The NERC Board of Trustees posted a notice saying it “is aware of the personal incident involving” Cauley and naming General Counsel Charles Berardesco as interim CEO. Cauley is on a leave of absence “until further notice,” the board said, adding that it is “taking steps to ensure the work of NERC continues seamlessly.”
Reached by phone before the statement was posted, NERC Board Chairman Roy Thilly declined to say whether he had spoken to Cauley but said he had been released from jail.
“I don’t want to discuss any further what our process is,” he said. “Obviously the board is aware, and we need to proceed very deliberately and expeditiously to determine what the facts are.”
Asked whether NERC was aware of any prior history of domestic abuse, Thilly said, “Not to my knowledge.”
A FERC spokeswoman said the agency had no comment.
Familiar Face
Cauley, who has led NERC as CEO for nearly eight years, is a familiar face in D.C., often testifying before Congress and FERC.
He holds a bachelor’s in math and electrical engineering from the U.S. Military Academy, a master’s in nuclear engineering from the University of Maryland and an MBA from Loyola University.
He served as the program manager for grid operations and planning at the Electric Power Research Institute and served five years as an officer in the U.S. Army Corps of Engineers before joining NERC in 1996.
As vice president and director of standards, he helped prepare NERC’s application to become the FERC-certified Electric Reliability Organization after the 2005 Energy Policy Act gave the commission the power to enact mandatory reliability standards.
He left NERC in March 2007 to become CEO of SERC Reliability Corp., returning as CEO in January 2010.
He earned $757,481 in salary and $80,985 in other compensation in 2015 according to NERC’s IRS form 990. NERC, which employs about 230, has a 2018 budget of almost $73 million.
Berardesco
Berardesco, who goes by “Charlie,” joined NERC as general counsel in July 2012 after more than nine years at Constellation Energy, where he served as senior vice president, general counsel, corporate secretary and chief compliance officer.
Before Constellation, Berardesco practiced law and served in executive positions at Fusara, a consortium of AIG, Kemper and Prudential, and HCIA, a health-care information company.
Berardesco | Duke University Chapel
He has a bachelor’s in political science from Duke University and a law degree from George Washington University, where he was managing editor of The George Washington Law Review and now serves on the dean’s board of advisors.
According to his NERC biography, his other nonprofit endeavors include serving as chair of Duke University Chapel’s advisory board; board chair of the Gay Men’s Chorus of Washington, and a member of the Business Council of the Human Rights Campaign.
Among his awards and recognition: named one of the top 10 “GC’s to Watch” by The Corporate Board magazine; named a Leader in the Law by The Daily Record; and winner of the Out and Proud Corporate Counsel award by the National LGBT Bar Association.
Increased labor costs from the expanding Western Energy Imbalance Market (EIM) helped push up CAISO’s 2018 revenue requirement by $1.9 million to $197.2 million, but growing EIM revenues will offset some of the costs, the ISO said Tuesday.
CAISO is taking comments on its proposed 2018 budget, which calls for $217.4 million in total outlays, up 1.4% from this year. The spending package includes 14 new full-time positions, along with raises, promotions and benefit increases. Offsetting the costs are a projected $3.4 million increase in revenues, including a projected $2.6 million growth in EIM proceeds.
“That is almost entirely being driven by EIM,” CAISO Chief Financial Officer Ryan Seghesio said of the new employee positions during a Nov. 7 conference call. “We see some needs to add some headcount, particularly in the technology space, to help the EIM market. The good news there is that it gets offset from some EIM revenue.” The proposal would bring the ISO’s total number of budgeted employees to 614, according to his presentation.
The operations and maintenance budget, which refers to costs of ongoing operations, grew by about 3% to $178.5 million, including the 14 new positions. Debt service — principal and interest payments — remains flat at about $16.9 million. Collection of capital was lowered by $2 million to $22 million to help absorb some of the operations and maintenance increase, he said. Transmission volume is expected to increase slightly to 241 TWh.
Proposed 2018 CAISO budget, by resource | CAISO
Capital and project requirements are budgeted at $18 million. CAISO listed dozens of proposed projects for 2018, divided into market and operational excellence; technology improvements; customer service; and grid evolution readiness and regional innovation opportunities.
EIM administrative charges are projected to grow by 56%, or $2.6 million, to about $7.4 million, because of increased participation. Fees for forecasting intermittent renewables are also projected to grow by 52%, or $1.1 million, to about $3.2 million because of new resources coming online.
