NYISO CEO Rich Dewey announced to the Management Committee on Wednesday that Director Gizman Abbas had accepted a position on Talen Energy’s board of directors.
Dewey said NYISO has determined that the appointment “does not present a conflict” with FERC’s rules and the ISO’s own Code of Conduct, as Talen no longer operates, nor owns any assets, in New York. But, he said, the ISO would “continue to watch and monitor the situation,” and revisit that determination should Talen move back into New York and “come up with a cure.”
Mark Reeder, representing the Alliance for Clean Energy New York, asked whether Talen had any interests in NYISO’s neighbors and if that was considered in the ISO’s determination.
The company does have interests in PJM and ISO-NE, owning several generators in Pennsylvania, New Jersey, Maryland and Massachusetts. Dewey said “it was considered, and we felt [under] a strict interpretation of the rules, it did not present a conflict.”
Capacity Accreditation
The MC voted to recommend that the Board of Directors approve proposed tariff modifications that would implement a new capacity accreditation process and market design.
Having been approved by the Business Issues Committee last week, several stakeholders again voiced their reservations about approving measures that they believed were either not fully understood or would be applied to resources unequally. (See NYISO Capacity Accreditation Implementation Worries Stakeholders.)
Michael DeSocio, director of market design at NYISO, said the ISO “remains committed” to doing the work required for capacity accreditation implementation and “acknowledges the need” to tackle portions of the project that were raised by stakeholders. DeSocio also assured the committee that these commitments would be reflected in the meeting’s minutes.
Hybrid Storage Resources
The MC voted to recommend that the board approve NYISO’s proposed tariff revisions that would integrate aggregated HSRs — multiple generators co-located with energy storage behind a single interconnection point — into the ISO’s markets.
Julia Popova, NRG energy manager of regulatory affairs and vice chair of the committee, asked why the revisions were being filed so late next year.
NYISO officials answered that they are targeting the third quarter because there are other projects that need to be implemented first, such as internal controllable lines. They also said the HSR construct would not be implemented until 2025 anyway, so there is no rush to get it to FERC.
CAC Scoping Plan
NYISO agreed to brief stakeholders on the New York Climate Action Council’s recently approved scoping plan and how it would impact the ISO’s work. (See related story, New York Climate Scoping Plan OK’d.)
Executive Vice President Emilie Nelson said NYISO is “looking through [the plan] carefully and is very, very interested in working with all stakeholders and state agencies going forward.” The ISO also “appreciates the acknowledgement within the plan that there are challenges ahead of us that we need to work together to solve.”
Reeder requested a “small,” formal presentation from NYISO about aspects of the plan that would affect its markets, though he acknowledged that the plan is just a framework that will take “at least multiple years” of legislation and agency rulemakings to implement.
Members, TAC Stripped of Responsibilities for Policy Development
ERCOT’s Board of Directors on Tuesday stripped away the right of corporate members to vote on future changes to the grid operator’s bylaws, rejecting an alternative stakeholder recommendation in the process.
The directors approved bylaw amendments, drafted by staff at the board’s direction, that remove ERCOT’s corporate members’ ability to vote “on any matter submitted to the general membership.” The amendment does allow members to comment on any such proposals and to propose amendments themselves.
The bylaw revisions take away the Technical Advisory Committee’s ability to recommend policy and procedural changes to the board. It leaves that top stakeholder group with doing little more than managing the process for changing market rules and document guides.
Stakeholders have expressed their opposition to the change since the draft amendments became public late this summer. The revisions are designed to align ERCOT’s governance with legislation, passed in the wake of the deadly 2021 winter storm, that created an independent board and removed market representatives from participating. (See ERCOT Stakeholders Wait on Bylaw Amendment Changes.)
“There’s no real avenue to meet with the board,” Demand Control 2’s Chris Hendrix told RTO Insider. “It makes it more like a PJM model or an ISO-NE model, where you have no access to the board.”
Hendrix represented the membership and six of the seven market segments (investor-owned utilities were not involved) in offering up an alternative recommendation that agreed with much of the bylaw revisions but carved out three exceptions: retaining members’ voting rights, removing staff’s language that gives the board authority to amend TAC’s procedures without a vote of its representatives and removing language that allows the directors to disband TAC.
“Keep corporate members voting because it is a corporate membership,” he said. “It’s an incentive. We pay to be a member, and that comes along with voting rights.”
Several directors pointed to revised language giving members a 21-day window to comment on any proposed changes and noted that TAC can’t be disbanded without the Public Utility Commission’s direction.
Hendrix said the changes allow the board to set TAC’s policies and procedures, which could lead to extreme measures such as meeting once a year or eventual disbandment. He said that its only “the good word of the PUC” that prevents drastic changes.
The commission in November issued a statement that helped set the stage for this week’s discussion. The commissioners agreed that ERCOT’s board is “empowered to amend its bylaws without obtaining the affirmative vote of the corporate members. It is necessary for ERCOT to amend its bylaws such that the ERCOT board of directors has the sole authority to change the bylaws, subject only to the approval of the commission.”
The statement also called for preserving market participant input in developing market functions by amending the bylaws such that the board “cannot eliminate [TAC] without specific direction from the commission.” (See “PUC Sides with ERCOT Board,” Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
“I believe the proposed bylaws changes represent something that is not dissimilar to the organizational structures that we see in the rest of the country,” PUC member Will McAdams said before the commission’s separate vote to approve the bylaw changes. “Ultimately, the commission has an appellate jurisdiction to approve all policies, and there’s an obligation on the part of stakeholders, the board and the commission under this contract … to collaborate and work through operational issues as they become apparent so that we can provide the best outcome for the public in Texas.”
Hendrix, who admitted he faced an uphill battle, said the revisions will only help ERCOT’s larger members who can afford to lobby legislators and regulators and might lead some market participants to forego memberships.
ERCOT held a 20-minute annual membership meeting following the board’s executive session, with only a handful of members present. ERCOT CEO Pablo Vegas promised a return to an in-person annual meeting next year and “better opportunities to connect with fellow corporate members, with the ERCOT board of directors … with staff, with commissioners and with other invited guests.”
“I think it’s an opportunity to really connect on the issues that are important to the industry and have an opportunity to get to know each other through that and have a higher-value discussion,” he said.
Board Chair Paul Foster also expressed desire for a “stronger engagement opportunity” next year and said the bylaw amendments represented “another milestone” in ERCOT’s changing governance structure.
“Each board director has now had time over the past year to see the TAC membership and the stakeholders in action and the role they provide in the policy development of the rules that helped run a reliable grid and a fair efficient market,” he said.
Grid Prepared for Winter Weather
Vegas reassured directors and stakeholders that the grid operator continues to expect adequate supplies and reserves in advance of sub-freezing temperatures forecast for the Christmas weekend. He said staff expects to have more than enough generation to handle a projected peak of nearly 68 GW with nearly 90 GW of capacity online. Wind and solar account for 20-22 GW of the available capacity.
