ARLINGTON, Va. — Newly appointed FERC Commissioner Robert Powelson, a former Pennsylvania Public Utility Commissioner, seemed at ease last week as he addressed the annual meeting of the Organization of PJM States Inc. He cracked jokes and shared memories with fellow regulators, RTO officials and stakeholders.
But when the subject turned to the Department of Energy’s recent proposal that FERC promulgate rules to support generators that can stockpile 90 days of fuel in deregulated states, he became emphatic.
“I will not support anything that undoes the value of the market,” he said Wednesday. “I remind everybody in this room, we are an independent agency. … FERC does not do politics.
“I give Energy Secretary [Rick] Perry credit. He’s trying to be thoughtful in the approach, but there’s many different approaches to how we can tackle this issue. I did not sign up for blowing up the markets,” he said to a round of applause. “We will not destroy the marketplace.”
The comments were in response to concerns that DOE’s Notice of Proposed Rulemaking would drive large subsidies to nuclear and coal units that would make competition untenable. (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Commissioner Cheryl LaFleur seconded Powelson’s vow “not to destroy” the markets, tweeting, “Great message!”
Perry Defends NOPR
On Friday, Perry defended the NOPR, saying it was not an order to the independent commission, but an effort to begin a “conversation” on the loss of baseload generation.
“I think it’s really important for people to understand, in general terms, there is no free market in the energy industry,” he told a meeting of the group Veterans for Energy, according to an account in The Hill. “And anybody that gets up and says that is lying — is not, with all due respect, educated as to what the reality of the market is.”
Perry said he was attempting to reverse the policies of the Obama administration, which he said, “had their thumb on the scale” to help out renewables to the “detriment … of reliable, baseload industries that are really important for the future security of this country.”
The commission last week issued a notice inviting comments on the NOPR (RM18-1). Comments are due by Oct. 23, with reply comments due Nov. 7.
Other Controversies
In his speech to OPSI, Powelson also referenced several other controversial issues before the commission, without explicitly identifying them.
“Dallas Winslow, do you have a question for me?” he asked the chairman of the Delaware Public Service Commission.
Delaware has been fighting use of the solution-based distribution factor (DFAX) cost-allocation method for Artificial Island upgrades, PJM’s first competitively bid project under FERC Order 1000. The original allocation left the Delmarva Peninsula on the hook for much of the project’s $280 million cost, but PJM has proposed alternative allocations that would shift much of the bill to New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
Winslow laughed but did not ask a question.
Powelson also hinted at action on natural gas pipelines, saying, “We love infrastructure, so we’re going to work on infrastructure — New Jersey included.”
The proposed 120-mile PennEast Pipeline — which would transport Marcellus Shale gas from northeast Pennsylvania to central New Jersey — is facing opposition from landowners in both states. In April, FERC staff filed their environmental impact statement on the project, concluding that it would have “less than significant” environmental effects (CP15-558).
MISO last week said it expects to have plenty of reserve capacity to cover upcoming winter operations, even as it announced a review of an emergency declaration made on the first day of fall when a heat wave pushed reserves to their acceptable limits.
The RTO’s preliminary forecast predicts a 28.3 to 37.3% reserve margin this winter, with about 142 GW of capacity on hand to meet an anticipated peak load of 103.4 GW, according to Rob Benbow, MISO senior director of systemwide operations.
“I would say this is a little colder-than-normal winter, but not by much. This is pretty typical of the last few years,” Benbow said during an Oct. 5 Reliability Subcommittee meeting.
MISO’s all-time winter peak of 109.3 GW occurred Jan. 6, 2014, during the so-called “polar vortex.”
Final values for forecasted winter capacity will be presented Nov. 6 at a MISO Winter Readiness Workshop.
| MISO
Benbow reminded stakeholders that MISO’s gas usage profile-sharing program will begin in December. Under the pilot program aimed at improving gas-electric coordination, the RTO will share hourly day-ahead gas usage profiles with a trio of selected gas system operators. (See FERC Approves MISO Plan to Share Generator Gas Data.)
Mark Thomas, electric-gas operations coordinator, said MISO is collecting data for its fourth annual gas-fired generation winter fuel survey, which focuses on generators’ winter preparedness efforts. Thomas said 87% of MISO’s gas-fired capacity participated in last year’s survey.
September Emergency
But even as MISO transitions to colder weather, it plans to review emergency operations spurred by an unexpected late summer/early fall heat wave.
MISO staff will offer a more detailed report on a late September maximum generation event during its Oct. 12 Market Subcommittee meeting, Benbow said.
| MISO
The event began to unfold 11 a.m. on Sept. 21 when the RTO initiated conservative operations measures in response to average temperatures reaching nearly 90 F, which produced a peak load approaching 109 GW. Peak load hit 114.7 GW the following day when temperatures climbed to 92 F, prompting MISO to declare a maximum generation event between 2 p.m. and 6:15 p.m. ET. The RTO declared another emergency warning Sept. 23 and finally lifted conservative operations at 8 p.m. on Sept. 26.
Benbow said a mixture of record temperatures, high load, and seasonal and forced generation outages contributed to the “challenging conditions.”
“Typical load this time of year might be 80 GW and even lower on the weekend,” Benbow said. “This heat dome was really caused by hurricanes stalling the [weather] system in our footprint.”
Benbow said the planning model did not forecast such extreme temperatures, and MISO staff are reviewing the RTO’s actions ― along with the outages ― leading up to the event. MISO has considered a possible expanded role in outage coordination since its Independent Market Monitor earlier this year recommended the RTO have a greater say in approving outages to reduced costs and instances of emergency situations. (See MISO in Harmony with IMM State of the Market Report.)
Some stakeholders last month also voiced support for more sophisticated outage planning between generators and transmission owners.