But the costs of conducting studies of large interconnection projects are projected to decrease by $700,000, or 37%, to $1.2 million, CAISO said. The ISO recovers its revenue through the grid management charges paid by market participants.
CAISO in the budget proposal also discussed its goals, including aggregating distributed energy and clean resources, citing 21,000 MW of renewables that are connected to the grid.
“The ISO is closely coordinating and collaborating with generators, utilities, transmission owners, energy regulators and diverse stakeholder groups, developing a grid and market structure that encourages distributed energy resources,” CAISO said. “Following a tariff filing and regulatory approval (which is expected in early 2018), entrepreneurs and utilities will be allowed to bundle, or aggregate, DERs such as energy storage, so that any extra energy can participate in the ISO wholesale market just like a utility-scale generator.”
Comments on the budget proposal are due on Nov. 14, with a vote by the Board of Governors set for Dec. 13-14.
While not even a year has passed since MISO implemented its new interconnection queue process, one market participant is already urging stakeholder groups to consider a two-stage queue instead of the RTO’s selected three-stage design.
EDF Renewable Energy argues that the “flawed” three-stage process is worsening the interconnection backlog, and that MISO has the means to implement a two-stage queue. During a Nov. 7 conference call, the company asked the RTO’s Steering Committee to assign the appropriate stakeholder committee a discussion on shortening the queue process for vetted projects and developing an earlier assessment of milestone payments.
“MISO’s published data shows a serious backlog in its queue,” EDF’s Omar Martino wrote in comments to the RTO. “It needs a streamlined process so that projects that demonstrate they are ready to proceed toward an interconnection agreement can actually achieve that.”
Steering Committee members determined they need more information on the EDF proposal before they can assign the issue to a stakeholder committee. They asked the company to return in January with a fuller explanation.
Bruce Grabow, an attorney with Locke Lord representing EDF, said that while MISO’s three-stage process is a “good” model, it doesn’t require enough front-end milestone fees to discourage “speculative megawatts.” He said charging milestone payments before the definitive planning phase (DPP) of the queue could discourage uncertain projects from entering.
In an effort to reduce restudies that caused backlogs in the old queue process, MISO’s new queue design divided the DPP — the final stage of the queue — into three phases in which system impact studies are performed three separate times in lieu of restudies. At the time, MISO estimated that interconnection customers would spend 460 days in all three stages combined, instead of the previous average 589 days in the DPP.
“Shore up a bit more the site control from the beginning,” Grabow urged, noting that 60 to 70% of MISO’s queue entrants now enter the queue without securing site control, electing to instead pay a $100,000 fee as part of the new queue rules.
“We’ve opened the floodgates, so to speak,” he said.
MISO views a queue overhaul so soon after the January approval of the new design as “premature,” MISO Stakeholder Relations Specialist Justin Stewart said. “FERC approved the process in January, and we’d like to see a full cycle through.”
Grabow said he was only asking to begin a discussion in the Planning Advisory Committee.
MISO External Affairs Director Vikram Godbole said stakeholders debated the merits of a two-phase queue process in 2015 and ultimately decided against it. He asked stakeholders to allow time for the new queue design to work before proposing modifications.
“I’m personally wary of making changes before we see how the changes we’ve just made roll through the process,” said PAC Chair Cynthia Crane.
Similar Requests Denied in FERC Order
EDF’s request for a faster queue comes on the heels of a Nov. 3 FERC order that denied a rehearing of several aspects of the new queue process.
That order stemmed from a filing by a group of generation developers who complained that MISO’s new process had failed to actually streamline the queue because it does not update system data as quickly as promised and charges only $100,000 upfront when a project developer has not yet secured site control (ER17-156).
The generation developers also questioned FERC allowing MISO to conduct restudies after a generation interconnection agreement has been signed, and also contended that a developer that withdraws its projects within six months of signing such an agreement should have to pay to mitigate the cost shifts stemming from the cancellation.
The commission rebuffed most of the developers’ arguments, saying the group failed to provide evidence or reasoning to support its proposal, and that MISO’s role was to “minimize but not necessarily eliminate restudies.”
But FERC did agree with the developers’ concerns about projects withdrawing from the queue after executing interconnection agreements, which prompts the need for restudies and increases interconnection costs. The commission directed MISO to include data on the number of such withdrawals — and the number of resulting restudies and their cost impacts — in its semiannual reports on the queue process.