During a press conference with Gov. Greg Abbott Wednesday morning, Vegas reduced the online capacity estimate to 85 GW, with wind and solar accounting for 12 GW. He was joined by PUC Chair Peter Lake, who said the ERCOT grid is “ready and reliable.”
ERCOT on Wednesday elevated a previously issued advisory for the extreme cold weather to a watch, effective Thursday morning through Monday, Dec. 26.
“Things are looking good to get through the weekend,” Vegas said.
Chris Coleman, ERCOT’s lead meteorologist, said the cold front, part of a powerful winter storm that has settled over the Midwest, will not be as severe as the deadly 2021 winter storm that almost brought down the ERCOT grid.
“We’re several degrees warmer than that, and we will also not have the precipitation associated with it,” he said.
North Texas and the Panhandle will likely see snow, Coleman said. He predicted low temperatures of about 12 degrees F in Dallas and 17 degrees in Austin Friday morning. Freezing temperatures could extend as far as the Rio Grande Valley before conditions begin returning to normal during the weekend.
“We could see 70 degrees [next week], so there’s something encouraging to look forward to,” Coleman said.
Coleman is sticking by his winter outlook, which predicts that this winter will not be as warm as last year’s, but not as cold as 2020/21. This is the third straight winter with the La Niña system in place and will deepen Texas’ drought conditions. Coleman said 52% of the state has drought concerns, up from 46% last year.
“I think the drought will remain in place and potentially expand and worsen here over the next few months,” he said. “I don’t think we’re going to get through this winter, saying, ‘Boy, we had a lot of fun. It was just never warm.’ It’ll likely turn around here, so I’m not closing the door beyond this week on more cold opportunities.”
TAC Membership Set for 2023
A cast of familiar faces will be back for TAC next year following the board’s approval of the committee’s 2023 representatives.
The Office of Public Utility Counsel’s Nabaraj Pokharel, CenterPoint Energy’s David Mercado and Garland Power and Light’s Russell Franklin are the only new additions to the 30-person stakeholder group.
Current TAC Chair Clif Lange, with South Texas Electric Cooperative, has offered to again lead the group next year. Members will vote on leadership during their Jan. 24 meeting.
ERCOT Gets 1st Adjunct Member
The directors approved an adjunct membership for Pine Gate Renewables, a utility-scale solar and storage developer headquartered in Asheville, N.C., with five projects in its Texas pipeline. ERCOT staff said the company does not currently meet any segment requirements but will align with the independent power producers in the stakeholder process.
In other actions, the board approved:
Robert Black’s hire as vice president of public affairs following a short stint with AEP Texas and a 30-year political career on the Republican side of the aisle;
ERCOT’s 2023 methodologies for determining minimum ancillary service requirements, previously endorsed by TAC;
the Reliability and Markets Committee’s charter, outlining its responsibility to review the grid operator’s core functions and disbanding the Credit Working Group. TAC will add the credit reporting functions to its structure.
Board Approves 10 Changes
The board approved a consent agenda that included six nodal protocol revision requests (NPRR), single changes to the Nodal Operating Guide (NOGRR), other binding documents (OBDRR) and the Resource Registration Glossary (RRGRR), and a system change request (SCR):
NPRR1128: Sets an ancillary service offer floor 1 cent/MW lower for fast frequency response (FFR) than for other RRS categories to allow FFR procurement up to the current limit, without proration with other RRS categories.
NPRR1132: Specifies that during local cold weather conditions, each qualified scheduling entity (QSE) must update its generation resources’ and energy storage resources’ current operating plans, real-time telemetry, and outage and derate reporting to reflect any limitations. It also requires each resource entity to provide resource-specific cold weather minimum temperature limits, hot weather maximum temperature limits, and alternate fuel capability information in its submitted resource registration data and update this information as necessary.
NPRR1138: Requires each resource entity to ensure the reactive capability curve for any intermittent renewable resource accurately reflects its reactive capability when it is not providing real power or is operating at lower levels of real power output.
NPRR1148: Resolves protocol gaps found during emergency contingency reserve service’s creation of its system change requirements.
NPRR1152: Removes the protocol requirements to submit emergency operations plans (EOPs), weatherization plans, and declarations of summer/winter weather preparedness; revises procedures for submitting declarations of natural gas pipeline coordination with natural gas generation resources; revises the list of items considered protected information to remove references to weatherization plans and add protections for information relating to weatherization activities; and revises the list of ERCOT critical energy infrastructure information to clarify language concerning EOPs and add protections for information relating to weatherization activities.
NPRR1154: Updates language to allow for a qualified alternate resource to be considered in calculating the availability reduction factor for the firm fuel supply service (FFSS) resource and provides a new settlement billing determinant providing the FFSS award amount per QSE per FFSS resource by hour.
NOGRR226: Adds provisions for transmission operator “anti-stall” automatic firm load shedding at 59.5 Hz to mitigate the risk of a total systemwide blackout.
OBDRR043: Aligns the operating reserve demand curve’s methodology with NPRR1148’s revisions, approved in August, in calculating the real-time reserve price adder.
RRGRR032: Adds data required to be shared with ERCOT as the reliability coordinator, balancing authority and transmission operator in considering cold weather limitations in its operational planning analysis, real-time monitoring, real-time assessments, and other analysis functions. The grid operator also requires this information for hot weather limitations and making this a requirement for distributed generation resources and distributed energy storage resources.
SCR821: Allows transmission and distribution service providers to set the voltage set point target information provided to distribution generation or distribution energy storage resources.
The PJM Markets and Reliability Committee rejected two proposals that would have created a “circuit breaker” mechanism to limit prices during extended periods of high prices.
Old Dominion Electric Cooperative, Southern Maryland Electric Cooperative and Northern Virginia Electric Cooperative had jointly proposed triggering a breaker when LMPs of at least $1,000/MWh last over the course of a 24-hour period, or $850 over a week. Prices would then be capped at $850/MWh until they remain below the cap for five consecutive business days.
The proposal would have also granted PJM the discretion to invoke the breaker based on conditions it’s observing; it would not have had the power to prevent a breaker being triggered. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)
Adrien Ford of ODEC said the circuit breaker is intended to be used only under extraordinary circumstances when the markets have gone “haywire.” For a small load-serving entity serving 200 MW of load, she said the total annual spending under typical average prices for the PJM footprint could be eclipsed in 2.25 days should prices reach the current $5,700/MWh cap, which includes maximum cost-based offers, reserve shortages and a $2,000/MWh transmission constraint penalty factor.
“The numbers just get cartoonish very quickly, and that’s why we’re trying to put this in place,” she said.
Calpine proposed a breaker triggered by 90 nonconsecutive hours of shortage events in one delivery year and cap prices at $2,000/MWh — a threshold the company’s David “Scarp” Scarpignato said is critical to proper price formation. After one breaker had been observed in a single year, any subsequent shortage in excess of three consecutive hours would trigger an additional breaker. The proposal would not provide PJM with the power to initiate a circuit breaker unilaterally.
Prolonged periods of high pricing can cause more harm through revenue issues than provided by the benefits of price formation, Scarp said.
