Municipalities across Pennsylvania have been charting their own course on climate and energy policy under divided federal and state governments, and while Democrats made major gains in the most recent cycle, Harrisburg could remain an uphill battle for the party’s priorities.
In Philadelphia, much of that effort has been channeled through a city agency created in 2010 to support affordability and sustainability amid concerns about electricity deregulation.
“We had to start it knowing we didn’t have a big source of federal funding or state funding,” said Emily Schapira, CEO of the Philadelphia Energy Authority (PEA). “We had to develop projects that could be financeable and could be budget neutral for the city and the school district.”
The authority has since launched about a dozen programs and in 2016 set a 10-year goal of $1 billion invested in clean energy citywide and the creation of 10,000 jobs. Schapira said the authority has so far invested $291 million through public-private partnerships and created 2,500 jobs.
Much of that work has taken the form of energy efficiency upgrades in city buildings, schools and low-income housing restoration programs. In some cases, such as the transition to 140,000 LED bulbs for street lighting, the long-term energy savings are being used to pay for the upfront capital costs of the initiatives. Workforce development programs and one of the nation’s first solar vocational high school curriculums have allowed the city to doubly benefit by keeping the labor for these projects local.
The authority additionally created a green bank last year to attract further private investments in energy efficiency, renewable energy and resilience projects, including its Solarize Philly initiative, which provides free assessments and discounted installations. Across its efforts, the PEA has assisted in the installation of 1,200 rooftop solar installations in the city.
Schapira said the authority designed many of its programs to be easily shared with other municipalities, including the software management systems it created to track funding sources. One of the biggest challenges it has found is that federal, state and local funds are often provided in isolation and with conflicting data sharing restrictions or requirements, an issue the software attempts to alleviate.
“We’ve really designed everything to really be scalable and replicable,” she said. “That’s a model that can be easily shared.”
In Pittsburgh, the Sustainability & Resilience wing of the Department of City Planning has been making progress on its Climate Action Plan goals for 2030. The city’s goals also call for reducing emissions from transportation by 50% and the Pittsburgh International Airport went live with a solar- and natural gas-powered microgrid last year.
Governor-elect Shapiro Promotes “All-of-the-above” Energy Policy
Many of the initiatives being undertaken in Philadelphia mirror the goals Democratic Governor-elect Josh Shapiro laid out in his “all-of-the-above” approach to energy policy. In a June overview of his economic priorities, Shapiro pushed for legislation to generate 30% of the state’s energy with renewables by 2030 and to set a goal to reach net zero by 2050.
His approach promised to marry investments in developing clean energy generation, while maintaining “responsible fracking” — which could include expanding no-drilling zones and strengthening health guidelines. Shapiro’s campaign did not return requests for comment following Tuesday’s election.
After the state joined the Regional Greenhouse Gas Initiative last April, Shapiro questioned the effectiveness of the multistate agreement and said he would have to further consider the impact to the economy and workers before pledging to continue the state’s participation. Even with his support, the implantation of RGGI has been held up by Republican objections in the state courts.
Equinor and bp have created a fund to help pay for workforce development and support community-empowerment aspects of New York’s nascent offshore wind industry.
The companies are partners in the Empire Wind and Beacon Wind projects planned for construction off the coast of New York. They announced the fund Tuesday with the New York City Economic Development Corp. and the Sunset Park Task Force.
The Offshore Wind Ecosystem Fund will help fund job education and training; bring employment and small-business opportunities to historically marginalized communities; and help bring minority- and women-owned business (M/WBE) enterprises into the burgeoning industry.
State law mandates 9 GW of offshore wind capacity be installed by 2035, and some scenarios being considered would entail 20 GW installed by 2050.
Brooklyn’s Sunset Park neighborhood will be a focal point of the offshore wind initiative, as a staging and assembly port is built there, and there is a concerted effort to offer the people who live there a chance to benefit from the development.
“The Offshore Wind Ecosystem Fund is bringing an integrated approach to environmental justice in Brooklyn,” Borough President Antonio Reynoso said in a news release. “Not only will these grants accelerate our clean energy efforts, but they will also open up green careers to new generations and empower small businesses owned by minorities, women and service-disabled veterans to participate in the offshore wind industry.”