FERC denied a request for a special “fast track” study process for developers who can demonstrate “site control, evidence of power sales opportunity and security in the amount of 20% of all identified network upgrades,” but it advised MISO to alleviate delays for those developers anxious about missing production tax credit deadlines.
The developers claimed that MISO’s queue transition timeline is already behind schedule, with interconnection agreements for the MISO West region February 2017 transition group delayed until June 2019, “a full five months beyond the planned January 2019 completion date.”
MISO argued that adding a faster study timeline option would throw its interconnection process “into disarray.”
“Although such delays suggest that MISO’s queue reforms may not be working as well as intended, we do not find that these delays rise to the level of the ‘extraordinary circumstances’ the commission has required to reopen the record … and to disturb the finality of the DPP framework accepted in the Jan. 3 order,” the commission said. “We strongly encourage MISO to consider measures that could be adopted to address the delays.”
After recently confronting confusion around the stakeholder task force nomination process, MISO’s Steering Committee is seeking to clarify how the RTO will nominate and elect individuals to fill stakeholder group leadership positions in the future.
The issue emerged at the Steering Committee’s September meeting, when the committee deviated from standard practice by administering separate elections for the positions of chair and vice chair of MISO’s Energy Storage Task Force during the same election cycle. Both candidates for chair expressed an interest in running for vice chair if they weren’t picked for the top spot and, as a result, one nomination for vice chair was submitted after the deadline, leaving the committee to decide whether to include the late submission for voting. Committee members voted to reopen the nominating process, but not all stakeholders were pleased with the process. (See Nomination Redux for MISO Energy Storage Task Force.)
MISO’s Stakeholder Governance Guide is silent on the issue of moving election dates, accepting late nominations or dealing with instances when stakeholders simultaneously run for two leadership positions in the same committee.
The Steering Committee will take up the issue in January, when it will vote on redline clarifications to the elections process outlined in the governance guide. The changes could allow consecutive ballots in instances where a stakeholder wants to run for chair but also be considered eligible for vice chair should they lose their bid for the chair position.
Ameren’s Ray McCausland said his company supports Stakeholder Governance Guide changes that allow a stakeholder to run for both chair and vice chair simultaneously, with the option for runoff elections when needed. If the same candidate is elected to both positions, the candidate would accept the chair position, and a runoff election would be held using the previous slate of vice chair candidates. Currently, elections for chair and vice chair for all MISO stakeholder committees and groups are held simultaneously via electronic ballot among MISO members with voting rights. No late nominations are accepted.
Madison Gas and Electric’s Megan Wisersky said that while she understood the RTO’s wish not to dissuade stakeholders from running for leadership positions, she could also see the value in compelling individuals to focus on running for a single position.
“I’m not much help here,” she joked during a Nov. 7 conference call.
WPPI Energy also advocated for the continued simultaneous election of chair and vice chairs, requiring candidates to choose to run for a single position and not both leadership positions.
McCausland argued that preventing a candidate from running for both positions might lead to empty vice chair positions.
The New England Power Generators Association (NEPGA) on Monday filed a request for rehearing of FERC’s Oct. 6 order accepting ISO-NE’s updated cost of new entry value for the RTO’s capacity auctions (ER17-795).
ISO-NE is required to recalculate the values every three years and will apply the revisions in next February’s Forward Capacity Auction 12 covering the 2021/22 capacity commitment period, as well as in FCAs 13 and 14. (See FERC Approves ISO-NE CONE, Offer Trigger Updates.)
The Brayton Point Power Station in Somerset, MA went offline in June 2017.
In its Nov. 6 filing, NEPGA specified several perceived errors in FERC’s order and asked the commission to reconsider its previous finding that a net CONE value based on simple cycle generator technology is just and reasonable. The group instead favors basing that value on the costs needed to support a combined cycle turbine. It is asking the commission to change the rules in time for FCA 12, which begins Feb. 7, 2018.
NEPGA contended that the order was “arbitrary and capricious and not the product of reasoned decision-making” because the commission did not balance the financial interests of capacity providers against the “substantial” benefits conferred to load. The group also argued that the commission failed to consider the record of evidence indicating that simple cycle generators are not likely to be built in New England.
The $8.04/kW-month net CONE value proposed by the grid operator will cause a $1.5 billion reduction in market-wide capacity revenues at equilibrium from FCA 11 to FCA 12, which for a 500-MW capacity resource means a $22.8 million cut in capacity revenues in a single year, and more than $67 million during the three years covered by the auction, NEPGA said.
