The PJM Board of Managers last week authorized $348 million in transmission projects. Coming two months after it greenlit $1 billion in projects, the approvals irked American Municipal Power, the RTO’s biggest critic when it comes to its Regional Transmission Expansion Plan.
“There was another $186 million of supplemental projects that will move forward in the PJM process. In other words, over a third of the transmission projects reviewed in this time frame were not approved by the PJM board,” American Municipal Power’s Ed Tatum said in an email. “These projects were not subjected to the same level of rigorous review afforded baseline projects, yet the cost of these facilities will ultimately be borne by the consumers in the constructing transmission owners’ zone.”
Tatum was referring to the separation within PJM’s RTEP between different types of projects: baseline projects requested to address reliability issues that receive significant RTO scrutiny; and “supplemental” projects proposed by TOs to address their own internal criteria that aren’t subject to the same level of analysis.
PJM must make recommendations and receive board authorization before assigning baseline projects, but TOs do not need RTO approval for supplementals.
“Another half-billion dollars of more supplemental projects are waiting in the wings. The sheer volume of projects moving forward absent adequate review for need and alternatives should be a grave concern to the PJM board,” Tatum said.
Last week’s decision by the board authorized 26 projects, most of which were reliability upgrades or replacements. There were three market efficiency proposals PJM staff recommended for authorization, though they accounted for less than $10 million. Twelve of them are in the Mid-Atlantic region of PJM’s footprint; 10 are in the Western area and four are in the Southern area.
The board also approved PJM’s installed reserve margin (IRM) of 15.8% for 2021/22. The IRM dropped from 16.6% thanks to an anticipated fleet-wide equivalent forced outage rate (EFORd) reduction from 6.59% to 5.89%. (See “IRM Results Approved,” PJM Planning/TEAC Briefs Oct. 12, 2017.) An IRM study earlier this year also created updated margins for other delivery years, which the board also approved: 16.1% for 2018/19 and 15.9% for 2019/20 and 2020/21.
The board also approved five targeted market efficiency projects (TMEPs) in conjunction with MISO that traverse the grid operators’ borders. The smaller, congestion-relieving interregional projects were also approved last week by MISO’s board. (See related story, MISO Board Approves $2.6B Transmission Spending Package.)
The portfolio of system upgrades has a combined cost of $20 million. On average, project costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million.
FERC last week approved several changes to MISO’s competitive transmission developer selection process under Order 1000, which the RTO says will greatly improve its efficiency.
The most substantial of these changes eliminates MISO’s facility-by-facility evaluation when considering a developer’s bid, allowing the RTO to evaluate the project as a whole (ER18-44). Previously, the RTO had to individually assess a project’s facilities, such as lines and substations, even if they were all part of the same project. MISO called this approach both “inefficient” and “analytically flawed.”
MISO will now evaluate mixed-facility projects (those consisting of both competitive lines and substations) using the following weights:
35% for cost and facility design quality;
30% for project implementation capabilities;
30% for operations, maintenance, repair and replacement capabilities; and
5% for MISO transmission planning process participation.
Previously, the RTO used separate weighting for lines and substations.
Developers Midcontinent MCN and LS Power protested the new weighting. Both said the cost and description criterion, though increased by 5% for both types of facilities, should have significantly greater weight.
FERC rejected this, saying it agreed with MISO “that providing greater weight (35%) for cost and reasonably descriptive facility design quality appropriately accounts for the evaluation criterion that MISO anticipates will result in the greatest challenges for these types of projects, which include different types of facilities.”
“Indeed, MISO’s proposal to provide greater weight for the cost and reasonably descriptive facility design quality evaluation criterion for mixed-facility projects is consistent with LS Power’s and Midcontinent MCN’s general view that this evaluation criteria should play a greater role in the competitive developer selection process,” the commission said.
Additionally, FERC accepted other noncontroversial changes to the selection process. One of these allows MISO to stagger its requests for proposals for competitive projects. The RTO had explained that, as its Board of Directors approves projects for bidding in packages, drafting RFPs for the projects at the same time created significant staffing crunches (ER18-41).
The commission also approved several revisions to MISO’s governing documents to update terms and definitions related to the competitive process, as well as to improve their clarity, grammar and formatting (ER18-39).
Public Service Enterprise Group CEO Ralph Izzo last week asked New Jersey legislators to approve subsidies for the company’s three in-state nuclear facilities, warning they may otherwise be shuttered.
Testifying at a joint session of the General Assembly’s Telecommunications and Utilities Committee and the Senate Environment and Energy Committee on Dec. 4, Izzo said PSEG’s three nuclear units at the Salem and Hope Creek facilities remain profitable but are threatened by low natural gas prices and could become uneconomic within two years. He said the plants’ finances have been propped up by hedging over the past three years, but most of those contracts are set to expire by the end of next year.
“Unless market prices change, we will no longer be covering our costs within the next two years. Without intervention — without a thoughtful economic safety net — PSEG will be forced to close its New Jersey nuclear plants,” he said. “It would be an extraordinarily painful decision because of how much we value the importance to New Jersey, but it is a cut-and-dry decision.”
