New York Gov. Kathy Hochul (D) has vetoed the Planned Offshore Wind Transmission Act approved by the state Legislature this year.
The legislation (A7764/S6218A) had two purposes: to establish a planning process for transmission capacity for future offshore wind generation and to allow an export cable for the Empire Wind project to run through parkland in the oceanside city of Long Beach.
Hochul said the first aspect is unneeded, as such planning is underway, and the second aspect is inappropriate, because renewable energy development needs to happen with support of the host community, not over its objections.
The Long Beach land matter was more immediate. Given the state of offshore wind development in New York state — almost the entire contracted portfolio, more than 4 GW in total, is in danger of cancellation — the reaction was predictable.
New York Offshore Wind Alliance Director Fred Zalcman said in a prepared statement: “The governor’s actions are not matching her words. As a previously professed champion of offshore wind, we are once again mystified by the governor’s decision to veto this essential authorization and to put another nail in the coffin of the Empire Wind project.”
Equinor, which is developing Empire Wind with bp, said: “The veto of The Planned Offshore Wind Transmission Act undermines New York’s commitment to the energy transition and the role offshore wind must play in achieving the state’s renewable energy mandates. This decision sends another troubling signal to renewable energy developers following [the] action by the New York State Public Service Commission.”
The PSC on Oct. 12 decided not to grant inflation-related cost adjustments to the Beacon, Empire and Sunrise offshore wind projects, along with 86 much smaller land-based wind and solar projects. (See New York Rejects Inflation Adjustment for Renewable Projects.)
Their developers had said they might not be able to commence construction without more money, as costs had increased greatly after they signed their contracts with New York state.
Long Beach became a rallying point because some residents do not want an underground cable running across the barrier island and their neighborhoods. (See ‘What Did We Do to Deserve This?’)
Under New York law, conveying parkland to a nonpublic entity or using it for something other than a park is called “alienation” and requires legislative authorization.
The language of the legislation authorized the city of Long Beach, at its discretion, to alienate roughly an acre of parkland. This left the choice to the city, and Hochul noted the city is opposed to alienation. But she went one step further in her veto message and denied even the choice to city leaders.
“It is incumbent upon renewable energy developers to cultivate and maintain strong ties to their host communities throughout the planning, siting and operation of all large-scale projects,” she wrote.
Other projects have been snagged by the state’s strong home-rule tradition, which can give local communities an outsized role in shaping large-scale development.
Critics of the route through Long Beach were pleased with the veto.
Rep. Anthony Esposito (R) cast it as a victory for a community fighting a deeply unpopular project being forced upon them.
He said in a news release: “Equinor’s attempt to bypass Long Islanders’ overwhelming opposition to the project by utilizing state legislators from New York City to force their corporate endorsed legislation on Nassau County was shameful. I am grateful Governor Hochul has listened to Long Islanders this time, but the fight to preserve our South Shore from Equinor’s corporate greed will continue.”
By contrast, the “planning” aspect of the Planned Offshore Wind Transmission Act was less emotional and more practical. It looks forward with the assumption that New York will want to expand offshore wind beyond the 9 GW of installed capacity goal that state law sets for 2035 and attempts to direct a more coordinated and cohesive transmission planning process to bring all that electricity to customers.
The legislation would have directed the New York State Energy Research and Development Authority to lead planning of independent transmission systems. Such shared transmission would minimize costs and environmental or community impacts, it said.
Hochul in her veto message said this is largely duplicative of existing planning requirements, such as New York’s Accelerated Renewable Energy Growth and Community Benefit Act. The PSC has begun meeting its requirements, she wrote.
“To the extent that this bill’s planning requirements are not duplicative, they would cause confusion by assigning contradictory and overlapping planning responsibilities to NYSERDA,” she wrote.
“In light of these concerns, I am constrained to veto this bill.”
A meeting of CAISO’s Greenhouse Gas Coordination Working Group on Oct. 19 illustrated the complexity Western stakeholders confront in addressing emissions in the region’s expanding electricity markets — including the challenge of agreeing on basic definitions.
The meeting was the third for the group, a forum for stakeholders to discuss how the cost of GHGs should be accounted for in CAISO’s Extended Day-Ahead Market (EDAM) and Western Energy Imbalance Market (WEIM). In both markets, the ISO must find ways to strike a balance between the needs of states that price carbon emissions in their economies and those that don’t.
The working group was established to evolve GHG accounting design as a whole, with the goal of WEIM participants developing an accurate system to attribute generator emissions to load across state lines. Stakeholders have identified many uncertainties and are still in the beginning stages of defining current and potential problems that could occur after implementation of the EDAM, which will carry over the WEIM’s current GHG accounting practices until needed changes are identified.
Of the 10 states participating in the WEIM, only two — California and Washington — price carbon through a cap-and-trade system, complicating the pricing of energy into and out of those “GHG zones.”
Further complicating matters is that California and Washington operate separate cap-and-trade programs, increasing the potential for the over- or undercounting of GHGs when accounting for power transfers between the two states. Washington officials expect to decide soon whether to seek to join the joint California-Quebec carbon market, but any such linkage would occur in 2025 at the earliest. (See Analysis Favors Wash. Linkage with Calif. Cap-and-trade Program.)
The working group will also consider how CAISO’s markets in the future might reflect obligations associated with “non-price” GHG policies, such as renewable portfolio standards, clean energy standards and renewable energy certificates.
Clarity on Definitions
Last week’s meeting was devoted to discussing problem statements that were submitted by stakeholders that outline current or foreseeable issues regarding emissions attributions. Participants discussed how best to phrase and think about the problem statements and then identified action items to address them. The goal of a problem statement is to determine the root cause of an issue and come up with a solution.
Problems identified included how to account for and control emissions “leakage”; the potential double-counting of emissions between Washington and California; and determining if the current system’s price formation accurately identifies total marginal GHG costs.
Much of the discussion dealt with the wording of the problem statements themselves, rather than trying to solve them. In Problem Statement 1, which describes the uncertainty around whether CAISO’s market correctly identifies the “available surplus” of resources that may be attributed to a GHG zone, the definition of “surplus” was questioned.