The filing did not seek to change the commission’s approval of offer review trigger price (ORTP) values, which were also part of the order.
CAISO is facing pressure from some stakeholders to broaden the scope of its latest effort intended to increase the participation of energy storage and distributed energy resources in its market.
The ISO is in the beginning stages of its Energy Storage and Distributed Energy Resources (ESDER) Phase 3 initiative, kicked off in September with an issue paper that will be developed into a straw proposal. (See CAISO Load-Shifting Product to Target Energy Storage.) Participants in the effort include companies such as eMotorWerks, Stem, investor-owned utilities and the California Energy Storage Alliance.
Energy storage company STEM is participating in CAISO’s ESDER Phase 3 | STEM
ESDER Phase 2 unearthed several issues for Phase 3, most which are touched on in the issue paper. Based on stakeholder input, CAISO is proposing that the latest initiative cover rule changes that would relax limitations on how demand response can participate in the market, as well as the integration of distributed resources, microgrids and electric vehicle charging infrastructure. The effort could also explore “multiple-use applications” for energy storage, which recognize the ability of those resources to provide services and receive revenue from more than one entity at a time, such as at the wholesale, transmission and distribution levels.
Developing electric vehicle charging equipment load curtailment as a proxy demand resource is one aspect of ESDER Phase 3 | emotorwerks
In a Nov. 6 conference call, the ISO asked stakeholders to prioritize among a list of six topics listed in the issue paper regarding changes to demand response rules, which provide a point of market entry for distributed resources. Those topics include how to handle challenges such as setting start-up and minimum/maximum load costs, dealing with variability of weather-sensitive DR, refining DR aggregation rules and others.
CAISO representatives at various points in the call indicated they do not want to delve too deeply into one particular focus area of the initiative, which includes many complex challenges in implementing new technologies and market products.
But Robert Anderson — chief technology officer for Olivine, a DR and DER services company — urged the ISO not to require commenters to choose among the six topics for the DR portion of the initiative, but instead cover them all.
“When is ESDER Phase 4?” Anderson asked rhetorically. “The question is: ‘When do we get another chance at this?’ I am very optimistic that you guys can take on a lot more than you think.” Instead of a slower approach to the proposals, “maybe we can get through them very quickly, and get them done and get them behind us,” he said.
Margaret Miller of Customized Energy Solutions said the microgrid sector is not well-represented in the stakeholder process, and there are a lot of unanswered questions as to how microgrids will participate in wholesale markets.
“There are decisions made today that could unduly limit those microgrids from participating,” she said, calling for policy guidance in ESDER 3 or elsewhere. “Otherwise, we are continuing to address these on a one-off basis.”
CAISO External Affairs Officer Peter Colussy said microgrids are being studied in other processes. ESDER 3 is aimed at looking at different technologies and platforms to provide various services, not focusing too much on one technology, he said.
“We are not trying to focus on microgrids here,” Colussy said.
The CAISO Board of Governors in July approved ESDER Phase 2, which is still pending approval by FERC. (See New CAISO Rules Spell Increased DER Role.) That initiative developed a set of alternative energy usage baselines to assess the performance of proxy demand resources, which are DER aggregations of retail customers. It also developed new rules that distinguish between charging energy and station power for storage resources, and created a net benefits test for DR resources that participate in the Western Energy Imbalance Market (EIM).
FERC on Tuesday agreed to sharply reduce the penalty Barclays Bank must pay to settle claims that it manipulated Western electricity markets a decade ago.
The commission approved a settlement agreement requiring the U.K.-based company to pay $105 million in penalties after company traders engaged in a two-year scheme to influence physical power prices at certain trading hubs in the West in order to benefit from their positions in financial swaps covering those same markets (IN08-8). The illegal trades occurred from November 2006 to December 2008, and involved the Mid-Columbia, NP-15, SP-15 and Palo Verde delivery points.
FERC accused Barclays traders of influencing prices at the Mid-Columbia, NP-15, SP-15 and Palo Verde trading hubs in order to benefit the bank’s positions in financial swaps covering those markets. | EIA
The agreement represents a significant comedown for FERC, which in July 2013 levied a record $470 million fine against Barclays, which included a requirement that the bank disgorge nearly $35 million in profits from the scheme. Those proceeds were to be paid into the low-income home energy assistance programs (LIHEAPs) of Arizona, California, Oregon and Washington. Former FERC Chairman Norman Bay was director of the commission’s Office of Enforcement at the time.