“I don’t believe that anyone had to shed load at any time. … Congratulations for keeping it together,” Indianapolis Power and Light’s Lin Franks said of MISO’s latest emergency declaration.
Benbow confirmed that no load shedding occurred during the five-day event.
AUSTIN, Texas — Appearing before the Gulf Coast Power Association’s Fall Conference last week, Texas Public Utility Commissioner Brandy Marty Marquez was asked about the retirement decisions facing owners of out-of-market coal plants.
“Everyone’s waiting for that shoe to drop,” she responded.
On Friday, the first pair hit the floor when Vistra Energy announced plans to retire three aging coal-fired units in East Texas. The Monticello units date back to the 1970s and have a capacity of 1,880 MW, rendered obsolete by ERCOT’s record low prices.
Vistra CEO Curt Morgan blamed the market’s “unprecedented low power price environment” as having “profoundly impacted” the plant’s operating revenues. He said the market, flooded with cheap renewable energy and low-cost gas generation, “no longer supports continued investment.”
Morgan alluded to the coming retirement announcement when he told the GCPA his company was “assessing the viability of our generation fleet.”
“We are willing to lead in this area, although we believe we are not the only ones who need to undertake some hard decisions,” he said.
Vistra’s decision was not unexpected. Executives told financial analysts in August it was considering retiring some of its coal plants and would make a decision in the fourth quarter. (See Analysts Debate Potential Vistra Coal Retirements.)
Luminant, Vistra’s generation arm, has two other 1970s-era coal-fired plants in Big Brown and Martin Lake. The plants, with 3.7 GW of capacity, have combined capacity factors of 59% and 52%, respectively. Luminant’s 18 GW of capacity includes 8 GW of coal-fired generation and 7.5 GW of gas.
Luminant’s Monticello Power Plant | Luminant
The Monticello units began life as a lignite mine mouth operation, but they switched to Powder River Basin coal in 2016.
Luminant filed a suspension-of-operations notice with ERCOT that triggered a reliability review. If the ISO determines the units are not needed for reliability reasons, Luminant expects to stop plant operations on Jan. 4, 2018.
Vistra estimates it will record one-time charges of approximately $20 million to $25 million in the third quarter of 2017 related to the retirement, including employee-related severance costs. Luminant has estimated the closure will affect about 200 employees.
ERCOT has also received suspension notifications for three smaller gas-fired units.
The City of Garland told ERCOT on Oct. 2 it plans to indefinitely suspend operations of two of its Spencer plant’s units, totaling 118 MW of capacity, in January. The units went into service in 1966 and 1973.
On Sept. 27, Talen Energy said it plans to retire a 330-MW gas unit at its Barney Davis plant near Corpus Christi in December. The unit went into service in 1974.
ARLINGTON, Va. — The panels at the Organization of PJM States Inc.’s annual meeting last week took on a wide variety of topics, but two themes rose to the top: cheap natural gas from local shale deposits has undoubtedly upended the electricity industry; and no matter how pure a market is, nothing will prevent the taint of politics.
“Politics sort of have everything to do right now in the energy market space,” said Susan Bruce, who represents the PJM Industrial Customers Coalition. “Low natural gas prices may have an adverse effect on certain PJM market participants, but as a general matter, the shale gas revolution should be viewed as a real positive for our region. Businesses make decisions to site here because of that. If we mute that in some fashion to give competitive advantage to others, I think we, looking at the issues as a whole, have done ourselves a disservice from an economic perspective.”
State regulators agreed. In the meeting’s opening panel, regulators of several PJM states tracked the current debate over providing subsidies to nuclear units — most notably through Illinois’ zero-emissions credit program — back to the low gas prices suppressing auction results so that “generation owners are not making enough money in the marketplace,” said Asim Haque, chair of the Public Utilities Commission of Ohio.
“If the power markets are just going to now be about state and federal politics, I think we’ve got a problem,” Haque said. “I worry where our collective heads are at. I worry that we’re all going to continue to be entrenched in our state policy and political objectives. … I do have fears of a full-on accommodation of all state subsidies.”
Pennsylvania Public Utility Commission Chair Gladys Brown noted her commission traditionally protests efforts to introduce unit-specific subsidies. The Pennsylvania legislature has developed a large pro-nuclear caucus and held two hearings on developing financial support for the state’s nine nuclear units, she said, but “we as a commission still have not been called over to provide any type of testimony.”
“It’s a catch-22 because we want access to that cheap natural gas, but they also know we’re a diverse state and we have so many other things that we could offer in terms of generation,” she said.
Illinois Commerce Commissioner John Rosales said he was “proud” of his state’s ability to coalesce around the issue and decide to support nuclear generators. “It was the right decision,” he said. “I realize there’s always going to be some political attributes that come into play.”
Kentucky Public Service Commissioner Talina Mathews noted that her state “loves to say how different it is” as one of the few in PJM that is fully regulated, has no renewable energy portfolio, energy efficiency standards or carbon emission goals, and remains a staunch advocate for coal use.
Still, she joined other regulators in defending states’ abilities to make decisions for their residents.
Differing Priorities
When asked what changes to the capacity market they endorse, only New Jersey Board of Public Utilities President Richard Mroz would say he favors a redesign that supports nuclear, saying “there are other attributes that are not being valued that should be valued.”
“I do not know who to trust anymore,” he said. “On the state side, you’ve just got different priorities developing. You’ve got different priorities developing in different states,” he said. “This is the sort of implicit cooperation that’s supposed to exist between the states when we’re all in this marketplace together, and Ohio unequivocally — when we made our [power purchase agreement] decisions [to subsidize some in-state generation units] — was a violator of that implicit cooperation.”
He said that Ohio is taking a different position now.
“The decision that I made when I was sworn in as the chair in 2016 was that the PUCO was out of the generation business,” he said. “Our advocacy now going forward will very much be tailored around trying to be constructive with that cooperation the best we can until we get to a breaking point where I think I’ve got to protect Ohioans. … We will start to become very active if I think that my residents and my businesses are going to be asked to stand on the Titanic.”
