FERC last week opened settlement proceedings to address a two-state complaint against an Entergy subsidiary’s proposed return on equity for nuclear power sales to four other company affiliates.
Utility commissions in Arkansas and Mississippi earlier this year filed a protest claiming that the ROE used by System Energy Resources Inc. (SERI) in its current formula rate for energy sales from the Grand Gulf nuclear plant is excessive and outdated. They’ve asked FERC to open an investigation to determine the fairness of the return.
SERI owns 90% of the 1,400-MW facility in Port Gibson, Miss., and sells the plant’s output under a FERC-regulated wholesale rate to Entergy Arkansas, Entergy Mississippi, Entergy Louisiana and Entergy New Orleans under a power sales agreement.
The commission said it will forward the matter to a still-unnamed administrative law judge who will oversee settlement discussions and report whether parties can negotiate a fair ROE. Barring a settlement, the issue would move to a trial-type evidentiary hearing (EL17-41).
Regulators from the two states contend that Grand Gulf should sell its energy to Entergy affiliates at cost-based rates “to avoid overcharging retail customers.” They point out that SERI’s current ROE of 10.94% was calculated using an average of three discounted cash flow analyses produced in 1996 and seek to reduce the figure to 8.5%, in part reflecting a reduction in income tax from $125 million to $97 million.
A “re-examination of [the] current cost of equity is more than due,” the two states argued, especially considering that the Nuclear Regulatory Commission last year extended Grand Gulf’s license another 20 years, until 2044.
In opening the proceeding, FERC brushed aside SERI’s argument that its existing ROE falls into the “zone of reasonableness” and does not require adjustment. The commission said it “has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE.”
Depreciation Rates also Under Review
The proceeding will also include an examination of SERI’s depreciation rates for Grand Gulf.
In a separate August FERC filing prompted by the license extension, SERI sought to revise Grand Gulf’s depreciation rates to an average 2.66% under the same power sales agreement for the four Entergy utilities (ER17-2219). The current 2.85% depreciation rate was based on the assumption that plant would operate only until Nov. 1, 2024. The Arkansas and Mississippi commissions, along with 10% plant owner Cooperative Energy, argue that SERI has not provided enough support for the new rates.
While FERC has for now accepted SERI’s proposed rates effective Oct. 1, it said its own review “indicates that a further decrease may be warranted” and consolidated the matter into the larger ROE settlement procedures.
VALLEY FORGE, Pa. — PJM is attempting to calculate the market seller offer cap (MSOC) for Capacity Performance units for the 2021/22 delivery year, but it’s come across a hitch in the process, stakeholders learned at last week’s Markets and Reliability Committee meeting.
The MSOC is calculated using the balancing ratios, often represented as “B,” from the three calendar years prior to the Base Residual Auction. The BRA for 2021/22 will happen next May.
B is calculated when emergencies, or performance assessment hours (PAHs), are called. It is used to determine each generation capacity resource’s obligation to deliver energy during the PAH.
However, no PAHs happened in 2015 or 2016, and none has happened so far in 2017. Even if one did, the resulting B might not be known in time for the MSOC values to be posted mid-December, PJM’s Adam Keech explained. That timing is important because market sellers will need to determine in early January whether they want to use the default MSOC values or pursue unit-specific valuations, he said.
PJM has proposed revising the Tariff to carry over the B used in the 2020/21 BRA of 78.5%, along with a problem statement and issue charge to explore a long-term solution that would be filed with FERC by October 2018, in time for the 2022/23 BRA. The focus of the investigation would be to determine if B should remain based on historic performance or something more prospective. Keech gave a presentation on the issue at September’s Market Implementation Committee meeting.
Joe Bowring, PJM’s Independent Market Monitor, disagreed with the proposal, saying the current Tariff language addresses such a situation. The math, he said, implies that B goes to zero and the MSOC values revert to each unit’s avoidable cost rate (ACR). Keech disagreed with that interpretation.
“In the absence of data, we don’t just assume that it is zero. And that’s the case that we don’t have balancing ratios to use,” he said. “PJM is not comfortable assuming that it’s just zero because that’s not the way the Tariff reads.”
“I’m not assuming anything,” Bowring responded. “It is a fact that there is zero performance assessment hours. It is a fact that the average of the last three years is zero.”
Calpine’s David “Scarp” Scarpignato asked how PJM planned to address other formulas that use B, such as the CP penalty calculations.
“If you’re changing your assumptions or calculations related to performance assessment hours [and how B is calculated], you should change it elsewhere in CP also because it’s all tied together,” he said.
Stakeholders raised additional concerns, such as the use of 30 expected PAHs in the formula. Borgatti suggested adopting ISO-NE’s flat fee for the penalty instead of being formula-based. Following the discussion, PJM agreed to review the proposed Tariff revisions, problem statement and issue charge and bring the revised versions for a vote at next month’s meeting.
Amendment on DER Charter Sparks Debate
PJM proposed a draft charter to transfer all of its work on distributed energy resources into a subcommittee, but a friendly amendment by FirstEnergy sparked debate on how stakeholders should defer to local and state governments.
FirstEnergy proposed that the charter include a statement that “market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the Relevant Electric Retail Regulatory Authority (RERRA).”
Under FERC Order 719-A, demand response resources served by large electric distribution companies (>4 million MWh) are permitted to participate in wholesale markets unless their RERRA — such as a state regulatory commission — prohibits it. DR resources served by small EDCs (<4 million MWh) are prohibited from participation without RERRA approval.
PJM’s Chantal Hendrzak presented the proposed charter, saying the current problem statement and issue charge on DER is “very narrow” and should be broadened to incorporate issues such as microgrids, coordination with EDCs, the visibility of non-wholesale resources and the pending FERC Notice of Proposed Rulemaking on DER and energy storage RM16-23, AD16-20). (See FERC Rule Would Boost Energy Storage, DER.)
Hendrzak said special sessions of the Market Implementation Committee are not the right forum for the issues, which affect markets, operations and planning.
FirstEnergy’s Jon Schneider said the additional language was necessary to ensure the involvement of EDCs. “We think it’s important to have the right folks at the table, specifically distribution operators,” he said. “We don’t think it’s appropriate to assume that transmission operators will fully represent the interests of distribution utilities.”