Barclays challenged the penalty in federal court, and Tuesday’s settlement indicates the bank largely prevailed in its nearly five-year legal battle with FERC. Under the terms of the agreement, the bank will pay just $70 million in civil penalties, though it must still relinquish its profits from the scheme, just over half of which will be directed to the LIHEAPs. The company and its traders did not admit nor deny committing any violations against the commission’s anti-manipulation rules.
“The commission concludes that the agreement is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations stated [in the order] and in the agreement,” FERC wrote in its decision to approve the order.
One critic of the settlement strongly disagreed with FERC’s take.
“FERC’s action is an outrage and sends a clear signal to market manipulators: Crime will now pay,” Tyson Slocum, director of Public Citizen’s energy program, said in a statement.
Slocum said the “egregious” settlement did not occur in isolation but instead points to a broader development in which FERC “may be getting soft on rule-breakers.” As evidence, he cited the recent appointment of General Counsel James Danly, who previously served on the legal team defending Dynegy in market manipulation case brought by Public Citizen (EL15-70). One of Danly’s former law partners has written articles “attacking” Bay’s enforcement actions and appointment as chair, Slocum pointed out.
“Consumers have benefited from FERC’s aggressive enforcement of wrongdoers,” Slocum said. “The evisceration of the Barclays settlement, when combined with key staffing decisions at FERC, may signal that the days of tough enforcement on banks, hedge funds and other energy traders may be coming to an end.”
Slocum called for Congress to hold an oversight hearing on FERC operations to ensure that consumers are protected from energy market manipulation.
David Applebaum, an attorney who previously served as director of investigations in the Office of Enforcement, told Bloomberg that FERC’s move was “inevitable” after a federal judge in September ruled the agency had waited too long to bring its case against Ryan Smith, one of the Barclays traders involved in the scheme. Smith, along with fellow traders Karen Levine and Daniel Brin, initially faced penalties of $1 million each, while their manager, Scott Connelly, was ordered to pay $15 million.
“I think once the Smith decision came out, it was inevitable that FERC would have to reduce its damages and civil penalties significantly,” Applebaum said.
Levine, Brin and Connelly were covered under Tuesday’s settlement.
ERCOT on Monday approved Luminant’s proposal to dispose of nearly 2,300 MW of coal-fired generation capacity in Texas.
The ISO’s reliability assessments determined that none of the four units at the company’s Big Brown and Sandow plants was “required to support ERCOT transmission system reliability.”
ERCOT said the Texas grid is undergoing “significant change,” with new technologies “changing the role that some older generation resources play in grid and market operations.” The ISO said lower natural gas prices have been reducing revenues for all generators in recent years, and wind and solar resources continue to flood the market.
As of Oct. 30, ERCOT has nearly 48 GW of new generation projects under study, and more than 21 GW of new projects have interconnection agreements. That includes more than 10 GW of proposed gas-fired projects, 2 GW of utility-scale solar and more than 8.7 GW of wind projects.
ERCOT has said it will have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. It will update the expected reserve margins for 2018 and the next several years in the next Capacity, Demand, and Reserves Report, scheduled for Dec. 18.
The Public Utility Commission of Texas has also directed the ISO to study and consider the appropriate level of reserves needed to maintain reliability while minimizing costs in its energy-only market.
Big Brown’s two units date back to the early 1970s and are capable of 1,150 MW of output. Vistra has said it is exploring a sale of the site north of Houston, but the plant will be shut down if it hasn’t been sold by Feb. 12, 2018.
Sandow’s units date back to 1981 and 2009 and have 1,137 MW of capacity. They will be closed Jan. 11.
Combined with the earlier retirement of Monticello’s three coal units, Luminant will have shuttered 4,167 MW of coal capacity by early next year — more than half of its 8,000 MW of available capacity. The company has only two coal plants left: Martin Lake (2,250 MW) in East Texas and Oak Grove (1,600 MW) in the southern part of the state.
Exelon will relinquish four Texas natural gas plants to its lenders and pay $60 million to keep a fifth plant in the latest response to what the company called “historically low power prices” in the state.
The plans were detailed in a Chapter 11 bankruptcy filing Nov. 7 by ExGen Texas Power, Exelon’s merchant generation business in Texas, and in an 8-K filing by Exelon. It follows Vistra Energy’s announcements last month that it would retire 4,100 MW of coal-fired generation in the state.
