Search
`
November 14, 2024

Posted on

FERC Rejects Complaints from IMM, W.Va. PSC Arguing for Access to PJM Liaison Committee

FERC has denied a pair of complaints against PJM from the Public Service Commission of West Virginia and the RTO’s Independent Market Monitor arguing that denying them access to the RTO’s Liaison Committee violates its governing documents and FERC orders on transparency and board independence (EL23-45, EL23-50). 

The PSC complaint, filed March 8, 2023, argued that language in PJM’s Operating Agreement (OA) detailing the structure of standing committees includes the LC and mandates that nonvoting ex officio members, such as state utility commissions, be permitted to attend. Excluding them from the room while representatives of the five PJM member sectors meet with the RTO’s Board of Managers prevents PSC staff from fully understanding PJM’s decision-making process and may enable FERC-regulated utilities to advocate for market rules that are not in the state’s interest before the board, the regulator argued. (See W.Va. PSC Files Complaint over PJM Meeting Policy.) 

The Monitor stated that the LC often discusses market issues that pertain to its monitoring role. Tariff Attachment M — which details the Monitor’s role in PJM — grants it access to the full stakeholder process, including working group and committee meetings, when it “deems appropriate or necessary to perform its function.” The Monitor’s complaint was filed on March 24, 2023. 

“Excluding the Market Monitor from stakeholder meetings compromises the ability of the Market Monitor to perform its function by depriving it of information exchanged in such meetings and the opportunity to state its independent views. The Market Monitor cannot effectively perform its function when it is excluded from stakeholder meetings. In addition, the Market Monitor has a direct interest in hearing communications and responding to communications from a member or members to the Board that concern the Market Monitor’s performance of the market monitoring function and the terms and conditions of its retention by PJM,” the Monitor’s complaint said. 

The commission’s March 1 order rejected the Monitor’s complaint, stating it had not demonstrated the LC is a part of the stakeholder process under Attachment M, nor established it is part of the Board of Managers’ decision-making process requiring the Monitor’s access. The order says the Monitor has sufficient access to the board through multiple stakeholder process meetings and direct meetings with the board that are closed to stakeholders. 

The Organization of PJM States Inc. (OPSI) submitted comments supporting the Monitor’s complaint, saying state regulators rely on the Monitor’s analysis when considering the effects RTO decisions could have on their rates. By preventing the Monitor from participating in the LC —which it argued is among the most important committees where stakeholders meet with PJM’s Board of Managers — OPSI said the Monitor’s ability to provide state utility commissions with fully informed opinions is inhibited. 

State commissions, FERC staff, the Monitor and OPSI had been permitted to attend the LC until September 2018, when the Members Committee voted to enforce a provision of the LC’s charter limiting attendance to PJM members and its board. (See PJM Stakeholders Table WVa PSC Attendance at Liaison Committee.) 

In rejecting the West Virginia complaint, the commission cited PJM’s argument that the LC is not a standing committee under the OA but instead was formed through a joint effort of the Board of Managers and MC, putting it outside the stakeholder process and not mandating the attendance of state commissions or the Monitor. FERC also said state commissions have adequate access to the board through meetings with PJM through OPSI and at stakeholder meetings with board participation, such as the Members Committee. 

Responding to the PSC’s complaint, PJM compared the LC’s formation to the memorandum of understanding signed with OPSI to hold regular meetings with the Board of Managers without the participation of other stakeholders. 

Transmission owners and the PJM Power Providers (P3) Group argued that keeping the committee closed is appropriate to allow market participants to have candid conversations with the Board of Managers, while the West Virginia commission argued it violates the transparency and board independence provisions of FERC Orders 2000 and 719. The Monitor argued that positions made by PJM members before the board should stand regardless of who is in attendance. 

P3 also argued that allowing the participation of consumer advocates, who are ex officio members with voting rights at the Members Committee, but not state committees, is appropriate because the LC provides an opportunity for voting members to express their views on issues they may be voting on before the board. 

Christie Dissents

Commissioner Mark Christie dissented from the order’s rejection of the Monitor’s complaint, arguing that the majority had focused too much on Attachment M and not considered its relation to the Monitor’s role in PJM, causing it to “miss the forest for the trees.” He argued that even if no votes are taken at the LC, meeting to express views on issues faced by PJM and its members is one in a series of actions that culminates in board decisions. Christie concurred with the order’s stance on the West Virginia complaint and stated he believes the result is correct but cannot join in the reasons the order gave. 

He argued that whether the Monitor has sufficient access to the board was not at issue in the complaint, but rather whether the Monitor was justified in believing that issues raised at the LC are pertinent to the Monitor’s functioning. Christie also said state regulators often are reliant on the Monitor’s analysis and understanding of PJM’s markets and proposed changes.  

“The IMM is given very specific and vitally important duties, both in Order No. 719, which devotes an entire section to the importance of independent market monitoring in all RTOs, as well as, more specifically, in PJM’s specific [Open Access Transmission Tariff] Attachment M. If attending these meetings is ‘necessary or appropriate’ to the IMM doing its job, then the IMM should be allowed to make that decision,” Christie wrote. 

On the PSC West Virginia complaint, Christie said he believes the state commission failed to meet the burden of proof to file the complaint, but stated he believes there’s a larger issue of states not having adequate influence at RTOs when wholesale market or transmission changes can directly affect consumer rates. 

