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.
New 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.)
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.
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.
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.
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.”
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.
PUC 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).
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, 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.”
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.
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.”
SPP staff are taking yet another crack at adding counterflow optimization (CFO) to the congestion-hedging process following a late-August workshop with the Board of Directors, Members Committee and other stakeholders.
Staff offered more than a dozen alternative congestion-hedging solutions, culled from surveys and meetings with stakeholders. Stakeholder groups will get another opportunity to discuss the final recommendations before they are brought to the governance committees and the board during their October meetings.
“My hope is the things that staff has developed, and the feedback we’ve heard today, provides us with a pathway to do some work with stakeholder groups to help shape whatever comes back to the board in October,” board Chair Larry Altenbaumer said. “I don’t want to presuppose staff’s recommendation or what it should be, but I want to make sure we’re being as thorough as possible in providing constructive guidance on whatever that solution might be.”
It hasn’t been easy for CFO to get this far. The Holistic Integrated Tariff Team recommended in 2019 that CFO, limited to excess auction revenue, be added to SPP’s market mechanism that hedges load against congestion charges. The process, which keeps system transmission flows between two points in balance, was meant to address concerns about how congestion rights instruments are awarded and the current process’s efficiency.
The Market Working Group spent months trying to reach agreement on how best to add CFO, only to eventually turn it over to the Strategic Planning Committee. (See SPP SPC Takes on Congestion Hedging Issues.)
That was when Altenbaumer stepped forward and suggested staff and stakeholders work together and reach consensus on how best to add CFO to the market. (See “Counterflow Optimization not Dead Yet,” SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
“There’s been no shortage of analysis. It’s simply a lack of consensus,” Altenbaumer said. “Lack of consensus doesn’t mean we have a lack of an issue. It’s reached a point where it doesn’t mean we should delay our concerns.”
Altenbaumer, who facilitated the Aug. 30 workshop’s panel discussions, alluded to the difficulties that still lie ahead for SPP’s staff and stakeholders.
“Facilitating this reminds me of a game show host,” he said. “I’m not sure whether it’s ‘Jeopardy,’ ‘Let’s Make a Deal,’ ‘The Price is Right’ or, God forbid, ‘Family Feud.’ We’ll see what happens when we get into this.”
That the positions in the opposing camps have only solidified quickly became evident. Some stakeholders say SPP’s congestion-hedging process is unfair and continue to ask for changes. Others says the status quo works for them.
John Stephens, who manages City Utilities of Springfield’s (Mo.) generation fleet and transmission system, said most market participants who nominate financial positions before transmission congestion rights (TCRs) are awarded are “absolutely happy” because they’re getting all of their nominated congestion hedges.
“This is not a complicated problem. There are a lot of details and we could spend hours and hours digging into those details, but essentially, we have 25 people in line, but we have 20 widgets to give away,” he said. “How we allocate those limited numbers of widgets is the problem in my mind. The first 20 guys in line are getting widgets, and the last five are not. We would like to see a more equitable process, where people get a similar percentage of the widget.”
Overview of SPP’s allocation process for auction revenue rights | SPP
“The main factors that have prevented stakeholders from moving forward is comfort with the status quo on a complex issue,” Southern Power’s Chase Smith said. “There’s the risk and uncertainty that is probably viewed by implementing something new and not completely understanding how it will impact each of the market participants. Some market participants are impacted by ARR [auction revenue rights] allocations more than others. There’s concern some moderate counterflows may impact the current congestion-hedging mechanism.”
“Unfortunately, the problem is that some people and their actions are not harmed directly by the actions of others, but the actions that they are taking or not taking is affecting someone else. And that’s hard to sort of grasp,” said Keith Collins, SPP vice president of market monitoring.
A consultant’s review last year determined market participants have too much latitude over the congestion-hedging process, staff said. It determined ARRs are set equal to transmission service rights requests, with 75 GW of candidate ARRs and a 50-GW nomination cap. The consulting firm found nomination patterns generally pursue highly valued paths, resulting in increased curtailments and asset owners leaving too much unclaimed monetary value.
Staff’s proposed solutions include aligning commercial and transmission models and using a planning feedback loop to provide a list of congested elements for considering in the planning processes. They said this will provide incentives for transmission expansion projects.
Under this proposal, SPP would also model load to ensure settlement locations, match network integrated transmission service agreements and model generators to better match candidate ARRs with generation in the day-ahead market.
Other proposals included:
adding an additional round to the long-term congestion rights process and allowing participants to keep their positions for a year;
baseload a percentage of the nomination cap for each participant based upon a ratio of every transmission service request’s path;
use CFO after the first round of the ARR allocation process, uplifting its cost to the market participants that opt in;
changing the nomination caps in the annual ARR process; and
limiting system capacity to 50% for each of the annual ARR and TCR process.
Stakeholders expressed their interest in further developing the alternative proposals, although there was pushback from those who have been heavily involved in the CFO effort.