Consideration of the packages was postponed during the November MRC meeting to afford their sponsors additional time the attempt to reach a compromise, but Ford said those efforts were not successful. She said consensus was sought on the circuit breaker alone, as well as by combining the issue with the market seller offer cap (MSOC).
Concerns with the packages included giving PJM staff the ability to initiate a circuit breaker; the impact of uplift payments on small LSEs; the level prices would be capped at; and a lack of detail on some provisions, such as how uplift payments would be allocated.
Constellation Energy’s Jason Barker encouraged stakeholders to vote against both packages and to engage in further discourse to find a compromise in the middle.
“It’s unfortunate that we’re pushing forward with stakeholder packages that we believe are suboptimal at best,” he said.
Consumer advocates and load representatives said the impact of sustained high prices necessitates a quick solution being found.
“There needs to be something in place to protect consumers,” said Greg Poulos, executive director of the Consumer Advocates of the PJM States, adding that it was hoped that a circuit breaker would be ready in time for the winter season.
Albert Pollard, of the Illinois Citizens Utility Board, said the issue could lead to a future Federal Power Act Section 206 filing with FERC if a stakeholder solution is not found. He argued that it might be more advantageous to opponents of the circuit breaker proposals to accept one of the solutions on the table rather than take their chances with a solution the commission may arrive at.
“We don’t know what’s going to happen if this lands on their desk,” he said.
First Read on Proposals for Accrediting Intermittent Resources
The sponsors of five packages addressing capacity accreditation for effective load-carrying capability resources gave a first read of their proposals, with the discussion focusing on how to address capacity interconnection rights (CIRs) for existing resources in the interim until the new rules can be put in place. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)
None of the packages reached 50% support in a poll conducted by the Planning Committee in October. LS Power’s Package E received the largest share of support in an October poll, at 44%, followed by Packages D and I from PJM, which received 40% and 28%, respectively. Endorsement of a package from the PC is scheduled for Jan. 10, while the MRC and Members Committee are set to vote on Jan. 25. The proposals would also require approval from the Board of Managers, which is set to take up the issue on Feb. 1.
Tom Hoatson of LS Power said Package E is essentially PJM’s original Package A, which was withdrawn by the RTO early in the stakeholder process. It would immediately limit generators’ accreditation to their current CIR level, require those resources to re-enter the interconnection queue at the end to request higher CIRs and require that they be responsible for any transmission upgrades.
PJM’s Package D would grant existing interconnection service agreement (ISA) holders higher CIRs by conducting new deliverability tests in the 2023 Regional Transmission Expansion Plan (RTEP). Some opponents have criticized this as permitting those requests to jump the queue and causing projects in the queue to bear higher costs.
The RTO’s Package I would place existing resources’ requests for higher CIRs at the end of the interconnection queue, but conduct a transitional system capability study to allow for the generator to take advantage of headroom on the transmission system, which PJM has estimated will be available for approximately five years.
Package G, from E-Cubed Policy Associates, builds upon LS Power’s proposal and expands the deliverability testing to include more months — particularly the fall shoulder months, as there have been increasing reliability concerns at the start of the fall maintenance period. The proposal would also allow generation owners retiring their assets to request an expedited CIR review for new generation being developed on the same site using the existing interconnection point, a component not included in any of the other proposals.
“We need to understand how those shoulder periods are going to be effected,” said E-Cubed President Paul Sotkiewicz.
The most recent proposal, Package K, was introduced by LS Power during the Dec. 6 PC meeting and aims to ensure that the provisions within PJM’s Package I are actionable for the June 2023 Base Residual Auction. It both specifies that the changes are mandatory to implement in that BRA and asks that the board direct PJM to submit a filing with FERC clarifying that the Reliability Assurance Agreement establishes CIRs as the hourly upper limit for the unforced capacity accreditation.
“We recognize it would only be an indicative vote; we cannot tell the board what to do,” Hoatson said.
Ford said that in the event that either no packages are endorsed by the PC or Package I is not among the proposals voted to be brought before the MRC, ODEC would motion for it to be voted upon by the committee.
Generator Deliverability Test Modifications
PJM provided a first read of proposed manual revisions to change how generator deliverability tests are conducted to account for higher variability associated with the growth of intermittent resources on the grid. The proposal would merge the methodology for summer, winter and light-load testing; expand the light-load period; incorporate procedures for ramping of wind and solar; and harmonize dispatch procedures.
The RTO is anticipating seeking endorsement from the PC on Jan. 10, followed by returning to the MRC on Jan. 25 for endorsement. If approved, the changes would be effective immediate and implemented for the 2023 RTEP.
Operating Agreement revisions to grant PJM the flexibility to permit market participants to continue operating in markets under certain circumstances, including grid reliability; the ability to provide collateral; and future ability to generate revenue. The language also recognizes that certain transmission customers cannot have their service terminated without FERC approval. PJM Associate General Counsel Colleen Hicks told the committee that the OA currently has conflicting language on whether PJM has discretion currently, with some sections using “shall” and others saying that “PJM may limit” and the revisions bring the documents into alignment. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022.)
Members Committee
Election of Representatives and Vice Chair
The Members Committee approved sector whips and representatives on the Finance Committee, as well as a new vice chair, during its Wednesday meeting.
Electric Distributors: Lynn Horning of American Municipal Power;
End Use Customers: Greg Poulos of the Consumer Advocates of the PJM States;
Generation Owners: Calpine’s Scarp;
Other Suppliers: Brian Kauffman of Enel North America; and
Transmission Owners: John Horstmann of Dayton Power and Light.
The sitting Finance Committee representatives will be joined by Jeff Riley of AMP (Distributors) and John Brodbeck of EDP Renewables (Generation).
Following the rotating schedule of which sector nominates vice chair, the TOs had selected Exelon’s Sharon Midgley, whom the MC also elected Wednesday.
PJM CEO Manu Asthana thanked outgoing MC Chair Erik Heinle, of the D.C. Office of the People’s Counsel, for his leadership through many meetings and discussions, including a handful of contentious issues before the committee.
The Generation sector had originally selected Scarp to fill the vice chair position, following the departure of Becky Robinson of Vistra, who as vice chair was in line to become chair next year. Thus, Scarp will become chair next year.
First Read on Manual Revisions to Allow Direct MC Consideration of Issues
ODEC’s Ford provided a first read of proposed revisions to Manual 34 that would create an avenue for PJM members to make a motion for the MC to consider issues directly, without going through the typical pathway of the lower committees. The revisions would require that a motion be introduced as a problem statement and issue charge to follow the existing governance process.
One of the biggest roadblocks to developing a domestic supply chain for the minerals that are critical to clean energy technologies is the General Mining Act of 1872, “a legal and regulatory framework from the 19th century” still in force today, according to Tommy Beaudreau, deputy secretary at the U.S. Department of the Interior.
The 150-year-old law is “about prospecting, staking claims, as opposed to a leasing process,” Beaudreau said Wednesday during a webinar on the future of U.S. mining, sponsored by the Bipartisan Policy Center (BPC).