A Brattle Group study produced for PSEG and Exelon found that allowing the facilities to close would increase New Jersey power bills by $400 million annually over the next decade while reducing state tax receipts by $37 million, eliminating 1,400 jobs and increasing carbon dioxide emissions by 13.8 million metric tons annually.
Izzo requested state subsidies like the zero-emission credits approved in Illinois and New York for units owned by Exelon, which also owns 43% of the two Salem units.
Opposition Coalescing
Opponents questioned Izzo’s prediction that the plants will become unprofitable.
“It is not enough to simply accept PSEG’s assertions regarding the plants’ profitability, and that even if the plants are shown to be at risk of losing money in the future, the solutions must be found within the federally administered markets and not through out-of-market payments for plants that are already profitable,” said Stefanie Brand, the director of New Jersey’s Division of Rate Counsel. “Just because nuclear plants in other parts of the country are not profitable, doesn’t mean that plants in New Jersey — the state with the highest prices in PJM — are also unprofitable.”
PSEG’s units benefit from constraints in New Jersey’s EMAAC locational deliverability area (LDA) that traditionally put its clearing prices near the top in PJM. Capacity prices for delivery year 2020/21 during May’s Base Residual Auction fell to $76.53/MW-day in most of the RTO, while EMAAC jumped to $187.87 from less than $120 for 2019/20. (See Analysts See End to New Builds in PJM Capacity Results.)
PJM sent identical letters to Sen. Bob Smith, chair of the Senate committee, and Wayne DeAngelo, chairman of the Assembly committee, urging lawmakers to consider a regional approach rather than having the state act on its own. “As a state within PJM, New Jersey need not address these challenges alone or in a vacuum. Being located within PJM — a regional organization with a multistate market — allows for solutions and alternatives that can augment, enhance and amplify the means by which you meet your state policy priorities.”
“There is no evidence that PSEG’s nuclear plants are uneconomic and facing a retirement signal from the PJM markets,” said Joe Bowring, PJM’s Independent Market Monitor. “Neither plant is defined as at risk according to the criteria that the IMM applies to all units in the IMM’s annual PJM State of the Market Report.”
He argued that subsidizing the units would also deter investment in newer technology.
“Subsidies suppress energy and capacity market prices and therefore suppress … investment incentives for innovation in the next generation of energy supply technologies and energy efficiency technologies. These impacts are large and long lasting,” he said. “If subsidies are provided to one generating plant, this will suppress prices for all generating plants and create a need for additional subsidies for the remaining units. Competition in the markets will be replaced by competition to receive subsidies.”
Other Opponents
Also opposing PSEG’s proposal are AARP, which launched an anti-subsidy ad campaign, and the New Jersey Coalition for Fair Energy — whose members include Calpine, Dynegy, NRG Energy and the Electric Power Supply Association — which released a TV spot.
The New Jersey Coalition Against Nuclear Taxes includes AARP, environmental groups, the New Jersey Petroleum Council and other groups. Over the summer, one of its members — Dennis Hart, executive director of the Chemistry Council of New Jersey — criticized PSEG for “trying to build support in the New Jersey Legislature for another government handout that may cost all New Jersey ratepayers about $350 million annually over a 10-year period, or $3.5 billion.”
In a press release announcing its formation about a week before last Monday’s hearing, the Coalition for Fair Energy upped that estimate to “the range of $475 million a year or more, or in excess of $4 billion total” based on analysis of the New York and Illinois initiatives.
“There is no need for the Legislature to rush to pass a bill of such magnitude in a lame duck session without a full and thoughtful examination of a subsidy and its implications on the cost of electricity and its impact on a fair, level and competitive electric marketplace,” coalition spokesman Matt Fossen said in the release. “The public deserves complete transparency and a review of PSEG’s finances to see if there is any basis for a ratepayer-financed subsidy.” In his testimony, Izzo promised to open his company’s financial books for an independent examination.
After the Dec. 4 hearing, Smith said that legislation supporting the plants could be enacted during the lame-duck session, which ends early in January. “I learned enough today to begin the discussion,” he told NJ Spotlight.
Outgoing Gov. Chris Christie said he would sign a bill to save the nuclear plants, but only if it does not include incentives sought by environmentalists.
FERC last week again rejected PJM’s 2012 compromise on the minimum offer price rule (MOPR), saying that eliminating unit-specific exemptions and subjecting generators to the offer floor for three years is unreasonable (ER13-535-004).
The commission originally rejected PJM’s proposal in 2013, saying it discouraged new entry because the exemptions were too narrow and the mitigation period was too long. However, it indicated it would accept the proposal if the unit-specific review were retained and the mitigation period remained unchanged. PJM agreed in a compliance filing adopting FERC’s changes, but a handful of stakeholders petitioned the D.C. Circuit Court of Appeals to review the order.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
In July, the D.C. Circuit said the commission had overstepped its authority in undoing the compromise. The court determined that FERC exceeded its “passive and reactive role” under Section 205 of the Federal Power Act, which requires it to accept proposed rate changes if they are just and reasonable and suggest only “minor” changes. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
PJM’s proposal would have replaced the unit-specific MOPR exemption with two new categorical exemptions and extended the mitigation period from one to three years before a unit could bid below the price floor. The change was prompted by generators’ concerns that the unit-specific review, which allowed units to prove confidentially to PJM that its costs were below the required minimum offer, lacked transparency and allowed below-cost bids.