Amanda Farias, chair of the City Council’s Economic Development Committee, said: “I am excited to see the attention that the NYCEDC, Equinor and the Sunset Park Task Force are paying to the intersectional needs of our workforce. To recover equitably, we must put our Black, brown and minority communities first. This grant does just that by making sure our offshore wind sector is focusing on M/WBEs, [service-disabled veteran-owned businesses] and environmental justice communities.”
Doreen Harris, CEO of the New York State Energy Research and Development Authority, said: “This Ecosystem Fund will support communities like Sunset Park with a pathway to provide historical knowledge and local expertise for workforce training and development initiatives — and guide community investments that will best serve their neighborhoods and the broader development of offshore wind projects.”
CHARLESTON, S.C. — Offshore wind and transmission developers say the states that are driving project development need to lead on the transmission side by collaborating to build an offshore grid.
That was the consensus that seemed to form at the Business Network for Offshore Wind OSW Grid & Transmission Summit last week as attendees brainstormed the most cost-effective way to interconnect the massive amounts of offshore wind states are procuring to meet their decarbonization goals.
The summit was held over two days at the Francis Marion Hotel to discuss strategies for offshore transmission development, mostly on the East Coast.
Rather than the typical format for an energy conference, the Business Network tried something different for the first day: a marathon series of discussions among the audience, mostly about the offshore wind industry’s dream: a “backbone” transmission line along the East Coast, from Maine to Florida, connected to the onshore Eastern Interconnection and allowing offshore wind projects to “plug and play.”
Such a “mesh-ready” system would save all stakeholders — states, developers, utilities and ratepayers — money on costly onshore transmission upgrades and allow projects to provide more capacity, speakers said.
The discussions were held under the Chatham House Rule: Attendees were free to use the information but not to reveal who provided it at the meeting. (As such, RTO Insider can not quote anyone who spoke.) Jason Gershowitz, principal at Kearns & West, lightly guided attendees as they traded tales of their experiences getting their projects built — the challenges, setbacks and successes. They also debated what is needed going forward and offered solutions for observed problems.
Also in attendance were state and federal officials charged with implementing their governments’ goals, as well as European developers.
What played out was an exercise in problem solving among players in a nascent industry still struggling to find its sea legs.
Bottom-up Collaboration Needed
The problems with offshore transmission development are similar to those onshore in the U.S.: diverse state policies and goals; clogged supply chains; different standards and rules in each grid operator; and opposition by not-in-my-backyard residents.
While FERC has instituted several proceedings seeking to encourage interregional transmission development onshore and make it easier for generators to interconnect to the queue, it has not sought an active role in offshore transmission. Judging by several comments at the conference, that isn’t necessarily desired. Though attendees did not come to any hard solutions, they agreed that there needs to be a bottom-up approach among stakeholders, not a top-down mandate from the federal government.
Currently, each state that is procuring offshore wind is soliciting transmission solutions on its own. There seemed to be some reluctant acceptance among attendees that the New Jersey Board of Public Utilities’ recent selection of the Larrabee Tri-Collector Solution — which will only involve onshore transmission upgrades and a new substation — was the state’s only real option given the costs of offshore transmission and lack of proposals for an offshore backbone. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
States are also very protective of the benefits that will come with the projects, especially the construction, manufacturing and shipping jobs, and they are competing among themselves for manufacturing and logistics hubs at their ports. Several attendees suggested pressuring states to put aside competition and collaborate on building an offshore grid that would benefit all involved. The states could form a coalition, laying out a clear goal and agreeing to share costs.
Others suggested that the three grid operators along the East Coast — ISO-NE, NYISO and PJM — come together, perhaps with a “nudge” from FERC, to independently plan an offshore grid. Still, states would need to play a key role in pushing the RTOs and FERC to work together. Here the challenge is a lack of consistency — as well as the inevitable difficulty of getting three different stakeholder bodies to reach agreement.
Still others suggested that wind developers themselves should collaborate among themselves rather than wait for the state governments to fix things for them. Developers could propose joint transmission solutions that incrementally build the backbone.
