WILMINGTON, Del. — PJM stakeholders appear ready and willing to explore carbon pricing in the RTO — a prospect that concerns utilities in coal-heavy states.
Michael Borgatti of Gabel Associates presented a first read of a problem statement and issue charge at the Markets and Reliability Committee meeting Thursday that would task stakeholders with creating rules to address carbon leakage and help states meet greenhouse gas reduction policies. Borgatti made the presentation on behalf of the Independent Energy Producers of New Jersey, which includes NextEra Energy and PSEG Power.
“Acknowledging the reality that some folks are pursuing these policies and others aren’t is not an indictment or an endorsement of either of those positions,” he said. “The conversation is being had whether we want to or not. We are not policymakers here. What we should do is consider options to make sure pricing reflects the difference between [those] pursuing these policies and those that are not.”
Many stakeholders expressed support for the initiative and said they looked forward to engaging in the process. Borgatti said he expected the initiative would take one to two years to consider policy changes.
“It’s one of those discussions that are in the hallways and the back of the room,” said Greg Poulos, executive director of the Consumer Advocates of PJM States. He said he supported the initiative, “so we can have a discussion in the front of the room.”
Gary Greiner of Public Service Electric and Gas also expressed support. “We agree it’s the right time to be in this, with [the Regional Greenhouse Gas Initiative] showing its head in New Jersey and Virginia.
In December, New Jersey Gov. Phil Murphy’s administration proposed rules to rejoin RGGI, which the state left in 2012 under Gov. Chris Christie. One proposal would set the state’s initial carbon dioxide cap for electric generation at 18 million tons in 2020 — when the return would be effective — declining by 3% annually through 2030. A second proposed rule concerns how the state would spend proceeds from the CO2 allowance auctions. The comment period on the proposals closed Feb. 15.
Earlier this month, Virginia Gov. Ralph Northam vetoed legislation that would have prevented his state from joining RGGI. Northam is pushing for the state to join the pact next year.
Only two PJM states, Delaware and Maryland, are currently RGGI members.
The problem statement refers to leakage concerns — changes to generator dispatch decisions that occur when energy offers from some resources reflect the cost of carbon while others do not. In addition to RGGI, it noted that New York and Canada are implementing carbon pricing.
Load interests expressed concern over the complexity and impact of carbon pricing given the diversity of climate policies in the 13-state RTO’s footprint.
“This is such a tricky issue because I think there are chicken-and-egg-type problems associated with it,” said Susan Bruce, representing the PJM Industrial Customer Coalition. “One concern right now … with the amount of change that’s occurring, we don’t know what we don’t know at this point in time, and that’s layering on an additional level of uncertainty.”
Carl Johnson of the PJM Public Power Coalition said the language in the problem statement suggests there’s already a solution for the issue.
“If the carbon price is zero and you don’t have leakage, then you don’t have to do anything,” he said. “If we are talking about just leakage, then I think we are fine. But if we start considering other issues, like resource adequacy, I can understand the hesitancy from nonparticipating states.”
American Electric Power’s Dana Horton noted that his company has many coal-fired generators and serves states that have not adopted aggressive climate policies. “We’re … concerned about what this might do to our customer base and their costs,” he said. “We have lots of reservations.”
Borgatti responded that the initiative is intended to ensure appropriate pricing in states with and without climate policies. “We’re talking about creating an option that the states don’t have today,” he said.
PJM’s Stu Bresler called the problem statement and issue charge “fortuitous.” The RTO issued a white paper in 2017 that explored ways to implement carbon pricing on a regional or subregional basis.
“I feel like the problem statement and issue charge is an ideal forum for feedback for what we can work into our process,” he said. “We support engaging stakeholders in this discussion because we were going to do this anyway.”
NEW ORLEANS — MISO’s most recent maximum generation emergency is yet another portent of its increasing need to rethink grid operations, executives told the Board of Directors last week.
Although it was better managed than the January 2018 MISO South emergency, the event demonstrates how the RTO has come to rely on intermittent resources subject to weather conditions and demand-based resources, which require a maximum generation event to access.
MISO Executive Director of Market Operations Shawn McFarlane said the Jan. 30 event in the Midwest seemed like a repeat of the extreme cold conditions a year ago.
Independent Market Monitor David Patton called the “highly regionalized” event an almost a mirror image of last year’s cold.
This time, however, McFarlane said MISO avoided the need for emergency purchases and was able to stay within the contractual limits of its transmission contract path while still accessing Southern capacity. The RTO estimated that both scheduled and voluntary load modifications, paired with school and business closings, reduced demand by 3 GW or more during the event.
Patton said MISO was able to effectively manage congestion during the event because of improved management of its market-to-market constraints with SPP and PJM.
Wind Forecast Lapse
But executives admitted a blind spot when it came to the RTO’s wind generation forecasting that day.
Last month, MISO pledged more study into generation cutoffs in extreme temperatures and how to account for voluntary load curtailments in load forecasting. It has said that “an earlier-than-expected drop in wind output increased insufficiency risk” early Jan. 30. Wind output during the morning peak was about 4 GW below MISO’s forecast as the worst of the cold struck the Midwest. (See “MISO Researching Generation Cutoffs, Voluntary Load Curtailment,” MISO Reliability Subcommittee Briefs: Feb. 27, 2019.)