“Buried in here is an assumption that there’s an agreed definition of ‘surplus,’” said Clare Breidenich, a consultant speaking for the Western Power Trading Forum. “We do not have that clarity from the California Air Resources Board.”
The assumption is that “surplus” is generation in excess of the load for the market footprint outside of California, Breidenich added, and that it shouldn’t necessarily be the same for all resource types, considering that entities operate differently in the market.
Jessica Zahnow of Puget Sound Energy suggested that looking at historical dispatches and attributions and running counterfactuals (the resource sufficiency evaluation in the WEIM) could help determine surplus and help stakeholders begin to understand if CAISO’s market correctly identifies it.
The discussion about Problem Statement 2 prompted questions about use of the term “secondary dispatch,” which has generally referred to the practice of a power producer directing output from a lower-emitting resource to a market that prices GHGs — such as California — while secondarily firing up an emitting resource to backfill load that would have otherwise been served by the cleaner resource. For states attempting to track and price carbon, the process results in the “leakage” of emissions in accounting for the true source of GHGs.
Problem Statement 2 states that the current attribution process still results in secondary dispatch and that the market lacks sufficient transparency into how often it is occurring. The discussion centered around identifying correct wording in order to best evaluate the issue. Stakeholders raised the concern that the statement assumes “secondary dispatch” and “leakage” are synonymous, when a producer may have to perform secondary dispatch for reasons not related to emissions.
Anja Gilbert, a lead policy developer at CAISO, suggested the two be differentiated and the problem be looked at in terms of leakage rather than secondary dispatch. Todd Ryan, principal market design analyst with Pacific Gas and Electric, echoed the concern.
“To my understanding, secondary dispatch can occur for a host of reasons, including economic displacement, which is the purpose of the Extended Day-Ahead Market and markets in general,” Ryan said. “Leakage is a specific type of secondary dispatch that occurs when resources are inappropriately shuffled in terms of carbon intensity. [The terms] are often used synonymously, but I believe that is incorrect.”
Kallie Wells, senior consultant with Gridwell Consulting, pointed out that the context of the conversation surrounding GHGs indicates that stakeholders are referring to leakage, not secondary dispatch, and that the differentiation should be made.
Gilbert added that a system of monitoring should be put in place to identify leakage when the EDAM goes live, given that CAISO and its stakeholders won’t be able to assess its degree until after implementation.
At the suggestion of CAISO Market Engineering Specialist Kevin Head, the group clarified the problem statement to reflect secondary dispatch “that is not occurring as a result of economic displacement,” but rather because of resource shuffling that leads to the inappropriate sale of non-renewable resources.
Further discussion indicated the need for an agreed-upon definition of leakage in the context of the statement and highlighted uncertainties about what type of leakage the problem statement refers to.
“What exactly are we talking about when we say leakage?” Wells said. “There’s so much gray area, and I think until we are very clear about that, we’re going to keep dancing around the same issue.”
Premature Discussion?
Wells’ comment was representative of a larger theme in the meeting: the need for more precision and a better understanding of how CAISO and its stakeholders should approach potential GHG-related problems in the absence of a way to test them.
Bonnie Blair, an attorney who represents the publicly owned utilities of the “Six Cities” in Southern California, echoed this concern.
“It’s not clear to me, with respect to either of these problem statements, what market we’re talking about” because the EDAM has yet to go live, Blair said. “We have the existing imbalance energy market, which does have a broad footprint and involves attribution of GHGs across [balancing authority areas]. We have the current day-ahead market, which is limited to the CAISO area and, I think, does not involve attribution of GHG impacts; and then we have the EDAM market design, which hasn’t yet been implemented and is not going to be implemented for, I think, two and a half years.”
Gilbert echoed the concern. “I think a complicating factor has been that we only have a live EIM market, and so without a live EDAM market, some of the proposed enhancements for EDAM that are looking to fix some of the issues with the WEIM enhancement can’t be tested until they go live,” she said.
An efficient way to view the problem statements, according to Gilbert, would be thinking about statements that could address potential enhancements that will need to be made in a future policy design phase.
Blair agreed, but she again emphasized the challenge of imagining problems in a system that does not yet exist.
“It provokes me to raise the question about whether it makes sense to try to focus now on fixing a problem that may or may not exist after the enhancements to the GHG process that are built into the EDAM design go into place,” Blair said. “I question whether that may be premature.”
The working group’s next meeting is tentatively scheduled for Oct. 30, when it will continue to address the list of problem statements submitted by stakeholders.
A Canadian company must prove it does not have market power in a geographic market that includes parts of northern Maine, or take steps to mitigate that market power, FERC ruled Oct. 19 (ER14-225-009).
New Brunswick Energy Marketing (NBEM) failed the wholesale market share indicative screen in three out of four seasons for the November 2020 to December 2021 study period, while passing the pivotal supplier indicative screen. FERC presumes the existence of horizontal market power when a seller fails one of the screens.
NBEM argued in its 2022 filing that a delivered price test and additional evidence indicate the NBEM does not have market power, despite the screen failure.
Based on the evidence it provided, NBEM urged the commission to “conclude that NB Energy Marketing has rebutted the presumption of horizontal market power and satisfies the commission’s horizontal market power standard for the grant of continued market‐based rate authority.”
FERC responded that despite the additional evidence, “we conclude that New Brunswick Energy Marketing’s failure of the wholesale market share indicative screen provides the basis for the commission to institute the instant section 206 proceeding … to determine whether New Brunswick Energy Marketing may continue to charge market-based rates.”
FERC added it can initiate an investigation into market power while it reviews the additional evidence provided. It directed NBEM to provide evidence to justify “why the commission should not revoke New Brunswick Energy Marketing’s market-based rate authority in the New Brunswick balancing authority area.”
NBEM alternatively could propose measures to mitigate any market power, adopt FERC’s default cost-based rates or submit different cost-based rates.
FERC told NBEM to file a response within 60 days of the order, and said it expects to issue a final decision by April 16, 2024.
LITTLE ROCK, Ark. — SPP stakeholders last week approved two revision requests following a lengthy discussion that set resource adequacy policies.
