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August 26, 2024

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Narrow Set of Options for Retaining Everett LNG Terminal

The fate of the LNG import terminal in Everett, Mass., has come into increasingly sharp focus in the last few months as ISO-NE has continued to sound the alarm about winter grid reliability in the region.

But as of right now, there’s no consensus about how to keep the facility operating past 2024, when the contract sustaining its “anchor tenant,” the Mystic gas generating plant, expires.

ISO-NE laid out the problem in a statement it published ahead of a FERC forum in Vermont earlier this month: “The region must ensure the continued operation of the Everett LNG facility to maintain reliable electric and natural gas service for New England consumers.”

In a recent interview with RTO Insider, however, ISO-NE CEO Gordon van Welie made clear that the grid operator is not interested in using its own authority to do so. (See related story, Gordon van Welie Stares down Another Winter in Charge of ISO-NE.)

“We’re a balancing authority. We balance supply and demand. It’s not our job to make sure that there’s fuel supply,” van Welie said.

The one route by which ISO-NE might help keep Everett alive is through an extension of the reliability-must-run (RMR) contract keeping the next-door Mystic plant operating through 2024.

But van Welie indicated that ISO-NE is loathe to expand the contentious Mystic agreement, which has been the subject of bottomless litigation.

“It could be done by retaining Mystic, but nobody wants us to retain Mystic, and we don’t want to retain Mystic,” he said. “If we extend the Mystic agreement, then we’re socializing the cost of Everett across all electricity ratepayers … and it basically makes it cheaper for the gas” distribution companies.

Constellation Asks for Help

Constellation Energy (NASDAQ:CEG), which has operated the facility since 2018, also acknowledges it will need action from elsewhere to keep the terminal running.

At the FERC forum in Vermont earlier this month, the company’s senior vice president and deputy general counsel, Carrie Allen, made the case that the region should step up and find a way to ensure that Everett can continue to operate. The facility provides pressure support for pipelines it’s connected to and regularly sends out gas to other generators and systems besides Mystic, Allen argued.

And, she said, its gas is cleaner than the oil that would likely replace it if the facility were to go out of service in two years: Constellation has estimated without Everett, carbon dioxide emissions in the region would double and NOx emissions would go up by 74%.

“I do think Everett can critically contribute to reliability in New England,” Allen said. “It’s already permitted; it’s existing. It’s been operating reliably for 50 years. It’s not a question of will it be here. It’s here. The question is, do we want to keep it here?”

Like ISO-NE, Constellation isn’t keen on continuing the contentious Mystic RMR agreement, Allen said, but it’s worried about what comes next without the gas plant serving as an anchor tenant.

“Our experience is that there’s been quite a bit of interest in contracts for supply from our facility post-RMR. But there seems to be a bit of a regulatory problem, and we’re trying to work it through, in terms of the state approval process,” she said.

The potential buyers believe that they need to use fixed commodity pricing to get approval by state regulators.

Allen said she doesn’t believe that’s the case, and that it’s also not something that her company can provide during a potential nine-month wait for state approval.

“I think we need to talk about whether people want Everett to be a bridge to the long-term future. Does New England want to retain it? If so, we don’t have that much time. We have no commitments post cost-of-service that would require us to keep operating,” she said. “We’re faced with a choice, and it’s coming on us very soon for what to do.”

Another Way?

In a recent press briefing with local and national environmental groups, advocates said they were still looking at the details of ISO-NE’s warnings about the need to keep Everett afloat.

But more broadly, they say, the region should be doing more to move off of gas and into clean energy.

In a recent white paper, eight environmental groups challenged ISO-NE’s prediction that gas facilities will need to be in place for the foreseeable future to meet reliability needs.

“In fact, energy storage can serve similar balancing functions as gas, while providing relief to the electric system during winter cold spells and reducing transmission needs,” they wrote.

The groups said that ISO-NE and state leaders should “re-target or supplement” programs like Massachusetts’ Connected Solutions battery program or ISO-NE’s Inventoried Energy Program to incentivize energy storage development.

“I would like to see the day that ISO-NE identifies a clean energy project that they’re really enthusiastic about bringing online in an expedited manner,” said Jeremy McDiarmid, vice president at the Northeast Clean Energy Council, commenting on the grid operator’s urgency related to the Everett facility.

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PJM MRC/MC Preview Sept. 21, 2022

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.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

The MRC will be asked to endorse revisions to the following manuals as part of its consent agenda:

      • Manual 10: Pre-Scheduling Operations, Manual 12: Balancing Operations and Manual 13: Emergency Operations, to address the reserve price formation implementation;
      • Manual 14D: Generator Operational Requirements and Manual 13: Emergency Operation, to conform with NERC standards EOP-011, IRO-010 and TOP-003;
      • Manual 15: Cost Development Guidelines, to address reserve price formation implementation and changes resulting from the manual’s periodic review process. Same-day endorsement may be sought at the MRC and MC meetings; (See “Manual Revisions OK’d on Reserve Price Formation,” PJM Market Implementation Committee Briefs: Aug. 10, 2022.)
      • Manual 10: Pre-Scheduling Operations, Manual 14D: Generator Operational Requirements and Manual 18: PJM Capacity Market, conform with FERC’s July 12 order accepting PJM’s clarifications on its rules for hybrid resources;
      • Manual 18: PJM Capacity Market and Manual 18B: Energy Efficiency Measurement & Verification, resulting from the periodic review process; and
      • Manual 27: Open Access Transmission Tariff Accounting, Manual 28: Operating Agreement Accounting and Manual 29: Billing, to address reserve price formation implementation.