Additionally, MISO said failed starts from conventional generation, uncertainty around the load forecast and risk of more outages contributed to the decision to call up about 2.5 GW worth of load-modifying resources (LMRs). Unplanned outages reached 29 GW on Jan. 30.
| MISO
Patton said MISO’s emergency offer pricing, which defaulted prices to above $600/MWh, was adequate to incent response. In fact, he said, it was even higher than needed because MISO’s extended locational marginal pricing couldn’t model accurately when to ramp up other online resources to displace emergency megawatts.
“Did you get that in the minutes?” MISO President Clair Moeller joked in response. Patton has long panned MISO’s emergency pricing as too low to properly rouse resources into action.
Director Barbara Krumsiek commended the RTO for keeping some less-than-economic units on to cover the failed starts of other generation. She said MISO’s commitment to public safety during the dangerous cold rightly eclipsed a focus on economics.
But she asked if the RTO’s lack of foresight on the cold weather wind cutoffs was a “new revelation” or simply an extreme temperature anomaly, unlikely to be repeated.
McFarlane said that while some turbines have cold weather packages, others must shut off to avoid blade damage, and MISO lacked insight on the specifics. Unfortunately, he said, wind generation in MISO North is clustered where the cold was the most extreme: Minnesota and western Iowa.
“We were relying on our [2014] polar vortex experience … and we expected 1 GW to drop off,” he said.
McFarlane said MISO has since instituted a general temperature cutoff assumption for wind generation. He said it will now hold conversations with wind operators to figure out more precise cutoff assumptions.
Director Baljit Dail asked if the emergency illustrates a need to rethink emergency preparedness altogether.
“Should we be thinking differently about the loss-of-load and reserve margin?” Dail asked.
Moeller said MISO’s ongoing research into resource availability and flexibility is just that — an investigation into loss-of-load risk in every hour of every day as opposed to an annual peak. None of MISO’s last three maximum generation events has occurred in the summer.
A bright spot, McFarlane said, is that half of MISO’s 12 GW in LMRs will be available in two hours or less in the upcoming planning year, thanks to FERC’s approval of rules requiring those resources to provide lead times they can consistently meet. Historically, only about 3 GW of LMRs were ready within two hours, McFarlane said. (See “LMR Registration Steady Despite New Requirements,” LSE Load Forecast Documents Incomplete, MISO says.)
“That will help significantly as we deal with tight conditions going forward,” he said.
Patton commended the better LMR response time. He said LMRs with up to eight-hour lead times are essentially “worthless” in an emergency.
“But in our LOLE [loss-of-load expectation] study, we model them as if they’re available,” he said.
MISO’s average winter load was 77.8 GW from December 2018 through February 2019, with a 101-GW peak occurring Jan. 30. The RTO said that except for extreme cold at the end of January, footprint temperatures were in line with historic norms over winter, which drove down load and congestion. As a result, prices averaged $28.41/MWh, a 6% decrease over the same time last year.
Evolving Resources, Evolving Operations
Richard Doying, executive vice president of market development strategy, said continued turnover in the resource stack and renewables growth will mandate operations changes in MISO.
“You’ve got a combination of factors that gives rise to changes in … grid operations,” Doying said, adding that “once upon a time,” it was much easier to dispatch the system.
“Some of these effects are already hitting us today,” Doying said in reference to MISO’s string of off-peak emergency events. “That flexibility is needed today … [and] we’re already seeing the consequences of these trends.”
To adapt, Doying said MISO has identified three areas of work: increasing the deliverability and availability of resources, bettering system flexibility, and improving its visibility of distributed energy resources.
“We know that there will have to be adjustments made to the market, but exactly what those are, we don’t yet know,” Doying said. He said the many possible solutions will be put to the stakeholder process. Fixes could include scarcity pricing, a 15-minute day-ahead market, more storage integration efforts, modeling smart inverters in planning, and collaboration with distribution operators so MISO can see DER contributions.
Dail asked if MISO was studying whether consumer costs could increase as it changes its market in response to trends.
“We’ve got [members] in economic distress,” he said.
Doying said MISO’s exploration of trends and grid response doesn’t include price effects but offered that market changes needed to maintain reliability would also maintain efficiency.
NERC Standards Committee Chair Andrew Gallo urged committee members Wednesday to file comments on Phase 2 of NERC’s Standards Efficiency Review before Friday’s deadline.
Gallo made his comments after Howard Gugel, NERC senior director of engineering and standards, presented an update on the review, which is considering retiring or consolidating administrative or duplicative standards.
The inquiry is considering changes in six areas of NERC’s Operations & Planning and Critical Infrastructure Protection standards, including evidence retention time frames, moving requirements to guidance, simplifying training requirements and consolidating data exchange requirements.
NERC held a webinar on the initiative Feb. 22 and accepted additional comments until Friday.
“I would really encourage all of the members of the Standards Committee … to please engage your folks in the process,” said Gallo, director of corporate compliance for Austin Energy. “It’s very rare that we [have] had opportunities to do a hard look at the standards.
“Everybody is so quick to [complain] about the standards … ‘[It’s] administrative. It’s burdensome. It doesn’t really help reliability,’” he added. “Those kinds of things you hear … all the time. Here’s our chance — let’s use it. This is a real good opportunity for us to try and do away with some of the things that are more administrative.”
Standards Grading Process on ‘Pause’
In a related matter, the committee agreed to “pause” work on the Standards Grading Process until May 2020 to avoid conflicts with other current initiatives with overlapping resources and scope.
In 2016 the SC created the Periodic Review Standing Review Team, composed of the chairs of the SC, Operating Committee, Planning Committee, a regional representative and NERC staff, to annually grade a selected set of standards.