The Markets and Operations Policy Committee first rejected a compromise position recommended by two stakeholder groups. They urged that one of the two revision requests, which details SPP’s proposed performance-based accreditation (PBA) policy (RR554), be modified to use seven years of historical data, rather than 10, in calculating conventional resources’ accredited capacity.
That motion received only 57% approval during MOPC’s two-day meeting. Replacing the seven years of historical data with 10 years resulted in 84% approval for RR554 and RR568, which lays out an effective load-carrying capability (ELCC) policy, with all 14 transmission owners voting yes.
RR568 is a response to FERC’s rejection earlier this year of SPP’s first attempt to add ELCC (the amount of incremental load a resource can dependably and reliably serve during peak hours). The revision reduces a three-tiered structure to just two, firm and non-firm transmission service. Staff will study only firm service in its ELCC analysis. (See FERC Grants Rehearing of SPP Capacity Accreditation Proposal.)
SPP’s Market Monitoring Unit initially proposed five years of historical data but settled on the seven-year compromise during a September meeting with the Resource and Energy Adequacy Leadership (REAL) Team. (See SPP REAL Team Compromises on PBA, ELCC Revisions.)
“It’s important that we have an accurate assessment of historical performance. We feel that [five years] is a much more accurate representation of an assessment period,” MMU’s executive director, Keith Collins, said. “As you think about going forward, are you doing things to improve the performance of your resource?”
Smaller utilities sided with the 10 years of historical data, saying it would give them and their smaller fleets more time to meet resource requirements.
“They’re facing an entirely different risk profile in this RTO going forward, and that can’t be overstated enough. The risk now is substantial in the loss of a unit over a period of time,” Golden Spread Electric Cooperative’s Mike Wise said.
“It is a balancing act,” SPP’s Casey Cathey, senior director of grid asset utilization, said. “It’s a question of if we can provide more accurate, responsible performing resources through maybe a shortened timeframe, then that might lessen the socializing of an increase in [planning reserve margin]. But to the extent that we can better accredit those resources, then it more accurately applies that to the individual resources as opposed to socializing them.”
MOPC also approved a Supply Adequacy Working Group policy paper on demand response (DR) that will be converted into a revision request and the stakeholder group’s direction on fuel assurance. Both motions passed with more than 91% approval.
The SAWG plans to develop a policy that facilitates diverse DR programs by considering the potential for increases in large loads that may claim its accreditation. Its members say SPP must accurately accredit DR resources according to their reliability contribution and develop qualification standards to drive consistency.
The group also voted to develop policy that incorporates PBA weighting based on critical system periods and considers modifications to the out-of-management-control exceptions related to fuel-related outages. The SAWG also will consider a policy for PBA and ELCC adjustments to reflect new reliability investments and it recommends SPP improve operational dispatch strategies to start units before extreme cold weather and keep them online.
Cathey said he hopes the changes can be implemented before the 2026-27 winter season.
Sunflower Waiver Request Rejected
Members rejected Sunflower Electric Power’s request that four byway transmission upgrades be allocated 100% to the entire pool, based on their regional use, under a cost-allocation methodology that FERC rejected earlier this year.
SPP’s largest transmission owners pushed back against the measure, saying allocating costs of existing facilities should not be done on an ad hoc basis by the RTO’s state regulators. They said deconstructing the grid operator’s highway/byway process with one-off reassignments sets a troubling precedent for future requests.
Eight of 12 TOs voted against the measure and six others abstained. Half of the transmission users voted for RR584. It failed with 50.8% approval.
“There’s no actual methodology associated with this. This is just some power facilities being moved into the tariff and being elevated to highway funding without clear direction or a repeatable process also being applied to it,” Southwestern Public Service Co.’s (SPS) Jarred Cooley said. “We at SPS are very concerned that this is going to set an ad hoc precedent on how cost allocation is performed moving forward on an ad hoc basis. It’s a repeatable process and without a methodology or a firm waiver process.”
FERC in July unanimously reversed a 2022 decision that established a process for SPP to allocate “byway” transmission projects on a case-by-case basis without prejudice. (See FERC Reverses Course on SPP Byway Cost Plan.)
Sunflower, a “wind-rich” cooperative that long has felt unduly burdened with transmission costs for renewable energy that benefits others, has filed a rehearing request with FERC and asked the U.S. Court of Appeals for D.C. to review the case (ER22-1846).
The cooperative submitted its waiver in November 2022 from SPP’s base-plan allocation methodology for upgrades between 100 kV and 300 kV, or byway projects. The process allocates one-third of the cost of byway projects to the RTO’s full footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide.
The Cost Allocation Working Group (CAWG) approved Sunflower’s waiver request in May. In September, it recommended to SPP state regulators that they approve and send to the board a revision request (RR584) allowing SPP to make a Section 205 filing at FERC that permits the four Sunflower upgrades be regionally allocated on a prospective basis.
The Regional Tariff Working Group approved RR584 later in September in a 9-5 vote, with five abstentions.
SPP’s Ben Bright, the CAWG’s staff secretary, said the group intends to continue working on the issue with the Regional State Committee (RSC), which has ultimate decision-making authority over SPP’s rates.
“The filings at FERC are still in limbo,” Bright told the MOPC. “Once those are more complete, then we will take up looking at a more comprehensive process, whether that be in the form of a waiver or just some sort of an assessment.”
The CAWG intends to make the same recommendation during the next RSC meeting.
Project Withdrawn, ITP Passes
MOPC approved two stakeholder groups’ (Transmission Working Group, Economic Studies Working Group) 2023 Integrated Transmission Plan (ITP) and its 10-year assessment , but not before members withdrew a $92 million, 48-mile, 115-kV joint economic project in Nebraska between the Western Area Power Administration’s Rocky Mountain Region and the Nebraska Public Power District.
The TWG’s motion failed with 53% approval when the project was included but passed with 97% approval when it was removed. The move gives SPP staff more time to find the right solution.
The Municipal Energy Agency of Nebraska’s Brad Hans motioned to add a notice to construct (NTC) for the Alliance-Victory Hill project. According to the assessment, the line would be congested by several elements in the area. Staff evaluated several alternatives, but timely rebuilds would be with non-SPP facilities, limiting viable solutions.