Endorsements (9:10-10:15)

1. Reserve Price Formation Manual Revisions (9:10-9:30)

PJM staff will review proposed revisions to Manual 11: Energy & Ancillary Services Market Operations to address reserve price formation implementation. The Independent Market Monitor will provide its perspective on the proposed revisions. (See “IMM, PJM to Collaborate on Manual Revisions Prior to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)

Issue Tracking: Energy Price Formation

2. Bankruptcy Protections (9:30-9:45)

PJM Assistant General Counsel Eric Scherling will review a proposed package of rule changes addressing bankruptcy protections. The revisions aim to provide greater protections against bankruptcies by market participants. The language was endorsed by the Risk Management Committee in July, and Scherling presented a first read to the MRC in August. (See “Revised Bankruptcy Rules,” PJM Markets and Reliability Committee Briefs: Aug. 24, 2022.)

Issue Tracking: Bankruptcy Protections

3. Market Seller Offer Cap (9:45-10:15)

Stakeholders will be asked to endorse one of two proposed packages of solutions — from PJM and LS Power — and tariff revisions related to changing the market seller offer cap. The PJM language seeks to ensure that market sellers can account for their Capacity Performance risk when offering into the Base Residual Auction. LS Power’s is similar to PJM’s, with differences reflecting sellers’ view of the risk of taking a capacity obligation. (See “Discussions Continue on Market Seller Offer Cap,” PJM Markets and Reliability Committee Briefs: Aug. 24, 2022.)

Issue Tracking: Capacity Reform Market

Members Committee

Consent Agenda (1:15-1:20)

C. Stakeholders will be asked to endorse or approve revisions to Manual 15: Cost Development Guidelines and Operating Agreement Schedule 2 to provide detailed guidance and updates to rules related to variable environmental charges and/or credits and their inclusion in cost-based energy offers. (See “Variable Environmental Costs and Credits,” PJM MIC Briefs: May 11, 2022.)

Issue Tracking: Variable Environmental Costs and Credits

D. The MC will be asked to endorse proposed revisions to Manual 15: Cost Development Guidelines. (See MRC consent agenda item above.)

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NV Energy Seeks Recovery of RTO-related Expenses

NV Energy is seeking approval from Nevada regulators to establish an account for tracking expenses related to its efforts to join an RTO by 2030 — a goal that’s likely to be accomplished “incrementally,” the company said.

After creating the regulatory asset account, NV Energy would seek recovery of its RTO exploration costs in future rate proceedings, according to a filing this month with the Public Utilities Commission of Nevada (PUCN). The request is part of a proposed amendment to the utility’s integrated resource plan.

Senate Bill 448 from the Nevada legislature’s 2021 session requires transmission providers in the state to join an RTO by Jan. 1, 2030, unless the PUCN grants a request for a waiver or delay.

NV Energy said it’s already spending money to meet the mandate, including hiring two new employees who are assigned to the task.

In addition, the company is facing costs related to its participation in the Western Markets Exploratory Group (WMEG). The stakeholder group is having in-depth discussions on the design of two proposed day-ahead markets: CAISO’s extended day-ahead market and SPP’s Markets+.

The group plans to hire an “unbiased third party” to conduct a cost-benefit analysis comparing the two day-ahead market proposals, with scenarios for the markets’ possible footprints. WMEG members would pay for the study on a load-share basis.

NV Energy described the day-ahead markets as a first step toward joining an RTO.

“In coordinating with the other Western stakeholders, it is apparent that formation of an RTO is most likely to be accomplished incrementally by first implementing additional organized market services to the real-time markets … as well as joining a day-ahead market,” Kiley Moore, NV Energy’s regional transmission and market development director, said in written testimony included in the filing.

Moore expects the cost-benefit study of the day-ahead markets to be finished in February. The studies will also analyze scenarios in which utilities that have joined a day-ahead market then establish and join an RTO.

Moore said that after NV Energy joins a day-ahead market, it will work with regional stakeholders on services such as regional transmission planning.

NV Energy has been participating in development of the Western Resource Adequacy Program (WRAP), which is Western Power Pool’s regional reliability planning and compliance program. NV Energy is one of 26 utilities that have joined WRAP’s non-binding phase.