“There is nothing that PJM does that would violate a reliability rule at the distribution company,” responded Direct Energy’s Marji Philips. “My concern is this is a very evolving industry. … To flatly say … that we’re not going to even talk about something because it violates an existing rule today doesn’t do anyone any good. The purpose of PJM is to provide a platform for discussion.”
Several stakeholders were concerned with another addition to the charter, which would require the subcommittee “proactively collaborate with states.” American Municipal Power’s Steve Lieberman said that commitment could lead to conflict about favoritism or prioritization.
“With 13 states [in PJM], if two of them feel you weren’t as proactive with them as you were with the other 11, then things could start to snowball unnecessarily,” he said.
Susan Bruce, who represents the PJM Industrial Customer Coalition, objected to the charter’s definition of DER including any generation or storage resource “behind a load meter.”
“Visibility into an industrial customer’s behind-the-meter generation that becomes visible to the world gives them a competitive disadvantage, and that’s a sensitivity that we would hope that PJM would respect for retail customers that are looking to just mind their own business, support their own operations,” she said. “The principle of what goes on behind a customer’s meter really is not anyone else’s business. It’s their economic decision from that perspective.”
Scarp found security in FirstEnergy’s amendment.
“If we’re going to delete that friendly amendment, I’m not sure I can still support the [proposed charter] because I don’t want to guarantee DER participation in the wholesale market. I think that’s a little bit strong when there’s lots of other things going on,” he said.
Hendrzak said staff will consider the comments in revising the charter before seeking an approval vote next month.
The Monitor sought to resume a debate on calculating the minimum tank suction level (MTSL) for black-start units, arguing that the vote at September’s MIC meeting to forego changes was “clearly wrong.” However, Ruth Ann Price of the Delaware Division of the Public Advocate, who intends to sponsor the Monitor’s proposal, asked Bowring to delay his comments until the issue can be brought back to the committee after further consideration. (See “MTSL Revisions Kaput,” PJM Market Implementation Committee Briefs: Sept. 13, 2017.)
Greg Poulos, the executive direction of the Consumer Advocates of the PJM States, explained that he had advised his membership “that this might not be the best time” to bring up the issue, which represents a relatively small amount of money, when there are many larger topics being debated.
Still, proponents warned that the issue wasn’t dead.
“There is a bit of heartburn if this comes off the table,” Bruce said. “To the extent that this is a vehicle being used for resilience, we would hope that there would be explicit recognition of that fact, that we are paying for this as a service.”
“As far as we’re concerned, this issue is not going away,” Bowring said. “It’s being postponed for a meeting or two. If you want to get it over with quickly and not waste any more time, just vote.”
‘Jump Ball’ on IA Changes Indicates Compromise Possible
None of six proposals considered by the Incremental Auction Senior Task Force won support of more than 39% of those taking part in a recent poll, but half the respondents called for some change to the status quo, giving some stakeholders hope that the issue is not dead. (See Consensus Fades on PJM Incremental Auction Solution.)
PJM’s Brian Chmielewski, who administers the task force, said the “jump ball” suggests that compromise is possible.
“Ending up with the status quo from a customer standpoint is not the right result,” Bruce said. “In the interest of not ending up with status quo, we are willing to negotiate, so I hope we get a chance to do so.”
“In the old days, we all gave blood,” said Philips, whose company proposed the problem statement that founded the group. “It looks like nobody wants to give blood anymore. The art of compromise is part of this process, and I hope we haven’t lost it.”
The group’s next meeting is Oct. 17.
Stakeholders Endorse Manual Revisions
Stakeholders endorsed several manual revisions and other operational changes:
The charter for the Primary Frequency Response Senior Task Force. (See “Primary FR Task Force Begins July 25,” PJM OC briefs: July 11, 2017.)
Tariff and Operating Agreement revisions to clarify definitions developed through the Governing Documents Enhancement & Clarification Subcommittee.
Manual 28: Operating Agreement Accounting. Changes eliminating redundant language and clarifying procedures associated with the implementation of intraday offers were endorsed by acclamation.
Members Committee
Stakeholders Approve Proposals
The Members Committee approved all proposals presented to them, including Tariff and Operating Agreement changes associated with PJM’s dynamic schedule pro forma agreements. (See Critics Protest PJM Dynamic Transfers Plan.)
Members also approved Tariff and OA revisions on limitations of billing claims and changes extending the proposal window for short-term transmission projects from 30 days to 60 days. (See “RTEP Cycle Revisions Approved,” PJM PC/TEAC Briefs: July 13, 2017.)
Nominating Committee Nominations Approved
Stakeholders appointed a representative from each of the five stakeholder sectors to a one-year term on the committee. The committee will be tasked with considering whether to nominate Neel Foster, Howard Schneider and Sarah Rogers, whose terms expire next May, for re-election to the Board of Managers.
DC Energy’s Bruce Bleiweis asked whether term limits could be waived “since we only have one original board member and we would not want him to leave” — a reference to Schneider, who has served on the board since its inception in 1997.
“I think waivers can be done through the board,” PJM CEO Andy Ott said. “I think I’ll just leave it at that.”
Reducing the Workload
MC Vice Chair Mike Borgatti of Gabel Associates announced that the MRC, MIC, Operating Committee and Planning Committee will be directed to determine if any timelines can be relaxed to “free up a little room in the schedule.” The directive came at the request of stakeholders, who have been complaining about the roughly 500 stakeholder meetings PJM conducts each year.
The workload concern is nothing new. In 2013, one member likened the stakeholders to ponies who will eat themselves to death if given unlimited access to food. (See PJM Faces Resource Limits.)
VALLEY FORGE, Pa. — With a myriad of proposals emerging to revamp PJM’s capacity market, stakeholders are focused on what the RTO will do, but staff aren’t tipping their hand.
Attendees at Tuesday’s meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) peppered PJM’s Stu Bresler with questions about his plans should stakeholders decide, after nearly a year of discussion, that the capacity market is better in its current design than anything else proposed. The RTO has proposed a two-stage “repricing” process that would ignore units that don’t clear the initial auction but clear in a second auction in which subsidized units are removed. Those so-called “in-between” units still wouldn’t receive a capacity commitment. (See NOVEC Offers 10th Capacity Proposal.)