“One of the challenges we have is, how do we meet the needs of the clean energy economy with domestic sourcing of critical minerals, like lithium and cobalt and other materials, while managing the potential for conflict that any industrial activity, including mining, has; and all of the interests that we’re responsible for helping meet on public lands,” he said.
The Biden administration has made the building out of domestic supply chains a top priority of its push for a carbon-free electricity system by 2035 and a net-zero economy by 2050. Critical minerals — such as lithium, cobalt, nickel and uranium — are essential materials for energy storage, electric vehicles and advanced nuclear reactors, and the U.S. is “blessed with a number of these resources,” including on public land, Beaudreau said.
Tommy Beaudreau, DOI | BPC
The BPC sees the issue as bringing together key national security, economic and environmental interests, which makes mining and mining permitting reform ripe for bipartisan collaboration, said Xan Fishman, the organization’s director for energy policy and carbon management.
But major partisan flashpoints still exist, especially on permitting reform, as seen by the recent defeat of Sen. Joe Manchin’s (D-W.Va.) permitting reform bill this month. (See Manchin Permitting Bill Falls Short in Senate.)
Seeking common ground, the Interior Department launched an interagency working group on mining and mining reform in February and has since held about 20 meetings with the public and tribes, along with 30 more meetings with “individual companies, mining operators, as well as environmental [nonprofits],” Beaudreau reported. The group also received more than 20,000 public comments, he said.
Such extensive engagement is needed, Beaudreau said, to “overcome the legacy of hard-rock mining in the United States, going back to the 19th century,” when prospectors went into tribal and public lands “to exploit resources without talking to the community, certainly without benefiting the folks in whose backyard [the mining] is happening.”
The working group will be issuing a report in the first quarter of 2023, and while Beaudreau was not ready to provide specific details, he said the group has developed a set of principles. “Our goal [is] to take advantage of the opportunities we have for reliable sourcing of critical minerals here in the United States and with our partners and allies, but at the same time doing so in a way that respects local communities and tribes, is good stewardship for the environment and wildlife habitat and is responsible,” he said.
Part of the way forward could be identifying potential environmental or community concerns around any specific mining or supply chain project and “deconflicting” them, a strategy first used during the Obama administration to accelerate the development of renewable energy projects on public lands.
This approach is not currently used in mining permitting, Beaudreau said, but the upcoming report could include a similar proposal. “By doing that, we’re actually able to accelerate project development because we’ve sort of front-loaded community engagement, understanding and deconflicting,” he said.
Collaboration with tribal governments is another priority, with a focus on transparency, Beaudreau said. “We’ve developed a new system to … identify geographic areas of interest for mining, and there are cases where tribes see opportunities as well. We can create planning conversations about potential [projects] and then work with operators on consultation, both about money, but also on the back end, reclamation work and providing assurances on potential environmental impacts.”
‘Doing It the Right Way’
The need for the U.S. to break its dependence on China, Russia and other unreliable nations for critical minerals has become a given on both sides of the aisle in Congress. “If you care about the environment, or you have a social conscience, you want mining to happen in Nevada and across the U.S.,” said Tyre Gray, president of the Nevada Mining Association.
Tyre Gray, Nevada Mining Association | BPC
“We are currently sourcing the vast amount of our minerals from countries that are not doing it the right way,” Gray said during an industry panel following Beaudreau. “And we do it here the right way.”
“We really approach this from a national economic security lens,” said Abigail Wulf, vice president and director for the Center for Critical Minerals Strategy at Securing America’s Future Energy, a Washington, D.C. think tank. “We want to make sure our supply chains for the minerals of the future … can’t be used as political pawns. So, we’re focused on diversifying supply chains, and for the future of mining, we see responsible mining and transparent supply chains as really being the way to diversify supply chains.”
Echoing Gray, Wulf said, “Where critical minerals are coming from right now, it’s ostensibly difficult to compete on cost because people are degrading the environment or exploiting workers in a way that would not be tolerated if it were done in the United States or among some of our like-minded partners.”
Gray also stressed that the General Mining Act of 1972 mostly covers public land use, and mining in Nevada and other states is highly regulated under several federal and state laws, including the National Environmental Protection Act and the Clean Air Act. In Nevada alone, “there are over 20 different agencies, if you count the federal agencies, that have some level of oversight in mining,” he said.
Abigail Wulf, SAFE | BPC
“Before a single shovel hits the ground here in Nevada, you have to plan for reclamation [and] closure,” he said.
At the same time, Gray believes the industry could benefit from “Good Samaritan” legislation that would allow companies to reclaim old mining sites “to see if there’s anything of value but not necessarily take on the responsibility” for past environmental damage.
Gray also sees the EV supply chain in broad terms, not just lithium, nickel and cobalt, but copper, silver and gold, which may also be used in other clean technologies. “I don’t want to get too focused on just a certain set of minerals, but really be able to address the whole suite of minerals,” he said.
“When we’re talking about green technology … and where we’re heading in the future, talking about everything without talking about particular minerals, it’s kind of like talking about a peanut butter-and-jelly sandwich without thinking about the bread,” he said.
The Tamarack Project
Talon Metals Corp. is one of a small but growing number of companies on the front line of responsible, transparent mining. Based in Ontario, Canada, the company is focused on providing minerals for the EV and electric battery storage market.
Todd Malan, Talon Metals | BPC
The company’s Tamarack Project in Minnesota is being developed to provide high-grade nickel, as well as cobalt and copper for EV batteries, and the company has received a $114.8 million grant from the Department of Energy to help build a processing plant in North Dakota, Malan said.
“Why should the public care about high-grade [nickel]? Because high-grade means high concentration,” he said. “That means we can actually go in an underground line very selectively and surgically, grab the high-grade material, take it out in a responsible way and still make sure that we’re protecting the environment.”
The company was one of 20 receiving grants from the Infrastructure Investment and Jobs Act to build out the EV battery supply chain.
But, Wulf said, at this point, responsible mining still costs more and will need further federal support. While the IIJA and Inflation Reduction Act have a range of incentives for critical minerals and manufacturing, the missing piece is incentives for mineral exploration, she said.
Trade policy is another must-have, she said. The U.S. needs “enforceable mechanisms for that responsible mining, and so sanctionable, enforceable trade deals among our allies will be one way we can do that.”
New Jersey officials said they will continue to study how to cut building emissions after backing off a controversial ban on new commercial size fossil fuel boilers.
The rules set for a Jan. 3 adoption by the New Jersey Department of Environmental Protection faced vigorous opposition from business and fuel groups.
The DEP rules, which formerly had three elements, now include two, and no longer contain a rule that would have prevented the DEP from issuing permits for new fossil fuel-fired boilers in certain situations. The omitted rule would have prohibited the installation of boilers 1 to 5 MMBtu unless it is “technically infeasible” to use a non-fossil fuel boiler because of “physical, chemical or engineering principles” or because the interruption of the operation of an existing boiler could “jeopardize public health, life or safety.”
The omitted rule didn’t stipulate that electric boilers should be installed, instead requiring the “most common non-fossil-fuel-fired technology currently available on the market.”