“Introducing a common resource adequacy requirement across the West ensures no one entity leans on the others for continuous support so all can receive a diversity benefit for joining a market and future RTO,” Moore wrote.

In addition, NV Energy is participating in Nevada’s Regional Transmission Coordination Task Force, which held its first meeting in April. Creation of the task force was a requirement of SB 448. (See Nev. Looks to Capitalize on Becoming Tx Crossroads.)

The next meeting of the task force is scheduled for Oct. 12. The group will prepare a report to the legislature, which is due by Nov. 30.

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PJM Names New Vice President and Chief Risk Officer

Carl Coscia (Carl Coscia via LinkedIn) Content.jpgNew PJM Chief Risk Officer Carl F. Coscia | Carl Coscia via LinkedIn

PJM named Carl F. Coscia Monday as its new vice president and chief risk officer, replacing Nigeria Bloczynski, who resigned unexpectedly in April after a dispute with stakeholders over collateral provisions.

Coscia is the former global head of risk management for the German-based energy company EnBW. Coscia managed the company’s market risk, enterprise risk, credit risk, compliance and approval for all master trading agreements, according to the announcement. He also served as the vice president of federal energy policy for Constellation Energy, a branch chief for FERC’s Office of Enforcement, and chief business officer and chief risk officer for Hartree Partners, LP.

“I look forward to managing risk for an organization that is so vital to the lives of the 65 million people it serves,” Coscia was quoted in a PJM announcement of his appointment. “Risk management becomes more important each day in this evolving, dynamic industry that produces and delivers power and administers the markets for wholesale electricity.”

His responsibilities will include coordinating risk management operations with PJM executives, including credit and enterprise risk management, market surveillance and insurance. He will also have oversight of the Risk and Audit Committee of the PJM Board of Managers and will report to CEO Manu Asthana. His new role begins on Sept. 28.

“Risk management is a critical function for PJM as an organization and for the protection of our members,” Asthana said in the announcement. “Carl brings a wealth of risk management, market and regulatory experience to PJM that will serve us and our stakeholders well.”

Coscia is a graduate of the University of Minnesota, where he received a Ph.D. in economics, and the University of Kansas, where he received a bachelor’s degrees in mathematics and economics.

Unexpected Departure

Coscia’s appointment comes five months after the resignation of Bloczynski, who departed with no warning after contentious stakeholder discussions over collateral requirements for financial transmission rights (FTR) traders. (See Bloczynski Resigns as PJM Chief Risk Officer.)

Her resignation was announced less than two weeks after stakeholders voted to urge FERC to reconsider a proposal the commission rejected in February to use a 97% confidence interval for setting the initial margin calculation for FTR trades. The commission said PJM failed to support its proposal because its independent auditors validated the model at a 99% confidence interval rather than the 97% proposed. FERC ordered a paper hearing in the case (ER22-2029, EL22-32) in August. (See FERC Orders ‘Paper’ Hearing on PJM FTR Collateral Dispute.)

CFO Lisa Drauschak assumed Bloczynski’s responsibilities after her departure.

The chief risk officer position was created in the wake of the GreenHat Energy default and a report drafted by an independent consultant hired to investigate the impact to PJM stakeholders. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)

The efforts to rewrite PJM’s rules and regulations to limit the fallout from future market participant defaults continues Wednesday, when the Markets and Reliability Committee will consider a proposal to provide greater protections against bankruptcies by market participants. (See “Revised Bankruptcy Rules,” PJM Markets and Reliability Committee Briefs: Aug. 24, 2022.)

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WECC Explores Greater Role in Transmission Planning

HENDERSON, Nev. — Time and complexity are among the key obstacles to transmission planning in the Western Interconnection, WECC learned from a series of recent interviews conducted with industry stakeholders.

WECC struck “gold” from the details it gleaned from the interviews, Branden Sudduth, WECC vice president of reliability planning and performance analysis, told the organization’s Board of Directors during its quarterly meeting Sept. 14. The process was designed to identify the biggest challenges to transmission planning in the West — and how WECC could help overcome them. 

In June, the board asked WECC staff to perform a “gap analysis” on the challenges and report on how the organization could “add value” to transmission planning in its footprint, which covers 14 Western states, the Canadian provinces of Alberta and British Columbia and northern portion of Baja California in Mexico.

WECC interviewed 26 stakeholders for the project, including merchant transmission developers, state and federal regulators, utility planners, independent power producers, planning consultants and regional planners. Details about interviewees were kept confidential, Sudduth said.

Sudduth said interviewees noted that some regional projects have been in the works for about 15 years.

“Some of those projects, when they were first proposed, had a very specific purpose, and because it’s been 15 years later and a lot of the goals of the state [and] goals of the utilities have changed, the purpose for those projects has also changed. But they’ve been flexible and adaptive and have been able to incorporate some of those changing objectives into those plans,” Sudduth said.