Stakeholders fear that, short of a clear mandate on which proposal to file with FERC for approval, PJM plans to file its own rather than maintain the status quo. They pressed Bresler to at least hint at PJM’s inclination, but he repeated that he would not be able to “definitively say” what staff will recommend to the Board of Managers by the next meeting of the task force on Oct. 16.
“It depends on too many factors,” he said. “We need to defend our markets.”
“It puts us all in the same predicament because we’re all trying to prevent something that we don’t really want to happen, and that is to have a unilateral filing made. We really want to avoid that,” said John Rainey of Northern Virginia Electric Cooperative (NOVEC).
Rainey said the “quandary” is that PJM has requested stakeholders declare their preferences among the proposals without indicating “whether status quo is a viable option.”
IMM Plan Leads Poll
Earlier in the six-hour discussion, the latest of 18 such meetings since March, attendees reviewed the results of a long-awaited poll on 10 proposals. The Independent Market Monitor’s extended minimum price offer rule (MOPR) proposal received the most overall support with a weighted average of 2.74. The three main two-stage “repricing” proposals from PJM, LS Power and NRG Energy received the next-highest levels of support of 2.05, 1.86 and 1.9, respectively.
The results also broke down how well the proposals addressed certain criteria, such as removing the price impact of a subsidy or driving a competitive outcome. The Monitor’s proposal received the most support in all but one question: whether it accommodated state initiatives. There, PJM’s design narrowly edged the other repricing proposals.
Four non-members also submitted responses. Their votes, which were presented separately from the member results, heavily favored a proposal from the Natural Resources Defense Council that would reduce the capacity requirement to the needs of the off-peak season and allow seasonal resources to account for the additional demand during the peak season.
Stakeholders complained that the structure of the poll was restrictive, so they provided comments to add nuance to their votes. However, PJM’s stakeholder process purposefully withholds any comparison to the status quo until stakeholders have chosen an alternative proposal on which to vote.
Some stakeholders, however, have already made up their minds.
“We’ve given this a huge amount of consideration,” said Carl Johnson, who represents the PJM Public Power Coalition. “How do we get across that we think that the current process is still the best process?”
Representatives from the Consumer Advocates of the PJM States and Old Dominion Electric Cooperative also said they preferred the status quo.
For the first time, the group hosted a substantial contingent of state representatives. In addition to Ruth Ann Price from Delaware’s Division of the Public Advocate and John Farber of the Delaware Public Service Commission, who are often involved in stakeholder meetings, the audience included Bill Fields from the Maryland Office of People’s Counsel, Kristin Munsch of the Illinois Citizens Utility Board and Brian Lipman from the New Jersey Division of Rate Counsel.
Lipman said his office’s understanding was that PJM is “going to file something,” which would indicate a change, and that the poll didn’t make it “obvious” how to indicate support for the status quo.
PJM’s Dave Anders, who administers the task force, acknowledged the complaints but declined to suggest any implications from the poll.
“I achieved consensus in a very difficult committee: Nobody liked the poll,” he said. “You’re all entitled to your interpretation of the results. I’m not trying to lead you [to any conclusions].”
Several stakeholders said their frustration was aimed at the topic, not Anders.
“Don’t take this as a knock on the poll design,” Johnson said. “I think it was a useful exercise, even though I didn’t want to do it. … Sometimes you can’t tease [your specific wishes] out until you have to make a decision about a question that’s right in front of you.”
NRG’s Neal Fitch asked that the poll results be used to “winnow down” the proposals still in contention to focus attention on viable candidates. PJM’s Adam Keech agreed that “maybe that’s a good place to start,” but Steve Lieberman of American Municipal Power, whose proposal polled near the bottom, cautioned against becoming narrowminded.
“Let’s be careful about latching onto one side,” he said.
To begin narrowing the options, Adrien Ford withdrew ODEC’s proposal, which took a different approach to the repricing concept, but also didn’t want to limit the focus.
“I struggle to agree that we should focus on the repricing proposals,” she said.
A Poll, not a Vote
Stakeholders also differed on how to treat non-member poll results. Calpine’s David “Scarp” Scarpignato said it “doesn’t mean much in regards to a pass/fail vote at the senior committee level.” Direct Energy’s Marji Philips said examining the results of an anonymous, four-voter poll is “inappropriate” and “could actually distract from the conversation.”
However, EnerNOC’s Katie Guerry said “it’s actually helpful to see what non-members think” in comparison to member preferences. “It’s so different,” she said.
Farber reminded stakeholders that “this is a poll, not a vote,” and that they should consider “the optics” of saying non-members can watch but not express opinions.
Anders requested that proposal sponsors indicate for the next meeting whether they intend to withdraw their proposal and, if not, to update the stakeholder matrix and develop a presentation with any changes. He also requested an “executive summary” describing the proposal.
“I don’t want a book. I don’t want 20 pages, but I want enough,” he said.
Energy Secretary Rick Perry acted within his legal authority in ordering FERC to consider his Notice of Proposed Rulemaking to support struggling coal and nuclear plants. But he has no power to make FERC provide the relief he is seeking, legal experts said Monday.
Trump (left) and Perry
As a result, the outcome of the baseload battle will come down to the commission’s five members and how much they are willing to assert their independence from the Trump administration’s pro-coal agenda. Perry’s proposal would require that generators with 90 days of on-site fuel supply receive “full recovery” of their costs. (See related story, Perry Orders FERC Rescue of Nukes, Coal.)
Perry issued the NOPR under Section 403 of the Department of Energy Organization Act, subsection (a), which authorizes the secretary and the commission “to propose rules, regulations and statements of policy of general applicability with respect to any function within the jurisdiction of the commission.”
But subsection (b) gives the commission “exclusive jurisdiction with respect to any proposal made under subsection (a).”
Smith | Van Ness Feldman LLP
“Section 403 is pretty clear. What [Perry has] done so far is within his authority,” said Douglas Smith, a partner with Van Ness Feldman who served as FERC general counsel from 1997 to 2001. “It’s also clear that the final determination about what to do with a NOPR like this rests entirely with FERC.”