The two elements still in the rules lower the acceptable limits for CO2 emissions from fossil-fired electric generating units (EGU) and ban the use of two fuel oils that have high CO2 emissions.
DEP spokesperson Vincent Grassi did not elaborate on the reason for the withdrawal but said discussions on the reduction of emissions from buildings are ongoing.
“DEP will continue to [have stakeholder discussions on] the boiler issue as part of our second round of PACT [Protecting Against Climate Threats] Climate Pollutant Reduction initiatives,” he said, referring to an ongoing effort by the department to research and draft measures that will cut greenhouse gas emissions in various areas. That will “ensure the eventual regulation of boilers achieves a reduction in greenhouse gas emissions at a reasonable cost,” he said.
Grassi added that stakeholder discussions to discuss “the regulation of boilers” will take place in 2023, although no timeline for when it will happen has yet been developed.
Bigger Picture
The change of plan comes three months after Gov. Phil Murphy announced that he would form a multi-stakeholder task force to accelerate the reduction of building emissions.
Commercial and industrial buildings emit 17 % of the state’s greenhouse gases, well behind transportation (42%) and electricity generation (19%), according to the state’s National Electric Vehicle Infrastructure plan.
The DEP’s original rules stated that there are about 8,421 fossil-fuel fired heating boilers in the state, and about 268 are replaced on average each year.
Eric DeGesero, executive vice president of the Fuel Merchants Association of New Jersey, welcomed the withdrawal of the rules but said he fears the issue is “far from over.”
“We can’t lose sight of the bigger picture here. The governor’s strategy for the Energy Master Plan is still to electrify every building,” he said. “Until such time as the governor says that he’s moving forward in a different path, that is still his objective to electrify everything.”
The New Jersey Business & Industry Association, one of the state’s largest business groups, called the move “appropriate and appreciated.” The organization said it would cost about $2 million to retrofit a building and convert it to housing an electric boiler. Those costs could have impacted approximately 1,500 apartment buildings; 1,500 K-12 public schools; 1,200 commercial, industrial and manufacturing facilities; 195 county government buildings; and 143 auto body shops, the group said.
“In addition to the millions of additional dollars this provision would have cost these establishments, the fact of the matter is converting a modern, fuel-efficient natural gas boiler to an electric one would actually increase carbon emissions due to the carbon footprint of the PJM grid,” the organization said in a statement.
Negative Reaction
Environmental groups, which supported the boiler installation ban, questioned where Murphy’s climate change strategy is heading.
“This is not a good sign that the Murphy administration dropped the boiler rule,” said Doug O’Malley, state director of Environment New Jersey, who described the rule as a “target” of fossil fuel industry activity. “Because if we’re going to move towards a more climate friendly future, we can’t keep relying on fossil fuels for heating.
“There needs to be a clear statement from the Murphy administration of its commitment to building electrification and the next steps in that process,” he said. “We can’t hit our climate goals, if we’re not moving forward with building electrification.”
Eric D. Miller, N.J. Energy Policy Director for the Natural Resources Defense Council, said the withdrawal is “disappointing” not only because of its harm to the climate but because the boilers’ pollution is a health hazard “in places like schools, libraries and multifamily buildings.”
“The N.J. DEP should re-propose these rules with an updated cost analysis that accounts for highly efficient cold climate heat pumps and other technologies and incorporates the significantly higher fracked gas prices that New Jersey customers are facing today.”
The analysis should take into account the recent rise in natural gas prices and that the costs of electrification could be reduced with federal funding from the Inflation Reduction Act, he said.
Opposition Coalition
The rules stoked controversy from their inception, drawing a strong negative reaction at the first public hearing to solicit stakeholder input in February when with both business groups and environmental groups voiced criticism — albeit over different parts of the package. Business and fossil fuel interests expressed concern at the new fossil boiler installation measure while the environmentalists argued that the limits on emissions from EGU’s were too modest to seriously reduce emissions. (See NJ’s New Emission Rules Draw Fire.)
A coalition of 24 New Jersey business and union interests elevated the fossil boiler ban issue in September, with a letter to the heads of the state Senate and General Assembly saying that the Murphy electrification program should be stopped because it will “dramatically increase costs for New Jersey residents and businesses at a time when the legislature is focused on affordability.”
On Oct. 4, Murphy announced at the Board of Public Utility’s Clean Energy Conference in Atlantic City that he would form the Clean Buildings Working Group, which would focus on how to implement the state’s transition from fossil fuels to clean energy and energy efficiency. (See Murphy Outlines NJ Building Electrification Push.)
Opponents of the boiler installation ban want to see the legislature pass a bill (S-2671) that that would prohibit any state agency from adopting rules and regulations that “mandate the use of electric heating systems or electric water heating systems as the sole or primary means of heating buildings or providing hot water to buildings, including, but not limited to, residences or commercial buildings.”
The bill, which has not moved in the legislature since its introduction in May, is similar to “pre-emption bills” in other states that have sought to prevent electrification requirements — often promoted by the fossil fuel industry. (See NJ Legislators Back Alternatives to Electric Heat.)
New Jersey at present does not mandate the electrification of buildings. The state’s Energy Master Plan calls for the building sector to be “largely decarbonized and electrified” by 2050, with a focus on “new construction and the electrification of oil- and propane-fueled buildings.”
[Editor’s Note: PJM filed the proposed tariff change on Dec. 23 (EL23-19).]
VALLEY FORGE, Pa. — PJM said Wednesday it will ask FERC to modify the rules of its 2024/25 capacity auction to avoid artificially high prices in one region of the RTO.
RTO officials told the Members Committee that they will make a Federal Power Act Section 205 filing asking to change the Base Residual Auction parameters for the DPL South locational deliverability area (LDA), essentially the Delmarva Peninsula.
The reliability requirement for the DPL South locational deliverability area (highlighted) increased by 373 MW (12%) since the 2023/24 capacity auction. The requirements for other LDAs were flat or declined slightly. | PJM
Senior Vice President of Market Services Stu Bresler said PJM will ask FERC to approve a tariff change to avoid an unjust and unreasonable clearing price resulting from a “mismatch” between the generation the RTO expected to offer into the auction and how much actually did.
The reliability requirement for DPL South increased by 373 MW (12%) since the 2023/24 capacity auction, while requirements for other LDAs were flat or declined slightly.
PJM’s disclosure, which came the day after it had planned to release the BRA results, resulted in almost three hours of discussion.
‘Mismatch’
The reliability requirement for each LDA is the sum of its internal generation and the capacity emergency transfer objective (CETO), the imports needed to maintain reliability based on the region’s load profile and anticipated outages.
Internal generation consists of existing units with must-offer obligations and planned generation with interconnection service agreements (ISAs) and commercial operation dates before the delivery year begins. PJM expected about 1,000 MW of new generation with ISAs to be in operation in DPL South by the beginning of the 2024/25 delivery year, June 1, 2024.
In small LDAs like DPL South, the additions of large or intermittent units can paradoxically cause an increase in the reliability requirement because capacity transfers are necessary to account for times when the resources are not available.