In exchange for eliminating the exemption, load-serving entities won an agreement for two new exemptions: a competitive-entry exemption for units that are unsubsidized or subsidized through a nondiscriminatory, state-sponsored procurement process; and a self-supply exemption for units intended to meet a portion of an LSE’s needs.
The compromise proposal was widely supported by PJM stakeholders — the first time that a significant MOPR revision had won a two-thirds sector-weighted vote, the court noted.
Although the commission’s membership has changed since 2012, its opinion of the PJM proposal did not.
“We continue to find that PJM has failed to show that its proposed categorical exemptions, standing alone, are just and reasonable … because there would be no means for nonexempted resources with lower costs than the MOPR offer floor to have a competitive bid considered in the auction,” Commissioners Cheryl LaFleur, Neil Chatterjee and Richard Glick wrote in the 3-0 order. “We also continue to find that PJM failed to show that extending the mitigation period from one year to three years is just and reasonable. … Accordingly, we reject PJM’s December 2012 filing in its entirety and reinstate its previously approved market design, i.e., a MOPR without categorical exemptions but with a unit-specific review process and a one-year MOPR mitigation period.”
Chairman Kevin McIntyre and Commissioner Robert Powelson did not participate in the ruling.
The commission said a unit-specific exemption was necessary because “the benchmark price that is used to set the MOPR is an estimate of the net [cost of new entry]. This derived price may exceed the actual costs of individual generators and such generators should have an opportunity to demonstrate as much.”
The fact that unit-specific reviews are more complicated than categorical exemptions did not justify their elimination, the commission said. “We concur with the [Independent Market Monitor], and we disagree with the notion that the unit-specific review is an unworkable method to prevent buyer-side market power, as evidenced by its effective use in ISO-New England Inc. and NYISO.”
It said the three-year mitigation period was improper because it would prevent resources from bidding based on their going-forward costs.
“Before a resource is built, its incremental cost would reflect the unit-specific net CONE, but once the resource has cleared in one auction, its developer would need to begin construction to meet its obligation three years later in the delivery year. At that point, the construction costs incurred prior to subsequent auctions become sunk costs, and they are not part of the resource’s incremental costs going forward,” the commissioners said. “But under a three-year mitigation period, developers whose offers are mitigated and clear in the auction would be prevented from offering at their going-forward costs for at least two years beyond the first auction in which they clear and would instead have to offer at … an artificially inflated price.”
The commission said, however, that it would not order PJM to rerun its capacity auctions under the rules in effect before the 2012 filing, saying it “would cause significant disruption and burdens that are not warranted.”
The situation may soon become moot as PJM completes its yearlong examination of its capacity construct. A proposal from the Monitor to extend the current MOPR process — the only plan to receive endorsement by the task force investigating the issue — is set for a vote at the Dec. 21 meeting of the Markets and Reliability Committee.
The proposal would expand the MOPR to all units indefinitely but would include exemptions for self supply, competitive entry, public power and state renewable portfolio standards programs.
The Monitor is holding a question-and-answer session following Tuesday’s Operating Committee meeting to address stakeholder questions ahead of the vote.
PJM has not confirmed it would file the proposal for FERC approval should it win endorsement, but Monitor Joe Bowring confirmed he would file it himself if the RTO refuses. (See related story “Stakeholders Have Questions Before Approving MOPR-Ex,” Markets and Reliability/Members Committees Briefs: Dec. 7, 2017.)
By Rory D. Sweeney, Jason Fordney and Rich Heidorn Jr.
PHILADELPHIA — PJM and reliability coordinator Peak Reliability announced Thursday they will explore the development of markets and other services in the West, creating a potential competitor to the expansion ambitions of CAISO and SPP.
Peak Reliability, the NERC-designated reliability coordinator for most of the Western Interconnection, announced the agreement to “explore reliability services and markets in the West” with PJM Connext, a non-regulated subsidiary of PJM Interconnection LLC, operator of the world’s largest wholesale electricity market and North America’s largest grid.
“Peak and PJM Connext will begin review of potential reliability services, market design, governance, product suites, rules, technology and organization,” they said in a press release, promising to report on their finding by the end of March 2018. “We believe that our partnership will lead to a viable and credible alternative structure in the West,” the release quoted PJM CEO Andy Ott.
“I think it’s a good fit,” Ott said in an interview after a meeting of the PJM Members Committee Thursday.
Ott said the initiative resulted from requests Peak had received about whether it could provide more services. “They’re geared toward reliability services. We could provide the market-oriented and operational services,” he said.
“At this point, it’s exploratory,” Ott added. “The notion of having this separate company allows us to do that and keep risk off of PJM members.”
“PJM has an established track record as an innovative and cost-effective provider of system operations and market services,” Peak CEO Marie Jordan said in a statement. “Our partnership seeks to leverage Peak’s West-wide system model, PJM’s markets expertise, and our combined processes, people and tools. Both Peak and PJM share a strong commitment to developing solutions, tailored to the Western Interconnection.”