The act also spells out FERC’s independence. Section 401 (d) states that, “In the performance of their functions, the members, employees or other personnel of the commission shall not be responsible to or subject to the supervision or direction of any officer, employee or agent of any other part of” DOE.
Does FERC have to Act?
The NOPR lists FERC docket number RM17-3, which was opened last December to consider fast-start pricing in RTO markets. (See FERC: Let Fast-Start Resources Set Prices.) But the commission filed the NOPR and Perry’s accompanying letter to FERC in a new docket, RM18-1. Late Monday, the commission issued a notice setting an Oct. 23 deadline on comments on the proposal, with reply comments due Nov. 7.
The notice came after 11 industry groups representing natural gas, wind, solar, rural electric cooperatives and other technologies filed a motion in that docket opposing DOE’s request and requesting a minimum 90-day comment period and a technical conference before the comment deadline. The groups said the deadline imposed by Perry — final action on the proposed rule within 60 days from its publication in the Federal Register — is “wholly unreasonable and insufficient.”
Former FERC Chairman Jon Wellinghoff, now a renewable energy advocate and consultant, said in an interview that FERC can ignore the proposal without taking any action.
But others said the commission will almost certainly make some sort of formal response.
“I don’t think they can ignore it. It would, No. 1, not be politically cricket,” said former FERC Chairman and General Counsel James Hoecker. “Particularly since [interim FERC Chairman] Neil [Chatterjee] is from Kentucky and his former boss, Sen. [Mitch] McConnell [R-Ky.], has been pretty clear about wanting to soften the blows on the coal industry. I’m sure the commission will do something.”
“Regardless of what legally the commission has to do, I think it’s unlikely the commission is going to just stiff arm the secretary and the administration,” agreed former Commissioner Tony Clark, now an adviser with Wilkinson Barker Knauer.
One reason for uncertainty is the recent turnover in the commission’s membership: Chatterjee and fellow Republican Robert Powelson joined Commissioner Cheryl LaFleur on the commission in August. Republican nominee Kevin McIntyre and Democratic nominee Richard Glick are awaiting a Senate floor vote.
The commission has traditionally been independent and rarely decides issues on party lines. But some FERC watchers fear that could change because they believe the White House has already exerted its influence by dictating the selection of the commission’s new general counsel, James Danly, and Chief of Staff Anthony Pugliese.
The two were named by Chatterjee, who is serving as interim chairman pending the confirmation of McIntyre, who was tapped by Trump to lead the agency. New chairmen typically select their own general counsel and staff chiefs. But at a news conference following the commission’s meeting Sept. 20, Chatterjee suggested Danly — an Iraq War veteran who joined the commission from Skadden, Arps, Slate, Meagher and Flom — was not a temporary hire.
Asked whether Danly would remain in his position after McIntyre arrives, Chatterjee said of Danly, “I think his biography and service to his country speak for themselves, and at this time I don’t anticipate any senior-level staffing changes.”
The Commissioners
Chatterjee, who like McConnell is from the coal state of Kentucky, has appeared sympathetic to Perry’s claims that the grid’s resilience is at risk from coal retirements.
In a podcast interview posted on the FERC website in August, Chatterjee said “baseload power … including our existing coal and nuclear fleet, need to be properly compensated to recognize the value they provide to the system.”
He added, “as a nation, we need to ensure that coal, along with gas and renewables, continue to be part of our diverse fuel mix.”
Whether the other commissioners share that view is unclear.
Asked at his confirmation hearing whether he agreed with Chatterjee, McIntyre said that “FERC is not an entity whose role includes choosing fuels for the generation of electricity.”
Glick echoed McIntyre’s position, adding that although the grid study released by DOE in August did not conclude that the loss of baseload generation had impacted reliability, “they also suggested it was something to keep an eye on and look for in the future.”
“McIntyre and Chatterjee, I just think will have so much political pressure to pursue this, the expectation is that they will want to do so,” said one former senior FERC official who asked not to be named. “Glick and LaFleur I would expect to be less inclined. The interesting one is Powelson. He’s a pro-market person. … How will he reconcile competition with what is proposed here?”
Rather than pursuing a cost-of-service approach, he said, the commission could adopt a more market-based approach that boosted prices for all capacity resources, including natural gas. “Then the gas folks end up winning just as much as coal and nuclear,” he said. “My expectation is that Powelson would go more [for] that route.”
What Does Perry Want?
Smith said it was unclear whether Perry is seeking to ensure generating plants have fuel on site or is concerned about frequency response, inertia and other attributes of traditional baseload units.
“There’s precious little detail in the proposed regulatory text about what exactly would be responsive,” said Smith. “From FERC’s perspective that may be good. It gives FERC more discretion … to determine what is plausibly responsive to this.”
Ari Peskoe, senior fellow in electricity law at the Harvard Law School Environmental Law Program Policy Initiative, and a former FERC practitioner, said Perry raised more questions than he answered. “Is this cost-of-service ratemaking or is DOE suggesting that rate should be based on a plant’s ‘benefits and services?’” he asked in a series of tweets last week. “Does an eligible generator always receive this rate, or do they normally get paid LMP but receive this rate under certain circumstances? How does dispatch work if an eligible plant is not bidding into the market? Or is an eligible plant ‘bidding’ this special rate?”
If FERC issues a rule predicated on fuel supply and not on the type of fuel itself, some observers have noted, it could extend to gas plants that add a tank containing 90 days of fuel oil or those that sign firm pipeline contracts. (See Steve Huntoon’s commentary, Counterflow: Cash for Clunkers Redux.)
The proposed “rule doesn’t appear to have any real limiting principle, so nukes, coal and gas (so long as they kept on site diesel) could all qualify,” said Montana Public Service Commissioner Travis Kavulla, former president of the National Association of Regulatory Utility Commissioners in a tweet.
Wellinghoff noted that solar can bid into PJM’s capacity market with a discounted capacity value. “Can solar show it has 90 days of resource? That will be a very interesting question,” he said.