“What happened in this case is … we didn’t get offers from all planned resources in the resource model,” creating the appearance of a “shortage condition that doesn’t exist, [producing] much higher prices,” Bresler said. “If all the planned generation had offered into the auction, we would have posted the results yesterday.”
FERC Filing
Bresler said the RTO must model all eligible units in the reliability analysis, because if units excluded do offer into the auction and come online, the RTO could procure too little capacity for reliability needs.
As a result, Bresler said, PJM determined it needs to be able to adjust the reliability requirement downward if modeled units don’t offer.
PJM will seek FERC approval to allow the RTO, during the auction clearing process, to exclude resources from the LDA reliability requirement if they do not participate and the requirement would otherwise increase by more than 1%.
Bresler said the RTO plans to file “indicative” auction results Jan. 3 under the existing rules and under the proposed change to allow stakeholders to evaluate the impact of the proposal before filing comments on it. The only significant price change resulting from PJM’s proposal would be to DPL South, he said, although there “could be some impact” to its “parent” region.
With FERC Chair Richard Glick about to leave the commission, the remaining members could deadlock 2-2 on PJM’s request. By law, that would result in the filing automatically going into effect.
PJM officials said they may also make a filing under FPA Section 206 to establish a refund effective date and allow FERC to consider other options for solving the dilemma if it rejects the 205 filing.
Short Lead Time
Bresler said it was the first time the situation has occurred. He said it may have resulted because the RTO is running its capacity auctions under a compressed time schedule, with only 17 months until the 2024/25 delivery year, as opposed to the standard three years. That increases the risk that a generator may not go into operation in time to meet its obligations.
Another factor, he said, was that the winter risk for solar resources in DPL South is not much lower than the summer risk because the winter load is nearly equal to summer and “the peak occurs before the sun is up in the wintertime.” As a result, the capacity value of solar is smaller in the LDA than in the rest of the RTO.
Bresler told RTO Insider after the meeting that he could not disclose how many expected resources failed to offer because DPL South is a small LDA, and disclosure of the information could identify the resources in question. But he said during the meeting that they were “not solely intermittent resources.”
Stakeholders Worried About Precedent
Several stakeholders objected to PJM’s proposed fix.
Jeff Whitehead of GT Power Group said load interests should be wary of the proposal. “The next time this comes around, the shoe could be on the other foot and the prices could be moving in the other direction.”
“It’s really troubling that we could look to change the rules in the middle of an auction,” said Neal Fitch of NRG Energy. “That’s a really bad outcome.”
“We’re taking a leap on a solution where perhaps not all the implications have been thought out,” he added.
Bresler said PJM will conduct discussions on potential long-term fixes. “This is not a step we take lightly. It’s a fix to a hole in the rules that wasn’t previously identified.”
Arnie Quinn of Vistra said PJM was “opening a Pandora’s box by setting a precedent that market rules can change after offers have been submitted.” He warned the precedent “will become a quagmire for PJM and FERC.”
If the rules change, Quinn added, generators should be able to change their offers.
Michael Borgatti of Gabel Associates suggested PJM request the change for the 2024/25 auction only to avoid making a “snap decision” on a long-term change.
Michael Cocco, of Old Dominion Electric Cooperative, defended PJM’s decision as “appropriate.”
PJM’s proposed resolution was also supported by Independent Market Monitor Joe Bowring.
“The results do not reflect the fundamental economic facts. The results do not reflect the actual balance of supply and demand in the LDA,” Bowring said. “PJM’s actions are reasonable and rational and proportional to the problem.”
However, Bowring said he disagreed with PJM’s plan to publish the DPL South results under the current rules, because they are incorrect and not “relevant.”
After New York’s Climate Action Council (CAC) voted Monday to approve the scoping plan to guide implementation of the state’s 2050 climate goals, questions remain about how much of the plan can be implemented through agency rulemaking and what will require new legislation. (See New York Climate Scoping Plan OK’d.)
The principle behind the scoping plan is to “reduce GHG emissions consistent with the interim and long-term directives established in” New York’s Climate Leadership and Community Protection Act (CLCPA).
The plan seeks to achieve “deep” emissions reductions by targeting sectors reliant on fossil fuels, such as buildings and transportation, while electrifying the state through heat pump installation, purchase of electric vehicles, and development of technologies that “manage energy use and reduce energy costs.”
Integration analysis conducted by the New York State Energy Research and Development Authority (NYSERDA) found that deep decarbonization by 2050 is feasible and will create hundreds of thousands of jobs.
The plan suggests enormous net benefits from climate action: creating stronger and more resilient energy systems; cleaner and healthier homes; high-quality jobs; and a more equitable future.
Many of the recommendations in the scoping plan are “big, bold and visionary,” Basil Seggos, Department of Environmental Conservation (DEC) commissioner, said at Monday’s meeting.
Sectoral Approach
The plan advances the CLCPA “both within and across economic sectors,” including transportation, buildings, electricity, industry, agriculture and forestry, waste, land use, local government, adaptation and resilience, and the gas system. Its most important recommendation is the implementation of an economywide cap-and-invest program that ensures CLCPA “emission limits are met while providing support for clean technology market development.”
The plan recommends that New York adopt this “innovative program design,” which limits emissions by forcing fossil fuel generators to buy allowances for their pollution. But a cap-and-invest program would require approval from the legislature, whose members may resist a market intervention, despite Democratic majorities that support such climate efforts.
The scoping plan also provides a framework that agencies can use to “develop a coordinated gas system transition” and ensure the “transition is equitable and cost-effective for consumers without compromising reliability, safety, energy, affordability and resiliency.”
Natural gas use was another contentious subject for the CAC, with climate justice advocates calling for a near ban on the fuel and protesting certain gas definitions, while gas advocates argued that every option should be on the table when it comes to decarbonization. (See NY CAC Debates the ‘Nomenclature’ of Natural Gas.)
Both cap-and-invest and the proposed gas system transition will face legislative hurdles, since many consumers, particularly in Northern and Western New York, depend on fossil fuels and will oppose any limits.
Climate Justice
The scoping plan was also developed to ensure the transition addresses the “health, environmental and energy burdens that have disproportionately impacted underrepresented or underserved communities … and to remedy the structural causes that underpin these burdens.”
The CLCPA mandates that disadvantaged communities (DACs) receive at least 35% of the benefits of climate spending. It places investments in five key areas identified in the scoping report as critical to offsetting historical marginalization: energy affordability, environmental overburdening, equitable and sustainable job growth, localized development of clean resources, and inclusive DAC involvement the implementation processes.
Many measures related to achieving climate justice can be accomplished through state or city agency rulemaking and regulation, as exemplified by the DEC’s recently finalized rules related to air permits and climate change consideration.
CAC members had debated workforce and business development across the state and what that development would look like, who it should predominantly benefit, and where it should be targeted. (See ‘‘Family-sustaining” Union Jobs, New York CAC Debates Inclusion of Blue Hydrogen, Union Jobs in Plan.)