“There exists a much broader issue concerning RTO governance and decision-making that deserves attention, however, that unfortunately is not teed up in this proceeding, which I regard sadly as a missed opportunity … that broader issue is the very real and compelling need to redefine and elevate the roles and authorities of state regulators in all RTOs. State regulators regulate the retail rates paid by consumers, the rates that actually determine the monthly power bills that consumers must pay,” Christie wrote. 

He described the order’s consideration of whether the LC is a standing committee as “‘how many angels can dance on the head of a pin, legalistic hairsplitting,” but stated he does not believe granting state commissions access to the LC would have done much to advance their standing at RTOs even if the complaint had been granted. 

Posted on

FERC Approves $272K in ERO Standard Violation Penalties

In a March 1 ruling, FERC approved settlements between three utilities and their regional entities over violations of NERC’s reliability standards, bearing a total penalty for the companies of $272,000. 

NERC filed the settlements — between ITC and ReliabilityFirst, Evergy and the Midwest Reliability Organization, and the U.S. Army Corps of Engineers’ Mobile district (USACE-MOB) and SERC Reliability — in its monthly spreadsheet notice of penalty Jan. 31 (NP24-5). The ERO also filed a separate spreadsheet NOP that was nonpublic, in keeping with NERC and FERC’s policy regarding violations of the Critical Infrastructure Protection standards. FERC said in its March 1 filing that it would not further review the settlements, leaving the penalties intact. 

RF Knocks ITC for Rating Errors

ReliabilityFirst’s settlement involves a $150,000 penalty against ITC Michigan — composed of Michigan Electric Transmission (METC) and ITC Transmission — as well as ITC Midwest, which operates in Iowa, Minnesota, Wisconsin, Illinois and Missouri. Between them, the companies operate about 15,300 miles of transmission lines. 

RF alleged that the ITC companies infringed on FAC-009-1 (Establish and communicate facility ratings). The standard applies to both transmission owners and generator owners; the relevant section, Requirement R1, requires applicable entities to “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associate facility ratings methodology [FRM].” 

According to the settlement, METC notified RF in June 2020 that it and the other companies named in the complaint were in violation of FAC-008-1; RF decided “upon further analysis” to classify it under FAC-009-1 instead. The RE grouped a separate self-report submitted by ITC Transmission two years later in with this violation because it demonstrated “factual similarity and overlapping issues.” 

The entities identified 15 circuits in which the facility rating was inconsistent with the FRM, around 1.8% of their more than 800 applicable facilities. Of the affected facilities, three affected ITC Midwest and ITC Michigan, and nine affected ITC Transmission. All 15 needed to have their ratings adjusted downward, and three circuits exceeded their correct ratings at some point during the 12 years of the violation. 

RF determined the violation posed a moderate risk to the reliability of the grid, noting that accurate facility ratings are needed to ensure equipment is not operated in an unsafe manner. The RE observed that the duration of the violation “is extensive, dating back over a decade, and covering a period where NERC … put the entities on notice to potential issues and the associated risk in this area.” 

In mitigation, the ITC companies reviewed sag limit data for all circuits at each company and updated their facility ratings and associated documentation. They also implemented a geographic information system to provide better real-time data on their facilities. 

RF added that because the violation extended into MRO’s territory, the REs will split the penalty based on net energy load, with MRO receiving $51,000. 

MRO’s settlement with Evergy, which carries a $122,000 penalty, also concerns facility ratings. In this case, MRO alleged the utility violated FAC-008-3 (Facility ratings), the successor to FAC-009-1 that took effect in 2013; specifically, requirement R6, which is nearly identical to R1 of the earlier standard. FAC-008-3 since has been replaced by FAC-008-5. 

Evergy’s violation occurred in both its role as a generator owner and a transmission owner. According to MRO, Westar and Kansas City Power and Light (KCPL) — Evergy’s predecessors that merged in 2018 — submitted separate self-reports of similar issues prior to the merger. The RE later combined the reports as a single self-report under the Evergy name.  

Westar’s initial self-report identified ratings discrepancies at three generating facilities, while KCPL found discrepancies at three transmission lines and three generating facilities. MRO said “the entity” — whether it meant the post-merger Evergy or the two predecessors was unclear — “performed an extensive review of its facilities and identified two scope expansion issues” in the Westar transmission system. Evergy later performed field walkdowns on all 363 in-scope facilities as part of a mitigation plan that started in 2019. 

According to MRO, Evergy found facility ratings at 133 of its in-scope facilities, including 89 transmission lines, six generators, 28 reactive devices and 10 transformers. The RE identified the cause of the noncompliance as deficiencies in Evergy’s facility rating verification process. 

As with RF and ITC’s settlement, MRO classified the violation as a moderate risk. Although it was considered unlikely the violation would affect grid reliability, the RE noted the length of the violation — occurring over about six years from the time the misratings first were recorded in 2015 until Evergy completed its mitigation plan in 2021 — meant the risk could not be rated as minimal. 

On the other hand, MRO also acknowledged the completion of all mitigation activity, including validating all relevant equipment ratings and making physical modifications where needed to address ratings issues, and provided credit for cooperation, self-reporting and Evergy’s internal compliance program.  