In a lunchtime address, PJM CEO Andy Ott explained that gas-fired units used to be on the margins of receiving enough revenue to cover their costs. However, they were small and flexible enough to turn on and off quickly as prices dictated. Cheap gas has allowed those units to offer into the market so low that they can always run and don’t have to respond to price signals. That has pushed large, inflexible units to the margin, where they can’t respond to price changes quickly, or at all. So that attribute of flexibility, which was previously inherent to the system, now needs to be valued in the market, he said.
“Hopefully, we’re not trying to solve a political problem,” he said.
Kathleen Barron, Exelon’s senior vice president for government and regulatory affairs, said markets are adjusting to state preferences. Her comments seemed to echo those made by James Wilson of Wilson Energy Economics, who consults for several state commissions and has argued at PJM stakeholder meetings that markets can absorb state actions given enough time and information. Tonja Wicks, who oversees FERC and RTO affairs for Duquesne Light, said her company has concluded the existing capacity design is the right one for now.
It wasn’t a surprise that Barron supported her own company’s proposed revisions, but she acknowledged, “I think we have a ways to go to make sure that what we actually adopt is fair to customers.”
Part of that may be because “we’re talking about different kinds of subsidies” that forestall exit from the market rather than incentivize entry as other state policies have done, said Marji Philips, Direct Energy’s director of RTO and federal services. They’re also targeted at a few very large units rather than many smaller ones.
“It’s about politics, and it’s really hard to price politics,” Philips said.
“What it really gets down to is investor confidence,” said Steve Schleimer, Calpine’s senior vice president for government and regulatory affairs.
There are trusted ways to secure a return on investments in competitive and regulated environments, but “where it’s part-competitive and part-regulated … that’s not stable.”
Split Over Cost Containment
In a separate session, stakeholders split on whether to factor cost-containment guarantees into proposals for transmission development.
PJM’s Craig Glazer said the RTO could consider caps on construction costs but isn’t prepared to determine whether other guarantees are suitable. He said PJM should “stay in our lane,” and Gloria Godson, vice president of federal and PJM policy for Exelon’s Pepco Holdings Inc., agreed.
However, Sharon Segner, vice president of power development for LS Power, disagreed.
“We have a lot of reservations about that policy. If PJM is going to take [the opposite perspective of] every other RTO on cost containment, that’s a discussion that should go on with FERC,” she said.
She and West Virginia Consumer Advocate Director Jackie Roberts said they were willing to pay extra to develop a “robust” independently administered evaluation process. Roberts suggested a plan in which proposals would be requested during a certain time frame and submitted using the same form so they could create “an apples-to-apples” comparison. The current system allows developers to submit proposals in any form they wish.
“If my money’s being spent, I want to know that the most creative solution is being proposed and that everybody is on a level playing field to fix that solution. This is what all businesses do, and the fact that it has not come to transmission planning is because PJM has been trying very hard to fix its time constraints,” Roberts said. “You just don’t have time for that, but others do. … I’m convinced that consumers will be better served by a real bid process that puts the risk of the business on the people making the bids, who are the people who know what the risks are and should bear them. That’s something that I’m willing to get my checkbook out for.”
EPA will repeal the Clean Power Plan, saying the Obama administration’s call for switching to more natural gas and renewable generation exceeded the agency’s authority.
According to a draft rule leaked last week, EPA will contend that Section 111(d) of the Clean Air Act requires emission regulations be based on reductions that can be applied at a single source.
“Instead, the CPP encompassed measures that would generally require power generators to change their energy portfolios through generation-shifting (rather than better equipping or operating their existing plants), including through the creation or subsidization of significant amounts of generation from power sources entirely outside the regulated source categories, such as solar and wind energy,” said the 43-page proposal, which numerous news sources obtained last week.
That is the same interpretation of Section 111(d) that EPA Administrator Scott Pruitt espoused as Oklahoma attorney general, when his state and more than two dozen others challenged the CPP in court. In August, after President Trump issued an executive order directing EPA to review the CPP, the D.C. Circuit Court of Appeals agreed to hold the challenges in abeyance. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)
President Trump signing his executive order seeking to undo the Clean Power Plan as coal miners, Interior Secretary Ryan Zinke, EPA Administrator Scott Pruitt and Vice President Mike Pence watch.
Pruitt told a gathering in Hazard, Ky., on Oct. 9 that the repeal will be formally announced on Tuesday. “Here’s the president’s message: The war on coal is over,” Pruitt said.
“Regulatory power should not be used by any regulatory body to pick winners and losers,” Reuters quoted Pruitt. “The past administration was unapologetic. They were using every bit of power, every bit of authority to use the EPA to pick winners and losers on how we generate electricity in this country. And that’s wrong.”
An EPA spokeswoman last week declined to comment on the authenticity of the leaked draft but issued a statement saying, “Any replacement rule that the Trump administration proposes will be done carefully and properly within the confines of the law.”
Building Blocks
EPA said it will seek to repeal the rule because two of the three “building blocks” in the CPP — switching from coal to natural gas and to renewables from fossil fuel plants — exceed the agency’s authority. The third building block, improving the heat rate of coal-fired plants, “could not stand on its own,” EPA said.
“Any potential future rule that regulates [greenhouse gas] emissions from existing EGUs [electricity utility generating units] under CAA Section 111(d) must begin with a fundamental re-evaluation of appropriate and authorized control measures and recalculation of performance standards,” it said.
Going forward, EPA said it will interpret the CAA’s “best system of emission reduction” as referring to measures “that can be applied to or at an individual stationary source. That is, such measures must be based on a physical or operational change to a building, structure, facility or installation at that source, rather than measures that the source’s owner or operator can implement on behalf of the source at another location.”