The two said their research will include an “outreach program” to Western Interconnection “industry leaders and stakeholders.”
| NERC
The announcement led Montana regulator Travis Kavulla to tweet Thursday afternoon that PJM and Peak “just sent a letter to regulators announcing they’re exploring how to form a new RTO in the West.”
“Big stakes here,” added Kavulla, a member of the Montana Public Service Commission and former chair of the National Association of Regulatory Utility Commissioners. “If Peak against the odds pulled this off, it’d be a huge coup. But Peak’s funders (including those championing rival RTO efforts) probably aren’t going to be very warm on this.”
Kavulla told RTO Insider: “I took the liberty of describing it as an RTO because I figured they are using a euphemism to avoid that description.”
Asked about Kavulla’s interpretation, PJM spokeswoman Susan Buehler said “The agreement allows PJM and Peak to explore opportunities in the West. We are looking at market services but it’s too early to predict anything else.”
Later, Kavulla tweeted a quote from Gary Ackerman, executive director of the Western Power Trading Forum, who weighed in with a report in the Friday Burrito, his weekly newsletter.
Ackerman said he spoke with Jordan and asked her “if the new venture was contemplating a full market including day-ahead, real-time energy and ancillary services? She assured me it was.
“She also said although no anchor balancing authorities have yet come forward, she has been in discussions with many … and there is widespread interest,” Ackerman wrote, according to Kavulla.
Kavulla also shared a portion of the letter to regulators, in which Peak called the announcement “an exciting opportunity to address challenges facing the West and the issues we have been hearing about as we’ve met with many of our stakeholders. We believe that Peak and PJM’s complementary strengths can lead to a viable and credible alternative option at the time when the West is looking at markets to reduce costs.”
RTO Requirements
Any effort to create a full-fledged RTO would require PJM and Peak to meet the requirements of FERC Order 2000. The order sets four minimum requirements for an RTO: “independence from market participants; appropriate scope and regional configuration; possession of operational authority for all transmission facilities under the RTO’s control; and exclusive authority to maintain short-term reliability.”
Headquartered in Vancouver, Wash., Peak runs reliability coordination offices there and in Loveland, Colo., which provide situational awareness and real-time monitoring of all or parts of 14 western states, the Canadian province of British Columbia and a small, northern portion of Baja California, Mexico. Its region totals 1.6 million square miles and includes 110,129 miles of transmission and a population of 74 million.
The venture is the latest development to indicate the West is warming to the notion of organized markets.
Eight members of Mountain West, including Xcel Energy’s Public Service Company of Colorado, are considering joining SPP. (See Col. Regulators Talk Governance with SPP, Mountain West.) Peak Reliability is Mountain West’s current reliability coordinator.
SPP Chief Operating Officer Carl Monroe did not seem concerned about the prospect of competition. “We’re supportive of markets and collaboration between reliability coordinators in the West and welcome the opportunity to work with PJM and Peak Reliability to bring reliability and economic benefits to ratepayers in the west, just as we have been successfully doing in the east for many years,” he told RTO Insider.
California enacted a law in 2015 that requires CAISO and state energy agencies to explore expanding the ISO to help the state meet its 50% renewable energy mandate. CAISO’s Western Energy Imbalance Market (EIM), which includes PacifiCorp, Arizona Public Service, Puget Sound Energy and NV Energy, has produced more than $213 million in gross benefits since commencing operation in November 2014.
But governance concerns have hampered efforts to build the EIM into a full-fledged RTO. One contentious issue for coal-burning states is California’s requirement that its utilities track carbon emissions from generation serving their loads to ensure compliance with emissions caps. (See CAISO Expansion in Question as EIM Grows.)
The Western Electricity Coordinating Council (WECC) said it had no comment on Peak’s plans. CAISO did not immediately respond to a request for comment.
Peak Reliability was formed in 2014 when WECC bifurcated, with it becoming a NERC Regional Entity and Peak Reliability becoming the reliability coordinator. FERC approved the bifurcation in February 2014, making Peak independent of WECC. WECC was formed in April 2002 from the merger of the Western Systems Coordinating Council, and two regional transmission associations.
NERC regional entities are responsible for reliability compliance monitoring and enforcement activities, while reliability coordinators maintain reliability in real-time, coordinating or directing actions to mitigate system issues.
WECC is in the midst of a separate rebranding and restructuring to focus more on its core reliability mission.
Evolution of PJM Technologies
PJM Connext, formerly known as PJM Technologies, was formed in 2000 under PJM’s “other activities protocol,” Ott said.
“We were one of the first RTOs, so some of the concept back then was if we were to monetize any of that intellectual property or groundbreaking ideas, then that feeds back to the membership. That would lower the stated rate,” Ott said.
PJM Technologies includes PJM EIS (Environmental Information Services), which operates the Generation Attribute Tracking System for tracking renewable energy credits. PJM is also looking to license its Dispatcher Interactive Map Application (DIMA) to transmission owners. (See “TOs Must Approve PJM Licensing of DIMA,” PJM Operating Committee Briefs: Nov. 7, 2017.)