Corps of Engineers Violation Spans 16 Years

SERC’s settlement with USACE-MOB, which carries no monetary penalty, arose from violations of PRC-005-1 (Transmission and generation protection system maintenance and testing) that began when the standard became enforceable in 2007 and were not addressed until 2023, when the successor standard PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) was in force. 

The RE determined via a compliance audit in April 2021 that as a generator operator, the Corps had “failed to maintain its components that are included within the time-based maintenance program” as required in PRC-005-6 (later determined to have begun under the earlier standard). SERC said it could not find any evidence that all of the required maintenance activities had been completed. It also found the Corps had not performed some of the obligatory maintenance activities within the past 18 months as the standard required. 

According to the NOP, SERC determined the cause of the issue was a “lack of internal controls” that could monitor and track compliance with the standard. The RE said the noncompliance posed a minimal risk to grid reliability, observing that none of the affected generators were part of a frequency response program or a black start or system restoration plan. In addition, SERC said there “is no common mode failure” for the affected systems and therefore “the likelihood that multiple generators would trip at the same time … is low.”  

Posted on

Crude Oil, Natural Gas Emissions Regs to be Published

New standards intended to reduce air emissions from the crude oil and natural gas industries are scheduled to be published this week. 

The EPA released the proposed rule in November 2021, supplemented it in December 2022 and announced the final rule in December 2023.  

The prepared text was posted Feb. 23. It will become effective 60 days after publication in the Federal Register, which is scheduled March 8. 

The standards cover new and existing facilities for production, processing, transport and storage of natural gas and crude petroleum. The sector is the largest U.S. industrial emitter of methane, a highly potent greenhouse gas blamed for one-third of the global warming resulting from human activity. 

EPA in December framed the new standards as a sweeping series of changes that would apply to hundreds of thousands of sources nationwide and prevent 58 million tons of methane emissions from 2024 to 2038, delivering health and economic benefits worth billions of dollars in the process. 

In the same time frame, EPA estimates reductions of 16 million tons of volatile organic compounds and 590,000 tons of various other toxic air pollutants that affect human health. It anticipates the prevention of the release of 400 billion cubic feet of fuel per year. 

“Standards of Performance for New, Reconstructed and Modified Sources and Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review” (Document No. 2024-00366) takes several approaches to meeting these goals: It encourages use of advanced technology for detecting methane, encourages continued innovation, sets up a program to identify the “super emitters” blamed for about half of the methane emissions from the oil and gas sector, bars flaring at new oil wells, sets zero-emissions standards for process controllers and pumps outside Alaska, and gives existing emitters three years to submit compliance plans. 

The 1,356-page unpublished version of the final rule lists four main components in its summary: 

    • finalizing revisions to the new source performance standards regulating greenhouse gases and volatile organic compounds emissions for the crude oil and natural gas source category pursuant to the Clean Air Act. 
    • finalizing emission guidelines for states to follow in developing, submitting and implementing state plans to establish performance standards to limit GHG emissions from existing sources in crude oil and natural gas sectors. 
    • finalizing several related actions stemming from the joint resolution of Congress on June 30, 2021, that disapproved EPA’s final 2020 rule for these emissions standards. 
    • finalizing a protocol under the general provisions for optical gas imaging. 

EPA said it received nearly a million comments on the November 2021 proposal and December 2022 supplement, ranging from support for the measures to a desire that they be further strengthened, to practical and cost concerns, to technical suggestions. 

After the rule was finalized in December 2023, it was hailed by groups such as the Environmental Defense Fund (“a major step forward in the fight against climate change”) and Clean Air Task Force (“worth the wait … worthy of celebration”). 

Others were not so happy. 

“The Biden administration has piled on another massive regulatory burden designed to encumber and even shut down American energy production,” said Sen. Kevin Cramer (R-N.D.), the nation’s No. 3 oil-producing state. 

The American Exploration & Production Council said: “While we appreciate EPA’s commitment to bringing all stakeholders to the table and see some improvement within the rule, other provisions remain flawed and risk undercutting U.S. production in the near and long-term.” 

Posted on

MISO Says 2nd LRTP Portfolio Should Run About $20B, Rate Mostly 765 kV

MISO on March 4 suggested an approximately $20 billion portfolio for its second long-range transmission planning (LRTP) effort, calling for several 765-kV line segments.  

The grid operator said its second LRTP draft portfolio for MISO Midwest “focuses on creating a 765-kV transmission ‘highway’ within the MISO region to maximize value based on land use, line distances, transfer levels and costs.” Together, MISO said the anticipated additions could range in cost from $17 billion to $23 billion.   

Several of the suggested 765-kV lines are located near 345-kV line routes approved as part of MISO’s first, $10 billion LRTP portfolio, including routes through Iowa that have been cast into uncertainty by a recent court ruling finding the state’s right of first refusal law unconstitutional. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.) 

The proposed 765-kV network snakes through Missouri, Iowa, Illinois, Wisconsin and Minnesota. Another suggested 765-kV segment cuts through Southern Michigan into Indiana. The second LRTP draft proposal also calls for several substations and more 345-kV lines in Minnesota, Wisconsin, Michigan, Iowa and Illinois.  

As with its first LRTP portfolio, MISO said it sought to minimize new rights-of-way permitting with state regulators to help head off environmental concerns. 

At the Gulf Coast Power Association’s MISO-SPP conference March 4, MISO CEO John Bear said the RTO hopes to finalize the second LRTP portfolio for approval by its board of directors at the end of the year.  