Repeal and what?
Now that Pruitt has decided on his legal strategy for undoing the CPP, he must develop an alternative response to the Supreme Court’s 2007 ruling that carbon dioxide is a pollutant that EPA must regulate. The draft indicated EPA will not seek to reverse the agency’s 2009 finding that GHGs endanger public health. “The substance of the 2009 endangerment finding is not at issue in this proposed rulemaking, and we are not soliciting comment on the EPA’s assessment of the impacts of greenhouse gases with this proposal,” the draft said.
The agency said it will solicit comments in an Advanced Notice of Proposed Rulemaking “in the near future” on systems of emission reduction applicable at individual sources. Developing a replacement regulation could take years.
The new interpretation will “substantially [diminish] the potential economic and political consequences of any future regulation of CO2 emissions from existing fossil fuel-fired EGUs,” the agency said.
EPA’s new regulatory impact analysis projects the repeal will save $3.7 billion in compliance costs in 2020, rising to $33.3 billion in 2030, while forgoing pollutant benefits of $1.6 billion to $21.5 billion over the same period. The analysis, which is based on a 3% discount rate, includes only the benefits of reducing CO2, unlike the Obama administration’s estimate, which also included the co-benefits of reduced SO2 and NOX emission reductions.
The Obama EPA said the CPP would produce net benefits of $26 billion to $45 billion in 2030.
The CPP would have required a 32% cut in emissions below 2005 levels by 2030. EPA previously estimated that “inside-the-fence-line” plant modifications, such as equipment upgrades and adoption of best practices, would improve average coal plant heat rates by 4%.
‘Wholesale Retreat’
Former EPA Administrator Gina McCarthy, who shepherded the CPP during the Obama administration, blasted her successor’s proposal.
“A proposal to repeal the Clean Power Plan without any timeline or even commitment to propose a rule to reduce carbon pollution isn’t a step forward; it’s a wholesale retreat from EPA’s legal, scientific and moral obligation to address the threats of climate change,” she said in a statement.
McCarthy also made an apparent reference to Energy Secretary Rick Perry’s Sept. 28 directive to FERC urging it to ensure that nuclear and coal generation in deregulated states with 90-days on-site fuel supply receive “full recovery” of their costs. (See related story, ICF Analysis: DOE NOPR Cost Could near $4B/Year.)
Coal plant | NOAA
McCarthy said the administration “is using contrived problems with our energy system to take money out of consumers’ pockets and giving it to fossil fuel companies, so they can force a shift away from clean energy and back to dirty fossil fuel. That not ‘back to basics,’ that’s just plain backwards.”
Clean Energy ‘Accelerating’
Some environmentalists have said a plant-specific approach could make a significant dent if it went beyond efficiency improvements to include switching to natural gas or installing carbon capture — though it would be more expensive.
Despite the repeal, “the transition to a clean energy future is accelerating,” insisted Charlie Jiang, a climate and energy associate for the Environmental Defense Fund, wrote in a blog post.
He cited carbon-reduction pledges announced by states and cities in response to Trump’s decision to withdraw from the Paris Agreement, and utilities’ continued move to renewables from coal. Wind and solar comprised more than 60% of utility-scale generating capacity added in 2016; in March, wind and solar totaled more than 10% of U.S. electricity generation for the first time ever.
As of the end of 2016, CO2 emissions from U.S. generators was already 25% below 2005 levels, “meaning the power sector is already almost 80% of the way to achieving the Clean Power Plan’s 2030 targets,” Jiang said.
Industry also is making the switch. At a House Energy and Commerce Committee hearing last week, a Walmart executive said the company seeks to obtain half of its energy from renewable sources 2025 — up from 25% in 2015. “It is a win-win,” said Mark Vanderhelm, Walmart’s vice president of energy. “Green power is more cost effective than brown power.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Left to right: Zinke, Pence, Trump, Perry and Pruitt
In addition, the Trump administration’s efforts to reverse Obama’s environmental rules have run into opposition in the courts. Last week, a federal magistrate in California vacated the Interior Department’s plan to delay implementation of rules curbing flaring of methane — the third time in three months that environmental rollbacks have been rejected by courts, according to a report in The New York Times. The administration also has withdrawn three rule changes in the face of legal challenges, the Times reported.
Consumer advocates on Thursday urged Congress to pressure FERC to improve the RTO stakeholder process and reject Energy Secretary Rick Perry’s directive to rescue at-risk coal and nuclear generation in competitive markets.
The House Energy and Commerce Committee hearing was called to consider consumers’ ability to participate in RTO/ISO decision-making. But the witnesses — and some Democratic committee members — also used the opportunity to tee off on Perry’s Sept. 29 Notice of Proposed Rulemaking, which would require RTOs to provide “full recovery of costs” for generators with a 90-day on-site fuel supply that are not subject to state or local cost-of-service rate regulation. (See FERC’s Independence to be Tested by DOE NOPR.)
Testifying before the House Energy and Commerce Committee Thursday were (from left) PJM Independent Market Monitor Joe Bowring; Rebecca Tepper, Consumer Liaison Group for ISO-NE; Mark Vanderhelm, Walmart; John Hughes, Electricity Consumers Resource Council;Stefanie Brand, N.J. Division of Rate Counsel, and Tyson Slocum, Public Citizen.
No one at the Energy Subcommittee hearing spoke in favor of Perry’s proposal, which called on FERC to develop a final rule providing RTOs with direction within 60 days. (Perry will be testifying before the committee next week.)
Consumer advocates from New Jersey and Massachusetts and representatives for Public Citizen and industrial consumers testified along with PJM’s Independent Market Monitor.