The 2023 ITP addresses reliability and economic issues on its seams. It recommends NTCs for 44 projects. The portfolio includes 150 miles of new transmission — 51 miles for 345-kV lines — and 93 miles of rebuild for a total engineering and construction cost of $735.5 million and a reduced 40-year adjusted production cost of nearly $3 billion.
Natalie McIntire, representing the Sustainable FERC Project and Natural Resources Defense Council, compared the portfolio’s size with that of recent MISO portfolios approaching $10 billion and suggested a third more aggressive future be used.
“The levels of expected increase in electrification [and] the rapid change in our generation mix across the country, seem to me to indicate that we’re going to need a lot more transmission. We’re going to need a much more robust grid,” she said. “I’m just concerned that SPP is going to find themselves behind the eight-ball in terms of meeting their members’ needs and maintaining a reliable system under this transition that we’re going through.”
Natasha Henderson, SPP’s director of system planning, said the grid operator has been doing economic planning for “some time,” resulting in small portfolios. She agreed the RTO must use accurate study inputs and said some of the more aggressive forecasts she’s seen for electrification triples the load.
“That makes my heart stop,” she said. “I stopped breathing for a little bit when I think about where we are and where we might be. I can’t necessarily say that, ‘Yeah, we’re going to triple the load by X time,’ but we really need to think about how we can proactively plan going forward.”
As is, the assessment says wind growth continues to outpace ITP projections. The 2023 ITP’s emerging technologies case projects 46.1 GW of in-service wind in 10 years, a nearly 25% increase from the 10-year assessment just two years ago. SPP had 37.1 GW of in-service wind resources when 2023 began.
MOPC also endorsed:
The TWG’s recommendation to modify the shortfall process for both the 2024 ITP and the 2025 ITP for Year 10 summer. SPP developed the process to address the potential for a network customer’s load to exceed their available designated network resources, The changes include using expected conventional resource additions from the generator interconnection queue, ensuring the replacement process is considered for current planned retirements and increasing firm service renewable amounts based on alternative historical time periods.
The PCWG’s proposal for a $12.3 million (47%) baseline increase for an American Electric Power-Oklahoma Gas & Electric 345-kV project in Oklahoma. The project’s costs escalated because a substation will need to be built nearly two miles farther than originally sited. “There’s not a lot of flat area in a canyon location,” OG&E’s Mark Barbee explained.
AEP’s Brian Johnson, the PCWG’s chair, said stakeholders, staff and the MMU have spent much of this year addressing transmission upgrade delays that have frustrated some renewable energy developers.
A revision request (RR574) is wending its way through the stakeholder process. It refines the task of identifying project in-service dates when a notification to construct is accepted and establishes routine project updates to stakeholders and governance groups and advanced notification of delays.
“Transparency and situational awareness … we’re looking for increased accuracy from [transmission operators] in that quarterly update,” Johnson said, noting project costs often have been the focus instead of service dates.
EDP Renewables’ David Mindham said it was apparent SPP is doing a “really, really good job” of building the construction it commits to and thanked Johnson for the work, but asked SPP be given more authority in the process.
“A lot of us have made very large investment decisions based on those transmission upgrades coming into service … Those upgrades need to be prioritized and SPP needs to have the authority to help mitigate those issues and, if the TO cannot build it for whatever reason, find a way to reassign that,” Mindham said. “I think it’s worthy of a discussion in this forum because we need more than just transparency. We need a clear message that these transmission lines are important. They’ve been approved by the SPP board to benefit SPP consumers and they need to be built.”
“When you have a project that is delayed and maybe causing economic issues, there’s a cost to that,” Johnson responded. “If there are alternatives available, maybe they cost some more money but save you time, those need to be vetted and understood and an informed decision made.”
Up to $610M in Annual RTO West Savings
Bruce Rew, senior vice president of operations, said SPP will see between $100 million and $610 million in annual value when its RTO West goes live in April 2026, primarily through the better use of seven DC ties the grid operator would manage between the Eastern and Western Interconnections.
SPP’s expansion into the West will result in a single balancing authority with two BA areas under a single tariff, Rew said. The SPP West BAA will operate as a member of the Western Power Pool Reserve Sharing Group. Single-market solutions will be optimized across the DC ties’ 510 MW of bi-directional capacity.
Several West-only working groups will be formed to help draft the estimated 15 revision requests that will go into the initial tariff changes that will be filed next year at FERC. Accommodating western differences in planning reserve margins and resource adequacy requirements will necessitate several supplemental filings.
“You will begin seeing a lot of engagement at the working group level,” Rew said. “There’s definitely a lot of work to do between now and April of 2026.”
Alluding to an image of the ceremonial golden spike ceremony marking the first transcontinental railroad’s completion in 1869 that Rew included in his presentation, MOPC chair Alan Myers asked, “Do you get to drive the Golden Spike when this comes together?”
Rew demurred, saying that task likely would fall to CEO Barbara Sugg.
JTIQ Costs Up to $1.67 Billion
SPP staff said the cost of its joint targeted interconnection queue (JTIQ) portfolio with MISO has increased from $1.06 billion two years ago to an “updated estimate” of $1.67 billion. That is staff’s rough attempt to reflect the total costs submitted in its Department of Energy funding application and adjusting for a replacement project.
“Just a caveat, we’ve refreshed these costs and benefits numbers, but they shouldn’t be necessarily considered final. They’re simply estimates of costs and benefits,” said Clint Savoy, manager of interregional strategy and engagement.
The JITQ portfolio and its five transmission lines was one of several grid resilience and improvement projects to be awarded DOE funding last week from the Infrastructure Investment and Jobs Act. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
MISO and SPP staff will hold a joint stakeholder meeting on the JTIQ proposal in November and bring a revision request to January’s MOPC meeting. Kelley said the RTOs will file three tariff revisions at FERC: one for each grid operator and the third to revise their joint operating agreement.
SPP Membership Now 111
MOPC welcomed SPP’s newest two members, non-transmission owning members Pine Gate Renewables and Sierra Club. North Carolina-based Pine Gate was the latest to join the RTO, doing so last Friday.