Gugel said the initiative resulted from a charge by the Board of Trustees to develop metrics to signal whether revised standards have resulted in improvements. The 2017 review graded 47 requirements of eight standards.
“Given all the changes that we’ll be making with the Standards Efficiency Review, and potentially changes that would [be made] in Phase 2, we thought it would be a good idea this year to put a pause on that so we can concentrate our efforts, our focus, on the efficiency review,” Gugel said.
Cyber System SAR Approved for Posting
The committee accepted a Standards Authorization Request (SAR) and authorized a 30-day comment period and 30-day drafting team nomination period to consider standard changes to accommodate use of third-party “cloud” data storage providers.
The SAR was proposed March 1 by Tri-State Generation and Transmission Association on behalf of a sub-group of the Critical Infrastructure Protection Committee (CIPC) to consider use of encryption as a security measure under NERC BES Cyber System Information (BCSI) access management rules.
The project, which was endorsed by the CIPC on March 5, would consider changes to CIP-004-6 and CIP-011-2.
“The standard should allow multiple methods for controlling access to BES Cyber System Information, rather than just electronic and physical access to the [BCSI] storage location,” the SAR says. “As currently drafted, the requirement is focused on access to the ‘storage location,’ and therefore does not permit methods such as encryption and key management to be utilized in lieu of physical/electronic access controls.”
Functional Model Advisory Group Work Frozen
The committee agreed to direct the Functional Model Advisory Group (FMAG) to cease work pending deliberations on whether the group should continue or be eliminated to avoid confusion over registration requirements and related standards.
Created in 2014, the FMAG was tasked last year with aligning the terms and definitions in the Functional Model guideline with those used in NERC’s Rules of Procedure. It also was asked to solicit industry input on whether it should continue its work and make “more substantive” revisions to the FM to align with industry practices, NERC said.
At its December 2018 meeting, the SC endorsed the FMAG’s work on the first task but delayed publication of its report. At the same time, several SC members called for creating a small group of members from the NERC standing committees to consider next steps.
In February, the Standing Committee Coordinating Group (SCCG) agreed to form an ad hoc group of NERC staff, Compliance and Certification Committee leadership and SC leadership to map out plans for the FM. SC Chair Gallo instructed the FMAG to refrain from additional work until the ad hoc group makes its recommendations.
“What’s happened historically is, any time a change is made to the Functional Model, there are those who think it automatically changes registration, how standards are written. So, it’s caused a lot of angst,” explained Charles Yeung, SPP’s executive director for interregional policy. “It’s only changes to the registration criteria that can change entity registration.”
Gallo, a member of the ad hoc group, said he’d like the issue resolved quickly. “We don’t want this to languish very long. The Functional Model work has been going on now for a couple of years. It’s been stopping and starting and [moving in] fits and starts,” he said. “That’s not good for anybody.”
Revised Charter OK’d
Members approved a new committee charter, replacing the version last amended in December 2014 and reviewed and reaffirmed in December 2016. The revisions, which are mostly cosmetic or updates, were drafted by the SC Executive Committee and will be submitted to the board at its next meeting.
“I thought there were a lot of changes in here that didn’t really change anything,” commented Barry Lawson, associate director of power delivery and reliability for National Rural Electric Cooperative Association. “A few of the changes are substantive.”
Section 5.1 amends the timing for selecting the committee chair and vice chair, requiring nominations about 150 calendar days before the end of the expiring terms.
Another member expressed concern about the elimination of a section mandating at least two Canadian representatives. But NERC’s Gugel said the section was removed as duplicative because Canadian representation is protected in Rules of Procedure Appendix 3B.
Modifications Within SAR Scope
The committee agreed that making modifications to IRO-008-2 and TOP-001-4 are within the scope of the Project 2015-09 system operating limits SAR.
The Standards Drafting Team (SDT) requested the committee’s approval to make clarifying modifications to the two standards to ensure their consistency with proposed FAC-011-4 Requirement R6 regarding logging and reporting of system operating limits (SOL) exceedances.
The SDT is modifying FAC standards that address SOLs and interconnection reliability operating limits (IROLs).
SDT member Stephen Solis, of ERCOT, said several entities have market mechanisms for addressing projected post-contingency exceedances identified in real-time assessments and generally can mitigate them within minutes.
Solis said the revised rules would give entities up to 30 minutes to address the issue before having to report an exceedance to its reliability coordinator or transmission operator (TOP).
Under proposed FAC-011-4 R6, if a TOP’s real-time assessment indicates that a contingency would cause a facility to exceed its emergency rating, it would constitute an SOL exceedance, triggering logging and other documentation requirements.
Several entities have complained that the requirement creates an undue burden for logging, communicating with the RC and creating audit-ready compliance documentation, Solis said. They said the unnecessary logging and communications would divert system operators’ attention from operating the system, creating an increased reliability risk.
“We can’t lower what the requirements are, but we can clarify what the requirements are,” Solis said. “Solidify for everybody what is and is not an SOL exceedance.
“If you’re a TOP and you see a voltage limit exceedance, you can [perform switching] in 30 seconds to a minute,” Solis said. “Why [should] you then [have] to call your RC right after these normal-type operating actions that happen throughout every day?”
Participant Conduct Policy
NERC Senior Counsel Lauren Perotti briefed the committee on NERC’s new Participant Conduct Policy, which spells out acceptable (e.g., discussing issues) and unacceptable (e.g., engaging in price fixing, using NERC for commercial purposes) conduct at stakeholder meetings.