Sudduth ticked off the other major challenges cited by stakeholders:

  • The inability to identify “major” interregional transmission projects and frustration with the FERC Order 1000 process.
  • Concerns about how to adapt to potential changes stemming from recent FERC Notices of Proposed Rulemaking on transmission planning (RM21-17) and generator interconnection processes (RM22-14).
  • The division between transmission and resource planning. It’s “quicker to get resources planned, sited and built than it is to get major transmission projects built,” Sudduth said. “So that timeline alone creates some challenges in terms of ensuring that we have enough transmission to meet the aggressive clean energy targets that we’re seeing in a lot of states in the West.”
  • The length of generator interconnection queues. Utilities expend a lot of effort processing queue requests, Sudduth said, and various entities have adopted different methodologies, such as the cluster or serial approach to processing. “These create some interesting and unique challenges when it comes to understanding what the transmission needs are based on those generator interconnection queues.”
  • Siting, permitting and cost allocation, which Sudduth acknowledged can’t necessarily be lumped together given the different challenges associated with each. For instance, permitting in the West can be difficult because of the amount of federally owned land, while cost allocation can be problematic due to inconsistent treatment across jurisdictions.
  • Workforce shortages, particularly among transmission planning engineers. Workforce issues were a running theme at WECC’s two-day meeting Sept. 13-14. (See WECC Forum Elicits Hopes, Fears About Future of Electric Sector.)

Centralization, Optimization

WECC also probed the interviewees on potential solutions to the transmission challenges.

“The RTO concept came up a lot,” Sudduth said. “I know there are a lot of different entities that are looking at multistate RTOs to help bridge some of the gaps that we currently see in transmission planning, and especially for those larger interstate transmission projects.”

WECC also heard about other centralized planning options, “without a lot of specificity around what that means or who would be performing that,” Sudduth said. He said many respondents felt that there was more planning coordination in the past, but that cooperation seemed to drop off over the last 20 years.

“Maybe it’s the [lack of] ability to come together and dedicate the time to some of the pre-planning coordination that’s necessary for some of these larger projects,” Sudduth said.

Respondents pointed to other potential solutions, including:

  • Integrated resource and transmission planning. “There’s this tension between resource planning and transmission planning, and the thought is if we could get those more closely aligned and coordinated, both at a wide-area level, but even within different entities within different companies … it might really help.”
  • Simplified and expedited approval processes over the long term.
  • Optimization before cost allocation, which Sudduth described as the desire of some stakeholders to explore what it would take to “optimize” the performance of the regional transmission system before making decisions about specific projects.

Recs for WECC

Sudduth said a top recommendation was for WECC to expand its existing tools, models and data sets from a 10-year to 20-year time frame.

“So [there is] a lot of support in WECC developing 20-year models to help support this type of planning activity, and this was one that we’ve actually started having conversations with the regional planning groups around; it’s already gaining a lot of momentum. I’m excited to see that there’s some potential here already to expand what we currently do,” Sudduth said.

Stakeholders’ other recommendations for WECC included:

  • Performing a “top-down” analysis of interconnection-wide transmission needs based on overall resource changes, as opposed to the more typical “bottom-up” approach that goes with transmission projects designed to address a local need.
  • Coordination at key “touch points” along the transmission planning process. “One of WECC’s strengths is the ability to bring together subject matter experts from around the interconnection to have conversations to coordinate on some of these plans,” Sudduth said.
  • Providing an “independent voice” on planning issues.

A recommendation that WECC play a role in “stronger centralized regulation” prompted WECC board member James Avery to ask: “What was the vision there? Because we’re not the regulator.”

“This could be anything from developing reliability standards to helping standardize some of these processes, to working with different state regulators trying to maybe identify possible opportunities for more common processes [and] common standards along the way,” Sudduth said.

Board member Joe McArthur asked Sudduth how stakeholders thought an RTO could improve the transmission planning process.

“I’m not sure how to phrase my question: Does an RTO speed that up, or just provide more focus on the approval process?” McArthur asked.

“I think [for] different components of that [it does speed up the process]. So, if you have an RTO that has a centralized cost allocation process or something like that, it might help in that regard. In terms of maybe the land permitting, siting, that kind of thing, I’m not sure,” Sudduth said.

WECC’s next steps will be to document the insights from the interviews and offer stakeholders and board members a proposal on “the direction we’d like to go,” Sudduth said. Staff must also evaluate WECC’s legal limitations on acting on the recommendations. “We know there’s things that we just cannot do,” he said.

WECC plans to provide an update on the effort at the board’s next meeting in December.

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California Gov. Newsom Signs 40 Climate Bills

California Gov. Gavin Newsom signed six bills Friday that completed his enactment of a broad-ranging 40-bill collection of energy and environmental measures passed this legislative session, which he said established the state as a world leader in climate action.

The bills Newsom signed in an event with lawmakers included Assembly Bill 1279, codifying the state’s goal of achieving carbon neutrality by 2045 and setting an 85% emissions reduction target. Another measure, Senate Bill 1020, established state goals of using 90% carbon-free electricity by 2035 and 95% by 2040 — steps on the way to supplying retail customers with 100% clean energy by 2045, as required by 2018’s Senate Bill 100.