SPP now has 111 members. They include 22 generation and transmission cooperatives, 20 independent power producers, 16 investor-owned utilities, 13 municipal systems, six state agencies, 13 independent transmission companies, 11 power marketers, four large retailers, three public-interest entities, two alternative power entities and one federal agency.
Annual VRL Analysis Endorsed
The committee’s consented agenda endorsed the 2023 annual violation relaxation limits analysis; aligning the PCWG’s scope with business practice language that adds transmission service projects where the cost is 100% directly assigned to one or more customers as an applicable project it can review; and a more than $16 million decrease (20.2%) for a Basin Electric 230-kV project in North Dakota.
The consent agenda also included 13 RRs that would:
RR556: Clarify market participants registering auxiliary load is consistent with any legal or regulatory requirements applicable to the auxiliary load or the entity serving the load.
RR558: Modify the Integrated Marketplace’s protocols and the tariff to allow an adder, not to exceed 10% of verifiable costs or cost expectations, in mitigated offers when those verifiable costs or cost expectations exceed $1,000/MWh.
RR564: Clarify managing the effective limit of flowgates and dispatching during congestion is part of maintaining system reliability.
RR570: Align demand response registration with registration timing requirements.
RR571: Modify the real-time make-whole payment commitment period amount’s existing formulation by summing all multi-configuration combined cycle resource (MCR) adjustments across all of the applicable intervals before adding it to the overall make-whole payment amount. Compensation still should be given for these MCR adjustments, even if the make-whole payment is $0.
RR572: Update the planning criteria with a definition for “qualified change” that reflects the new NERC mandatory reliability standard FAC-002 (Facility Interconnection Studies).
RR575: Compile the annual update of grandfathered agreements to remove expired or terminated GFAs and update termination dates and changes in buying or selling parties.
RR576: Remove vendor-specific requirements from the ITP manual’s fuel prices section to allow more flexibility in choosing data that is used in the ITP assessments.
RR579: Add language to the market protocols to clarify that in the event of a 0-MW effective limit, those constraints will have the highest VRL value ($/MW).
RR580: Improve the SmartQ online portal (https://smartq.spp.org/) to handle generation interconnection request submissions and align data requirements to the evolving IC requests.
RR581: Comply with FERC Order 895 by allowing additional credit-related information to be shared among SPP and other commission-authorized market operators beyond existing confidentiality provisions. The information shared would be treated as confidential, as defined within each market operators’ tariff.
RR585: Correct current footnote to correctly reflect business practice 7250’s (GI Manual) process for both steady state and stability if requests are electrically equivalent.
RR586: Provide examples of what is and what is not considered a non-transmission solution technology in SPP’s effort to expand “transmission” as improving the use of existing assets and modify planning processes to allow use of non-transmission expansion solutions.
As SPP moves closer to finalizing the governance structure of its Markets+ day-ahead offering, the grid operator hosted an Oct. 19 webinar focused largely on a committee that will nominate members of the Markets+ decision-making body.
The committee will put forth candidates to serve on the five-member Markets+ Independent Panel (MIP), described as the highest level of authority for Markets+ decisions. The SPP Board of Directors will have oversight of the MIP.
MIP members must be independent from Markets+ participants and stakeholders. Panel members will be elected by the Markets+ Participants Executive Committee (MPEC), which will consist of representatives of each Markets+ participant and stakeholder.
A slide presented during an MPEC meeting in Portland, Ore., in August led some to mistakenly believe the nominating committee was being eliminated, according to Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel. Instead, the nominating committee will have an expanded role to also conduct “periodic reviews” of the Markets+ governance structure.
“It’s not eliminated. It’s actually expanded in its duties,” Suskie said during the Markets+ governance webinar.
The name of the committee has been changed to the Markets+ Nominating and Governance Committee (MNGC) to better reflect its roles and eliminate confusion. Most stakeholders who have weighed in support the committee’s expanded role.
Day-ahead Competition
The discussion comes as competition is heating up between two day-ahead offerings: SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM). Governance is an issue that often arises when the two are compared, raising debates about independence. (See In Contest for the West, Markets+ Gathers Momentum – and Skeptics.)
The Markets+ governing documents will be included as an attachment to the Markets+ tariff, expected to be filed with FERC early next year.
But before the FERC filing, the governing documents will be presented to the MPEC next month. Stakeholders still have a chance to submit proposed amendments through Nov. 17.
SPP staff will recommend that the MPEC approve tariff language at its December meeting. From there, it’s expected to go to the interim MIP, with the SPP board of directors voting on it in January.
The newly dubbed MNGC will include a representative from each of 12 sectors, such as independent power producers, cooperatives, municipal utilities and federal agencies. The latest governance proposal has added a representative of state agencies and provincial entities.
Suskie said one issue still to be worked out is how to prevent the MNGC from becoming geographically lopsided. As an example, he said, the sectors could potentially all select a representative from Colorado.
SPP is looking at ways to avoid such a scenario.
“It’s something we’re going to think through, reach out to some folks, and maybe propose something for the MPEC to consider,” Suskie said.
The MNGC will nominate candidates to vacant seats on the MIP. Candidates may also be nominated with support from at least 20% of MPEC representatives.
The MNGC will also be able to make recommendations to the MPEC regarding governance changes. Proposed changes would need a four-fifths vote from the MIP before being filed with FERC.
State-based Advisory Panel
Yet another committee in the governance structure is the Markets+ State Committee (MSC), an advisory panel to the MIP, MPEC and task forces or working groups.
As now proposed, MSC members will come from each state in which a Markets+ participant has generation or load. Some stakeholders have argued that states with MSC representation should be required to have load.
BPA supports the participation in MSC of states with “generation or load.” In written comments, BPA said the committee’s advisory role “is strengthened by the inclusivity of states in the Markets+ footprint, both generation and load.”
But AEPCO argued that only states with load in the Markets+ footprint should be eligible to participate in the MSC.
“A state with only generation should not be eligible, as a single generator in a non-contiguous state that contracts with Markets+ could otherwise trigger MSC eligibility,” AEPCO said in written comments.
COVINGTON, Ky. — The Organization of PJM States Inc. (OPSI) heard calls for increased transparency and new RTO governance rules at its annual meeting Oct. 17.