MISO planners have long said “significant” overloads and congestion eventually will threaten the system if the RTO doesn’t recommend a second set of Midwestern transmission solutions. (See MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio.) 

MISO’s new line suggestions are premised on the RTO’s estimate that it will need 369 GW of new, mostly renewable resources by 2042 based on its members’ plans. MISO said the second LRTP portfolio is the next step to “developing a system needed to reliably and efficiently meet the load growth and resource evolution described in MISO’s members’ plans.” 

“This portfolio focuses on creating a regional backbone to meet the long-term needs of our region,” MISO Vice President of System Planning Aubrey Johnson said in a press release. “Our transmission solutions — creating a sort of interstate highway system for electricity — enable the future resource plans of our states, utilities and members by addressing regional needs, while recognizing that local issues will continue to be addressed through our MTEP and generator interconnection queue processes.” 

“The future grid must be able to integrate new load growth and respond to extreme weather, and a robust transmission system is required to ensure this occurs reliably and efficiently,” said Laura Rauch, executive director of transmission planning at MISO. “We know further transmission development can provide value and we will continue working with our stakeholders to refine this portfolio and ensure it is sufficiently robust.” 

MISO said it will continue analyzing the benefits of anticipated portfolio over the coming months and take stakeholders’ suggestions for project alternatives through April 5.  

MISO will hold its next LRTP workshop with stakeholders on March 15.  

Posted on

Utilities Facing Increased Scrutiny over Political Activities

Bribery scandals and concerns over reliability and the pace of decarbonization have caused increasing scrutiny of utilities’ political activities. 

Almost one-third of U.S. states have approved or are considering actions to bar investor-owned utilities from using customer funds to support political activities.   

Michigan last month became the 11th state to consider legislation restricting utilities’ political spending, which already has been approved by four states, according to the Energy and Policy Institute, a watchdog group. In addition, the Louisiana Public Service Commission began a rulemaking last year to investigate utilities’ use of ratepayer money for trade association dues and political influence activities. 

The scrutiny of utilities’ political activities follows a string of recent utility scandals, most notably the bribery indictments in Ohio and Illinois. (See Ex-PUCO Chair, Ex-FirstEnergy Execs Indicted in Ohio and Jury Finds Former ComEd CEO, 3 Others Guilty in Bribery Trial.)

Floodlight, a nonprofit newsroom, reported recently that utility fraud and corruption in those states and Florida, Mississippi and South Carolina have cost ratepayers at least $6.6 billion. “Ratepayers have bankrolled nuclear plants that never got built, transmission systems that were over-engineered to beef up profits and aging coal facilities that couldn’t compete with cheaper ones powered by methane, which the industry calls natural gas,” it said.   

Pay for Play?

Last week, a group of activists calling themselves the “Flip the Switch” coalition gathered outside the Washington, D.C., hotel where hundreds of state regulators, utility officials and other stakeholders gathered for the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit. The group protested what it called the “pay-for-play relationship between utility regulators and the fossil fuel industry” and called on NARUC to stop accepting sponsorship money from groups NARUC members regulate.  

Natalie Mebane, chief program officer, for climate justice organization Zero Hour, speaks at protest outside the NARUC Winter Policy Meeting in Washington last week. | Zero Hour

The Winter Policy Summit’s sponsors included the American Gas Association, American Petroleum Institute and Edison Electric Institute, the organization representing investor-owned utilities. Groups supporting renewables, such as the American Clean Power Association, Advanced Energy United and the Solar Energy Industries Association, also were sponsors. (Disclosure: RTO Insider LLC also was a sponsor.) 

Regina L. Davis, NARUC’s assistant executive director, rejected the protestors’ claim of a “pay-to-play” relationship.

“Because we work hard to convene meetings that foster collaborative discussions and dialogues on a range of issues, we will attract trade groups, whether or not they are sponsors,” she said. “As a fuel-agnostic association, our sponsors represent a range of energy sectors. At this meeting, more than 90% of our sponsors were not affiliated with the fossil fuel industry.”

“We would encourage anyone seriously interested in how our meetings are run to review the Winter meeting agenda instead of making broad generalizations that are not based in fact,” she added. “Our members and stakeholders hold diverse views related to the clean energy transition and are focused on how best to ensure safe, reliable, and affordable energy.”

She noted that attendees included consumer advocates and that NARUC provides free admission to the press, “who function as the eyes and ears of the public.”

In a statement last month, EEI defended its lobbying and its environmental record, saying U.S. power sector carbon emissions are as low as they were 40 years ago, while electricity use has climbed 73%. 

“EEI’s member companies are among the most regulated companies in the country, and EEI engages on their behalf with federal and state legislators, regulators and other policymakers through lobbying, advocacy and regulatory proceedings, with the goal of providing customers with the affordable, reliable and resilient clean energy they need and expect,” it said. 

In 2021, FERC opened a Notice of Inquiry over the recovery of trade association dues in utility rates, with commissioners questioning whether customers should pay for groups that seek policies that may be contrary to consumers’ interests (RM22-5). However, there has been no substantive action in the docket since comments were filed almost two years ago. (See FERC Questions Ratepayer Funding of Trade Association Dues.) 

Michigan Legislation

At a press conference Feb. 22, several Michigan Democrats called for legislation to bar the state’s electric utilities from making political contributions to candidates, political parties and accounts tied to state politicians or social welfare groups. 