Slocum
Tyson Slocum, director of Public Citizen’s Energy Program, was the most critical witness, citing a “triple threat” to consumers posed by “political efforts by owners of mismanaged and uneconomic generation seeking subsidies; regional transmission organizations constructed to serve transmission and generator interests at the expense of the public interest; and a FERC that fails to uphold just and reasonable rate design, oversight and enforcement.”
No to Coal, Nuclear Subsidies
Slocum said Perry’s proposal “reads more like a President Trump tweet than a reasoned, serious policy proposal,” joining other witnesses in rejecting Perry’s claim of a resiliency “crisis.”
“Even more shocking than the Department of Energy’s proposal is FERC’s response to fast-track its consideration, with its order giving the public only 21 days to provide initial comments on the DOE rulemaking,” Slocum said.
Bowring
PJM Monitor Joe Bowring said the RTO’s market “has resulted in a reliable system despite significant changes in underlying market forces … [working] flexibly to address both market exit and entry without preferences for any technologies.”
He dismissed concerns over fuel diversity, saying PJM’s is higher than ever.
“There is no reason to intervene in the markets in order to provide reliability and resilience,” he said. Concerns over natural gas supply interruptions would be better addressed through “a careful evaluation [of] the reliability of gas pipelines, the compatibility of the gas pipeline regulated business model with the merchant generator market business model, the degree to which electric generators have truly firm gas service and the need for a gas RTO to help ensure reliability,” he said.
Hughes
John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents industrial consumers, said the NOPR would result in “the destruction of the competitive wholesale electric markets.”
By proposing out-of-market payments to prevent plant retirements, he said, “DOE is saying manufacturing jobs are not as important as the jobs at economically obsolete coal-fired and nuclear power plants — plants for which the market has already provided much more economic alternatives.
“We know that coal-fired and nuclear plants are not immune from so-called Black Swan events such as hurricanes, tornadoes, earthquakes and tsunamis,” he added.
Hughes said grid operators can ensure sufficient supplies of “essential reliability services” such as frequency response through markets and without subsidies.
He criticized FERC, saying it “backtracked from its policy to favor market-based solutions over command-and-control” when it issued a proposed rulemaking in November 2016 requiring all new generators to provide primary frequency response. (See FERC: Renewables Must Provide Frequency Response.)
A FERC spokeswoman said the commission had no response to the criticism at the hearing.
Mark Vanderhelm, Walmart vice president of energy, also made a plug for markets. “When we compare our cost per kilowatt-hour in 2016 to our cost per kilowatt-hour in 2007, we find that our cost in customer-choice jurisdictions decreased by almost 7% on average. In contrast, our cost in jurisdictions without customer choice increased by 14%,” he said.
‘Arbitrary’ Fuel Requirement
Slocum said DOE’s call for 90 days of on-site fuel was “arbitrary.” He noted that during Hurricane Harvey, the coal piles at NRG Energy’s W.A. Parish plant in Texas were so soaked with water that the plant switched two units to natural gas for the first time since 2009, and that Florida lost much of its nuclear generation during Hurricane Irma because of precautionary shutdowns and mechanical problems.
Green
Rep. Gene Green (D-Texas) noted that NRG’s San Jacinto natural gas plant kept operating despite receiving 47 inches of rain. “Natural gas was by far the largest [electric] provider during the storm, although I can also say our nuclear power plant in Southeast Texas continued to function very well,” Green said. “It’s frankly just not the case that increasing natural gas-fired plants is threatening reliability of the grid.”
Rep. Frank Pallone (D-N.J.) criticized what he called Perry’s “ill-conceived and wholly unjustified effort to commandeer” the FERC rulemaking process.
“Subsidizing noncompetitive generation for a small, if any, grid benefit at massive expense to consumers is wrong,” Rep. Paul Tonko (D- N.Y.) said. “And it definitely should not be done through a rushed process.”
Energy Subcommittee Vice Chairman Pete Olson (R-Texas) also indicated concern over the proposal, citing FERC Commissioner Robert Powelson’s speech to the Organization of PJM States Inc. (OPSI) annual meeting Wednesday, at which he stressed FERC’s independence and sought to reassure those who fear the rule would destroy competitive markets.
“[Powelson] said regarding concerns if the rule does undo competitive markets, quote, ‘When that happens, we’re done. I’m done,’” Olson recounted.
“Wow!” Olson added. “That is pretty strong.”
Commissioner Cheryl LaFleur seconded Powelson’s vow “not to destroy” the markets, tweeting, “Great message!”
Consumers’ Voice in Stakeholder Process
The witnesses were also critical of FERC’s and RTOs’ efforts on behalf of consumers.
BrandTepper
Stefanie Brand, director of the New Jersey Division of Rate Counsel, and Rebecca Tepper, chairman of ISO-NE’s Consumer Liaison Group, said RTOs should explicitly consider consumer costs in their policymaking and transmission planning, noting that generation and transmission costs account for 60% of customers’ bills in their states.
They said RTOs should provide dedicated funding to ensure consumer advocates can attend stakeholder meetings — as enjoyed by the Consumer Advocates of PJM States and the New England States Committee on Electricity.
Tepper, chief of the Massachusetts attorney general’s energy and telecommunications division, said RTOs should provide cost impact analyses on all major proposals and require that at least one RTO board member has “experience in consumer issues” or serves as a consumer liaison.
Slocum, who criticized RTOs as “political entities designed to serve entrenched economic interests,” called for increased transparency, saying stakeholder meetings should be recorded and transcribed and that RTOs be subject to the Freedom of Information Act.
He also called for splitting RTO functions to limit management’s role in stakeholder meetings; establishing a two-year “revolving door” prohibition on state regulators and utility executives going to work for an RTO; and barring entities under RTO jurisdiction from serving as financial sponsors of RTO special events.
He had specific criticism for PJM’s sector-weighted voting process, which he said appears “to be designed for the primary purpose of expanding the voting power of transmission owners and generators, and diminishing the voting power of end users.”