“Our energy sector is at a critical turning point, as renewable energy is more affordable, more reliable, more in demand than ever before and it is growing exponentially,” Sen. Edward Markey (D-Mass.) said in a pre-recorded video for the meeting. “And we know we need more power lines to bridge the gap between clean power and the cities and towns that need it. We need a 21st century grid, not one recognizable by Thomas Edison, which is the one we have right now.”
He said the Connecting Hard-to-reach Areas with Renewably Generated Energy (CHARGE) Act he sponsored in the Senate in July would increase public access, increase accountability, require independent RTO boards and limit “revolving door” appointments. He said the bill would also aid the clean energy transition while promoting reliability by requiring transmission planners to consider grid-enhancing technologies and account for severe weather scenarios, establish interregional minimum transfer requirements and build on the interconnection rules FERC put in place with its Order 2023. (See Dems Introduce Bill on Transmission Planning, RTO Transparency.)
“When operators get in a room and design the future grid, the doors are often closed to activists, to environmental justice groups and the general public. That has to change. My bill would require transparency and accountability in voting,” Markey said.
Study Author Presents Recommendations on RTO Governance
The meeting also featured a discussion with Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School, who authored a report last month arguing that current RTO governance preserves the status of larger incumbent market participants. The session was moderated by Michael Richard, of the Maryland Public Service Commission, and former FERC Chief of Staff Pamela Quinlan, principal of GQ New Energy Strategies — which she founded with FERC Chair Richard Glick this year.
The report, titled “Replacing the Utility Transmission Syndicate’s Control,” said representation of new and smaller market participants can be improved by revising the way RTO board members are selected, reworking membership sectors and expanding state and RTO filing rights.
Peskoe argued that the creation of a sixth member “innovation sector” would address the dilution of market entrants seeking to introduce new technologies that haven’t been supported by larger companies he said dominate the stakeholder process, particularly in the lower committees, where they can use affiliate voting.
The report says the new sector could include “advanced transmission technology providers, distributed energy resource aggregators and storage developers.” It notes that the commission issued a Notice of Proposed Rulemaking in 2002 that contemplated the six RTO membership categories, including an “alternative energy provider” sector (RM01-12).
Peskoe said FERC has pushed back against governance structures that give incumbent transmission owners the upper hand, particularly with orders related to storage and distributed resources. However, he said the commission hasn’t connected the dots showing a connection between RTO decision making and the influence of investor-owned utilities.
The report states that RTOs’ planning processes can give transmission owners an advantage in proposing projects and defining needs as local to limit the risk of a project being awarded to a non-incumbent developer through a competitive process. The amount of information available for supplemental projects at PJM’s Transmission Expansion Advisory Committee has been an ongoing concern for state advocates.
He also said the transmission owners’ filing rights — and the limited opposition their rate filings have seen from RTOs — subvert regional governance. He suggested that expanding RTOs’ filing rights over regional cost allocation and local planning, as well as giving states filing rights, could counterbalance the special filing rights incumbent TOs possess.
Quinlan asked Peskoe what role the Independent Market Monitor has to play in moderating incumbent advantages and whether a counterpart on the transmission side could be a solution to the influence utilities have. He said the monitor does call out market design issues he believes should be addressed, but his recommendations have not always been adopted by the RTO and stakeholders.
He could envision a more limited role in the local planning process for a monitor to ensure the process isn’t discriminating against any participants and to produce independent reports on the state of the network.
Jason Barker, Vitol’s vice president of regulatory affairs, said PJM creates detailed voting reports showing how individual companies and sectors voted at the higher standing committees. He also argued that incumbent bias and the ability of larger companies to have staff at stakeholder meetings are counterbalanced by organizations that help members stay informed.
Peskoe said he isn’t sure third-party representation and education are enough to counter the influence that companies with the resources to have representatives in the room wield in the stakeholder process.
LS Power Senior Vice President of Wholesale Market Policy Marji Philips said she doesn’t believe companies that have not made significant investments in the PJM markets and region should have the same access as participants who have.
Peskoe responded that governance design should be focused on promoting competition, part of which includes displacing incumbents.
“We actually need to elevate new players more because the deck is stacked against them,” he said.
Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
B. Endorse proposed revisions to Manual 3A: Energy Management Systems Model Updates and Quality Assurance (QA) with the aim of clarifying how transmission owners should submit modeling data to capture outages that aren’t linked to have a network model ticket. The changes, resulting from the manual’s periodic review, also aims to clarify definitions of monitored priorities. (See “Periodic Review Revisions to Several Manuals Discussed,” PJM OC Briefs: Oct. 5, 2023.)
C. Endorse proposed revisions to Manual 19: Load Forecasting and Analysis to require that load forecast adjustments include a 15-year forecast and more granular hourly load history to be provided. Electric distribution companies and load-serving entities (LSEs) also would be required to include a public document outlining how the forecast adjustment was calculated. (See “More Extensive Guidelines for Load Forecast Adjustment Endorsed,” PJM PC/TEAC Briefs: Oct. 3, 2023.)
Endorsements (9:10-10:30)
Capacity Offer Opportunities for Generation with Co-located Load (9:10-9:30)
PJM’s Jeff Bastian is set to review a proposal to define how generators with co-located load not interconnected with PJM’s grid may enter into the capacity market. The language would allow the resource to retain its full capacity interconnection rights, rather than reducing its accreditation by the amount of energy supplied to the co-located load and would define the generator as an LSE for the load, subject to all applicable credits and charges. (See “Stakeholders Endorse Proposal on Co-located Load,” PJM MIC Briefs: Aug. 9, 2023.)
The committee will be asked to endorse the proposal.
2023 Reserve Requirement Study (9:30-9:45)
PJM’s Patricio Rocha Garrido will review the recommended values for the installed reserve margin (IRM) and forecast pool requirement (FPR) produced by the annual reserve requirement study (RRS). The IRM, which sets the targeted capacity level above expected loads, would rise from 14.7% for the 2026/27 delivery year in the 2022 study to 17.6% for the 2027/28 DY. The FPR, which includes forced outage rates, also would increase from 9.18 to 11.65% for the corresponding delivery years. (See “Stakeholders Endorse Reserve Requirement Study Values,” PJM PC/TEAC Briefs: Oct. 3, 2023.)