Two bills, SB 905 and SB 1314, aim to advance carbon capture and sequestration as viable means of reducing greenhouse gasses, while AB 1757 tasks the state’s Natural Resources Agency with establishing ambitious carbon sequestration targets for “natural and working lands.”

Newsom asked lawmakers to introduce the six bills — part of his California Climate Commitment — toward the end of the 2021/22 legislative session in August. Democratic lawmakers cooperated and quickly passed the measures, including a bill to keep the state’s last nuclear plant operating at least five years beyond its planned retirement.

Newsom thanked lawmakers and touted such efforts as an engine of economic progress in a state that ranks as the world’s fifth largest economy with a gross domestic product last year of roughly $3.4 trillion, not far behind Germany.

“We often talk about electricity and electric power,” he said. “It’s not about electric power; it’s about economic power. Electricity is the architecture to transform and decarbonize … our economy. It allows us to leapfrog in low-carbon green growth. It allows us to dominate in the next big industry.”

The 40 new laws Newsom has signed will produce 4 million jobs and $23 billion in taxpayer savings while reducing air pollution by 60% and fossil fuel use in transportation and buildings by 92%, the governor’s office estimated. Overall, the state has directed nearly $54 billion toward fighting climate change and promoting a green energy economy in the coming decades.

The governor’s office issued a news release with a full list of climate-related measures he signed this past legislative season, half of them recently. Information on all the measures can be found at the state’s legislative website.

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Western Governors Talk Climate Change

A climate crisis on the West Coast requires interregional cooperation, the governors of California, Oregon and Washington and the premier of British Columbia said at last week’s Cascadia Innovation Corridor Conference, where they shared a virtual dais.

“We know no borders when it comes to climate change and the consequences of a heating planet,” Premier John Horgan said. “All of us here on the West coast have experienced unprecedented drought, fires [and] floods. The consequences are catastrophic, and British Columbia has had its infrastructure bent and broken significantly over the past number of years.

“The only way forward is to put aside the national boundaries, to put aside the subnational boundaries that separate us, and go to the values that unite us,” he said.

This year’s conference — in Blaine, Wash, on the U.S.-Canada border and sponsored by Microsoft and Amazon, among others — highlighted climate change and the region’s “net-zero future.”

It featured a report saying the “Cascadia mega-region, running from Portland through Seattle to Vancouver, British Columbia, has become synonymous with building a better future. Home to so many natural assets and incredible innovation and talent, one of our greatest strengths is partnership. Now is the time to partner to address one of the greatest challenges of our time: the threat of climate change to the region and the world.”

Oregon Gov. Kate Brown agreed the “need for action could not be more urgent.”

“Climate change is something we’re no longer trying to avert. It is actually here,” Brown said. “And so, I think our strategies are going to have to evolve toward mitigation and adaptation.”

Last year’s June heat dome over Oregon, which killed 96 residents as it drove temperatures to 116 in Portland, disproportionately harmed “communities of color [and] families with low incomes in our rural communities,” Brown said.  

“I think it’s so critically important as we move forward, as we continue to take action to develop policy” that Oregon focuses on historically underserved communities, she said.

“One of the simplest [means] is the legislation that we passed [last year] to ensure that families with low and moderate incomes could access our [electric vehicle] rebates, both on new and used vehicles. And we were the first state in the entire country to do that. I was pleased to see that Congress followed our lead in making that available at the national level” in the Inflation Reduction Act of 2022, she said.

‘Economic Power’

Moderator Rachel Smith, CEO of the Seattle Metropolitan Chamber of Commerce, asked California Gov. Gavin Newsom to discuss his state’s most recent experience with extreme weather and a package of bills he sponsored in August.   

“California is on the frontlines of the climate crisis with an unprecedented heatwave,” Smith said. “Just this past week saw record temperatures across the state. You also made a very big push with legislative partners on climate last month.”

Newsom started by thanking his colleagues for inviting him to the conference, which traditionally has involved mainly delegates from the Pacific Northwest, then segued to a talk on climate change globally and in the West.

Over a 10-day period this month, California and the Southwest broke 1,000 temperature records, and the heat stressed CAISO’s grid to near-blackouts, Newsom said. (See California Runs on Fumes but Avoids Blackouts.)

The bills that the legislature passed at the end of August, and which Newsom signed Friday, included measures to move the state more aggressively to achieve carbon neutrality and supply all retail customers with 100% zero-carbon energy by 2045, as required by previous legislative actions and executive orders.

The California Air Resources Board adopted regulations last month requiring all new cars sold in the state to be zero-emission or plug-in hybrids by 2035, firming up his similar executive order from September 2020, Newsom noted. (See Calif. Adopts Rule Banning Gas-power Car Sales in 2035.)  