In October, PJM announced the unit had signed a contract to help the Chinese province of Zhejiang develop a real-time energy market. That effort will involve three to four full-time equivalent PJM staffers for 18 months. The province, south of Shanghai, has a load equal to almost half of PJM’s.
PJM is consulting with the Chinese on market design, whereas the deal with Peak is for market operation, Ott said.
“There’s more opportunities presenting themselves” now, Ott said “In this case, we see several popping up at once. Just so happens there are more of them, and we’re being more transparent” about announcing the work, he added. “It’s an opportunity for us to further the advance of competitive markets around the world.”
WASHINGTON — EPA Administrator Scott Pruitt on Thursday confirmed that the agency is working on a replacement to the Obama administration’s Clean Power Plan.
The revelation came in response to a question from Rep. Raul Ruiz (D-Calif.) at a House Environment Subcommittee hearing on the agency’s activities. Pruitt had previously only committed to considering a replacement plan.
Ruiz had asked whether EPA had relied on any new peer-reviewed studies on pollution to support the proposed repeal of the CPP, criticizing Pruitt for reversing the agency’s stance on climate pollution.
Pruitt denied that he had. “Moreover, we are going to be introducing a replacement rule too,” he said.
His statement came at the very end of an hourlong session of the subcommittee in which he answered questions from six members before he left to attend a meeting with President Trump.
Pruitt would return three hours later to resume the hearing, but no subcommittee members followed up on his statement regarding replacement of the CPP or pressed for details about a new plan. Instead, the members’ questions covered a wide array of topics, including Superfund sites, pesticides, water quality, vehicle emissions and fuel standards, hurricane recovery and Pruitt’s frequent travel to his home state of Oklahoma. Pruitt declined to take questions from reporters after the hearing.
He also gave no indication of plans to overturn the agency’s endangerment finding on carbon dioxide.
Earlier in the morning session, Rep. Joe Barton (R-Texas) encouraged Pruitt to revisit the finding, which both agreed EPA had rushed to put out in 2009 in the wake of Massachusetts v. EPA, the Supreme Court decision confirming the agency’s authority to regulate carbon dioxide as a pollutant.
Pruitt also said that he is still working on a “red team/blue team” debate regarding the science of climate change and hoped to announce it at the beginning of next year “at the latest.”
“I think one of the most important things we can do for the American people is provide that type of discussion, because it hasn’t happened at the agency,” Pruitt told Barton. “We need to ensure that type of discussion occurs, and it occurs in a way that the American people know that an objective, transparent review has taken place.”
Thursday’s hearing was predictably partisan in nature. Pruitt received a warm welcome and pats on the back from Republicans, who praised his work at the agency and his so-called “back to basics” approach. Democrats, on the other hand, lambasted him for his rollback of numerous Obama-era regulations, including the CPP.
Many of Pruitt’s answers mirrored those he gave at his Senate confirmation hearing in January. He talked about the importance of the “rule of law” and process, saying EPA had overstepped its bounds under President Barack Obama. (See Dems Unmoved by EPA Pick’s Charm Offensive.)
On Wednesday, EPA announced that it would hold three additional hearings on the CPP after what Pruitt called “the overwhelming response” to the agency’s hearing in Charlestown, W.Va. (See No Unanimity in ‘Coal Country’ Hearing on CPP Repeal.) The agency said the hearings will be in San Francisco, Kansas City, Mo., and Gillette, Wyo., though it did not provide specific dates or venue locations.
By Rich Heidorn Jr., Amanda Durish Cook and Michael Kuser
Kevin McIntyre, sworn in as FERC chairman Thursday, will have a month to build support for his response to the Department of Energy’s controversial proposal for coal and nuclear price supports.
On Friday, Energy Secretary Rick Perry granted a 30-day delay from the Dec. 11 deadline set in Perry’s Notice of Proposed Rulemaking. Saying they were needed for grid resiliency, Perry called for compensating coal and nuclear plants in regions with competitive capacity markets that maintain 90 days of fuel on site.
FERC Chief Administrative Law Judge Carmen A. Citron swears in Kevin McIntyre as his wife, Jennifer Brosnahan McIntyre, holds a Bible. | FERC
In a letter to Perry, McIntyre said the delay was “critical to afford adequate time” for him and Democrat Richard Glick, who was sworn in Nov. 29, to review the more than 1,500 comments filed in the docket (RM18-1) “and engage fully in deliberations.”
Perry agreed to the request Friday, setting a new deadline of Jan. 10. “The commission is nevertheless authorized to act at any time prior to this deadline and I urge the commission to act expeditiously,” Perry wrote. “… I continue to believe that urgent action must be taken to ensure the resilience and security of the electric grid, which is so vitally important to the economic and national security of the United States.”
New commissioners often choose not to vote on issues subject to deliberations before their arrival. Glick, for example, did not participate in a Dec. 1 order on a state-federal jurisdictional dispute over energy efficiency. (See FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out.)
Glick (left) and McIntyre | FERC
Although McIntyre and Glick have had access to the comments in the docket, McIntyre has not had time to build a consensus around his own response.
What McIntyre may have in mind is not apparent. His only prior public comments on the NOPR came at his confirmation hearing in September. (See McIntyre to Senate: ‘FERC does not Pick Fuels’.)