The committee will be asked to endorse the recommended values.
Outage Coordination (9:45-10:05)
PJM’s Paul Dajewski will review a proposal and corresponding manual revisions to increase coordination between utilities and PJM to identify potential extended transmission outages. (See “Stakeholders Endorse Outage Coordination Manual Revisions,” PJM OC Briefs: Oct. 5, 2023.)
The committee will be asked to endorse the proposed solution and corresponding revisions to Manual 38: Operations Planning.
Local Considerations in Net Cost of New Entry (10:05-10:25)
PJM’s Gary Helm will review a proposal and corresponding tariff revisions to create a fifth cost of new entry (CONE) area for the Commonwealth Edison (ComEd) zone, breaking it out of CONE Area 3. The proposal is the result of a stakeholder discussion on if and how to account for state or local policies that impact the inputs for calculating CONE for a region, in this case focusing on the Illinois Climate and Equitable Jobs Act. (See “Creation of Fifth CONE Area Endorsed,” PJM MIC Briefs: Oct. 4, 2023.)
The committee will be asked to endorse the proposed solution and tariff revisions. Endorsement from the Members Committee also is to be considered Wednesday.
Members Committee
Endorsements (1:25-1:35)
Local Considerations in Net Cost of New Entry (1:25-1:35)
PJM’s Gary Helm will present a proposal and corresponding tariff revisions to create a fifth CONE area for the ComEd zone.
The committee will be asked to endorse the proposed solution and tariff revisions.
Federal regulators have designated a draft wind energy area in the Gulf of Maine, shrinking it substantially from its earlier stages and excluding a key lobster fishing area.
The 3.52-million-acre zone has a potential capacity estimated at more than 40 GW. It stretches as much as 120 miles off the New England coastline, and ranges across water too deep for wind turbines with fixed-bottom foundations.
The buildout instead will require floating turbines, which still are being developed and improved. They have begun to be installed only recently, three decades after the first fixed-bottom offshore wind farm was built off the coast of Denmark.
In announcing the draft wind energy area on Oct. 19, the U.S. Bureau of Ocean Energy Management touched on the newness of the floating wind sector, saying the Gulf of Maine presented an opportunity for the United States to take a leadership role.
The state of Maine hopes to do exactly that, and for years has been priming itself to reap the expected environmental benefits of floating wind and the economic benefits of leading its buildout.
The state has set a goal of 3 GW of offshore wind by 2040. The state university has been steadily researching designs; it floated a scaled-down turbine close to shore a decade ago.
BOEM is processing the state’s request for a research lease that would allow it to place up to 12 floating turbines rated at up to 144 MW in a 9,700-acre area of the gulf.
The trade group Business Network for Offshore Wind welcomed BOEM’s announcement. In a prepared statement, Vice President John Begala said: “Advancing leasing in the Gulf of Maine sustains that confidence and unlocks new investment in the U.S. floating offshore wind supply chain, giving our nation the opportunity to catch up with the global market in this emerging field. Floating offshore wind is also crucial to New England states, whose demand for new, clean power generation is predicted to grow from current levels as they move to decarbonize their economies.”
President Biden has set a national target of 30 GW of offshore wind by 2030 but lowered the goalpost for floating wind: only 15 GW, and not until 2035.
The extra time will allow for further research and development to address the technical challenges of floating wind.
The world’s deepest fixed-bottom wind farm stands in not quite 200 feet of water off the Scottish coast. In the Gulf of Maine, the area with the greatest wind energy potential is 600 to 800 feet deep.
The longer time frame also should allow the U.S. offshore wind industry time to overcome the financial and logistical problems it is struggling with.
Many of the fixed-bottom projects contracted but not yet under construction off the Northeast coast have run into major headwinds. Three are in limbo after reaching deals to cancel their power purchase agreements, and developers of others are threatening to pause or cancel their projects unless they get more money.
However, policymakers, the offshore wind industry and its advocates continue to mark achievements amid the struggles. They expect the need for clean power to smooth out the growing pains offshore wind is experiencing.
The Business Network for Offshore Wind presented both sides of the ledger in its third-quarter report, issued Oct. 17.
BOEM Director Elizabeth Klein said in a news release that public comment and stakeholder concerns were incorporated into the draft wind energy area. The boundaries do not include Lobster Management Area 1 or North Atlantic Right Whale restricted areas, for example, and there is a six-mile buffer around important groundfish areas. BOEM also said it tried to avoid a majority of historic and present fishing grounds of Tribal Nations.
Gov. Janet Mills (D) and the state’s congressional delegation earlier this year urged these considerations. In a prepared statement Oct. 20, Mills said: “We look forward to reviewing the proposal in detail, but we are encouraged that the Bureau has initially listened to our concerns and those of the fishing community by excluding Lobster Management Area 1 in its draft.”
At an earlier stage of the process, BOEM’s draft call area had spanned 9.9 million acres and included Lobster Management Area 1.
Advocates for the fishing industry, the environment and labor hailed the removal.
“This is how the process is supposed to work,” Virginia Olsen, Executive Liaison of Maine Lobstering Union Local 207 said in a news release. “The federal government listened to the concerns of our fishing communities, and now they are sending a strong signal that an offshore wind industry that fundamentally harms the hardworking Mainers making their living on the water is neither in line with Maine’s values nor welcome in the Gulf of Maine.”
Publication of the Gulf of Maine Draft Wind Energy Area launched a 30-day public comment period.
Additional adjustments are expected to be made based on input received, BOEM said.
A Blackstone subsidiary is free to acquire an almost 20% stake in Northen Indiana Public Service Co. after FERC’s consent Oct. 19.
FERC said Blackstone Investment Partner’s Blue Buyer, owned by funds managed by Blackstone, can scoop up 19.9% of NIPSCO for $2.15 billion without setting off adverse market impacts (EC23-99). But the decision caused Commissioner Mark Christie to cast doubts again on FERC’s review process and over the recent trend of big asset managers investing in the energy industry.
NIPSCO parent NiSource announced in late 2022 that it was looking for a buyer for a minority interest in the utility. CEO Llyod Yates said the sale will help pick up the tab on a 2040 net-zero emissions goal and approximately $15 billion in grid and gas infrastructure modernization and clean energy investments over the next five years. (See NiSource Selling Minority Interest in NIPSCO.)