Several Europeans in attendance seemed bewildered that U.S. states with similar clean energy policies, such as those in New England, could not come together like countries in the North Sea — such as Belgium, the Netherlands, Germany, Denmark and Norway — which recently committed to building an offshore network in the sea by 2050.
Not Enough People
The attendees also discussed the lack of workers to fill all the open positions in the offshore wind field.
The industry began by picking off workers from the offshore oil and gas industry for their expertise in ocean construction and operating marine vessels. It then began enticing more with promises of training for industry-specific jobs.
Now that that labor pool has been exhausted, several attendees noted, developers are recruiting workers from competitors with hefty signing bonuses.
Attendees said there needs to be more engagement with students in high school and lower grades to encourage them to study electrical engineering and other related fields in college. One attendee, however, noted that it’s difficult to get children excited about infrastructure.
NEW ORLEANS — The Joint Federal-State Task Force on Electric Transmission’s fifth meeting since its inception last year featured dialogue on local project review, cost management and FERC’s notice of proposed rulemaking on regional transmission planning, cost allocation and cost containment (AD22-8). (See States Urge More Transparency on Tx Planning, Independent Monitors.)
FERC Chairman Richard Glick opened the task force’s discussion Tuesday during the National Association of Regulatory Utility Commissioners’ annual confab by noting there is a lot of “costly” transmission on the horizon.
“So, we need to make sure that consumers get the best bang for their buck,” he said.
Jason Stanek, chair of the Maryland Public Service Commission, said even if the task force already had managed to achieve consensus on a planning approach and cost allocation methodology, cost management and project review would still be issues.
“What I’ve been hearing is something is lacking, something is missing in this process,” FERC Commissioner Willie Phillips said of transparency in proposing and reviewing local transmission projects.
Phillips said it’s “interesting” that states seem unable to replicate the results of utility planning studies, especially since FERC requires them to do so.
Glick said the depth and breadth of regulatory gaps depend on the type of project and whether they’re located in an RTO. But he said a great number of local projects don’t appear to have a “sufficient level of review.”
“It’s not easy to determine whether a decision is right, especially when there’s a lack of transparency in the process,” he said.
Pennsylvania Public Utility Commissioner Gladys Brown Dutrieuille said only projects 101 kV and above that require new siting are subject to intensive review in the state. She said over the last several years, her commission has seen big increases in smaller and rebuild transmission projects that are handled by staff and don’t require a thorough review.
California Public Utilities Commissioner Darcie Houck said that most of PG&E’s billions of dollars in planned projects through 2026 will fall under CAISO’s category of self-approved projects that bypass review.
“We’re seeing the same trends,” Michigan Public Service Chairman Dan Scripps said. He admitted that he isn’t yet sure who should provide project oversight and said it might be some combination of FERC, the states and grid operators. He also said should the federal agency introduce independent transmission monitors, it should take care to make sure it doesn’t slow project development.
Phillips said FERC also must ensure that an independent transmission monitor doesn’t create an incentive for utilities to leave RTOs.
Review Tied to Formula Rates?
FERC Commissioner Mark Christie said some projects are scrutinized at the state level while others get by without oversight. He pointed out that while FERC cannot prescribe projects, it does wield control over formula rates. The commission could condition its formula rate treatment on whether a project has undergone a credible, state-level review, he said.
“And we’ll let the states tell us if it was credible,” suggested Christie, adding that FERC could apply the question to multiple states for interstate lines.
Christie said the national transmission rate base has increased 9% or more for the third year in a row.
“What goes into rate base goes into customers’ bills — every nickel,” he said.
Stanek said he didn’t think states, which are “perpetually” underfunded and understaffed, should be tasked with undertaking project prudency studies on the bulk power system. He said such analyses would be too complex and expensive.
“I think Commissioner Christie is on the money that formula rates are an incentive. They’re a carrot,” said Matthew Nelson, chair of the Massachusetts Public Utilities Commission. He said he supported the idea of “step-down” return on investments, where cost overruns would trigger reduced rates.
FERC Commissioner Allison Clements said the task force might consider creating a standardized data collection from transmission developers across all 50 states. She asked what happens if FERC discovers a state doesn’t have a credible project review process.