‘Just and Reasonable’ Standard
If FERC were to act in response to Perry’s proposal under Section 206 of the Federal Power Act, it would first have to make a finding both that current rules are not just and reasonable and that the new rules are, FERC legal experts say.
But the commission won’t find that evidence in Perry’s NOPR.
“The NOPR does not devote much attention to connecting the policy arguments in the preamble of the NOPR to the specific predicate findings required under Section 206, i.e., that current rates are not just and reasonable,” Smith said. “FERC would need to connect those dots.”
The evidence also is far from clear cut in the DOE grid study released in August. The study quoted NERC’s warning that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.” But it also noted that NERC’s most recent State of Reliability report concluded “bulk power system reliability remained … adequate” in 2016, repeating the group’s findings from 2013–2015.
“If there’s some ability to make a showing that plants with on-site fuel contribute to resilience and reliability … it may be appropriate to compensate that value, but I have yet to a see a study that does that,” said Wellinghoff. “That’s why it was shocking to see this letter on the heels of the DOE grid study. It seems to be contradictory to that study.”
“DOE is calling this a proposed rule, but it’s not,” Peskoe said. “There’s no rule; just an impossible timeline for FERC/RTOs to figure something out. And since there’s no proposed rule, I don’t think FERC can proceed to a final rule; DOE’s timeline is practically and legally impossible.”
Peskoe quoted from the Administrative Procedure Act, which says a proposed rule must “provide sufficient factual detail and rationale for the rule to permit interested parties to comment meaningfully.”
“The two-sentence description of the proposed ‘Reliability and Resiliency Rate’ raises many questions that DOE doesn’t even attempt to answer,” Peskoe said. “There’s a legal question about what [Perry’s] document actually is. Can FERC treat it merely as a filed comment?
“DOE’s so-called proposed rule doesn’t say that current rates are not just and reasonable; hence, [there is] no authority for FERC to take final action,” he continued. “It’s not just that DOE’s notice is missing the magic words; it has no discussion of current RTO tariffs.”
Clark said that whatever FERC decides, it is unlikely to act in the short time frame Perry called for. “If they did something major within just the context of this rulemaking on a very expedited timetable, they’d probably open themselves to some litigation risk, because you have a fairly vague rule that people are being asked to comment on.”
Kavulla said Perry’s proposal would replace competitive markets with “FERC-administered cost of service regulation,” making it “the largest change to electricity regulation in decades.”
“Some conservative reforms might have tried to take away or mitigate subsidized resources’ perks. Instead, this reform is sort of the [DOE] equivalent of the Oprah ‘you get a car, and you get a car. And you? A car!’ approach,” he added.
“The practical effect of implementing the order as written would be to basically destroy the wholesale energy markets as we know them, and I don’t think anyone wants that,” Wellinghoff said. “Ultimately it will cause prices to go up significantly for consumers.”
Brownell | NY Energy Week
Former Commissioner Nora Mead Brownell, a Republican, said she was “shocked and frankly disappointed” by the proposal. “If Republicans are presumably about fiscal responsibility and markets, this totally contradicts that,” she said in an interview.
“It’s the antithesis of good economics. It’s going to destroy the markets [and] drive away investment in new more efficient technologies, whether they be generating plants or energy efficiency, at a cost to business and ratepayers that is astronomical.”
“If you want to throw $80 or $90 billion at something, spend it on cybersecurity.”
Brownell noted that the coal and nuclear plants in question are fully depreciated and in many cases received stranded cost compensation in states that adopted retail choice. Before the rise of shale gas and renewables cut clearing prices,
“these plants made a lot of money,” she said. “In what other industry would we save old, fully depreciated, inefficient plants that have been paid for many times over? Markets are supposed to allocate resources efficiently and this totally distorts any valid signals you might have.”
Clark said the NOPR, like the DOE grid study, “puts another exclamation point” on the issue of price formation in the markets.
“Is the commission going to do more than it was already prepared to do? That I don’t know,” he said.
“It’s pretty clear it would be challenging to the market design as it exists today, like the New York and Illinois [zero-emission credits for nuclear plants are] challenging to those markets. You’d be talking about nuclear plants across the entire footprint of restructured markets, and most coal plants too.”
WESTBOROUGH, Mass. — ISO-NE’s Planning Advisory Committee on Thursday hashed over technical details from about 95 stakeholder comments regarding the grid operator’s draft 2016 Scenario Analysis – Phase I Report.
“Two sets of comments concern carbon emissions and making some judgement on whether the region will meet the [Regional Greenhouse Gas Initiative] goals that are being promulgated,” said Michael Henderson, ISO-NE director of regional planning and coordination, as he reviewed the feedback during a Sept. 28 committee meeting. “Other comments concern the inverter-based resources (solar, wind, storage), which becomes more important with the growth of wind and the increased penetration of energy efficiency.”
The New England States Committee on Electricity wanted a disclaimer placed more prominently in the report saying, “The report and the hypothetical future scenarios are not plans, predictions or preferences.” The grid operator agreed to the request.
Scenarios, not Policies
Henderson emphasized that the report constitutes the RTO’s analysis of scenarios provided by the New England Power Pool — not an evaluation of state policies.
Bob Stein of Signal Hill Consulting Group said, “We have heard they are NEPOOL scenarios, but I don’t think NEPOOL endorses any of the scenarios, either.”
Joining by phone, David Ismay of the Conservation Law Foundation said, “The study would be more valuable to the region if it considered various state policies … what we’re getting at is a level of emissions that approximates goals.”
“The ISO is taking the proper approach,” said NESCOE’s Ben D’Antonio. “The idea here is to make sure the report is clear so people can understand it … keeping it straightforward and clear is right.”
The American Wind Energy Association complained that the report’s assumed wind development costs used out-of-date U.S. Energy Information Administration data.
“Our main concern is that transmission costs are too high by a factor of 10. Most obviously, there is a 50% ‘margin’ added to transmission costs which are already extremely high,” wrote AWEA’s Michael Goggin. “This assumption has a major impact on the results, since the transmission costs nearly as much as the wind generation in the scenarios with high levels of onshore wind.”