The 738-MW Wolf Hollow facility in Granbury, Texas, is one of the four power plants in the state Exelon will sell as part of the bankruptcy of its ExGen Texas Power subsidiary. | GE Power
Exelon said it made the bankruptcy filing to offload most of a $675 million loan due in September 2021. “Pending a competitive bidding process,” the company said in a statement, it will pay $60 million to lenders to keep its 1,265-MW Handley Generating Plant in Fort Worth.
“Lenders have agreed to exchange the debt they currently hold in EGTP’s other four plants for equity in the plants, effectively taking ownership of these facilities,” Exelon said.
The company told the Securities and Exchange Commission that it expects a pre-tax gain of $125 million to $200 million in the fourth quarter off the sale. It had recorded pre-tax impairment charges of $418 million in the second quarter of 2017 and $40 million in the third quarter for the plants.
The other four plants are the 738-MW Wolf Hollow combined cycle facility in Granbury; the 510-MW Colorado Bend combined cycle in Wharton; the 808-MW Mountain Creek steam boiler in Dallas; and the 156-MW simple cycle facility in La Porte.
The company has been seeking to sell its Texas fleet since at least March, when Reuters reported that it had hired a debt restructuring adviser to help it evaluate its options. This followed a January decision by Moody’s Investors Services to downgrade EGTP’s debt from B2 to Caa1.
Exelon’s stock closed at $41.27/share Tuesday, up 1.45% from Monday’s close.
Independent Market Monitor Beth Garza told ERCOT’s Board of Directors last month that the Vistra retirements will result in higher prices and lower capacity margins, citing two years of “clearly unsustainably low prices with high reserve margins.” (See ERCOT IMM: ‘Fat and Happy’ Times Ending with Coal Closures.)
Nuclear and coal generators made their closing argument for price supports Tuesday, as opponents urged FERC to reject the proposal or let RTO stakeholders take up the resilience debate.
Tuesday was the deadline for reply comments in response to the Department of Energy’s Notice of Proposed Rulemaking, which called for cost-of-service pricing for coal and nuclear generators in competitive markets (RM18-1). The deadline for initial comments was Oct. 23. (See FERC Flooded with Comments on DOE NOPR.)
The Rule of Three
Three-step proposals were all the rage in the latest filings, with the Nuclear Energy Institute calling for a cost-of-service mechanism to prevent “premature” retirements, an order requiring RTOs to promptly improve their price formation rules, and a long-term program for ensuring that organized markets value resilience.
Exelon, which is the beneficiary of nuclear subsidies in Illinois and New York, had its own three-step proposal, starting with “immediate action” to correct “inaccurate price signals [for] fuel-secure resources,” including ordering PJM to make energy market reforms within 90 days. RTOs and ISOs also would be prevented from mitigating the capacity market bids of plants receiving zero-emission credits “or other support payments.”
FERC should follow those actions, the company argued, with an order requiring RTOs to report on their systems’ vulnerabilities to high-impact, low-frequency events. Lastly, it said the commission should use that data, “together with threat analysis from the national security and intelligence communities, to establish a design basis threat (DBT) that can inform cost-effective market reforms.” The DBT would provide a resilience benchmark and a basis for developing solutions, the company said.
The last two steps of Advanced Energy Management Alliance’s proposal were like those of Exelon’s, with the opening of a resilience proceeding and reporting by RTOs.
But the group, which represents distributed energy resource companies and storage providers, had its own idea for step one: “Eliminate barriers to storage and distributed energy resource participation” by finalizing FERC’s November 2016 NOPR (RM16-23). (See FERC Rule Would Boost Energy Storage, DER.)
The commission received hundreds of responses to the DOE NOPR. FERC staffer Patrick Clarey told the SPP Board of Directors meeting Oct. 24 that the commission had received more than 700 comments; AEMA said it had counted “roughly 750 sets of comments.”
Congress Weighs in
Among the most recent responses were dueling submissions from members of Congress, with Republicans generally supporting the proposal and Democrats mostly in opposition.
Illinois Republican Reps. Mike Bost, Rodney Davis and Darin LaHood said “the proposed DOE rule makes critical strides toward correcting faulty market designs and valuing the role of baseload generation.”