The policy will replace individual policies previously adopted by the SC and Operating Committee. It applies to all NERC standing committees.
“The whole point of us putting this together was to promote an efficient and effective use of our participants’ time. NERC relies on its stakeholders to achieve its mission,” Perotti said.
The rules bar members using NERC’s listserv to express personal views unless they are directly related to the scope of work. “‘I really hate XYZ politician’ is not appropriate,” Perotti said.
Perotti said that when stakeholders speak to news reporters, they should specify that they are speaking for themselves or their company and not for NERC.
FERC last week dismissed a Louisiana city’s complaint that Cleco Power collected $6.7 million in excess revenue last year because its rates did not immediately reflect the 2018 federal corporate income tax cut (EL19-6).
The city of Alexandria’s October complaint asked FERC to require Cleco to flow back to transmission customers excess accumulated deferred income tax (ADIT) collected from January to May 2018.
But FERC on Thursday said the city filed its complaint too late and in the wrong docket. But even without the procedural deficiencies, the commission said, it would not have granted Alexandria’s request because Cleco’s rates use historical test year costs as a “reasonable proxy” for rate collections and there is no true-up mechanism to ensure recovery of actual costs.
Cleco’s annual transmission revenue requirement (ATRR) is based on a rate year of June 1 through May 31. Cleco used the 35% federal income tax rate in its May 31, 2017, ATRR update for its 2017 rate year and replaced it with the 21% in its filing for the 2018 rate year.
Alexandria contended that because the lower tax rates took effect Jan. 1, 2018, Cleco over-collected its transmission rates by $6.7 million for the last five months of the 2017 rate year, with the city overpaying by $271,000. It called the amount “a permanent windfall” to Cleco.
Alexandria, La. | Alexandria Office of the Mayor
The company responded that it “would be a violation of the approved historical test year approach” if it included cost increases or decreases that occurred outside the test year.
Cleco also said Alexandria was seeking to “cherry-pick” a single declining cost in its transmission formula rate, while ignoring other costs that increased. For example, Cleco said its transmission wages increased by 13% in 2017 because of additional hires but that it did not attempt to recover the increased costs in the ATRR until the 2018 rate year.
FERC agreed: “Due to this nature of Cleco’s transmission formula rate, Cleco may under-collect or over-collect various costs during a given rate year.”
MISO requires all transmission owners’ rates return or recover excess or deficient ADIT from customers as a result of tax law changes. But FERC said that requirement doesn’t speak to the precise timing of when the new rates must take effect.
“Cleco’s template calculates a single ATRR for the entire rate year. There is no provision in Cleco’s template for a partial year ATRR calculation, nor is there a provision to calculate the ATRR for a given rate year using two different federal corporate income tax rates,” FERC said. “The change in the federal corporate income tax rate that took effect on Jan. 1, 2018, was unknown when Cleco prepared the annual update for the 2017 rate year.”
Additionally, FERC pointed out that there is no provision in Cleco’s rate rules that it must recalculate ATRR if a tax change takes place during a rate year.
The commission also said Alexandria failed to file its challenge in time under Cleco’s rate rules. Alexandria submitted its informal challenge with Cleco after the Jan. 31, 2018, deadline and its formal challenge with FERC after the April 15, 2018, deadline. “Further, Alexandria did not file the formal challenge in the same docket as Cleco’s informational filing of its 2017 annual update” (ER18-999), FERC said.
The Gulf Coast Power Association will honor former Executive Director Tom Foreman with its 2019 Pat Wood Power Star Award during its spring conference in Houston next month. The award is presented in recognition of the recipient’s “significant contributions towards the advancement of [Texas’] competitive energy markets.” Foreman retired as GCPA’s executive director last year, capping a 41-year career in the utility industry. (See GCPA’s Foreman to Retire as Executive Director.)
“Throughout his long career in the Texas power market, Tom Foreman has been a thoughtful, inclusive, creative and loyal friend to so many of us,” said the award’s namesake, former FERC Chairman Pat Wood III. “Under his leadership, the GCPA has grown to its largest and most diverse membership in history. Tom Foreman is an exemplary Power Star.”
Foreman served as the organization’s third executive director from 2013-2018. During his tenure, GCPA launched its emPOWERing Women program and expanded the organization’s geographic reach with conferences for electric markets in states and countries bordering Texas that are evolving competitively. The association will hold its fourth Mexico Electric Power Market Conference on June 6 in Mexico City. GCPA also donated approximately $500,000 to universities during Foreman’s tenure.
Tom Foreman | GCPA
“Tom has done an outstanding job by expanding into other regions, establishing the emPOWERing Women program and growing the scholarship program,” said Kim Casey, who succeeded Foreman as executive director.
Foreman began his career at Gulf States Utilities in Beaumont, Texas. He consulted in Austin before spending 23 years with the Lower Colorado River Authority, followed by his six-year stint with GCPA. He holds bachelor’s and master’s degrees in engineering from the University of Texas at Austin.
Wood, who also chaired Texas’ Public Utility Commission under Gov. George W. Bush, will be on hand to help present the award during GCPA’s 33rd annual Spring Conference April 16-17.
WILMINGTON, Del. — Stakeholders on Thursday reluctantly agreed on a path forward for PJM’s proposed “fuel security” initiative after about two hours of debate over whether RTO officials have already decided the outcome.
The Markets and Reliability Committee approved a compromise problem statement and issue charge, adding a requirement that PJM quantify the likelihood of scenarios that might present a risk of fuel insecurity.