Christie suggested commissions call on expert RTO witnesses to testify on the prudency of some proposed projects. He reminded regulators that utilities bear the burden of demonstrating that a project is necessary before state commissions.
Kansas Corporation Commissioner Andrew French said establishing independent transmission monitors would be most helpful for local projects. He said large projects subject to regional cost sharing already are sufficiently inspected by parties that stand to pay.
French said at present, transmission owners can easily finalize local and replacement projects that maintain a status quo system.
“There just isn’t an incentive to [propose] an optimal solution,” he said, adding that commission staffs need help understanding the pace of investment and whether transmission owners are engaging in optimal planning.
However, Georgia Public Service Commissioner Tricia Pridemore, who replaced former Arkansas regulator Ted Thomas on the task force, denounced a “top-down” level of review. She said Georgia has a solid planning process that invites economic development, and it has never experienced a major blackout.
Glick countered that there has been a “ballooning” of local projects and some attention on them would be worthwhile.
“It might be that non-RTO states have sufficient authority,” he said.
In a Monday keynote during the NARUC meeting, Clements urged thoughtful, low-regret transmission planning so customers don’t experience “wild jumps” in the transmission component of their bills.
Clements said FERC commissioners could issue hundreds of pages of cost-management decrees and “sit very smugly,” but if states and utilities don’t think the resulting cost containment rules are fair, they will be pointless.
She said the commission is laying crucial groundwork to get new infrastructure built: “To me it’s not so much as an ambitious agenda as it is an imperative need.”
Clements repeated the industry adage that the transmission system is on the cusp of a buildout like that of the nation’s highway system in the mid-1950s. She said the key to mitigating widespread extreme weather events is to have an interconnected transmission system greater than the size of the weather patterns.
She pointed out that interconnection queues are brimming with projects waiting for grid treatment.
“Right now, we’re looking at twice as much generation than exists on the transmission system today trying to get on,” Clements said.
She said federal and state regulators should help utilities ensure the most efficient use of the existing system through dynamic line ratings and other grid-enhancing technologies,
“Now is the time to do it, since we’re thinking about larger investments in backbone transmission,” she said.
However, Clements said she understands grid operators’ hesitation to introduce system stressors with new transmission technologies. She said control room operators are understandably cautious and protective of system reliability and that FERC is trying to land on “the least scary way” to introduce new technologies.
“If the speed limit is 60, and it’s a nice day in April, maybe go 75,” Clement said. “But if it’s February and icy, go 40. Make the system better and smarter, and I think that’s a great analogy.”
State Rights of First Refusal and Order 1000
A Tuesday NARUC panel deliberated on which is worse: FERC’s failed attempt at competition under Order 1000 or the ensuing wave of state rights of first refusals for incumbent utilities.
Former FERC commissioner Tony Clark, now an adviser with Wilkinson Barker Knauer, said some prefer continued transmission development under monopolies rather than a “complex bidding process that doesn’t work” under Order 1000.
“The state ROFRs are the symptom, but Order 1000 is the disease,” Clark said. “I think we ought to admit that this is an industry that naturally trends toward a natural monopoly.”
Devin Hartman, R Street Institute’s director of energy and environment, said consumers could potentially save several billion dollars with competitive solicitations. He said consumer groups and grassroots movements are organizing to fight state ROFR laws.
Hartman said there’s “no economic reason” to reinstall a federal ROFR.
Ten states have enacted ROFRs: Indiana, Iowa, Michigan, Minnesota, Montana, Nebraska, North Dakota, Oklahoma, South Dakota and Texas.
Four other states have considered such laws: Colorado, Kansas, New Mexico and Wisconsin.
A consumer collective has filed a joint complaint at FERC against MISO’s practice of respecting state ROFR laws in its regional transmission planning and cost allocation (EL22-78). (See Consumer Groups File FERC Complaint Against MISO.)
Wisconsin Public Service Commissioner Ellen Nowak, whose state discussed a bill that ultimately didn’t pass, said viewing the issue as a debate between competition and full regulation is a “false choice.”
“It hasn’t played out as we have expected,” Nowak said of competitive processes in practice. “The sticker price looked good, but then there’s a lot of little exemptions that have to play out.”