HB 5521 prohibits an electric or natural gas utility regulated by the Michigan Public Service Commission from making donations or contributions to 501(c)(4) (political nonprofits) or 527 (political action committees) organizations. HB 5520 prohibits 501(c)(4) or 527 organizations affiliated with state regulated utilities from making donations or contributions to other 501(c)(4) or 527 groups. 

The proposal is backed by a number of environmental and community activist groups but is opposed by DTE Energy and CMS Energy, Michigan’s largest utilities.  

The proposal is aimed at forcing utilities to focus on improving their overall service “instead of increasing their profits,” said the sponsor, Rep. Dylan Wegela (D), referring to blackouts that have followed major storms.  

Wegela, from the Detroit suburb of Garden City, was joined at the press conference by state Sen. Jeff Irwin (D) of Ann Arbor — a city that has an ongoing standoff with DTE over service and rates — as well as state Rep. Emily Dievendorf (D) of Lansing. Lansing and some of its suburbs are served by the city-owned Board of Water and Light and have had fewer blackout problems than either DTE or CMS. In December 2013, however, BWL customers suffered through a blackout that affected customers for as many as 10 days. 

Katie Carey, a spokesperson for CMS, blasted the bills. 

“We’re a Michigan company, and we’re all in on Michigan’s prosperity. We strive to conduct our business in a transparent way, including our participation in the legislative and political process. Contributions to elected officials can come from one of two places — either shareholder profits, or voluntary contributions made by our employees to the Employees for Better Government (EBG) PAC — and never customer dollars. The EBG PAC is nonprofit, nonpartisan and governed by an employee-run steering committee that is independent of the corporation’s officers and board. Participation in the PAC is voluntary and gives employees a voice in the political process, and all PAC contributions are publicly disclosed on the secretary of state’s website.” 

DTE issued a statement, saying: “DTE’s political giving is transparent and within all campaign finance limits. Like most other organizations, DTE participated in the electoral process to advocate to propose safe, reliable, affordable and clean energy for the 3 million Michigan residents and businesses it serves every day.” 

Both utilities have been tied to big money contributions in previous campaigns. In 2022, Michigan Energy First, a 501(c)(4) organization that got money from DTE, donated $1.1 million to the Michigan Democratic Party. In the same year, Citizens for Energizing Michigan’s Economy, a 501(c)(4) organization connected to CMS, donated $200,000 to the Michigan House Democrats. 

Given that politicians from both parties have benefited from contributions from utility employees and community groups backed by the utilities, it’s unlikely either party will take a position in favor of Wegela’s bills. Bridge Michigan reported last year that 102 of 148 sitting Michigan lawmakers have received campaign funds from utility company PACs.  

Bills Approved

Last year, Colorado, Connecticut and Maine enacted prohibitions on utilities’ recovery of lobbying, advertising or trade association costs, according to the Energy and Policy Institute, which seeks to “expose attacks on renewable energy and counter misinformation by fossil fuel and utility interests.” New Hampshire enacted similar legislation in 2019. 

Posted on

FERC Rejects Bridgepoint-ECP Deal for Failing to Disclose Common Owner

FERC denied a merger proposal in which Bridgepoint tried to buy a 19.9% stake in Energy Capital Partners, saying it did so without prejudice because the first firm failed to disclose its relationship with a third company — Blue Owl (EC24-2). 

ECP is a private equity firm that owns interests in Calpine Corp., Terra-Gen Power Holdings, Convergent Energy and Power, and Pivot Energy, while Bridgepoint has a similar business model, but with more assets outside of FERC’s purview. 

Blue Owl owned stock in both firms but told FERC only about its shares in Bridgepoint, saying part of the deal would involve executing an irrevocable deed under United Kingdom law to restrict its actual voting shares below 10%, which is the commission’s threshold that triggers affiliate regulations.  

Public Citizen intervened in the FERC case to note that in requesting approval for the deal from U.K. regulators, the firms said that Blue Owl also owns 19.3% of ECP’s share. That information was never filed at FERC. 

“We find that, based on the record in this proceeding, applicants have not shown the voting restriction is sufficient to eliminate a potential affiliation between Blue Owl and Bridgepoint and that applicants did not provide information as to the holdings of Blue Owl for the purposes of the commission’s competition analysis,” FERC said. 

FERC staff would have normally reached out to the applicants and asked them to file information related to Blue Owl’s overlapping holdings, but the rejection (without prejudice) shows the commission is running out of patience when sophisticated players do not reveal required information, said Public Citizen’s Energy Program Director Tyson Slocum. 

“FERC is a regulator that relies almost exclusively on self-reporting,” Slocum said. “They heavily rely on companies to just come to the table and put all of their cards on the table. And FERC apparently perceived that they didn’t do that here.” 

Because the deal was rejected without prejudice, Bridgepoint said March 4 that it would shortly refile the application with the previously missing information and hoped to close the deal for nearly a fifth of ECP by the second quarter of this year. 

“I think FERC is trying to navigate this space of dealing with increasingly complicated financial structures that are getting into the utility business,” Slocum said. 

ECP is a dominant player in FERC-jurisdictional markets while Bridgepoint owns a great deal of energy infrastructure in Europe, so their combination would be huge. While the deal involves just $1 billion in cash, Slocum said the fact that two top executives at ECP are getting voting rights at Bridgepoint makes this “a merger of equals.” 