The state has devoted $54 billion toward fighting climate change in the next five years, more than all but a handful of nations, he said. Approximately $10 billion of that amount is intended to promote adoption of electric vehicles, a top priority in California, he said.

More than 50% of greenhouse gas emissions in California come from transportation, including 41% from tailpipe emissions and the rest from fossil fuel extraction and production.

“If we’re going to get serious about greenhouse gases, we have to get serious about decarbonizing the transportation sector,” Newsom said.

Ford and General Motors have decided to focus on producing electric vehicles, “so we’re moving markets internationally,” he said. “This is not about electric power. This is about economic power.”

Gov. Jay Inslee of Washington also emphasized the economic benefits of a clean energy agenda.

“The West Coast has demonstrated that if you want to have a robust, dynamic, productive economy, get on the clean energy bandwagon,” Inslee said. “Because the No. 1 economy in the world today is the West Coast of the United States and British Columbia.

“And one of the reasons is we are growing jobs like crazy in the clean energy, high-tech, innovative economy. We demonstrated it. We have shown it. This is not a hypothetical. It’s not a marketing bumper sticker. It’s an economy that is zooming because we’ve embraced clean energy. And that’s what people want. They want jobs, and we are delivering jobs in clean energy.”

The federal government’s decision to devote $360 billion to “finally” fight climate change in the Inflation Reduction Act lags the West Coast states efforts but will accelerate them, he said.

The denial of climate change by many Republicans has delayed efforts to fight it by decades, Inslee said.   

Horgan, however, said a bipartisan consensus has prevailed in British Columbia and other parts of Canada regarding the need to address climate change, including through forest management to prevent wildfires. He said he hopes the majority of the U.S. will come to recognize the reality of climate change in the near future.  

“We are fortunate in Canada that the [climate change] deniers are diminishing by the day because of the obvious evidence that is right in front of us, but I do not doubt for a minute — Jay and Kate and Gavin — the challenges you face because of the fracture in your country right now. All of us on this side of the border are hoping and praying that sanity will prevail in the months ahead.”

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Texas PUC Briefs: Sept. 15, 2022

Commission, Stakeholders Working to Streamline Battery Interconnection Process

Texas regulators last week said they are working with the electric industry to streamline interconnection processes for all resources at both the transmission and distribution levels.

Will McAdams (Admin Monitor) FI.jpgPUC Commissioner Will McAdams explains the issues facing battery-storage developers in bringing their resources to the grid. | Admin Monitor

 Public Utility Commissioners Will McAdams and Jimmy Glotfelty told their fellow regulators during Thursday’s open meeting that they will soon file “a framework that will serve as the building blocks of a strawman and set the parameters for discussion that all groups can agree on and move forward with.”

Their focus is mostly on interconnecting distribution-level battery storage systems. ERCOT only has 350 MW of distribution-side batteries on its system providing transmission benefits, McAdams said. However, according to the latest U.S. Energy Storage Monitor report from Wood Mackenzie and the American Clean Power Association, Texas accounted for 60% of the second quarter’s 2.98 GW of residential storage and grid-scale installations.

“This is trying to build a comprehensive grid where you have a firm grasp of the demand side and the supply side at both the transmission and — now — the distribution level … and trying to account for everything that we can bring to bear on the system for the purposes of reliability,” McAdams said.

“We need resources. We need resources at the transmission and distribution levels, and we’re going to get them whether we want them or not,” Glotfelty said. “We’re trying to give certainty to the distribution companies and their distribution customers, and we’re trying to give certainty to those who are investing private capital into our system on what they’re going to be paying today and in the future.”

Battery developers have been petitioning the PUC for more clarity, transparency and standardization, the commissioners said. McAdams said developers and utilities have made “great headway” working behind the scenes to develop a framework for a potential rulemaking or project.

At issue are processes and timelines, cost allocation and the use of dedicated feeders that may require rule changes in batteries that bid into the ancillary services markets.

McAdams told the commissioners that distributed energy resources are incented to interconnect on distribution systems because of substations’ spare capacity. DERs have found that is quicker than going through a separate transmission study process. Using substations as interconnection points also solves the issue of finding real estate in areas without transmission congestion and existing resources.

“It’s in the state’s interest to make it as easy as possible for these resources to come in at the locations that they’re applying for,” McAdams said.

DERs do not need to pay construction costs to interconnect to distribution systems. A PUC rule also designates batteries as pass-through resources in that they’re only charging and discharging and never actually producing power on the system.

“This is the industry coming together and coming up with the proposed rule,” Glotfelty said. “Everybody has a right to look at that and give us their input and have those discussions.”

Plant’s Conversion to Gas Approved

The PUC approved Southwestern Public Service’s (SPS) request to convert Harrington Generating Station’s three coal-powered units to natural gas and to build, own and operate a new gas pipeline (52485).

The conversion comes after a 2020 agreement between SPS and the Texas Commission on Environmental Quality to stop burning coal at the plant by 2025 after it violated the national ambient air quality standard for sulfur dioxide from 2017 to 2019. SPS determined that the best way to reach compliance was by converting the plant, which sits in the SPP footprint, to burn gas.