A Republican, McIntyre joins FERC after 22 years at Jones Day, where he was coleader of the law firm’s global energy practice. His former Jones Day colleague Don McGahn is President Trump’s White House counsel.
Perry acted within his legal authority in ordering FERC to consider his NOPR. But he has no power to make FERC provide the relief he is seeking, legal experts say. (See FERC’s Independence to be Tested by DOE NOPR.)
McIntyre did not appear to have signaled his plans to fellow commissioners Cheryl LaFleur or Rob Powelson, who indicated in public appearances Wednesday and Thursday that they expected to rule on Monday, as promised by interim Chairman Neil Chatterjee. DOE Under Secretary Mark Menezes said Wednesday that the ruling was likely to be pushed back one day to Dec. 12. (See DOE: German Energy Struggles Sparked NOPR.)
FERC’s website was briefly overwhelmed by traffic after the agency tweeted out a link to McIntyre’s letter at 6:35 p.m. Thursday.
Analysts at ClearView Energy Partners had said before news of the letter that the commission appeared to lack a consensus for responding to the NOPR. “Over the course of this week, Commissioner Neil Chatterjee conceded that he has not successful in persuading his other colleagues to support the interim solution he prefers,” the analysts wrote in an email to the firm’s clients Friday morning. “Last night’s action indicates to us that the new chairman may not be persuaded that closing the docket and issuing a Notice of Inquiry to the FERC-jurisdictional regional transmission organizations — the option purportedly preferred by Commissioners Cheryl LaFleur and Rob Powelson — is necessarily a course of action he prefers.”
LaFleur told MISO’s Board of Directors meeting in Carmel, Ind., on Thursday that the commissioners were “busily scurrying to get something out on Monday.”
“I’m actually to the point where I’m relieved [the deadline] is Monday because if it was March 11, we’d talk about it until March 11,” she said.
Republicans Chatterjee and Powelson have indicated support for Perry’s proposal. On Wednesday, Powelson told the PJM General Session that the commission would craft a “defensible” response to the NOPR that does not upend competitive markets.
LaFleur Previews Ruling
LaFleur, a Democrat, has been noncommittal in her public statements. (See DOE, Pugliese Press ‘Baseload’ Rescue at NARUC.) She told MISO’s board meeting Thursday that if customers are made to pay for generation attributes, it should be done based on data through a transparent market process.
She also said considerations of resilience should include severe weather, cyber threats and transmission. “It probably shouldn’t be confined to the areas with mandatory capacity auctions because their resilience isn’t more important,” she added.
LaFleur said the commission has reached a saturation point on dissecting the resiliency rule. “Finally, last week, even I had too much, and I said, ‘That’s it; pencils down.’”
She said the NOPR interrupted commission work on the backlog of filings that built up during the six months the commission was without a quorum after the resignation of former Chairman Norman Bay. “It’s as if we had all of our jets lined up for takeoff and someone took the airspace,” she said.
Chatterjee, speaking to a meeting of ISO-NE’s Consumer Liaison Group in Boston on Thursday, reiterated his call for providing “interim” relief to at-risk generators while FERC considers the NOPR. (See Chatterjee: ‘We’ve Moved Past’ DOE NOPR.) Chatterjee also sought to calm those who fear the new commission, now dominated 3-2 by Republicans, will be more partisan and less independent than in the past.
Advice for McIntyre
Among those offering McIntyre congratulations was interim NERC CEO Charles Berardesco. “We have a long and productive relationship with FERC,” he said in a statement. “NERC looks forward to continuing work on the key priorities impacting grid reliability, including the changing resource mix, essential reliability services and security challenges.”
Some of those issuing statements welcoming McIntyre also gave advice on how he should rule on the NOPR and other issues.
The Affordable Energy Coalition, an ad hoc group that includes industrial customers and the American Wind Energy Association, urged McIntyre to reject the NOPR. “Chairman McIntyre joins the commission at a critical moment in the agency’s history,” the group said, adding that the ruling on the DOE proposal “will determine the affordability of electricity for tens of millions of American consumers.”
John Moore, director of the Natural Resource Defense Council’s Sustainable FERC Project said the commission “is at a crossroads.”
“As an independent commission, FERC has largely avoided pressure from the White House and Congress in recent years, and hewed mostly to a nonpartisan (if not always harmonious) path,” Moore wrote in a blog post. “In the last several months, however, FERC has faced unprecedented pressure from the Trump administration to subsidize coal plants and nuclear for their claimed ‘resilience’ attributes. McIntyre’s leadership will be a test of the extent to which he can withstand pressure from the White House to bend to its political ends.”
McIntyre replaces Chatterjee, a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), whose nearly four months as interim chair have been marked by his advocacy for the coal industry and sparring on social media with actor James Cromwell.
It is the first time FERC has had a full complement of five members since October 2015, when Republican Philip Moeller left the commission. The panel faces decisions on ways to harmonize RTO markets with state subsidies for nuclear plants, rulemakings on energy efficiency and distributed energy resources, and pipeline licensing.