“I don’t think we are using the costs incorrectly, especially when you consider the interconnection costs for a wind farm in Maine can be extraordinarily higher than for one located right next to a major transmission line,” Henderson said.
Henderson added that the RTO didn’t just look at offshore wind and measure the shortest distance to shore to derive cost estimates.
“Transmission costs were the same issue and, again, they are order-of-magnitude estimates,” he said. “They proved remarkably accurate because they were part of the Maine wind integration study.” (See ISO-NE Files Cluster Study Rules; Window to Open in Nov.)
2027 Needs Assessment Scope of Work
ISO-NE senior transmission engineer Kaushal Kumar presented the assumptions and study methodology behind the 2027 Needs Assessment Scope of Work, a study produced biannually to provide insights into the system 10 years into the future.
The studies evaluate performance and identify reliability-based needs in six study regions, factoring in future load distribution, reliability over a range of scenarios, project coordination and the retirement or addition of major resources. They also apply all relevant transmission planning reliability standards from NERC, the Northeast Power Coordinating Council and ISO-NE.
Questioning Assumptions
One of Kumar’s slides contained a footnote saying that demand resource assumptions included 5.5% distribution losses. Stein asked where the figure came from, and also questioned the RTO’s assumption of cutting that loss to zero when modeling solar, contending that not all PV installations are located right next to load.
ISO-NE Director of Transmission Planning Brent Oberlin said the RTO’s modeling has long assumed an 8% energy loss, with 2.5% lost in transmission and 5.5% in distribution. But he added that he would consider refining the assumptions for PV’s reduction of distribution losses.
2017 Renewable Energy Integration Study Nears Completion
Professor Amro M. Farid, of Dartmouth College’s Thayer School of Engineering, briefed stakeholders on the scope of his team’s work on the grid operator’s 2017 System Operational Analysis and Renewable Energy Integration Study (SOARES).
The study focuses on regulation, ramping and reserves, and addresses the reduction in traditional thermal generation that provides the grid with inertia and other reliability services.
“We need to adopt a holistic way of looking at how renewable energy integration causes fundamental changes in grid dynamics and erodes the power grid’s overall dispatchability,” Farid said.
| Thayer School of Engineering at Dartmouth
Methodologies used in past renewable energy studies operate on assumptions for which there is no supporting research, Farid said. Farid said the Electric Power Enterprise Control System simulator his group developed to address this need can more accurately study such things as the impact of energy storage on load-following resources and the RTO’s day-ahead unit commitment.
SOARES is a key element of Phase II of the 2016 NEPOOL Scenario Analysis/Economic Study. Farid expects to complete SOARES by the end of the year.
FERC last week rejected a request by several SPP members that they be exempted from congestion and marginal loss charges under a grandfathered contract signed before they joined the RTO (ER14-2850-008, ER14-2851-008).
The commission ruled Sept. 26 that Missouri River Energy Services, Basin Electric Power Cooperative, Western Area Power Administration – Upper Great Plains (Western-UGP), Heartland Consumers Power District and Nebraska Public Power District (NPPD) were ineligible for “carve-out treatment” under the SPP Tariff and a 1977 transmission service contract between NPPD and Basin Electric.
The 1977 contract arose from construction of NPPD transmission needed to deliver power to Western-UGP and Lincoln Electric System from the Missouri Basin Power Project — a venture owned by six public power and cooperative utilities that includes the 1,710-MW Laramie River coal generator, the Grayrocks Dam and reservoir, and more than 500 miles of EHV transmission.
Laramie River Station | Burns & McDonnell
The commission ruled that the utilities were not eligible for a carve-out, although it acknowledged that the section of the SPP Tariff governing grandfathered agreements (GFAs) was “ambiguous.”
The commission rejected the utilities’ claim that they should be exempted from the charges because FERC had previously granted carve-out status to Lincoln, which was also a party to the 1977 contract.
“Though parties to the same contract, Lincoln Electric and [the] parties seeking carve-out treatment are in a fundamentally different position with regard to the costs of participating in SPP because of when each party chose to join SPP,” the commission said. “Lincoln Electric, an SPP member since 2008, was subject to a forced transition to a day-two energy market when SPP adopted the Integrated Marketplace in 2014 and, therefore, received carve-out treatment along with several other non-jurisdictional GFAs that were also subject to a forced transition. On the other hand, [the] parties seeking carve-out treatment were not subject to a forced transition to a day-two energy market when they joined SPP after the commencement of the Integrated Marketplace. Parties seeking carve-out treatment had a choice of whether or not to subject themselves to SPP’s market rules.”
Network Agreements Approved
In a separate order Sept. 25, the commission approved SPP’s unexecuted network integration transmission service agreements with Kansas Power Pool (KPP) effective June 1, 2017, and its executed network operating agreements with KPP, Midwest Energy Inc., Mid-Kansas Electric Co. and Westar Energy effective Sept. 1, 2017 (ER17-2032-002, ER17-2038-002).
KPP protested the service agreements’ inclusion of language describing KPP’s potential liability for credit payment obligations. KPP said that SPP staff had informed it that transmission studies had indicated it would not be responsible for any credit payments because they would be fully covered by base plan funding.
The commission rejected KPP’s complaint, saying the company could be liable for credit payments because final cost information is not available for one upgrade under the agreements, the Woodward EHV 138-kV phase shifting transformer circuit #1.
“When SPP receives the final cost information for the Woodward upgrade, SPP can determine whether all the credit payment obligations are fully covered by base plan funding,” the commission said.
Last week saw a handful of CAISO-related developments at FERC, including the commission’s suspension of a Pacific Gas and Electric transmission rate request and approval of Portland General Electric (PGE)’s authority to charge market-based rates in the Western Energy Imbalance Market (EIM) ahead of the utility’s Oct. 1 entry into the market.
The commission on Thursday set settlement hearings over PG&E’s request for a transmission rate increase after receiving protests from state regulators and others. FERC accepted and suspended until March 1, 2018, PG&E’s request for a 6% increase, saying there are issues that “are more appropriately addressed through hearing and settlement judge procedures” (ER17-2154).