“End users actually represent half of the energy system, and should therefore represent half of the weighted sector voting rights,” he said. PJM’s consumers are grouped in the End Users sector, and receive a 20% weighting like the four other sectors: Transmission Owners, Generation Owners, Other Suppliers and Electric Distributors.
Asked to respond to the criticism, PJM spokesman Ray Dotter said the RTO saves consumers $3 billion annually and runs an “open and inclusive” stakeholder process.
“PJM’s governance is designed to ensure that no membership sectors have undue influence and has been approved by the FERC. At the same time, our independent board is empowered to act without the consent of members when it determines that market rule changes are necessary – and it has done so,” Dotter said in a statement. “Nevertheless, such rule changes must be considered and approved by the FERC.”
Transmission Spending
Pallone
Rep. Pallone asked Brand about a report released Sept. 29 by American Municipal Power that found more than half of the $24.3 billion in transmission projects in PJM since 2012 were supplemental projects initiated by TOs and not required to comply with RTO or federal reliability requirements. (See Report Decries Rising PJM Tx Costs; Seeks Project Transparency.)
Brand said the TOs propose supplemental projects “because they’re incredibly lucrative.”
“Returns on transmission are huge, so everyone wants to build whatever they can,” she said. “The need for the projects is not adequately reviewed at PJM. … The returns that are granted by FERC for transmission are completely off the charts. Some utilities are getting close to a 12% return on these projects, which in this economy is a bit crazy.”
FERC
Brand, speaking on behalf of the National Association of State Utility Consumer Advocates, said FERC also needs to do more to create “consumer friendly” proceedings. “Nearly all proceedings are conducted on paper, with limited opportunity for public input. Evidentiary and public hearings are rare. … There is no opportunity for cross-examination if factual certifications are submitted, and there is no oral argument on the legal or policy issues.”
Slocum repeated his call for FERC to provide funding for intervenors representing the public before the commission so that they can afford attorneys and expert witnesses.
CAISO is facing criticism over fundamental aspects of an initiative meant to keep needed generating resources from retiring prematurely, with state regulators saying the program will fail to meet its goals and others questioning the ISO’s rationale for the plan.
The ISO faces the challenge of aligning the risk-of-retirement program with resource adequacy (RA) contracting in order to prevent double-paying resources for reliability. Market participants have carefully analyzed the plan’s two proposed windows in April and November of each year to apply for a Capacity Procurement Mechanism Risk-of-Retirement Enhancements (CPM ROR) designation. (See CAISO Finalizes Risk-of-Retirement Program Changes.)
The La Paloma generating plant filed for bankruptcy in late 2016 after being refused permission to suspend operations | Kern County Public Health Services Department
In comments filed this week regarding CAISO’s draft final proposal for the program, the California Public Utilities Commission and Office of Ratepayer Advocate (ORA) said they oppose the current version of the initiative, which the Board of Governors is due to vote on at its Nov. 1-2 meeting.
PUC staff in comments said that inclusion of the April window within the CPM ROR process gives resources undue insight into RA program price discovery. The process must also better align with the ISO’s Reliability-Must-Run and Temporary Suspension of Resource Operations (TSRO) initiatives, the agency said.
The agency said it “remains concerned that moving a CPM ROR determination to a date prior to the conclusion of the year-ahead procurement process will result in front-running the RA bilateral procurement process.”
CAISO has altered the cost threshold requirement for obtaining a “Type 2” designation during the April window, rolling back a previous stipulation that a resource may not submit an ROR request for April unless its costs exceed the CPM soft offer cap. Type 2 refers to a request by an RA or a non-RA resource for designation in the calendar year following the current RA compliance year.
The latest proposal would require that a resource attest that it “reasonably believes” its annual fixed costs meet or exceed certain price thresholds.
But the PUC said that “this change to the proposal does not further mitigate the issue of front running the RA procurement process. If anything, it does the opposite because a generator no longer must demonstrate that its costs are above the soft offer cap, but to only attest that its costs exceed the relevant thresholds.” The agency said that resources could use market power to achieve the procurement vehicle that yields the most revenue.
‘Other Flaws’
The ORA said it does not support the proposal “because it is unlikely to effectively address the issue of early retirement of resources and could significantly increase ratepayer costs.” It said it believes that the program would allow resource owners to know if they are eligible for CPM payments before the RA contracting period begins. Because CPM generally pays more, that would unfairly tilt the bargaining process between load-serving entities and CPM resources.
“Other flaws of the draft final proposal include its failure to define resource retirement, its reliance on anecdotal information rather than a quantification of the currently known risks associated with resource retirements, and the proposal to provide capacity payments to resources before they are needed for reliability,” the ORA said.
The Western Power Trading Forum (WPTF) criticized fundamental elements of the proposal, saying it is struggling to see how the current proposal was not RMR with more obligations on the retiring resource.
WPTF said CAISO should introduce two windows to submit offers for CPM ROR designation “with no obligation to prove costs are above an artificial, irrelevant dataset.” It said the proposal to compare a resource’s costs with average RA contract prices is “ridiculous” since the average price has nothing to do with the current RA market in any one area.
Calpine said that while some resource owners may find the ISO’s modifications workable, Calpine does not.
“The time-crunch imposed on resources is only exacerbated when one imposes a ‘no front-running’ ban on backstop procurement,” Calpine said, calling it a “timing dissonance” that features in other CAISO retirement-related programs as well.
In March, the CAISO board approved the ISO’s request to designate two Calpine natural gas-fired plants in Northern California as RMR despite criticism from several stakeholders. (See CAISO RMRs Win Board OK, Stakeholders Critical.)
NRG’s Encina natural gas plant
While the company does not object to the plan, it does not think the program will be used in any meaningful way by resources making rational business planning decisions. Requests for compensation must be reviewed by FERC, so resources would not know their cost recovery until well into the CPM contract.