“I certainly want to make sure what we’re doing is consistent with where we think we need to be in five, six or seven years downstream, and that we don’t put a Band-Aid on something that will certainly change,” Altenbaumer said. “We need to have a good understanding of the interdependencies. We don’t want to solve this problem in the marketplace if there are some options to develop strategic transmission that provides overall benefits to the system.”
“To the extent we need to run some of these ideas to ground, I think we can do that,” American Electric Power’s Richard Ross — chair of the Market Working Group that has been responsible for much of the development — told Altenbaumer. “I may perhaps be a little pessimistic, but I’m not sure that I’ve heard one [idea] that I feel like is going to minimize the impact on others quite as much as the option that we’ve been talking about for so long.”
SPP’s Micha Bailey, who conducted the workshop, said his concern remains future uncertainty.
“Look at the [generator interconnection] queue and look at all the solar and the batteries that are right behind [wind requests],” he said. “Once again, I wish I had a crystal ball. I wish I could say, ‘Look all y’all, we’re great. All y’all are protected.’ If we don’t work towards a solution together, it’s very bleak for me to say, ‘Hey, we’re in a good spot.’”
Refunds on Overlapping Congestion Charges
Staff also told stakeholders Wednesday during a Seams Advisory Group meeting that SPP and MISO will issue refunds in October to AEP and the city of Prescott, Ark., for overlapping congestion charges on pseudo-tied loads and resources between the two markets.
FERC approved a settlement agreement on Sept. 7. Under its terms, the RTOs will refund $142,768 to AEP and $53,017 to Prescott, split evenly between the grid operators (ER22-2221).
The commission opened an investigation in 2019 into the overlapping charges following complaints from AEP subsidiary Southwestern Electric Power Co. and Prescott that both the host and attaining markets were charging for congestion across the same transmission path. It accepted the RTOs’ proposed” predictive flow factor process” solution in December and directed them to refund the complainants. (See FERC Accepts MISO-SPP Congestion Charge Solution.)
SPP will recover its portion of the settlement payments through a revenue neutrality uplift from market participants that either provide generation, consume generation, have scheduled interchange transactions, or have virtual bids or offers.
The predictive flow factor process improves the exchange of market flow data and better predicts impacting market flows when determining relief obligations during market-to-market. The two RTOs have more than 2.7 GW in combined pseudo-tied generation or load.
ERCOT’s Technical Advisory Committee last week followed direction from the Board of Directors as it discussed proposed revisions to its membership qualifications and ways to accelerate the revision request process during its annual procedural and organizational review.
Acting at the behest of the board’s new Reliability and Markets (R&M) Committee, TAC’s members expanded a requirement that they have a combined five years of industry experience in regulatory, markets, operations and/or finance to include plant operations and energy procurement.
They agreed with a requirement that employers or sponsors certify that TAC members are authorized to make segmental decisions. A certification form has yet to be developed.
“The R&M wants people sitting on TAC to be qualified,” TAC Chair Clif Lange, with South Texas Electric Cooperative, said during the Sept. 12 virtual meeting.
Representatives from the Office of Public Utility Counsel and the residential consumer segment are exempt from the requirements.
Lange and Vice Chair Bob Helton, with ENGIE North America, also discussed a proposed “shot clock” for revision requests “languishing in the process” that would speed up their movement. The shot clock would be used for existing requests the Public Utility Commission has “explicitly stated” they would like moved forward. However, it can’t be used when an RR is first introduced at TAC’s Protocol Revision Subcommittee; urgent status is used in that instance.
The committee’s leadership is suggesting its procedures be amended so that a decisive vote must be taken at TAC or one of its subcommittees if requested by the RR’s sponsor or ERCOT. Failed votes would still be appealable through the normal appeals process.
Lange said the proposal was brought in August to the R&M, which approved of the direction.
“There are some details to work out,” he said. “This creates potentially a very clean way to move things forward without developing an alternative process.”
The Sierra Club’s Cyrus Reed, who does not sit on TAC, raised a concern over whether the revised process would violate administrative procedures rule. Staff pointed out that any proposals would have to go through the stakeholder approval process, allowing for further discussion then.
Lange and Helton told members that TAC will continue to report to the board its activities and decisions. The committee’s leadership will meet with the full R&M Committee to provide background on its decisions and counter positions. The board’s committees meet the day before full board meetings.
TAC’s membership will return with feedback on the proposals during its regular monthly meeting Sept. 28.
TAC Passes on Bylaw Changes
The committee also delayed discussion of proposed amendments to ERCOT’s bylaws until its Sept. 28 meeting.
The proposed changes, drafted at the board’s direction, would no longer require members’ approval of bylaw amendments. It would require that members be provided notice and the chance to comment on any proposed amendments or other “fundamental actions.”
Other changes would expand the directors’ ability to participate and vote by teleconference or similar means when an in-person quorum is achieved for their meetings.
Members have until Sept. 30 to comment on the revisions. The board plans to discuss the amendments when it next meets on Oct. 17-18.
The changes are a result of legislation passed last year after the February 2021 winter storm that shifted authority from market participants to the independent board.
ERCOT distributed a market notice with the proposed changes just before the close of business on Sept. 9, a Friday.