Stakeholders also rejected PJM’s proposal to complete work on the issue by the end of the year. Instead, stakeholders will complete their initial research by the end of August and the MRC will set a final deadline for action — if any — at its September meeting.
Members also added language to the issue charge to consider the market responses to conditions that could lead to fuel insecurity and assess whether the current market construct is sufficient to cure the problem.
The compromise was approved by acclamation with one objection.
‘Stress Test’
Critics have complained the initiative is yet another effort to provide additional compensation to coal and nuclear generators, following failed efforts by President Trump and Energy Secretary Rick Perry.
PJM issued a study last year that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said. (See Full PJM Study Makes Case for Fuel Security Payments.)
Marji Philips, Direct Energy
Marji Philips of Direct Energy said PJM’s proposed December 2019 filing deadline was “suspicious.”
Philips said she agreed on the need for an end date but said the 2019 target “tells me it’s not going to be a meaningful process.”
Bob O’Connell of Panda Power Funds said a “fundamental flaw” in PJM’s proposal is that its analysis made no effort to quantify the risk of the dire scenarios it outlined. He disputed the RTO’s claim that all of its scenarios are “plausible.”
“Many of us … believe that the risk of some of these scenarios is a decimal point, six zeroes and a one,” he said.
O’Connell also disputed PJM’s assertion that it has not identified any solution.
Bob O’Connell, Panda Power Funds
He cited an interview PJM CEO Andy Ott recently gave to Bloomberg in which he said the region’s gas units have 30 to 40 hours of backup fuel and that “what we need them to keep is about five days.”
“That sounds like a solution to me,” O’Connell said. “What’s left for the stakeholders is just fighting over how to pay for it.”
PJM’s Tim Horger said later that incorporating a probabilistic analysis would be “challenging.”
“I don’t know if it’s feasible,” he said.
Tim Horger, PJM
Jim Wilson, a consultant to state consumer advocates, also expressed skepticism about such an analysis. “Probabilistic analyses usually rely on historical data. [The fuel security analysis] is based on events that have never occurred,” he said, citing an example of a terrorist attack on a natural gas pipeline.
“I don’t think we should focus a lot of effort on this … because it will necessarily rely on speculative assumptions,” he said.
Philips and David “Scarp” Scarpignato of Calpine questioned the value that fuel-secure nuclear plants bring the RTO when they often shut down in advance of a major storm.
Jason Barker of Exelon said the issue of nuclear shutdowns is irrelevant.
Jason Barker, Exelon
“It mixes reliability analysis and PJM’s request to address fuel security,” he said. “If this [inquiry] becomes too broad, we’re setting ourselves up for failure.”
Paul Sotkiewicz, PJM’s former chief economist, said the RTO’s study predicted load shed could result from an “inordinate amount” of plant retirements but failed to consider how the market would respond to so many plant closures.
“None of that analysis has been done,” he said. “The current market design may be able to handle this under Capacity Performance.”
Ott Interview
In the interview on Bloomberg’s “Commodities Edge” show, Ott said the initiative should determine the cheapest way to provide the security of natural gas plants with five days of backup fuel.
“What the vulnerability is … the gas units keep about 30 to 40 hours of onsite fuel. What we need them to keep is about five days. So the point is there’s got to be an infrastructure build if we’re going to use those resources as firm fuel supply resources. … Either larger on-site fuel storage, or we buy more fuel trucks to say they’re on standby essentially to deliver fuel more dependably in the winter.
“The other alternative, of course, is to say what’s that money spend, and is it cheaper than to keep the nuclear plant or keep the coal plant? … It’s going to be an economic decision, and the best technology will win.”
Ott said PJM expects 18,000 MW of coal retirements over the next five years and could sustain as much as 30,000 MW. “If it gets beyond that, we start to look at what are the alternatives?
“A gradual transition we can easily deal with over time. What folks are worried about, and what the U.S. federal government is worried about, is if there going to be an abrupt change.”
Wilmington, Del. — PJM on Thursday offered stakeholders four options for navigating its upcoming capacity auction, noting that each comes with risks and uncertainties.
“We are in a bit of quandary,” said Stu Bresler, PJM’s vice president of operations and markets. “There really are no obvious good answers as to how we can move forward at this point. I think it falls into the lesser of two evils category.”
Bresler’s comments come on the heels of PJM’s filing with FERC urging guidance for the Aug. 14 Base Residual Auction, given a previous commission decision that the RTO should revamp its minimum offer price rule (MOPR) to address price suppression resulting from rising state subsidies for renewable and nuclear power (ER18-2222). PJM filed changes in October and had hoped for a FERC response by March 15 to no avail. (See PJM to FERC: Hurry Up with Auction Guidance.)
“Absent from any other order from FERC in this regard, we are obligated to follow the Tariff,” Bresler told the Markets and Reliability Committee on Thursday.
The Choices
Bresler presented the four paths PJM staff identified as viable and solicited feedback from the MRC on each of them, including:
Move forward with existing rules and accept the possibility that FERC will retroactively apply new rules, forcing PJM to rerun the August BRA.
File a waiver with FERC to delay the BRA until closer to the May 2020 auction, noting FERC has no timeline for ruling on such a request.
File a request for FERC to confirm existing rules for the interim, eliminating the risk of re-rerunning the auction after the commission decides on the MOPR. Bresler noted this option has very little chance of success.
Present an alternative interim rate in a Section 205 filing that would sunset after the August BRA, eliminating the risk of having to re-execute the auction at a later date. This type of filing bakes in a 60-day timeline for FERC to issue guidance but may require stakeholders to follow a “parallel path” in case FERC denies the filing.