FERC is looking at how it regulates investments in the utility with a Notice of Inquiry (AD24-6) announced late last year, which Slocum said will see comments later this month. (See FERC Reconsidering Blanket Authorizations for Investment Companies.) 

Part of the reason for the NOI is the growth in “passive” investors like Vanguard and Blackrock that have put money behind multiple utilities but are not supposed to be active in their governance. 

“Blackrock is a little unique in that it doesn’t just passively manage these funds on behalf of folks’ retirement accounts,” Slocum said. “They also have an actively managed fleet of private equity vehicles that go in and buy up majority stakes in infrastructure assets.” 

Posted on

IMIP Sends Markets+ Tariff on to SPP Board

The panel of independent directors overseeing SPP Markets+’s development in the Western Interconnection lent its approval to the market’s draft tariff March 1, the culmination of months of drafting and refinement. 

The tariff still must be approved by SPP’s Board of Directors before it can be filed with FERC by the end of the month. The board will hold a webinar March 25 to review the tariff. 

“Moments like this, sometimes they can be understated. This is really a momentous occasion,” Steve Wright, chair of the Interim Markets+ Independent Panel (IMIP), said during the virtual meeting March 1. “This is a huge project that has significant implications for how the West will operate over the coming years. It shows an incredible amount of dedication and commitment on the part of the various market participants to be able to move this forward and get to this point.” 

To move forward, though, the IMIP agreed to temporarily pull language specific to Western Area Power Administration’s Desert Southwest Region (WAPA-DSW), which produces hydro power for customers in Arizona, southern California and southern Nevada.  

Antoine Lucas, SPP’s vice president of markets, told the IMIP that staff received a letter from WAPA-DSW on the morning of March 1 that asserted the federal agency’s intention to terminate its Markets+ Phase 1 funding agreement. 

“There are certain special provisions included in the Markets+ draft tariff that are only included in the tariff specifically for WAPA, given their status as a federal entity,” Lucas said. “The special provisions included in the tariff on behalf of WAPA-DSW are very much contained into very specific, discrete areas of the tariff. We do not think they will impact any other aspects of the tariff.” 

Working in real time, staff and stakeholders agreed to set the language — found in Article 2, Section 6.4 — aside for the time being.  

The section’s language will have to be deleted before the tariff is filed with FERC to ensure its approval, Lucas said. The Markets+ legal subgroup will review the WAPA language and provide a recommendation on its inclusion. 

Lucas declined to give reasons for WAPA-DSW’s withdrawal from Markets+’s first phase of development and whether it eventually would join the market. He said his interpretation of the letter was that it is a “formal request” to terminate the agreement. 

SPP attorney Chris Nolen said the Markets+ participation agreement anticipated a participant terminating their agreement and then joining the market after it goes live. It includes provisions that ensure participants who chose that route still would have to pay what would have been their share of Markets+’s costs. 

“We’ve crafted that agreement so that we would avoid the potentiality that some parties might not want to take the risk of a substantial time pending at FERC,” Nolen said, noting the market’s $500,000 monthly run rate. 

“The agreement was crafted where if someone leaves before Phase 2, not only do they have to pay their fair share when they come back in, they don’t get any credit for what they paid in Phase 1,” Nolen added. “That just goes to the market bucket to offset the cost of Markets+, so there was a disincentive built into the Phase 1 funding agreement.” 

The IMIP easily approved several other pieces of tariff language, including greenhouse gas settlement and substantive and non-substantive items. 

“We’re looking at a pretty good pathway to getting this filed by the end of March,” said The Energy Authority’s Laura Trolese, chair of the stakeholder-driven Markets+ Participant Executive Committee. 

Posted on

Hydrogen Getting Resource-specific Rules in NYISO Markets

NYISO on Feb. 29 took the first steps to creating market rules enabling hydrogen to participate in its marketplace, after kicking off the market design concept for the clean energy resource. 

The ISO’s current rules do not cover how an emissions-free generator co-located with a load resource like an electrolyzer, producing clean hydrogen using energy from a nearby solar or wind facility, could participate in New York. NYISO proposes investigating if it can enable this either by creating new, or modifying existing, participation models. 

NYISO estimates its clean hydrogen market participation models will be deployed in 2027 but acknowledges hydrogen is a nascent technology and so any proposed enhancements must be adaptable to innovations. 

Aaron Breidenbaugh, senior director of regulatory affairs at CPower Energy Management, sought clarification on whether the final proposals, though tailored to hydrogen, could apply to a range of future resources. CPower aggregates demand response and distributed energy resources, advocating for NYISO to always incorporate evolving technologies into its proposals. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.) 

Harris Eisenhardt, a market design specialist with NYISO, responded that the ISO’s objective is to propose a final market concept that is “technology-agnostic” and “suitable for other use cases as well.” 

New York has devoted less attention to developing hydrogen and other less prominent fossil fuel alternatives, like nuclear or bioenergy, because they can be controversial among climate activists. (See Take the Long View on Clean Energy, NY Legislators Urged.) Instead, the focus has been on yet-unknown technologies that NYISO collectively terms dispatchable emission-free resources (DEFRs). These DEFRs are not yet commercially available, prompting the state’s Public Service Commission to explore clean energy technologies, including hydrogen, bioenergy, nuclear power and carbon capture (15-E-0302). (See NY Drills Down on Statutory Meaning of ‘Zero Emissions’.) 