During his two decades at Jones Day, McIntyre represented clients in administrative and appellate litigation, compliance and enforcement matters, and corporate transactions. According to his Jones Day biography, McIntyre’s clients have included American Electric Power (negotiations to settle claims in connection with the California energy crisis); SCANA (settlement of Calpine bankruptcy claims); South Carolina Electric & Gas (FERC-jurisdictional rates for electric transmission service); Public Service Company of North Carolina (litigation before FERC concerning the Atlantic Coast Pipeline); and E.ON AG ($1.9 billion acquisition of the North American operations of Irish wind farm operator Airtricity).
McIntyre has been a regular contributor to Republican candidates. In the 2016 presidential primaries, he initially backed both Wisconsin Gov. Scott Walker and Sen. Marco Rubio (R-Fla.), giving each $1,000 in July 2015. He gave Rubio another $1,700 in February 2016. He also has contributed to the Republican National Committee, Sens. Tom Cotton (R-Ark.), Pat Toomey (R-Pa.) and Rob Portman (R-Ohio), and Republican presidential nominees Mitt Romney and John McCain.
McIntyre is a graduate of San Diego State University (A.B., political science) and Georgetown Law. His wife, Jennifer Brosnahan McIntyre, a former deputy general counsel for the U.S. Department of Transportation and associate counsel to President George W. Bush, became chief counsel of Boeing’s Washington Operations in 2010. Married in 2008, the couple have three children.
Cook reported from Carmel, Ind. Kuser reported from Boston.
CAISO on Monday continued an electric transmission emergency in Ventura County because of raging wildfires in Southern California that have forced the evacuation of almost 200,000 people and destroyed more than 1,000 structures. The emergency was extended until midnight Dec. 12.
As of 9:30 p.m. Monday, Southern California Edison said, the Thomas fire was causing intermittent outages and power surges in the Santa Barbara area, potentially affecting up to 85,000 customers. In the Ventura area, 2,393 customers were without power.
On Thursday, ISO spokesman Steven Greenlee told RTO Insider that the Thomas fire was a threat to four 230-kV lines in the Ventura area “and the fire is burning underneath the lines as we speak. But the lines remain in service.”
Rye Fire in Santa Clarita | SCE
In response, CAISO invoked its capacity procurement mechanism (CPM) to dispatch about 614 MW of local generation positioned to provide power should the lines go down, Greenlee said. The CPM units came online at about 2:30 p.m. Dec. 5 and are compensated outside the ISO’s normal market operations.
The Rye and Creek fires in northern Los Angeles County were considered a minimal threat to high-voltage lines in those areas, but Greenlee said CAISO was watching them closely.
Those fires have since been 90% contained, but the Thomas fire has grown to engulf 230,000 acres, making it the fifth largest in state history.
“The [Thomas] fire experienced extreme fire behavior with rapid rates of spread due to the predicted strong Santa Ana winds,” the state’s Department of Forestry and Fire Protection (Cal Fire) said.
Winds in the Santa Monica Mountains in Ventura County sustained speeds of 66 mph and gusted up to 85 mph. The agency is providing regular updates on the fires.
Red icons show active fires as of Thursday morning, black icons show fires in June-October 2017 | Google Maps and CalFire
“Damage assessment teams have not been granted access to fire-damaged areas of the Thomas fire,” SCE said in a statement last week. “When they gain access, progress of their work will be determined by weather conditions, terrain and the movement of the fires.” The utility is also providing updates on its website.
The cause of the fires has not been determined.
Pacific Gas and Electric is facing lawsuits for a separate set of large fires in October, but the cause of those fires is still under investigation as well. (See Wildfires Color California PUC Utility Decisions.) The California Public Utilities Commission recently denied San Diego Gas & Electric cost recovery for other destructive fires in 2007. (See Besieged CPUC Denies SDG&E Wildfire Recovery.)
“The opportunity for people to store energy when prices are low and to access that storage when prices are high could have huge positive benefit to everybody,” Baker said. “There are times within the past few years when we have been paying the highest price in the world for our energy — up to $100/kWh.”
Baker spoke at University of Massachusetts Memorial Hospital, which received a $686,000 grant to integrate a 400-kW solar canopy and a 300-kW/800-kWh flow battery with combined heat and power. The project will not only reduce energy use and costs, but also help the hospital better handle unexpected power outages.
The awards ranged from $221,000 for a project at the West Boylston Municipal Light Plant, to $1.25 million awarded to each of four projects proposed by EnerNOC, Tesla, Constellation Energy Group and the Taunton Municipal Light Plant.
The program received nearly 70 strong proposals, which prompted the state to double the funding from a planned $10 million to $20 million, Department of Energy Resources Commissioner Judith Judson said. The projects would also draw an additional $32 million in matching funds pledged by developers or by host municipalities, she said.
Baker could have declared it energy storage week in the state as ISO-NE hosted a storage panel in Boston later in the day, following a Northeast Energy and Commerce Association storage seminar on Tuesday. The Massachusetts Institute of Technology will hold a clean energy and storage event in Cambridge on Friday. (See ISO-NE Preparing for Energy Storage Growth.)
