers and indigenous communities.”
“If the federal government gives them a great voice in these deliberations, energy projects could be further delayed,” Payan said. “My guess is López Obrador will rediscover the goodness of private competition.”
Payan, a political scientist who spent 15 years on the U.S.-Mexico border at the University of Texas at El Paso, took a moment to address the trade agreement between the two countries trumpeted earlier in the day. He called it “much ado about nothing” and forecast a frosty reception in Mexico.
“I don’t think it’s going to go well in Mexico, once the critics begin to parse the agreement,” he said. “I think it actually strengthens the American manufacturing industry … steel, aluminum, cars. It weakens the car industry in Mexico and places it at a greater disadvantage than before.”
In the end, Payan said, López Obrador just wants NAFTA off his plate and may instruct his supporters in Congress to approve whatever the outgoing administration sends them. In the new Congress that began convening Sept. 1, the three parties that nominated him together hold commanding advantages in the Senate (68 of 128 seats) and Chamber of Deputies (307 of 500 seats).
“There’s a lot of uncertainty in the air. It’s not as amicable as you would think,” Payan said. “López Obrador has a lot more to clarify and define. He will have a tough time maintaining political discipline in Mexico. In general, I think we’re in for a rougher ride than we think.”
[Editor’s Note: A previous version of this story incorrectly reported that López Obrador’s MORENA party held 68 Senate and 307 Chamber seats. MORENA joined with the Social Encounter and Labor parties to nominate him and form a coalition government.]
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.
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.