The plan calls for “the advancement of a low-carbon and clean energy economy that results in new economic development opportunities across New York and a just and equitable transition for New York’s existing and emerging workforce.”
The plan pushes for the development of clean technology manufacturing that targets those less fortunate by building out a “robust clean technology supply chain in New York.”
The recommendations for a “just transition” provide direct support for displaced workers, apply consistent labor standards across all industries and promote workforce training opportunities for new economic activities. The plan also calls for creation of an Office of Just Transition and a Work Support and Community Assurance Fund.
Those entities would guide policymaking related to supporting transition-impacted communities by spurring job growth — particularly union jobs — and leveraging financial resources for workforce training and business development.
The plan says “union labor is important to [CLCPA] implementation,” calling for agencies to “work with workers and their unions to ensure jobs created as a result of the state’s energy transition are good union jobs.”
Next Steps
The scoping plan will now be incorporated into the State Energy Plan and updated every five years by the CAC.
The plan moves to the DEC, which has until Jan. 1, 2024, to “draft and promulgate enforceable regulations to ensure that the state meets the Climate Act’s statewide GHG emission limits,” as well as publish an implementation report every four years measuring the success of emission reductions policies.
After July 1, 2024, the Public Service Commission (PSC) will be required to issue a biannual review of the plan’s renewable energy program, which will include progress reports on the programs “the PSC has established to require procurement of 9 GW of offshore wind by 2035, 6 GW of solar PV by 2025, and 3 GW of energy storage by 2030.”
The PSC will also provide regular updates on how DACs have benefitted from the plan’s implementation.
Massachusetts has committed $180 million to support the wind power industry it hopes will grow off its coast and become a key part of its clean-energy future.
The grants announced Dec. 20 in the competitive Offshore Wind Ports Infrastructure Investment Challenge, showed Massachusetts remains committed to the young industry despite developers’ concerns over rising costs.
Most of the grants went to projects in New Bedford ($79.6 million) and Salem ($75 million), with $25.4 million to Somerset:
$75 million to Crowley Wind Services and the city of Salem to convert a former coal-fired power plant to an OSW marshaling port.
$45 million to the Massachusetts Clean Energy Center to improve its New Bedford Marine Commerce Terminal.
$15 million to the New Bedford Port Authority to improve its North Terminal 1 for increased vessel traffic.
$15 million to the New Bedford Foss Marine Terminal to redevelop the former Sprague/Eversource power plant into a port supporting construction and operation of OSW facilities.
$4.63 million to Shoreline Marine Terminals to build out terminals in New Bedford to support daily operations of vessels carrying OSW crews and maintaining those and other vessels.
$25 million to Prysmian Projects North America to redevelop part of the Brayton Point Marine Commerce Center in Somerset into a manufacturing facility and terminal for marine high-voltage cables.
$360,800 to Gladding Hearn Shipbuilding to upgrade its Somerset facility to build and repair high-speed crew transfer vessels for OSW projects.
Lt. Gov. Karyn Polito said the funding announcements will help capture high-value supply-chain and workforce opportunities. “This $180 million investment will not only provide clean, affordable energy, but will also help revitalize gateway communities by delivering valuable jobs for our residents,” she said in a statement.
The state in August codified 5.7 GW of OSW capacity as a mid-2027 goal, but clouds arose soon afterward.
The developer of the 1.2-GW Commonwealth Wind project moved to delay and then cancel the contracts it had committed to, saying inflation and interest rate hikes had made the terms untenable. The developer of Mayflower Wind said it had similar problems with its commitments for 400 MW, though it did not move to cancel its power purchase agreements. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.)
The only other OSW project in the pipeline in Massachusetts is the 800-MW Vineyard Wind, which is under construction and targeted to go online in 2023.
When trying to incorporate equity into EV charging programs, simply placing a charger in a disadvantaged community is not enough, speakers said last week during a Western regional EV charging summit.
“It’s not … just about putting that dot on the map in that community because the map says that’s where it should go,” said Kay Kelly, chief of innovative mobility at the Colorado Department of Transportation. “It’s really about involving the community, understanding what their needs are, and making sure that they have an opportunity to benefit from that location.”
Kelly’s comments came during the National EV Charging Initiative’s Western Summit on Dec. 14. The initiative is a coalition working to develop a national charging network for light-, medium- and heavy-duty electric vehicles.
Kelly said that charger installation can be accompanied by community benefit agreements. Benefits might include using the local workforce to build and maintain charging stations — or training residents to service electric vehicles. Community members can be offered charging at reduced rates, or the chargers can be used to support community EV car share programs.
Another option is making the charging stations available to electric transit or school buses that serve the community.
“What we certainly don’t want to have is for EV charging stations to become an instrument of gentrification for that neighborhood,” Kelly said.
CEC Perspective
Kelly was part of a panel discussion on challenges to EV charger deployment. The panel also included Mark Wenzel, branch manager of light-duty electric vehicle infrastructure and analysis at the California Energy Commission.
Wenzel said the CEC performs equity analysis of charger placement. To aid in that process, CEC has launched an effort to better measure benefits provided by the agency’s Clean Transportation Program, which includes funding for EV charging infrastructure.
The CEC held a workshop on community benefits last month and plans to continue gathering public input. The agency hopes to publish a draft community benefits framework by mid-2023, it told NetZero Insider.
There’s also a Disadvantaged Communities Advisory Group that reviews clean energy programs and policies from the CEC and CPUC.
Wenzel said some of the CEC’s funds go toward at-home charging in low-income and disadvantaged communities, including at multi-family housing complexes, so those residents can have access to low-cost, convenient EV charging.
The panelists also discussed community engagement. Kelly said it’s not enough to listen to comments during government meetings, where community members typically have two or three minutes apiece to state their views.
“We need to be having more roundtable discussions,” she said. “More walking tours. More authentic engagement with communities that transcends what that typical government meeting model looks like.”
Rolling Out NEVI Plans
The goal of the National EV Charging Initiative is to “spur bold actions” in public and private sectors in response to the Infrastructure Investment and Jobs Act.
In January, the initiative hosted a national conversation on EV infrastructure. Now, the focus is shifting to the states, “where the most important activities to ensure successful deployment of the national EV charging network occurs.” Last week’s Western summit was the first in what’s expected to be a series of regional events.
As part of the IIJA, the federal government is awarding $5 billion over five years to fund state EV charger plans submitted under the National Electric Vehicle Infrastructure Formula Program (NEVI). All 50 states plus the District of Columbia and Puerto Rico submitted NEVI plans; all have been approved. The states now have $1.5 billion in formula funding to start implementing the plans. (See US Completes Review of State EV Charging Plans.)
In a second panel discussion during last week’s summit, Sara Rafalson, vice president of market development for EVgo, discussed barriers to building out a national EV charging network.
FERC last week rejected a proposed settlement agreement intended to resolve a longstanding appeals court dispute over how to implement Order 1000 in the WestConnect planning region (ER22-1105).