“States want control over who is building critical infrastructure in their state… It’s not putting up another Dunkin’ Donuts; it’s critical infrastructure,” Nowak said, explaining that states need trusted utilities. She said incumbent utilities are still beholden to a transparent process, and they can be subjected to cost caps.
However, Nowak predicted that the bill will again be introduced during Wisconsin’s next legislative session.
“ROFRs are anti-competition laws,” said Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative. “This is benefitting the largest incumbents. I’m not sure who else benefits from this.”
Stakeholders in New York are challenging a proposed revision to PJM’s tariff that they say could saddle them with some of the $1.07 billion New Jersey regulators have agreed to pay for transmission upgrades to accommodate the Garden State’s offshore wind projects.
The PJM Transmission Owners filed a proposal Aug. 19 to assign the costs of the transmission upgrades to New Jersey ratepayers on a load-share ratio basis, and provided additional information, in response to a FERC deficiency letter, on Oct. 5 (ER22-2690).
The TOs’ filings prompted a protest Oct. 31 by Long Island Power Authority, New York Power Authority and three merchant transmission facilities, Neptune Regional Transmission System, Linden VFT, and Hudson Transmission Partners (filing as the “MTF Parties”), who said the tariff change could lead to cost assessments on parties outside of New Jersey, in violation of PJM’s State Agreement Approach. The SAA allows states to sponsor transmission to support their public policy needs while requiring them to pay 100% of the costs. (See NJ BPU OKs $1.07B OSW Transmission Expansion.)
The MTF Parties said they were alarmed by the TOs’ response to the deficiency letter, which suggested they could face costs if FERC rejects an uncontested settlement in a separate dispute over revisions to PJM’s border rate, which has not been increased since 2004 (ER19-2105). (See Settlement Hearing Set for PJM Border Rate Dispute.)
Linden said the proposed changes would increase its border rate charges from $6.1 million to about $16 million annually, leaving it insolvent or forcing it to change its business model. Under the settlement, the border rates would more than double over seven years but with discounts for customers using transmission paths from PJM to the three MTFs. The settlement, which was certified as uncontested in December 2021, awaits commission action.
In their response to FERC’s deficiency letter in the SAA docket, the PJM TOs stated that “even if the commission declines to approve the border rate settlement and at some point in the future the revenue requirement of projects constructed under Rate Schedule FERC No. 49 is included in the border yearly charge, it would constitute only a very small fraction of the border yearly charge applicable to point-to-point transmission service with a point of delivery to an MTF.”
The MTF Parties asked FERC to revise the SAA cost allocation provisions to require that cost responsibility apply only to firm point-to-point transmission service within New Jersey “for the delivery of energy to, and consumption of such energy by, native load customers within the state of New Jersey.” It also requests that language be added that precludes border of PJM service customers from being assigned any cost responsibility
“The commission must further make clear that border rate service is excluded from cost responsibility for the NJ-SAA projects — and that principle and commitment by the NJ BPU cannot be undermined by indirect means,” they said.
The New Jersey Board of Public Utilities and the TOs responded to the MTF protest Nov. 10, saying the issues they raised are speculative and out of scope.
The BPU said “that if the MTFs believe that the current border rate tariff provisions may inappropriately allocate a small portion of public policy project costs to them, they should address those concerns in a separate proceeding rather than delay approval of the proposed methodology for allocating the direct costs of SAA projects.”
The 660-MW Hudson Transmission project connects PJM and New York City, providing power for customers of the NYPA. | Hudson Transmission Partners
The TOs said that when SAA projects are complete, they become a part of the PJM’s integrated transmission system and border rate service does not reflect the cost of individual Regional Transmission Expansion Plan projects.
“When voluntarily requesting border rate service, the MTF Parties are paying, through the border yearly charge, for the support provided by the entire PJM transmission system to enable their export transactions — they are not paying for the costs of specific RTEP projects’ construction for which cost responsibility has been assigned to responsible customers,” the PJM TOs said.