New York has, however, seen some actions recently promoting hydrogen development. State senators have introduced a handful of bills this year to facilitate its deployment (S378A) (S8455); Gov. Kathy Hochul (D) announced several multimillion-dollar investments in hydrogen initiatives across the state last year (14-M-0094); and New York now leads a multistate regional clean hydrogen hub competing for federal funds. (See NY Moves to Boost Hydrogen Production and Development and Vermont Joins Northeast Clean Hydrogen Hub.)  

Additionally, Constellation Energy’s Nine Mile Point Nuclear Plant in Oswego, N.Y., started producing hydrogen with nuclear energy last year. (See Constellation Expands Nuclear Clean Energy Matching.)  

NYISO plans to review its draft market design concepts with stakeholders in the second quarter of this year and expects to finalize the proposal by the end of the third quarter. 

Capacity Accreditation

NYISO also informed the ICAP/MIWG that the final capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs) for the 2024/25 capability year are published online. 

CAFs calculate the marginal reliability contribution of “representative” generators for each CARC, a differentiation based on technology and operating characteristics. The CAFs reflect factors such as energy duration limitations and correlated unavailability due to weather or fuel supply limitations and were used alongside resource-specific derating factors to account for differences in a unit’s output from the modeled CARC profile. 

Final capacity accreditation factors for 2024/25 capability year | NYISO

Last year, NYISO addressed issues in its capacity accreditation modeling, such as misrepresented marginal reliability contributions of some resources, leading to inaccurate CAF and CARC calculations. (See “Capacity Accreditation,” NYISO Finds No Need for New Capacity Zones and “Capacity Accreditation Modeling,” NYISO BIC Stakeholders OK Modeling, Market Design.) 

ICAP suppliers who notice a discrepancy in their assigned values must notify NYISO by 5 p.m. March 18, when CAF assignments will be considered official. 

Posted on

Nev. Regulators to Weigh Approaches to RTO Membership

NV Energy and several stakeholder groups have weighed in on how Nevada regulators should evaluate a request from the utility to join a day-ahead market or RTO. 

Several of those who filed comments with the Public Utilities Commission of Nevada noted that PUCN faced a similar issue in 2014 — when NV Energy asked for approval to join CAISO’s Western Energy Imbalance Market (WEIM). 

NV Energy made that request through an amendment to its energy supply plan. Some stakeholders said that process could also work well for considering a request to join a day-ahead market.  

But joining an RTO raises new issues, stakeholders said, and PUCN should consider rulemaking to detail how such a request would be considered. 

“NV Energy’s participation in the day-ahead market is analogous to its current participation in the WEIM in that NV Energy would not transfer operational control over any assets … and current state regulatory authority would be left unchanged,” Ben Fitch-Fleischmann of Interwest Energy Alliance, an association of utility-scale renewable energy developers, said in written comments. 

“In contrast, joining an RTO may require a host of changes, including the development of joint transmission tariffs, consolidation of balancing area authority and operations, and changes to how transmission planning would be coordinated, and costs allocated,” Fitch-Fleischmann added. 

PUCN will hold a workshop March 4 to discuss a process for reviewing an RTO or day-ahead market request. 

Legislative Mandate

Senate Bill 448 of the Nevada Legislature’s 2021 session directs NV Energy to join an RTO by 2030, unless PUCN waives the requirement or grants a delay. A waiver or delay is allowed if the utility can’t find “a viable and available” RTO to join or determines that joining an RTO wouldn’t be in the best interests of the utility and its customers. 

PUCN opened a docket on the matter last year and, in January, ordered NV Energy to file comments by Feb. 16 answering several questions about how the commission should evaluate a request to join an RTO. Stakeholders had the opportunity to comment as well. 

In NV Energy’s filing, Deputy General Counsel Timothy Clausen noted the utility’s promise in a 2013 proceeding to seek PUCN approval before participating in an RTO- or ISO-run market. But a procedure for seeking approval wasn’t detailed at that time. 

In 2014, NV Energy asked for approval to participate in the WEIM through an amendment to the portfolio optimization procedures in its energy supply plan (ESP).  

NV Energy said the ESP could also be used to request approval to participate in a day-ahead market or RTO. But certain aspects of joining an RTO or day-ahead market might need approval through the IRP process, the utility said. Those could include building or procuring resources or transmission to meet resource adequacy requirements. 

Day-ahead Market Timeline

Some commenters worried that PUCN rulemaking to create a new approval process could delay NV Energy’s participation in a day-ahead market. CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ day-ahead offering are both expected to launch in 2026. 

“Any delay in obtaining permanent regulations can impact the timeliness of NV Energy joining a day-ahead market. This delay would affect NV Energy’s customers who, in the interim, would miss out on benefits anticipated by joining a day-ahead market,” Justina Caviglia, an attorney representing Google, said in written comments. The company has data centers in Nevada. 

But Advanced Energy United argued against using the IRP or ESP process for evaluating a request to join a day-ahead market or RTO. 

“The regulations governing ESP/IRP [do] not currently contain requirements or standards for the evaluation of several relevant criteria, including market pricing policies, transparency and oversight, stakeholder and policymaker engagement and input, or respect for state policy mandates,” AEU director Brian Turner said in written comments. 