CAISO has also proposed that CPM designations become mandatory as RMR designations are, but Calpine opposes that change.
Some Support
The Six Cities group of Southern California municipal utilities said it generally supported the proposal, but suggested some modifications, while CAISO’s Department of Market Monitoring did not oppose it.
The department said the proposal allows resources to know earlier in the year whether they will receive a CPM designation, making it a more viable option for resources considering retirement.
“This is an improvement over the current risk-of-retirement CPM process which occurs too late in the year to be of practical use,” the department said. “Several aspects of the proposal reduce the likelihood that a resource will submit inefficient retirement requests.”
Southern California Edison supported the proposal, while Pacific Gas and Electric said it has “not addressed the current CPM limitations that resulted in using the CAISO reliability-must-run tariff provisions for reliability procurement.”
CAISO’s internal Market Monitor on Tuesday provided more details about rising energy prices in the second quarter and extreme day-ahead price spikes occurring over a three-day period during a June heat wave in the West.
The frequency of price spikes In the 15-minute market increased In the second quarter | CAISO
Day-ahead energy prices increased each month in the quarter because of high temperatures that drove up electricity demand, the ISO’s Department of Monitoring said during a stakeholder call Tuesday. The Monitor announced the second-quarter results last week. (See Monitor: CAISO Q2 Prices Hit Record Despite Mitigation.)
“We generally saw them increasing in terms of just seasonal conditions. It wasn’t out of the ordinary,” DMM Market Analyst Kyle Westendorf said. “With the higher temperatures, we saw the higher prices.”
Westendorf did shine more light on events that occurred over several days leading up to June 21, when day-ahead prices hit $600/MWh. His presentation showed that each day over June 18-21 saw less generation bid into the market below $100/MWh, with June 21 wind energy supply coming in below average and down from the previous day. Traders also bid significantly fewer virtual supply offers below $100/MWh into the market between June 20 and 21.
The Day-Ahead market system marginal energy price reached more than $600/MWh on June 21 | CAISO
“One of the things that was happening here, was participants engaging in convergence bidding were shifting away from virtual supply and more towards virtual demand positions in anticipation of higher real-time prices,” Westendorf said.
Convergence bidding refers to financial positions taken in the day-ahead market and liquidated with an opposite transaction in real time. It includes “virtual supply” that looks like a dispatchable energy resource to the market and “virtual demand” that looks like load.
Virtual demand, which is charged the day-ahead LMP, is considered a long position in the market, while virtual supply is paid the day-ahead LMP and is considered a short position. There is no physical transfer of energy in virtual bidding, which is a financial instrument.
Imports into CAISO also significantly declined between June 18 and 19, Westendorf said, and again between June 20 and 21.
“You start to see a pattern now,” he said, adding that the lack of imports was because of extremely high temperatures across the West, creating tight supply conditions across the region, affecting intertie activity and driving some of CAISO’s market results. The stress on the system of heat and high demand pushed the market software solution to a higher day-ahead price, he said.
The ISO and DMM are also investigating why energy prices increased on June 21 after mitigation was applied through computer software. The Monitor has said that, generally, prices should not rise after mitigation.
FERC on Tuesday approved a joint MISO–PJM proposal to create a new category of small interregional transmission projects intended to address historical congestion along the RTOs’ seams.
But the commission’s decision, which clears a path for developing five proposed interregional projects, was conditioned on the RTOs providing their stakeholders with more details about the decisions behind selecting so-called target market efficiency projects (TMEPs) (ER17-718).
In a related order, the commission also approved MISO’s plan for allocating TMEP costs within its footprint (ER17-2246).
FERC staff, in absence of a commission quorum, tentatively approved the TMEP project type in late June. (See FERC Tentatively OKs New MISO-PJM Project Type.) While the commission on Tuesday found the RTOs’ joint operating agreement language creating TMEPs to be mostly consistent with transparency principles in FERC Order 890, their ruling pointed to one missing detail: It did not spell out that stakeholders would “receive a sufficient explanation” about why the RTOs would recommend — or not recommend — a proposed TMEP to their respective boards.
“We find that stakeholders must have this information in order to play a meaningful role in the TMEP planning process and to allow them to monitor and provide feedback on how MISO and PJM are planning transmission projects to alleviate the congestion that is the subject of a TMEP study,” the commission wrote. “Failure to present this information to stakeholders may lead to more frequent after-the-fact disputes regarding the TMEP planning process.”
The commission ordered both RTOs to revise the JOA to show they will provide their Interregional Planning Stakeholder Advisory Committee with supporting explanations behind decisions whether or not to: (1) evaluate a potential TMEP that could economically relieve congestion at a particular flowgate; and (2) recommend an evaluated TMEP to their respective boards. The revision also must include a promise to disclose to stakeholders “any additional criteria used to evaluate potential TMEP solutions.”
MISO TMEP Cost Allocation Approved
The commission on Tuesday also approved MISO’s plan to internally allocate its share of TMEP costs to transmission pricing zones based on their historical contribution to the market-to-market congestion relieved by the project. MISO’s cost allocation also establishes minimum benefit thresholds guaranteeing that no zone will be charged for benefits estimated to be either $5,000 or less, or less than 1% of MISO’s share of the project’s cost.
FERC also accepted a provision stating that, during the Entergy transition period of integrating into MISO, transmission pricing zones within MISO South will not be allocated costs for TMEPs that terminate in other MISO areas or wholly outside the RTO.
“We find that this proposed limitation is generally consistent with the proposal the commission accepted for allocating the costs of new transmission facilities within MISO during [MISO South’s] transition period,” the commission said. “Given the limited duration of the transition period, we conclude that [the] proposal will not prevent MISO’s share of the costs of TMEPs from being allocated in a manner that is at least roughly commensurate with the benefits.”