Judson also appeared on the ISO-NE storage panel, as did Christopher Parent, the RTO’s director of market development. As of Dec. 1, Parent said, ISO-NE has 400 MW of energy storage in the interconnection queue, equal to about 3% of all generation applying to interconnect.
Massachusetts also has a goal to have 300,000 electric vehicles registered in the state by 2025. The state’s $2,500 rebates are helping drive EV sales, illustrated by the 282 rebates issued in November, up from 153 a year earlier. (See Mass. Prepares for EV Growth, Alternative Energy Standard.)
ISO-NE is working to ensure that its wholesale markets can accommodate an expected exponential growth of energy storage resources, an RTO manager said Tuesday.
“We want to be sure that our wholesale markets are favorable to all resource types equally, so when we think about energy storage, we want to make sure it fits in the box,” Carissa Sedlacek, ISO-NE director of market development, said during a Dec. 5 energy storage seminar hosted by the Northeast Energy and Commerce Association in Boston.
| ISO-NE as of December 1, 2017
With 20 MW of energy storage already interconnected in ISO-NE and nearly 80 MW in the interconnection queue, the RTO is adjusting some of its market rules to accommodate the new and flexible resources coming online, Sedlacek said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)
“How is that energy storage facility going to operate?” Sedlacek said. “Is it going to operate at full capacity for one hour, or is it going to operate at quarter-capacity for four hours? How is it going to respond if it’s coupled with wind or solar? Is it going to be there for longer durations? Is it going to be used more in the winter than in the summer? These are the types of questions we ask in the planning department as we consider new resources, especially something like energy storage.”
Spreading the Risk
ISO-NE predicts energy storage providers will largely focus participation in the RTO’s ancillary services market because many of them are not prepared to assume the financial burden of qualifying for the Forward Capacity Market (FCM) — or to confront the risk of coming up short on a capacity supply obligation (CSO), Sedlacek said.
| ISO-NE
“If you get a megawatt CSO that you cannot achieve, there will be a financial penalty,” Sedlacek said, noting that penalties go into effect June 1, 2018, leaving some storage developers “a little gun shy” about offering into the FCM. She noted that solar and wind participants in the FCM don’t typically attempt to qualify for their nameplate capacity, but only a percentage of nameplate (usually 40 to 42%) to ensure their obligation is achievable.
“Because under the [FCM], you’re on the hook to provide those megawatts,” she said.
Sedlacek explained how energy storage developers might hedge their risk by pursuing incentives offered for over-performing in the FCM.
“So you can figure out what your output would be over a four-hour period, because that’s what you have done analysis on and you think might actually last for a shortage of that [capacity amount],” she said. “That’s the megawatts you want to actually take on as the CSO, but be happy to take on additional megawatts or have more output on real shortage events, days or hours, and kind of scoop up the additional revenue.”
Wholesale Market Revenue
ENGIE subsidiary Green Charge Networks recently signed a 20-year agreement to supply Holyoke Gas & Electric with power from the first combined solar and storage project in Massachusetts, according to Jonathan Poor, Green Charge’s director of business development. While the 5-MW solar farm on the site of the retired coal-fired Mount Tom Station in Holyoke is currently in operation, the 3-MW battery will interconnect around May 2018, Poor said.
The storage project is particularly suited to organized markets in New England and New York because it will help firm up output from the solar farm and reduce capacity costs, he said.
“We see, at least in New York ISO and ISO New England, some of the business case coming from wholesale market revenue,” Poor said.
Future solar projects will likely include storage in the interconnection request, given the value of storage, he said.
“We appreciate how holistic the [Solar Massachusetts Renewable Target] program is in Massachusetts for energy storage, and we see a real opportunity to deploy solar and storage and are looking for repeatable use cases that we can scale,” Poor said.
Massachusetts Programs
Massachusetts Clean Energy Center CEO Stephen Pike said that most people know the state’s 2016 Energy Diversity Act for its solicitation for 9.45 TWh of clean energy, but the legislation also included an energy storage mandate, leading the state’s Department of Energy Resources earlier this year to set a 200-MWh storage target for 2020.
While some industry participants considered that goal to be less than ambitious, Pike said there were only 2 MW of storage deployed in Massachusetts when the department began preparing its 2016 State of the Charge report and 4 MW by the time of publication. (See Massachusetts Underwhelms with 200-MWh Storage Target.)
The state’s $10 million in grant funding from its Energy Storage Initiative spurred nearly 70 proposals for storage demonstration projects, Pike said, hinting that awards could be announced within a couple of days.
Richard Stuebi, president of Future Energy Advisors, said improving economics is driving the energy storage market.
“Batteries were $1,000/kWh a few years ago, and now they’re $300/kWh,” Stuebi said. “And, alongside declining cost of batteries, largely driven by the growing market demand for electric vehicles, the costs of all the other components of a complete energy storage system — inverters, control systems and racks — are falling too.”
| MOR-EV
Most of the 700 MW of energy storage currently deployed in the U.S. is utility-scale, and California dominates with 60% of the installed base and a mandate for nearly 2 GW in storage to be operational by 2020, Stuebi said.
But even places like Florida and Michigan, which Steubi hadn’t initially considered promising areas, could get interesting pretty quickly for behind-the-meter storage applications, he said.