The West Texas plant’s continued operation will also help SPS meet SPP’s new 15% minimum reserve margin. The utility said full conversion also allows it to seamlessly maintain its existing interconnection rights at Harrington.

Harrington’s three boilers were designed to burn both coal and natural gas. The three units have a combined net capacity of 1,050 MW.

The conversion will cost $65 million to $75 million, and the $57 million needed to construct the pipeline will account for the bulk of the price tag. Texas customers will be allocated up to $53 million of the costs.

“This case disturbs me a little bit, but I have to be OK with it,” Glotfelty said. “I don’t like upgrading and changing fuels on a very old plant. I would hope in the future this could be … a new type of gas plant rather than a conversion of an old coal plant that uses old technology. But that’s not where we are today.”

The commission also approved an uncontested settlement, effective Oct. 15, in El Paso Electric’s rate request that will yield retail base-rate revenues of $35.69 million with a 9.35% return on equity. EPE had originally requested a $41 million rate increase (52195).

Interventions in Legal Dockets

The commissioners spent nearly two hours in executive session with their legal staff shortly after the meeting began. They then approved intervening in several ongoing dockets by:

  • filing amicus briefs in ERCOT cases over its sovereign-immunity claims from lawsuits before the Texas Supreme Court involving CPS Energy (22-0056) and Panda Generation (22-0196);
  • supporting a MISO and Edison Electric Institute motion at FERC to dismiss a complaint seeking to remove the grid operator’s compliance with state and local right-of-first refusal laws (EL22-78);
  • supporting ERCOT’s position in any appeal of the adversary proceeding judgement in the Brazos Electric Power Cooperative bankruptcy case before the U.S. Bankruptcy Court for the Southern District of Texas (21-30725); and
  • filing an amicus brief supporting ERCOT’s sovereign-immunity claims in Just Energy’s appeal of its bankruptcy case before the 5th Circuit Court of Appeals (22-20424).
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Legislative Action Sought for New England’s Winter Reliability Challenges

SARATOGA SPRINGS, N.Y. — Limited supplies will likely result in higher natural gas prices in New England this winter and could prompt more supportive state policies for the industry, stakeholders told the Independent Power Producers of New York Fall Conference on Sept. 14.

Tight gas supplies could result in rolling blackouts and prices significantly higher than the current national average of more than $8/MMBtu, Northeast Gas Association CEO Charles Crews said during a panel discussion at the conference.  

James Daly 2022-09-14 (RTO Insider LLC) FI.jpgJames Daly, Eversource Energy | © RTO Insider LLC

James Daly, vice president of energy supply for Eversource Energy, predicted 60 to 100% increases in the price of electricity — excluding transmission and distribution costs — partially because of Russia’s cuts in gas supplies to Europe, which have raised LNG prices internationally. 

The Russian invasion of Ukraine has compounded New England’s challenges: environmental activism that has blocked new gas pipelines and the century-old Jones Act, which prevents tankers from bringing U.S. LNG to the region. 

Natural gas had wide support as a “bridge” fuel to a low-carbon future until the anti-fossil fuel movement began “vociferously” opposing pipeline expansions, Daly said.

“Renewables are being supported heavily by new legislation, but there’s no support at all for natural gas. And there’s opposition to the natural gas, even though the two things could be … complimentary in terms of” decarbonization, he added.

“The war in Ukraine … could be certainly a multiyear [struggle],” he said. “So once customers start to voice their objections to those very high bills, [policies] could change.”

Dan Dolan 2022-09-14 (RTO Insider LLC) FI.jpgNew England Power Generators Association President Dan Dolan | © RTO Insider LLC

Last winter brought higher gas prices and increased volatility largely because of the impacts of the COVID-19 pandemic and the quick economic rebound, said Dan Dolan, president of the New England Power Generators Association. “The story at the time was, ‘It’s going to be okay; this is a one-season issue.’ Then Russia invaded Ukraine, and the world fundamentally changed. And now we are looking at a persistent multiyear situation in which the commodity is constrained, volatility has increased. And in the midst of all that, New England is going through a very similar transformation [to] here in New York, in meeting our climate obligations.” 

Coal and oil provided less than 1% of New England’s January megawatt-hours in 2019-2021 but generated 20 to 30% in 2022, Dolan said, and he expects the same in 2023 and beyond. This insulates electric costs from the volatility of gas prices but boosts emissions, he said.

No New Pipelines?

New England is served by five gas pipelines, with most of its supplies coming from the west, through New York. Efforts to expand the infrastructure have been blocked both in New York and New England.

The Massachusetts Supreme Court blocked a proposed gas pipeline that would have been contracted by Eversource and other electric distribution companies because it was inconsistent with the state’s retail restructuring law. “So a change in law would be needed,” Daly said.

Dolan is not optimistic that will happen.