Bresler said staff will return to the April 10 meeting of the Market Implementation Committee with its agreed-upon path forward.
“I don’t think there’s a drop-dead date [for delaying the auction],” he said. “But with some of these other options, the sooner the better.”
Stakeholders Torn
The anxiety expressed by stakeholders at the March 6 MIC meeting carried forward into Thursday’s MRC, with representatives across the board abandoning hope of a short-staffed FERC offering guidance anytime soon. (See FERC’s McIntyre Loses Cancer Battle.)
“One of the things we keep going back to is the uncertainty of when actual action will be taken,” said Neal Fitch, of NRG Energy, noting a fifth commissioner — capable of breaking any deadlocked rulings — has yet to be named. “We think it’s right to move along with an auction in August … simply because we have no idea when FERC will act.”
Others argued that delaying the auction until next spring remained the only prudent choice and appeared unconvinced by PJM’s assessment that FERC is unlikely to force the RTO to re-execute the auction under new rules. The commission in January ordered PJM to rerun the July 2018 FTR auction to liquidate GreenHat’s FTR positions, which could add $250 million to $300 million to the already $186 million projected cost to members from the default. Last month, the RTO requested a stay of that ruling. (See PJM Won’t Act on FTR Order Before Stay Ruling.)
Carl Johnson, representing the PJM Public Power Coalition, argued delaying the auction could impact the market negatively.
“Without any guidance from FERC, you’re shooting in the dark,” he said. “I think the idea of putting together some interim [Section] 205 [filing] bridge to justness and reasonableness might have some attraction.”
WASHINGTON — FERC Chairman Neil Chatterjee on Thursday praised former Chief of Staff Anthony Pugliese, denying there had been any conflict between the two but also staying mum on the reason for his departure from the commission.
“I want to thank Anthony for his friendship, for his willingness to serve the agency and the country, and we wish him well in his future ventures,” Chatterjee said at the beginning of the commission’s monthly open meeting.
Pugliese announced his resignation via Twitter the day before, saying he was “grateful for the opportunity to serve [President Trump], [FERC] and the American people as chief of staff! Excited for my next challenge and opportunity — continuing the American model of energy for the world. Stay tuned! But first a little time for a vacation!”
Following his tweet, FERC made its own announcement, saying Pugliese’s resignation was effective March 15. In a press conference after the meeting, Chatterjee told reporters that he was planning to make the announcement himself during the meeting, but “I think some of you all maybe were starting to ask questions, [which] prompted his tweet.”
Chatterjee was reluctant to talk about the circumstances around the departure. But, he said firmly, Pugliese “was not asked to leave.” He declined to comment on the search for a replacement.
Pugliese told Politico on the day of his announcement that he had been planning on leaving since Commissioner Kevin McIntyre’s death in January.
A former lobbyist in Pennsylvania’s capital and an unsuccessful state legislative candidate there, Pugliese had served as chief of staff since August 2017, before the arrival of McIntyre as chair in December of that year. He stirred controversy last July for remarks he made at a conference of the American Nuclear Society and on the “Breitbart Radio Show,” in which he praised Trump and criticized Democratic governors for blocking pipelines.
In a letter to congressional Democrats, McIntyre defended Pugliese, saying his comments did not reflect FERC policy. After taking the role of chair because of McIntyre’s ailing health, Chatterjee in late October also defended Pugliese. Both praised Pugliese’s management and administrative skills. (See Returning Chair Pledges to Protect FERC’s Independence.)
Asked if his relationship with Pugliese had “deteriorated,” Chatterjee responded, “Look, Anthony is a personal friend of mine, and I don’t agree with that characterization.” He also declined to say what, if any, disagreements led to the resignation, repeating that Pugliese was a friend and that he wished him well.
Coal, Nuke Bailout Still Alive
Chatterjee also said he had never had any conversations with the White House during his nomination process about the Trump administration’s push to bail out uneconomic coal plants.
The question came in response to a Politico article published Tuesday reporting that Trump had dropped plans to nominate former NRG Energy General Counsel David Hill to fill McIntyre’s spot after pressure from Energy Secretary Rick Perry and coal company executives Joe Craft and Robert Murray. Hill, who was DOE general counsel under former President George W. Bush, had opposed the DOE’s effort to support coal generators.
The article came the same day the White House published its annual economic report, which contained a paragraph about “the strategic need for an electricity generation reserve.”
“The entire portfolio of generation assets in the United States could be eligible to be part of a reserve, with different strategic weights placed on various types of generation — for example, nuclear or coal-fired generation might provide greater resilience benefits and therefore be preferentially selected into the reserve,” the report says.
WASHINGTON — FERC will seek comments on how it could improve its transmission incentives and return on equity policies under two Notices of Inquiry issued Thursday.
The commission will examine whether transmission incentives “should continue to be granted based on a project’s risks and challenges or … on the benefits that a project provides,” FERC said at its monthly open meeting (PL19-3).
Under the other inquiry, the commission will examine whether, and if so how, to change how it calculates ROEs for electric infrastructure, as well as for natural gas and oil pipelines (PL19-4).
“Given the complexity and scale of building new transmission projects, the decisions my colleagues and I make now will have impacts for decades to come,” FERC Chairman Neil Chatterjee said. “What all this boils down to is [that] getting these policies right will be critical to ensuring the energy revolution we’re currently undergoing results in more reliable services and lower prices for customers. To that end, I think the two NOIs we are issuing today are an important step toward getting our transmission policies right.”