And adding to the already complex subject matter of an IRP could be overwhelming for NV Energy, PUCN and stakeholders, AEU said. 

If the commission starts rulemaking now, AEU said, regulations could be in place this summer or fall and NV Energy could apply for day-ahead market approval late this year or in early 2025. 

Posted on

NARUC Looks at How to Manage New Large Loads

WASHINGTON, D.C. — The power industry is facing an increasingly delicate balancing act as policies drive some generators to retirement, while major new loads are popping up and making planning for the future more difficult, presenters said during the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit. 

Historically, PJM has seen its markets drive retirement decisions. Some 90% of the 66,000 MW that have retired in the past couple of decades have come offline when they requested, and most needed no upgrades to accommodate their absence from the grid, said PJM Director of State Policy Solutions Tim Burdis. 

“I look out the next 10 years. In 2035 in the PJM footprint, we have 26 GW slated to come off of the system, just based on state and federal policy requirements,” Burdis said. “So that’s not factoring in anything related to the market signal, or the underlying reliability aspects.” 

That’s going to lead to more of a division between generators coming off the system and its reliability needs, which means PJM and its members will need to do more to ensure reliability, he added. 

“It’s also 26 GW of new load coming onto the system over that same time period in PJM’s latest load forecast,” Burdis said. “So that’s about 52,000 MW or so that are going to have to be accounted for of new supply on the system.” 

While historically PJM has balanced the relatively few instances where a retirement leads to reliability issues by expanding the grid, that might not be enough going forward. Both the demand side and new generation being built at retired sites could help ensure the shift happens reliably, Burdis said. 

The state of Oregon is facing many of the same issues on load, especially, which is making the PUC’s job of integrated resource planning more difficult, said Chair Megan Decker. 

“I’m not going to waste our time with statistics, but suffice it to say that the Pacific Northwest in general and Oregon in particular are seeing significant interest from the data centers that are needed to power, among other things, the AI revolution and, even more exciting for our state’s economy, … high-tech manufacturing,” Decker said. “These can be hundreds or more megawatts at a time and collectively are pushing load growth projections for the region beyond anything we’ve seen or really imagined until very recently.” 

Integrated resource plans (IRP) are not accustomed to the uncertainty around big new loads, with data center demand showing up more quickly than load traditionally has, and sometimes in the middle of an IRP process, making them hard to plan for. 

“Because of the customer’s competitive sensitivities, they can’t be as transparently scrutinized,” Decker said. 

Oregon is the rare state outside of an RTO with retail competition, and to the extent those new loads are served by competitors, Decker questioned how much retailers would contribute to the overall resource adequacy of the system. 

One way of handling the situation would be to move away from IRPs and have the PUC look at procurement after the fact, but that would have negative implications for meeting state policies and affordability, she added. 

Southern Renewable Energy Association Executive Director Simon Mahan is no stranger to IRPs, representing independent power producers interested in building clean energy around the Southeast. He has intervened on their behalf in many cases. 

“The process is not necessarily geared towards ensuring that intervening parties like myself, like our organization, have all the information available,” Mahan said. “The information asymmetry is astronomically high as an intervening party.” 

That makes it important for state regulators and their staff to prepare well ahead of time with data collection and ask the right questions, rather than waiting for the contested process to launch that starts a “sprint towards the finish line,” he added. 

Typically, the processes might take a year, but utilities work on the filings starting well before that, which means they can be out of date by the time they are filed. 

“They will vigorously defend the report, even though there may be news articles or press releases, even from their own corporate headquarters, saying: ‘oh, by the way, we plan to do XYZ,’ which is in total contradiction [to] what the Integrated Resource Plan actually says,” Mahan said. 

Mahan quipped that the IRP reports are so full of redactions, including sometimes even publicly available data, that utilities must have a “side hustle in” markers. 

The rapid changes make forecasting more difficult, and that means regulators and other intervenors are going to have to “trust but verify” what is being filed. 

“How can we verify that what we’re being provided through the lens of the utility is what the customers need the best?” Mahan asked. “And one of the best ways is by letting people like me in the process, so that we can serve as another pair of eyes.” 

While the industry and its regulators face hurdles to ensuring reliability on a transitioning grid, University of Chicago Law School assistant professor Joshua Macey said one common misconception of utility is not among them. 

“To the extent that regulators are open to trying ambitious new options, there are no legal barriers. Our constraints are political, and they are economic,” Macey said. 

The “regulatory compact” was overturned in 1934 by the Supreme Court in Nebbia v. New York, which gave Congress more power to regulate the economy. That overturned the old precedent on regulation, where utilities could be overseen because they had been granted a monopoly over the service territory. 

“So, what’s notable about this is we have a set of industries that are the only industries where we have constitutional authority to regulate,” Macey said. “We then have a series of Supreme Court cases that say the question of proper regulation was a legislative determination. And yet we continue to hear arguments that the old model applies only in these industries.” 

Cases since then (many dealing with the fallout from Three Mile Island and its impact on the nuclear industry) have made it clear that utilities are entitled to their existing assets, but the next set of assets are open to whatever regulatory determination is correct. 

“I think we should be open to experimentation,” Macey said. “The fact that someone has done it in the past may or may not mean they’re in a position to do it most effectively in the future. But it certainly means utilities can take a loss. If they don’t reach their meet their contractual obligation, they can take a real loss.”