Rep. Joyce Beatty (D-Ohio) joined with David Joyce and 10 other Ohio Republicans to warn that premature plant closings “have resulted in an electrical grid with weakened resiliency and a diminished ability to respond to crisis.”
New Jersey Republican Reps. Frank LoBiondo and Leonard Lance expressed fear that the state could lose its nuclear generation — the source of almost half of its electricity.
Hope Creek Nuclear Generating Station in New Jersey
Rep. Jerry McNerney (D-Calif.) and 13 other Democrats from his state, Pennsylvania, Hawaii, New York, Massachusetts, North Carolina, Virginia and Vermont expressed “serious concerns with the proposal and its timeline.”
They cited DOE data showing outages resulting from extreme weather increased 10-fold from 1984 to 2012 and doubled between 2003 and 2014. “Given these facts and the compounding, regional and varied effects of climate change on extreme weather, a one-size-fits-all approach to resiliency, as outlined in the NOPR, is inappropriate and not adequate to the challenge,” they said.
House Energy Subcommittee Vice Chair Pete Olson (R-Texas) joined with ranking member Bobby Rush (D-Ill.) to say more time is needed to study the “remarkably complex issue.” They said it should be addressed “through existing proceedings at the federal and regional level rather than quickly moving to make a sweeping, top-down decision in the near term.”
“FERC — with bipartisan support from members of Congress and presidents — have worked for decades to improve these markets. Ultimately, this has given us markets that provide a reliable and resilient power system through open competition. This has also meant that risks are borne by investors in generating assets, not consumers or taxpayers. We continue to believe this is critically important,” they said.
Among those also registering support for the NOPR were the Interior Department, Southern Co. and AES (parent of Indianapolis Power & Light, Dayton Power and Light and AES Energy Storage).
Opponents Urge Time for Study
In contrast, the Electricity Consumers Resource Council and other industrial energy users said the NOPR would “overturn decades of precedent and suddenly determine the existing RTO/ISO tariffs are unjust and unreasonable.”
A broad coalition including the American Petroleum Institute, American Wind Energy Association, Conservation Law Foundation and Electric Power Supply Association reiterated its earlier comments, urging FERC to reject what they called an “abrupt and unjustified cost-based compensation mechanism.”
The National Association of State Utility Consumer Advocates, which had not filed initial comments, said acting on DOE’s demand for a final rule within 60 days would violate the Administrative Procedure Act by failing to provide the public with adequate notice or reasonable time to have meaningful input.
ISO-NE said the “very limited time” FERC allowed for reply comments did “not permit a comprehensive rebuttal to the efforts of the NOPR’s supporters to overcome the proposal’s unsound foundation.”
“However, in-depth analysis is not needed to understand why the proposal is both legally untenable and an unviable policy option,” the RTO said. “The breadth and depth of opposition to the NOPR among industry stakeholders and electricity consumers is striking in its own right.”
American Municipal Power also cited procedural concerns. “Several other commenters suggested that the commission adopt alternative proposals to modify the RTO energy market rules or take other actions that are beyond what was contemplated by the DOE proposal. The commission cannot lawfully accept such proposals as part of this rulemaking process.”
Former FERC Chairman Norman Bay made a similar point at the GTM U.S. Power and Renewables Summit in Austin, Texas, Tuesday.
“The timeline really amounts to a rocket docket. There’s no other way to describe it,” Bay said. “When you look at FERC Order 888, FERC spent a year on that particular order. In the normal course of events, it’s not uncommon to see a rulemaking take 12-15 months, or even longer than that,” Bay said.
AMP also agreed with many critics that the DOE proposal failed to prove existing RTO market rules are unjust and unreasonable. “The legal deficiencies coupled with the practical reality that the DOE proposal would not resolve the reliability concerns raised by the secretary but would impose significant new costs on customers should make this an easy call for the commission,” AMP said.
The Environmental Defense Fund urged FERC to “further enhance gas-electric coordination in a focused and targeted manner.”
“Electric generators were the smallest sector for natural gas demand in 1988, and they now are the largest,” EDF said. “But the natural gas regulatory framework has not kept pace with this new development.”
Next Steps
The commission has said it expects to take some action on the proposal within 60 days after its Oct. 10 publication in the Federal Register.
FERC will address the NOPR with a full complement of commissioners, thanks to the Senate’s Nov. 2 confirmation of Republican Kevin McIntyre and Democrat Richard Glick.
Tom Kleckner and Michael Kuser contributed to this article.