The 660-MW Hudson Transmission project connects PJM and New York City, providing power for customers of the NYPA. Neptune operates a 660-MW 65-mile undersea and underground HVDC line from Sayreville, N.J. to Nassau County, Long Island under a long-term agreement with LIPA. Linden VFT delivers power from its only customer, PSEG Energy Resources & Trade, to its facilities near the PJM border.
$400M Reduction in Capacity Costs?
During a Nov. 4 PJM Transmission Expansion Advisory Committee special session, Committee Chair Suzanne Glatz said the RTO anticipated a resolution of the SAA revisions in October but that the deficiency letter and subsequent filings have extended that timeline to December.
PJM’s TEAC presentation estimated the installation of 7,500 megawatts of offshore wind, with a 2,370-MW unforced capacity rating, could reduce the cost of capacity sold in the 2028/29 Base Residual Auction by as much as $400 million. The estimate relies on a set of assumptions including the 2023/24 BRA market offers and associated price mitigation rules, planning parameters remaining similar, and a 2028/29 load forecast from the RTEP study.
With those assumptions, the estimate found an expected $1,007,908,145 in capacity sold with no addition of offshore wind and $612,091,604 sold with the addition of the project and corresponding transmission upgrades. Each of the three alternative scenarios considered for the upgrades had approximately the same estimated impact.
PJM cautioned that the figures it presented are not projections of future market prices and were produced to compare the impact of the transmission studies.
“The market analysis simulations were performed as a potential factor in differentiating between the transmission solutions proposed and not for the purpose of projecting or forecasting future market performance. Our intent was to compare transmission solutions; the key takeaway is that the difference in market performance between the transmission solutions studied was negligible,” PJM wrote in an email.
Neptune operates a 660-MW 65-mile undersea and underground HVDC line from Sayreville, N.J. to Nassau County, Long Island under a long-term agreement with LIPA. | Neptune Regional Transmission System
Glen Thomas, president of PJM Power Providers, said in an interview that the PJM markets have demonstrated the ability to “absorb significant amounts of new generation,” however he’s concerned about the possibility for the OSW to bid into the BRA for the 2025/26 delivery year, the earliest the project is expected to come online, and construction delays resulting in that capacity not being available when the year comes. In his opinion, the project should not be permitted to participate in BRAs until there’s a “reasonable assurance” that they’ll be available on time.
“These projects tend to come in behind schedule and when you have a three year forward capacity market that’s hard, because they have to know in [2022] if they’re going to be available in [2025/26],” he said.
SACRAMENTO, Calif. — The need for new transmission to transport clean energy across the West was a key theme of this year’s CAISO Stakeholder Symposium, which returned in person last week to the Sacramento Convention Center Complex after a three-year hiatus.
Solar power from the Southwest, hydropower from the Northwest, and wind from Wyoming and New Mexico will need to flow to California and other states with clean-energy goals in the coming years, panelists said.
“That resource diversity is extremely valuable to the Western Interconnection,” said Maury Galbraith, executive director of the Western Interstate Energy Board. “Transmission is the technology that allows us to leverage that geographic diversity. Transmission is what allows generation and electrons to flow from low-priced areas to high-priced areas and allows us to spread out surpluses and fill in the deficits.”
That will require regional planning of transmission to facilitate market transactions, such as those in CAISO’s interstate Western Energy Imbalance Market (WEIM), he said. The ISO already has been incorporating that need into its transmission planning, Galbraith said, “but I don’t think it’s yet taken over the rest of the West.”
In the future it will have to, he said.
Neil Millar, CAISO vice president of infrastructure and operations planning, said the ISO has had to plan for transmission both internally and externally because of the state’s clean-energy and electrification mandates.
“Five years ago, we were actually dealing with forecasts for transmission planning of flat or even negative load growth,” Millar said. “Now, we’re looking at some of the steepest load-growth forecasts we’ve seen in 15 years. A lot of that is from the emergence of electrification, not only transportation but other industries, that’s driving the requirements, as well as the need to clean the grid in general.”
Until two years ago, CAISO’s 10-year transmission plan, which is updated annually, anticipated the addition of 1,000 MW of new resources per year, he said. This year’s plan projects 4,000 MW of new resources per year, and the “draft portfolios for next year are looking at about 7,000 MW of installed capacity a year,” he said.