The transaction includes a five-year hold harmless period for NIPSCO transmission customers to shield them from transaction-related costs.
Public Citizen and Citizens Action Coalition lodged a joint protest against the sale, arguing Blackstone will control two seats on the NIPSCO board of directors in addition to Blackstone already selecting a director of its choosing on FirstEnergy’s board. They also pointed out Blackstone controls one seat on the board of Texas-based natural gas company Cheniere Energy and another two seats on the board of subsidiary Cheniere Energy Partners. They said Blackstone members are becoming too commonplace on the boards of FERC-jurisdictional utilities.
FERC said Blackstone’s affiliations with energy companies won’t harm competition. It pointed out that FirstEnergy operates in PJM, while the NIPSCO transaction involves the MISO footprint.
“Regarding concerns over Blackstone’s ability to control boards of directors, we find that the proposed transaction will not adversely affect competition because our analysis … would not change even if Blackstone executives were to simultaneously serve on the boards of NiSource and FirstEnergy. This is because FirstEnergy’s utility holdings are located in PJM, while the relevant geographic market for the proposed transaction is MISO,” FERC said.
The commission said the sale won’t raise market power concerns because although Blackstone owns transmission facilities in other markets and an intrastate natural gas pipeline, the transmission facilities will be placed under RTO control when they become operational and the pipeline is located in Texas, far from the NIPSCO service area, although partially in MISO territory.
However, FERC said it couldn’t evaluate whether the acquisition would violate antitrust laws because its jurisdiction does not extend to the enforcement of the Clayton Antitrust Act.
Beyond that, FERC declined to take up Public Citizen and Citizens Action Coalition’s arguments that the transaction stands to raise rates not only for Indiana customers but MISO as a whole because Blackstone will exploit the state’s new right of first refusal (ROFR) law, which grants incumbent transmission owners first dibs to build lines approved by MISO. FERC said that contention was beyond the scope of its proceeding.
“Though joint protestors take issue with Indiana’s ROFR law, they have not identified any way in which the Proposed Transaction will adversely affect vertical competition,” FERC wrote.
NiSource said it will continue to control NIPSCO despite the transaction. It said that at the time it applied for the sale, affiliates of the Vanguard Group, T. Rowe Price Group and BlackRock each held more than 10% of NiSource’s shares.
Commissioner Mark Christie wrote separately to say he believed Blackstone’s involvement in Midcoast Pipelines in Texas warranted NIPSCO and Blackstone to perform a vertical competitive analysis, which they did not file. Christie said the two’s application should be considered incomplete.
“In recent years, the commission has rarely, if ever, required a vertical competitive analysis when approving section 203 applications — even where, as here, the merging entities participate in the same geographic market. The commission has relied on other evidence presented by the applicant to confirm that there are no vertical market power concerns. Although this may be a more administratively convenient approach, it ultimately does not conform to the commission’s regulations,” Christie wrote.
Christie said though he ultimately concurred with the commission’s decision, it may be time to “revisit” FERC’s policies when approving transactions — especially in the face of increasing partial acquisitions among utilities. He said he worried the motivations of investment firms run counter to public interest.
“I have previously written separately about my concerns over these partial acquisitions and what they may mean for the public interest, competition and reliability. There is an inherent tension between the profit-seeking motivations of large investment management entities and public utilities with the responsibility to provide reliable power at a just and reasonable rate,” he said. “It is the commission’s responsibility … to evaluate transactions involving these large investment management entities to determine whether they comport with the public interest. To do so… the commission must have regulations it can enforce that capture the concerns present in the types of transactions that occur today.”
Public Citizen to File Letter with FTC Over FERC Antitrust Considerations
In an interview with RTO Insider, Public Citizen Energy Program Director Tyson Slocum said he shares Christie’s frustrations with “FERC’s insistence on utilizing such a narrow approach on reviewing mergers and acquisitions.”
He said Public Citizen is “obviously disappointed” with the outcome of the docket and it plans to send a letter to the Federal Trade Commission about FERC “bizarrely” believing it lacks authority to consider violations of antitrust statutes when it decides mergers and acquisitions.
Slocum said it’s a “clear violation” of antitrust laws for Blackstone executives to simultaneously serve on the boards of NiSource and FirstEnergy, even when they’re situated in different RTOs.
“I think it’s fair to say that NiSource and First Energy are engaged in some level of commerce that should be a flag for antitrust violations,” Slocum said.
Slocum predicted a “sustained push” by private equity investors to acquire interest in utilities and “negotiate control over the board and other aspects of management.” Utilities are experiencing “financial weakness” and slumping share prices because of high interest rates, he said, making it attractive for firms to step in.
“I think we’re going to continue to see private equity firms playing a bigger role in public utilities,” he said.
Slocum said he’s also concerned such firms have “more opaque corporate structures and far less transparent public accounting” than utilities are tasked with. But he said there’s only a slim chance FERC retools its mergers and acquisitions evaluation process if commissioners begin to view the transaction trend as a problem.
FERC has granted a solar developer’s request for a 28-month extension of its commercial operation deadline, finding that it acted in good faith to develop the facility (ER23-2603).
Twelvemile Solar Energy requested the extension in August for its planned 100-MW solar farm in Oklahoma that will interconnect with the SPP system. It executed a generator interconnection agreement with SPP and Oklahoma Gas and Electric in January 2019, reflecting a December 2020 commercial operation date. That date was extended in January to this December because of schedule disruptions caused by the COVID-19 pandemic and U.S. trade restrictions on imported solar equipment.
The developer said the pandemic and trade action created a “constrained” market in which demand for utility-scale PV panels considerably exceeds available supply.
The GIA included a provision that it could be terminated should Twelvemile Solar fail to meet the commercial operation date for three consecutive years.
FERC said in an Oct. 19 ruling that the request meets the commission’s criteria for granting waivers: The developer acted in good faith to develop the facility in accordance with the GIA; the waiver was limited in scope and applied only to the deadline; it addressed a concrete problem; and granting it would not result in undesirable consequences.