“I do not believe we will ever see another major new natural gas pipeline coming into New England,” he said. “The story now becomes how do we maximize the infrastructure we have? How do we better value those reliability products?”

Dolan said FERC’s gas-electric conference earlier this month left him with some optimism. “It was the first time I’ve heard in years a refocusing around this question of reliability, a recognition that the valuation of that reliability has not received as much attention as it as it needs,” he said. “There was discussion of creating further reserves in the region. There are many different ways in which we can structure that.” (See FERC Comes to Vermont and Leaves with a New England-sized Headache.)

Dispatchability

Gas will likely return to its role as a peaking resource in New England as tougher emissions targets take hold, Dolan said. And it will likely be needed as a dispatchable resource for decades, he added.

“Whether it’s in Massachusetts or Connecticut, or it seems like in New York, there is a recognition we need that level of dispatchability, and reliability overall onto the system. It feels like right now that’s code word for gas, but nobody wants to say it out loud,” he said. (See Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance.)

He questioned whether hydrogen could provide a solution because New England’s geology is not suited for storage. “I’m hard pressed to see how the vast majority of natural gas fleet that exists in New England doesn’t persist.” he said.

Other Solutions?

Yet New England “does not have a plan beyond two years [for] reliability,” Daly said, a reference to the planned 2024 retirement of Constellation Energy’s Mystic Generating Station and attached LNG import facility in Everett, Mass. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

Daly said Eversource has identified opportunities for “relatively inexpensive” electric transmission upgrades using existing corridors, but their impact will be limited, he said.

Adding more storage for LNG would be very expensive, requiring legislative support for funding, he said.

Dolan questioned whether the elimination of the Jones Act would make a difference for New England because of a trend toward global LNG pricing. “If global markets do settle out, being able to leverage domestic production would be nice,” he said.

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EU Retreat from Competition, Ukraine Conflict Seen Impacting US Energy Markets

SARATOGA SPRINGS, N.Y. — Europe appears to be retreating from electric competition and single-price clearing auctions, trends that could spread to the U.S., MIT professor Michael Mehling told the Independent Power Producers of New York’s (IPPNY) Fall Conference on Wednesday.

Mehling, deputy director of the MIT Center for Energy and Environmental Policy Research, spoke after the annual European State of the Union, where European Commission President Ursula von der Leyen proposed capping prices for renewable and nuclear generators at $180/MWh and imposing windfall profit taxes on oil, gas and coal companies. Von der Leyen also called for “a deep and comprehensive reform” of the merit-order electricity market, saying the EU needs to “decouple the dominant influence of gas” on prices.

Von der Leyen’s proposals came in response to rapidly rising prices resulting from drought, reduced offshore wind production, the phaseout of nuclear units and, most recently, Russian gas supply cuts.

Energy Security

The EU’s energy security has also been impacted by its aggressive climate targets, which prompted a shift from dispatchable coal and gas resources to renewables, Mehling said.

The European Parliament recently backed a target to get 45% of its energy from renewable sources by 2030, compared with 22% in 2020. Additionally, the EU adopted laws requiring at least 55% GHG emission reductions by 2030 compared to 1990 levels and net-zero emissions by 2050. It also created energy efficiency directives that require the continent to achieve a 20% reduction in energy consumption by 2020.

“Energy security is definitely — there’s no argument about it — compromised in the EU now,” Mehling said.

European leaders have increasingly considered market interventions. As of October 2021, 25 member states had adopted price regulations or transfer mechanisms such as income supports and tax reductions to address rising prices. The French government recently bought the remaining shares of the nation’s main utility, Electricite de France. Germany’s government has started talking about reopening many of its retired nuclear plants, Mehling said, while Poland “has gone back to coal.”

Lessons for the US

Mehling said one lesson from Europe’s experience is “how quickly you can go from believing firmly in … deregulated markets to seeing a tremendous appetite to intervene at every level, both in the name of climate policy, but also in the name of reducing energy costs.”

“Is that something that could also happen here?” he asked. “Some would say it’s already beginning with, you know, all kinds of different policy complements to the traditional … liberalized parts of U.S. electricity markets.”

In 2021, before its invasion of Ukraine, Russia supplied almost half of Europe’s gas and coal imports and a quarter of its oil. Russia is now responsible for less than 10% of Europe’s gas imports. As the EU weans itself from Russian gas and builds more LNG terminals, demand for U.S. gas will increase significantly, creating a “convergence of prices around the globe,” Mehling said.

Mehling said EU leaders risk making mistakes in attempting to respond to the crisis with quick, decisive actions, such as the proposal to decouple natural gas from setting market prices.

But he said economists and policymakers must determine whether single-price clearing markets still make sense as the fuel mix shifts to one dominated by low variable cost renewables that often produce negative prices.

“For 20 or 30 years, we thought we knew what the optimal [market] design would be,” he said. “But with changing circumstances … I think we also have to be sober enough to realize that at some point, this dearly held principle of what the optimal approach would be may have to be revisited.”