WestConnect covers parts of Arizona, California, Colorado, Nebraska, Nevada, New Mexico, South Dakota, Texas and Wyoming. It includes FERC-jurisdictional public utilities that are subject to the requirements of Order 1000 as well as several nonpublic utilities not subject to the order.
Order 1000, which FERC issued in 2011, requires jurisdictional utilities to participate in regional transmission planning and to develop a process for allocating costs for projects selected through the planning process.
The settlement agreement rejected by FERC on Thursday was negotiated by nine WestConnect public utilities, including Arizona Public Service; Black Hills Colorado; Black Hills Power; Cheyenne Light, Fuel and Power; El Paso Electric; Public Service Company of Colorado; Public Service Company of New Mexico; Tucson Electric Power; and UNS Electric.
The dispute at issue in the settlement agreement originated in 2012, when WestConnect public utility transmission providers submitted a series of compliance filings in response to Order 1000. FERC rejected several filings related to how the planning group would handle regional cost allocation, but it accepted a proposed participation framework that allowed non-jurisdictional utilities to choose to participate in the WestConnect planning region as either enrolled members subject to binding regional cost allocation or as “coordinating transmission owners” (CTOs) not subject to allocation.
In 2016, the 5th U.S. Circuit Court of Appeals vacated FERC’s decision to accept that framework, concluding that the commission had failed to provide a reasoned explanation for doing so.
The commission provided its explanation in an order on remand, saying that, after considering alternatives, it continued to believe the approved framework could “ensure just and reasonable rates while taking into account the uniquely integrated nature of the transmission systems of public and nonpublic utility transmission providers in WestConnect.” It also explained that nonpublic utilities in the region would be incentivized to participate in cost allocation because projects from which they would receive benefits would be less likely to advance without their participation.
In December 2017, the commission denied a request by the WestConnect utilities to rehear the order on remand. The utilities, contending that the original issues had not been resolved, then petitioned the 5th Circuit, where their appeal is still pending, having been subject to a stay until Tuesday.
New Process
Thursday’s ruling dealt with a proposal by the WestConnect public utilities to resolve the appeals court case by establishing a new framework that seeks to address concerns about free-ridership by nonpublic utilities, which the parties to the agreement believe is at the heart of the 5th Circuit case.
The proposal outlines a process by which nonpublic utilities can opt in and contractually bind themselves to regional cost allocation for projects from which they receive benefits. The plan would allow a nonpublic utility to vote on a project after opting in to cost allocation. It would also include “processes and protections” to ensure that more than one WestConnect public utility would benefit from selected projects and seeks to clarify through “defined criteria” the types of projects that are eligible for regional cost allocation.
Under the proposed plan, if the regional transmission planning process identifies a transmission need for more than one enrolled member, WestConnect will solicit proposals to address the need. The WestConnect Planning Management Committee (PMC) would then develop a comprehensive list of solutions, with each being analyzed to determine whether a CTO is a beneficiary. Any benefiting CTOs could then opt in as a “cost-bound” beneficiary.
Thereafter, any cost-bound beneficiaries for projects on the comprehensive list could vote to decide which of the projects move to a short list of potential solutions.
“The Planning Management Committee then evaluates all the transmission projects on the short list under regional cost allocation criteria to determine if each project is eligible for selection in the regional transmission plan for purposes of cost allocation,” the commission explained. Projects that meet the criteria then move to final consideration by the PMC.
The proposal also stipulates that if one or more CTOs identified as beneficiaries do not opt to become cost-bound entities for a project, but two or more enrolled transmission providers in at least two balancing authority areas are also identified as beneficiaries, then those remaining beneficiaries may unanimously vote to either allow the project to advance through the planning process, choose an alternative or request the PMC convene a new solicitation.
Inconsistent with Order 1000
In rejecting the proposal Thursday, FERC noted that a late-filed protest by LS Power obligated the commission to consider the agreement to be a contested settlement, making it subject to review under the approach outlined in FERC’s Trailblazer decision. Citing that precedent, the commission said it could not find the “overall package” in the agreement to be just and reasonable.
The commission noted that WestConnect’s current process allows a nonpublic utility to participate in the transmission planning process as a CTO without being bound to cost allocation for a selected project. However, if the CTO finds that it would benefit from a project, it can voluntarily agree to accept its share of the costs. If the CTO does not agree to accept cost allocation, the PMC reruns the cost-benefit analysis for the project after removing the benefits the CTO would have received. If the project continues to meet the required cost-benefit analysis, it remains eligible for regional cost allocation.
But in the settlement agreement’s revised process, the commission explained, the decision by a beneficiary CTO not to opt into cost allocation for a transmission project means the project cannot move ahead without unanimous approval by the remaining beneficiaries.
“Instead, the remaining beneficiaries can identify an alternate transmission project (either from an existing list or newly proposed), but if the alternate project provides benefits to any coordinating transmission owner or enrolled transmission owner that was not identified as a beneficiary of the original transmission project, the entire process begins again,” the commission wrote. “This proposed process makes it highly unlikely for a transmission project to move forward if any potential coordinating transmission owner beneficiary does not agree to become cost-bound, regardless of the potential project benefits.”
The commission also found that the proposed criteria for determining whether a project is eligible for regional cost allocation was inconsistent with the intent of Order 1000.
The commission first rejected the requirement that an eligible project must physically interconnect one or more transmission providers in more than one BAA.
“We find that this criterion is inconsistent with the requirements of Order No. 1000 because, given the large size of several BAAs within the WestConnect transmission planning region, this criterion would preclude from consideration transmission projects (including those of significant size and scope) located within a single BAA that could more efficiently or cost-effectively address the needs of multiple transmission providers,” the commission wrote.
The commission also rejected another provision in the agreement that would require that cost-bound beneficiaries must receive 90% or more of the total benefits for a project in order for the project to be eligible for regional cost allocation. FERC pointed out that the provision was similar to an earlier WestConnect proposal the commission had already rejected.
“The commission rejected this requirement because it could eliminate from consideration for selection in the regional transmission plan for purposes of cost allocation transmission projects that, even after accounting for any cost shift to the remaining beneficiaries, are the more efficient or cost-effective transmission solution for remaining beneficiaries compared to other alternatives,” FERC said.
The commission also found fault with the agreement’s requirement that a supermajority of 80% of cost-bound beneficiaries must vote in favor of making a project eligible for regional cost allocation, which proponents said was consistent with NYISO’s policy.
The WestConnect proposal omitted two provisions included in NYISO’s process, the commission noted, including requirements that a beneficiary of a project that votes against it provide a written explanation for its rejection, and that NYISO submit an informational report to FERC detailing the vote.
“Without such requirements, we are concerned that beneficial transmission projects could be eliminated from consideration without explanation or justification,” the commission said, adding that the NYISO supermajority voting requirement applies only to economic transmission facilities.
“Altogether, we find that the proposed process under the settlement agreement would impose significant restrictions on the pool of transmission projects that could be considered as more efficient or cost-effective transmission solutions for potential selection in the regional transmission plan for purposes of cost allocation, even in situations where those projects would provide significant benefits to public utility transmission providers in WestConnect that outweigh their costs,” the commission wrote.