In its July 27 tariff filing, the utility said the rate increase will allow it to recover costs incurred so far in 2017 for transmission expansion, as well as in 2018. It expects to invest $1.2 billion this year and another $1.4 billion next year. The approved rates would produce about $1.8 billion in revenue in 2018.
PG&E said the requested increase is largely driven by the need to replace aging infrastructure. Other factors include compliance with reliability rules and the magnitude and location of changes in California’s forecasted electricity load. A substantial amount of its system was built more than 50 years ago, PG&E said.
Numerous protests were filed by parties, including the California Public Utilities Commission, a handful of California cities, the Energy Producers and Users Coalition, municipal electric agencies and the Transmission Agency of Northern California.
Some protesters argued that PG&E’s proposed 10.25% return on equity should be no higher than 8.84%, and there were disputes over the proxy group screening tool, which is used to determine a reasonable return. Others disputed the utility’s request for a 50-basis-point adder for participation in CAISO, which FERC granted.
The PUC’s challenge of two recent FERC approvals of the adder in previous tariff filings are on appeal with the 9th U.S. Circuit Court of Appeals. FERC rejected the PUC’s request to abstain from a ruling on the current adder until that court proceeding is resolved.
ISO Submits Aliso Canyon Measures
CAISO also submitted Tariff amendments to address the loss of the Aliso Canyon natural gas storage facility. The measures extend previously approved changes that can limit market bidding flexibility in response to gas constraints.
“The maximum gas constraint has proven to be a useful and discrete tool that balancing authority areas can use to reflect the interactions of gas limitations in the electric market optimization. Therefore, the CAISO proposes to adopt that measure on a permanent basis and throughout its entire system,” CAISO said.
The measures allow the grid operator to constrain the operations of gas plants across the state and the EIM, part of a package of initiatives drawn up in response to the loss of the storage facility after a massive leak was discovered in October 2015. The proposal required approval by the CAISO Board of Governors and the EIM Governing Body. (See CAISO Board Approves Aliso Canyon Rules Package.)
Portland General Electric Begins EIM Participation
FERC also approved PGE’s application to charge market-based rates in the EIM, saying that the Oregon utility’s balancing authority area will not be a sub-market and does not require a separate market power analysis (ER17-1693).
PGE began transacting in the EIM on Oct. 1. The company in early September briefed the EIM Governing Body on its implementation activities. It reached an implementation agreement with CAISO in November 2015.
“We could never have imagined in ’27, or even in 1997, what we’d grow into,” Ott said. Yet, he added, “Our mission remains the same: to keep the lights on.”
Senior executives of the three utilities that founded PJM — Exelon’s PECO Energy (formerly Philadelphia Electric Co.), PPL and Public Service Electric and Gas — were among more than 100 in attendance.
“Today, PJM represents the largest energy-transaction marketplace in the world,” said Exelon Utilities CEO Denis O’Brien, noting that his company now owns almost half of the dozen companies that were PJM members when he began his career 35 years ago. He presented Ott with a photograph of the lighted signs at the top of PECO’s landmark building in Philadelphia displaying a message of congratulations to PJM.
PPL CEO William Spence congratulated the many people who transformed PJM into the world’s first continuing power pool.
“Today, nearly a century after PJM’s founding, it’s hard to imagine life without the electricity that we provide,” he said, noting its importance to medicine, education and the economy. “It was these people who transformed that 1920s patchwork of power lines and power plants into the robust interconnected system that we have today.”
Ralph Izzo, CEO of PSE&G parent Public Service Enterprise Group, noted that PJM was originally named PNJ, but changed its name as it expanded. The idea for the interconnection came when a company engineer realized that if every electrical device was turned out simultaneously, it would demand 3.5 times more power than the company owned, Izzo said. Only through “a fortunate lack of coincidence … this nightmare never materialized,” Izzo said.
The power pool allowed resources that were going unused in one company’s territory to be used in another area where demand was outstripping supply. “At the outset, transmission was the great enabler of the founders’ vision,” Izzo said.
The mood at the celebration was light, and many speakers found opportunities for humor.
PJM has “lasted through the Great Depression, through war and economic troubles, through FERC Order 1000,” Izzo joked. “Oh, that wasn’t in the script.”
Commissioner Robert Powelson came to FERC’s defense.
“I think it’s fair to say that if Thomas Edison were here today he would say, ‘Job well done, Andy and team,’” he said. “And he would say, ‘Job well done, Federal Energy Regulatory Commission.’”
Powelson, a former member and chair of the Pennsylvania Public Utility Commission, also singled out Mike Bryson, PJM’s vice president of operations, for “doing the boring good” to ensure the reliability of the RTO’s $30 billion in annual electron sales.
“Not a lot of people know who you are; I know who you are,” he said. The PJM staff “make Federal Energy Regulatory Commission commissioners look good in spite of ourselves.”
Current PUC Chair Gladys Brown noted that PJM is 10 years older than her commission. She thanked the RTO for being the “backbone” of wholesale energy transactions that enables her state’s competitive retail sales program.
She also voiced appreciation for the “tightrope and tug-of-war” that PJM staff administer in the stakeholder process, referencing the current efforts to accommodate state generation subsidies without allowing them to impact competitive prices. (See related story, PJM Pressed on Plans to File Capacity Changes.)
Pennsylvania is “proud” to be PJM’s home and birthplace, she said.
Richard Mroz, president of the New Jersey Board of Public Utilities, brought congratulations from a long list of industry stakeholders, including the National Association of Regulatory Utility Commissioners.
U.S. Rep. Ryan Costello, who represents the district that is home to PJM headquarters, said “a secure, safe, reliable, efficient grid is critical for the future of our country.”
“It is a particular source of pride for me when we have a power subcommittee roundtable and we’re talking about the challenges facing RTOs moving forward, and who’s really running the show? Who does everybody listen to?” he said. “It’s the folks at PJM, because you are out front in terms of innovation, and you are out front in terms of wrestling with the complexities and the challenges that RTOs face.”
MISO planners continue to sift through the largest batch of interconnection applications in a decade while still working out lingering details about the RTO’s new queue process.