FERC has not yet ruled on PJM’s regional cost allocation plan submitted in April (ER17-1406).
TMEPs at the Ready
TMEPs are designed to address cost-effective and congestion-relieving seams projects that might otherwise be overlooked because of their low cost and small size. To qualify, projects must cost less than $20 million, be in-service within three years of approval and provide historical congestion relief that is equal to or greater than construction costs within the first four years of operation. Construction costs will be divided among MISO and PJM based on the percentage of congestion relief benefits.
Five such TMEPs have been sitting in the pipeline for the better part of a year, representing $17.25 million worth of upgrades. They expect the projects to deliver a 5.8:1 benefit-cost ratio and realize $100 million in benefits within four years of going into service. (See MISO-PJM TMEP Projects Drop to Five.) Both MISO and PJM plan to ask for respective board approval of TMEP candidates by the end of the year.
MISO-PJM Coordinated System Plan Produces One Project
Meanwhile, MISO and PJM will this month wrap up their two-year coordinated system plan, and they see potential for one interregional project under the more expensive traditional market efficiency project type.
Thayer Morrison transmission project | MISO and PJM
Using their regional benefit criteria, the RTOs point to a new 30-mile, 138-kV line between Northern Indiana Public Service Co.’s Thayer and Morrison substations near the northern Indiana-Illinois border as the only potential interregional project to emerge from the study. NIPSCO expects the line to cost $42.5 million and be in-service by December 2022. If approved, MISO and PJM will split interregional costs based on each RTO’s benefit share and determine a regional allocation.
MISO is eyeing a June 2018 board recommendation for its portion of the project, as it doesn’t yet have in place a cost allocation method for sub-345-kV interregional projects. The RTO said it is “open to additional cost allocation methodologies” and is close to completing a study on a preferred regional cost allocation approach for the projects. For now, MISO has suggested allocating 100% of regional project costs to benefiting local resource zones or transmission pricing zones. MISO hopes to make a regional cost allocation filing with FERC in March 2018.
The U.S. Department of Energy’s proposed rescue plan for at-risk coal and nuclear plants could cost ratepayers $800 million to $3.8 billion annually through 2030, ICF analysts said Wednesday.
The analysts said the wide range is the result of considerable uncertainty about how FERC might implement the Notice of Proposed Rulemaking issued by Energy Secretary Rick Perry last week. The NOPR directed FERC to ensure that nuclear and coal generation in deregulated states with 90-days on-site fuel supply receive “full recovery” of their costs.
But ICF senior vice president Judah Rose said during a webinar Wednesday that he sees “a significant possibility” that FERC will take some action to address the secretary’s “resilience” concerns, especially in the wake of Hurricanes Harvey, Maria and Irma.
“DOE has rarely, if ever, exercised its authority vis-a-vis FERC in this manner. It is even more rare to act with such very tight deadlines — i.e. 60 days, and with such broad regional coverage — it applies to any ISO or RTO with an energy market (day-ahead and real-time) and any plant not subject to state rate of return regulation,” Rose and ICF principal George Katsigiannakis wrote in a blog post. “In the past, most NOPRs originated from FERC directly. Thus, past experience is not necessarily a good guide regarding handicapping the likelihood of implementation. Also, the political environment is without obvious precedent.”
The “lower bound” annual cost of $800 million ($6.6 billion net present value (NPV) at a 7% discount rate) assumes high natural gas prices, normal energy demand, and that units’ fixed operations and maintenance costs are partially recovered in the market.
The “upper bound” cost of $3.8 billion ($31 billion NPV) is based on an expectation of low gas prices and low energy demand with a minimum offer price rule for all regulated units.
The “lower bound” assumes high natural gas prices, normal energy demand, and that units’ fixed operations and maintenance costs are partially recovered in the market. The “upper bound” is based on an expectation of low gas prices and low energy demand with a minimum offer price rule for all regulated units. | ICF
Among the uncertainties, Rose said, is whether FERC seeks to provide cost recovery through energy prices, as proposed in the NOPR, or through capacity prices “because the service is to some degree more akin to a capacity service.”
One particularly important question is whether the rules will include mitigation of buy-side or sell-side market power, an issue not mentioned in the NOPR. If a large share of the generation fleet is subject to rate of service regulation, the analysts said, it could delay retirements and lower supply bids, reducing energy and capacity revenues for remaining units.
If coal plants have bid below costs in the past, prices could increase, but if mitigation is not pursued vigorously, market prices could decrease.
Impact on Gas, Renewables
By reducing coal and nuclear retirements, said ICF Managing Director Michael Sloan, the rule would likely reduce the development of new natural gas-fired capacity by 20 to 40 GW, leading to a reduction of gas demand of as much as 5 Bcfd by 2030, causing gas prices to drop by 4 to 7%.
One uncertainty: whether gas plants with firm pipeline contracts or access to underground storage or local production could qualify for cost recovery.
Renewable generation would be less impacted by the capacity market but could be affected by other FERC actions on price formation, such as restrictions on negative pricing.
The analysts said the NOPR also raised these questions:
Will the rules permit expansions at existing units or reopening of mothballed units? If expansions are allowed, how many megawatts?
Who will set the rate of return and what will be the amortization period?
Why is the NOPR restricted to RTOs and merchant plants? Given FERC’s role in ensuring reliability, “What showing, if any, do rate-of-return states have to show that they have the correct procedures in place to achieve resilience? Will this ultimately apply to all jurisdictional transmission providers?”
“This NOPR could have a major impact on the industry and markets, and could be a huge game changer for baseload plants. Timing is unclear along with most of the details. The only certainty is the uncertainty that this will create in the marketplace as the rule is developed and the details debated,” said the analysts, who questioned whether upcoming capacity auctions in ISO-NE (January 2018) and PJM (May 2018) and monthly auctions in NYISO will be delayed.