Initial comments on both NOIs are due 90 days after their publication in the Federal Register, with reply comments due 30 days after that.
FERC noted in its transmission incentives policy NOI that 13 years have passed since it established its current policy in Order 679, after Congress in the Energy Policy Act of 2005 directed the commission “to promulgate a rule providing incentive-based rates for electric transmission for the purpose of benefiting consumers through increased reliability and lower costs of power.”
“During that time, the landscape for planning, developing, operating and maintaining transmission infrastructure has changed considerably,” FERC said, including issuance of Order 1000, the shift in the generation mix, the increase in the number of new resources seeking transmission service, shifts in load patterns and an increased emphasis on the reliability of transmission infrastructure.
“I believe we are really at an inflection point in the energy future of our nation, and FERC’s transmission policies are going to be key to shaping that future,” Chatterjee said.
Order 679 required “that each applicant demonstrate that there is a nexus between the incentive sought and the risks and challenges of the investment being made.” FERC asked stakeholders whether it should stick with this “risks-and-challenges” approach, if it should be retained while also considering other factors, or if it should just be replaced entirely. The commission asked stakeholders to weigh in on other approaches, such as considering the economic and reliability benefits of a project or considering project characteristics (such as location in areas of persistent need or interregional efforts) as a “proxy” to benefits.
Commissioner Cheryl LaFleur said she was particularly interested in comments on the transmission-only company and RTO participation adders, and on the interplay between the incentives policy and Order 1000.
“I do believe there’s a clear need to construct more transmission to ease the interconnection of location-constrained renewables,” LaFleur said. “And I think that’s evidenced by the choking interconnection queues in several of the regions, suggesting there might be transmission that’s needed rather than just hundreds of interconnections, and we have to make sure the processes support that.”
“It is not clear to me that in some cases the incentives we are handing out are actually incenting anything,” Commissioner Richard Glick said. “If we’re going to design the right approach, we need to be reasonably certain the incentives are necessary or whether the investments in question would occur anyway. In other words, we shouldn’t be handing out what some people refer to as ‘FERC candy’ without actually achieving something beneficial in return.”
The NOI on the commission’s ROE policies comes in response to the D.C. Circuit Court of Appeals’ 2017 ruling that remanded a FERC order setting the base ROE for a group of New England transmission owners at 10.57%. (See Court Rejects FERC ROE Order for New England.)
FERC set the ROE at the midpoint of the upper half of the zone of reasonableness produced by a two-step discounted cash flow (DCF) analysis. In Emera Maine v. FERC, the court found that FERC had failed to show how this was just and reasonable, though it did not challenge the commission’s methodology. Nevertheless, in October, FERC proposed a new policy for how it would set transmission ROEs, suggesting it would no longer rely solely on the DCF method. (See FERC Changing ROE Rules; Higher Rates Likely.)
The NOI issued Thursday will take a much broader look at FERC’s ROE policies, including whether any changes to its transmission ROE policies should be applied to interstate natural gas and oil pipelines. The commission noted that the NOI won’t affect the docket it opened in October, nor other current ROE proceedings.
“The commission recognizes the potentially significant and widespread effect of our ROE policies upon public utilities,” FERC said. “The importance of ROE policy for public utilities extends beyond the particular interests of the parties to the Emera Maine proceeding.”
FERC asks more than 70 questions in the NOI. In a press release, it divided them into eight general areas:
The role of FERC’s base ROE in investment decision-making and what objectives should guide the commission’s approach;
Whether uniform application of FERC’s base ROE policy across the electric, natural gas pipeline and oil pipeline industries is appropriate and advisable;
The DCF model’s performance;
The composition of proxy groups;
The choice of financial model used;
The mismatch between market-based ROE determinations and book-value rate base;
How FERC determines whether an existing ROE is unjust and unreasonable under the first prong of FPA Section 206; and
The mechanics and implementation of the models.
“The questions we ask are extremely detailed and comprehensive, and this has been a notoriously difficult area of our work, around which to develop a consensus and sustain in court,” LaFleur said. “I strongly encourage commenters to be focused and concise in their comments.” She stressed that commenters need not answer every single question.
FERC on Thursday ordered MISO (ER18-2397) and SPP (ER18-2318) to make additional Tariff changes to comply with the transparency requirements of Order 844 while approving PJM’s filing (ER18-2401).
Order 844, issued in April 2018, requires RTOs and ISOs to submit monthly reports detailing their uplift payments and operator-initiated commitments. The commission said that existing reporting practices were insufficiently transparent and caused unjust and unreasonable rates. (See FERC Orders RTOs to Shine Light on Uplift Data.)
PJM 2018 energy uplift credits changes by category, and change from 2017 | Monitoring Analytics
MISO Order
The commission disagreed with MISO’s decision to exclude price volatility make-whole payments from its zonal uplift and resource-specific uplift reports.
“We understand MISO’s argument to be that price volatility make-whole payments are not classified as uplift in Order No. 844 because they are not triggered by a specific reliability need. However, we disagree that such a narrow definition of uplift was implied by the statement in Order No. 844 that ‘uplift payments reflect the portion of the cost of reliably serving load that is not included in market prices.’”
The commission said the payments — intended to maintain resources’ incentives to follow dispatch signals and operator instructions — are uplift “because they provide economic incentives to resources to operate in a manner consistent with system needs at costs that are ‘not included in market prices.’”
It also directed MISO to replace the word “uplift,” which is not a defined term in the Tariff, with terms describing types of uplift that are defined, such as the day-ahead revenue sufficiency guarantee credit.