In the last year the queue has grown to 355 projects totaling 58.8 GW.
| MISO
“I don’t think we’ve ever had 191 projects enter the definitive planning phase at once,” said MISO planning manager Neil Shah, speaking about the August 2017 cycle of projects, representing 32 GW. The RTO accepts new projects into its queue twice per year, in August and February.
Stakeholders participating in a Sept. 26 Interconnection Process Task Force (IPTF) conference call asked if all the proposed projects will complete the queue’s studies.
“From MISO’s perspective, they’ve submitted everything they’ve needed under the Tariff,” Shah said.
“There’s a lot of capacity in the queue, and a lot of it won’t come online, but a lot of it will,” CEO John Bear said during a Sept. 21 board meeting, adding that solar and renewables represent a large share of prospective projects. At the same meeting, Executive Vice President of Operations Clair Moeller noted that the queue hasn’t been so packed since 2007.
Amid the heavy queue workload, stakeholders must also decide whether to continue the IPTF under its current structure, or convert it into a working group to finish implementation of the new queue design, which is intended to streamline a process beset by restudies and backlogs. However, MISO staff have already warned stakeholders to prepare for delays as the approximately 100-employee queue team examines the copious amount of projects.
Rhonda Peters, a Wind on the Wires consultant, urged IPTF leadership to consider the switch to a working group.
| MISO
“We have a lot of needs with this interconnection queue, and they’re not going away. They’re urgent needs. … We need to not waste time discussing a sunset date every six months,” Peters said.
Wisconsin Public Service’s Chris Plante said he was also in favor of moving to a more permanent working group organization, noting that he’s saved documents from 2008 IPTF meetings.
“We’re pushing 10 years here, and from a Stakeholder Governance Guide standpoint, that’s not temporary,” Plante said.
Vikram Godbole, MISO director of resource utilization, said the larger goal was that stakeholders continue working out a new queue process, whatever the venue. IPTF Chair Randy Oye asked for stakeholder comments on whether they support discussing interconnection issues under a working group or task force structure.
MISO attorney Jacob Krause also said the RTO is seeking written stakeholder feedback on the number of days that should be allowed for negotiating and executing generator interconnection agreements.
In early September, FERC ruled that MISO did not provide “sufficient support” for Tariff revisions that would have required that generator interconnection agreements be negotiated and executed within 90 days, down from the current 150 days. (See FERC Blocks MISO Plan to Shorten Queue Negotiations.)
Oye said he didn’t see why the RTO couldn’t shorten the agreement timeline by having interconnection customers and transmission owners simultaneously sign off on agreements. Currently, agreements are negotiated for 60 days, with customers given additional 60 days to execute the agreement. TOs then have another 30 days to sign off.
MISO staff asked for written comments so the issue could be taken up again in October.
MISO is seeking stakeholder guidance on how to forecast the probable locations of future renewable, energy storage and distributed energy resources in order to better inform its transmission planning.
To prepare for MISO’s 2019 Transmission Expansion Plan modeling, stakeholders had asked the RTO to update probable utility-scale renewable zones, map out future storage placement based on likely economic benefits, create an electric vehicle siting methodology and gather more information on DER through forecasts of customer-driven adoption and surveys of load-serving entities.
“Some of these categories are relatively new to our MTEP process,” MISO Senior Policy Studies Engineer Jordan Bakke said.
James Okullo with MISO’s policy studies group said MTEP 19’s utility-scale renewable study, prepared by Vibrant Clean Energy and used to predict future renewable siting, may include areas outside of the RTO’s territory.
“We cannot ignore the impact of our neighbors and what’s happening outside of our footprint,” Okullo said during a Sept. 29 MTEP 19 workshop.
The RTO’s current MTEP siting methodology allows for siting of about 50 GW of new wind projects and 9 GW of utility-scale solar expansion in the footprint over the next 15 years.
Okullo said MISO would also examine which states have opened state-owned land to renewable project siting.
ITC Holdings’ Cynthia Crane asked if the RTO would want utilities and states to supply information on county efforts to stifle renewable siting, pointing to residents in Michigan’s Thumb region that are actively campaigning against new wind farms.
Okullo said such information would be useful to MISO planners.
After stakeholders suggested the RTO rank its states in order of receptivity to renewable development, Indiana Utility Regulatory Commission adviser Dave Johnston cautioned against such a political exercise.
“In a state like mine, you wouldn’t think we’d be very open to renewable development, but we’re very into economic development and manufacturing, so we welcome those plants. So it’s hard to paint states in certain boxes. It’s hard to predict,” he said.
In MTEP 18, MISO projected the siting of 2 GW of future energy storage in its future with the most aggressive growth of DER. It also placed no more than 100 MW of energy storage at any single load bus in the next 15 years. In MTEP 19, MISO could predict greater penetration by studying the full range of storage benefits, engineer Kunjal Yagnik said.
Wind on the Wires’ Natalie McIntire asked why MISO would include energy storage in MTEP resource assumptions when storage could very well solve transmission needs and become a project recommendation itself.
“It seems like it could serve both functions,” she said. MISO officials agreed.
Bakke said MISO will have to sort through the several nuanced benefits of storage when predicting future locations. For example, storage could be placed near a proliferation of renewable resources or situated in areas where frequency response could use improvement, he said. Customized Energy Solutions’ David Sapper said he agreed with MISO’s view of storage as a “composite resource.”
Ann Benson, a MISO policy adviser, said the RTO is looking for better ways to increase DER visibility in MTEP siting. She asked stakeholders for ideas about how MISO could prepare a more complete database of existing and anticipated DER locations.
Marcus Hawkins, director of member services for the Organization of MISO States, advised MISO against using footprint-wide assumptions for DER trends, noting that in listening to recent discussion from stakeholders and regulators, he’s heard a clear preference for a state-by-state differentiation of DER assumptions.
If appropriate, MISO could also forecast use of other emerging technologies, MISO policy studies staffer Temujin Roach said. Those could include small hydropower resources near rivers and lakes, small modular nuclear reactors and compressed air energy storage.
MISO will hold two more workshops before moving forward with final MTEP modeling in early 2018. For now, the RTO is asking stakeholders by Nov. 1 to provide suggestions on how to incorporate forecasts for renewable and new technologies into MTEP modeling and resource siting.