The commission agreed with MISO’s decision to use local resource zones (LRZs) — which are used to settle charges under the RTO’s resource adequacy process — for reporting purposes. But it said the RTO needs to explain how it will account for uplift paid to imports.
“We direct MISO to explain on compliance whether the commercial pricing nodes associated with imports are located within LRZs and how it intends to report uplift associated with an import if its commercial pricing node does not exist within a LRZ,” FERC said.
The commission also ordered MISO to amend its Tariff to include “as soon as practicable” similar language to describe the notice issued to market participants for temporarily changing transmission constraint penalty factor (TCPF) values.
FERC rejected a request by the Louisiana Energy Users Group and Texas Industrial Energy Consumers to require MISO to report by categories in its resource-specific uplift report. The industrial users contended that aggregating all uplift payments by resource does not provide enough information about the resource locations to address day-ahead voltage and local reliability (VLR) problems in MISO South.
The groups said the 90-day delay in releasing resource-specific data would protect competition and individual market participants.
FERC agreed with MISO that reporting on categories was not required by Order 844 for the resource-specific report.
SPP Order
The commission accepted part of SPP’s compliance filing but rejected other parts and directed it to make a further compliance filing within 30 days.
FERC found that the RTO’s proposed changes to its zonal uplift report partially complied with Order 844 requirements in that SPP would compile and post make-whole payments categorized by settlement area within 20 days of a month’s end. FERC also accepted a proposal to divide the report by settlement area, saying it “conforms to the commission’s definition of ‘transmission zone’ and provides an appropriate level of geographic granularity.”
But FERC said SPP’s filing didn’t specify what uplift categories it would report “and thus does not reflect all the uplift that SPP intends to report in compliance.” The commission said the proposed Tariff language indicated the report would be broken out by day, and it directed SPP to include the uplift types it will report and to note the report will be broken out by day in the compliance filing.
The commission said SPP’s proposed changes to the resource-specific uplift report also only partially complied with Order 844 because specific uplift categories would not be included in the report, leaving it incomplete. It directed the RTO to modify its Tariff changes to include resource-specific uplift categories.
While FERC agreed with many of the changes to SPP’s operator-initiated commitment report, it said the report did not meet requirements to include all commitments made for a reason other than to “minimize the total production cost of serving load.” The RTO contended that its reliability unit commitment processes minimize total production costs, but the commission disagreed, pointing to SPP Tariff and protocols that “make clear” that RUC processes minimizing total commitment costs are only a subset of total system production costs.
The commission directed SPP to revise its Tariff to include in the report commitments made under its day-ahead, short-term and intraday RUC processes. It found that SPP’s proposal to average the economic minimum across the commitment period does not comply with Order 844, saying the plan “provides less transparency into the size and timing of a system need.”
FERC also found that SPP’s Tariff revisions to TCPFs did not comply with requirements to enumerate any procedures by which factors may be temporarily changed. The commission said SPP conducts an annual review to consider changes to the factor values, but that the process does not address the “temporary, potentially intraday changes to those values.”
“Accordingly, we direct SPP to … clarify whether it temporarily changes its transmission constraint penalty factors,” the commission said, ordering SPP to revise the Tariff to include the procedures for temporarily changing those values and show its intention to provide notice to market participants as soon as practicable.
PJM Order
The commission approved PJM’s compliance filing with few substantive changes.
It rejected the Independent Market Monitor’s claim that PJM’s proposal to identify demand resources and economic load response participants by number, not name, did not comply with Order 844. The Monitor said the names of these resources are not confidential because they are publicly available through the Energy Information Administration and that demand resources should not be able to mask their identity when other participants are transparent.
The Advanced Energy Management Alliance countered that the Monitor’s recommendation would compromise competitive information, noting curtailment service providers’ investments in identifying and recruiting customers.
The commission ruled that PJM’s proposal to report the identification number of demand resources and their location “provides the same level of geographical granularity as there would be if PJM used specific resource names.”
The commission differed with the RTO’s interpretation that the definition of operator-initiated commitment is limited to new commitments that are brought online from an offline status.
FERC agreed that PJM does not need to report commitment extensions ordered to minimize total production costs during periods of price volatility. But it said “manual adjustments by PJM to increase or decrease the amount of committed capacity, or to extend the commitments of units that are currently running beyond the hour for which they were committed by PJM’s [security-constrained economic dispatch] software (i.e., a process to minimize total production costs), must be included in the operator-initiated commitment report, if those commitments are made for noneconomic reasons.”
The commission also rejected the Monitor’s request to require that PJM report the end time as well as the start time of operator-initiated commitments. It also rejected the Monitor’s request to require PJM to disclose operator-initiated commitments cleared before the day-ahead market closes, calling it “a collateral attack” on Order 844.
“In the Notice of Proposed Rulemaking, the commission considered including day-ahead must-run generation in the definition of operator-initiated commitments. However, after considering concerns that day-ahead must-run generation clears the day-ahead market on the basis of reliability and economics, the commission modified the definition to explicitly exclude these commitments,” FERC said. “The IMM did not seek rehearing on the definition of operator-initiated commitments.”
The Monitor also sought clarification that no rules prohibited it from reporting uplift data itself.
“While Order No. 844 does not apply to market monitors, we find that the IMM is not precluded from continuing to report uplift data … in the IMM’s State of the Market reports, to the extent this information does not violate the confidentiality provisions of the Tariff and Operating Agreement,” FERC said.