California needs the new resources, including solar and storage, to maintain grid reliability while meeting its 100% clean energy mandate by 2045.
CAISO’s first 20-year transmission outlook, published Feb. 1, projected the need for lines traveling from wind farms in Wyoming and New Mexico and a 200-mile undersea line to carry offshore wind from far Northern California to the San Francisco Bay Area. In-state lines to move renewable generation from rural areas to urban load pockets also must be built, CAISO said.
Panelists said a major problem will be who pays for interregional transmission lines.
“Everybody wants to go to heaven, and nobody wants to die when it comes to cost allocation,” said Scott Bolton, senior vice president of transmission and market development at PacifiCorp, prompting laughter.
PacifiCorp’s sprawling footprint in the West allows it to build long-haul transmission lines to benefit its own customers, he said. Going forward, utilities like PacifiCorp will need to justify transmission that serves multiple jurisdictions, including CAISO.
“And so, as Maury hits on, which frankly is an underpinning theme of this whole symposium, the emergence of markets needs to become a much more robust part of that analysis,” he said.
PacifiCorp and others will need to “be able to show … that this additional transmission capability being built by others [in the West] contributes to a more robust platform for trading [and] for being able to transact in energy in ways that will lower power costs and be able to deliver those savings to retail customers, just by different means than what we’ve traditionally demonstrated,” he said.
The benefits will have to exceed the $3 billion already achieved through the WEIM since it started in 2014, he said. CAISO’s proposed extended day-ahead market (EDAM) for the WEIM could amplify those benefits.
“We will have to be able to … better optimize the system and lower those production costs and lower the power costs that customers experience,” Bolton said.
“If coordinated right, it should provide those additional benefits beyond just reliability and meeting load growth,” he said. “That’s where the markets discussion is so exciting because it does introduce an opportunity, frankly, to monetize that transmission for customers who are supporting that investment and to really get paid back on that increased market activity [by using] transmission more efficiently and much more dynamically.”
A U.S. bankruptcy judge on Monday approved a settlement agreement between ERCOT and Brazos Electric Power Cooperative and the co-op’s exit plan from Chapter 11 bankruptcy, resolving a dispute over $1.89 billion in market transactions during the February 2021 winter storm.
Chief Judge David Jones, with the U.S. Bankruptcy Court for Southern Texas, said the exit plan was “so much better” than he had expected.
Under terms of the settlement, ERCOT will receive $1.4 billion. Brazos will pay $1.15 billion up front and then make annual payments to ERCOT of $13.8 million for 12 years. The cooperative will also contribute about $116 million from the sale of its generation assets to fund payments through ERCOT for market participants still short from transactions during the week of the storm. (See ERCOT, Brazos Reach Agreement in Bankruptcy Case.)
Brazos agreed to sell its generation assets and transition to a transmission and distribution utility. It owns about 4 GW of natural gas-fired capacity (21-30725).
The cooperative declared bankruptcy in the wake of the winter storm after being billed for $2.1 billion in wholesale prices. ERCOT later revised the amount due to the market to $1.89 billion.
ERCOT said it completed its economic and other principles in the deal. They included avoiding a default uplift to the market; immediate recovery from Brazos of $599.7 million in congestion revenue rights to fully replenish CRR funds and pay down securitization bonds; and ensuring the cooperative is no longer a financial counterparty or a CRR account holder in the market.
“Brazos will no longer be a financial counterparty with ERCOT again,” Chad Seely, the grid operator’s general counsel, told Texas regulators during a Nov. 3 open meeting.
ERCOT said Brazos has indicated the first payments will be made to ERCOT by February.
Summary of market participants’ election to recover short pay from Brazos | ERCOT
The grid operator distributed 755 election notices to market participants that gave them four options to recover their allocable portion of the Brazos short pay claim. Most (51.39%) selected the “accelerated cash” recovery option that will result in a 65% nominal recovery after 12 years, but with 43% of that coming on the effective date. Another 41.85% of the market participants chose “convenience cash” option, which results in a 63% nominal recovery on the effective date.
The 15 market participants who did not make a selection were given a 100% nominal recovery option that will take 30 years.
PJM last week defended the proposed capacity auction parameters in its quadrennial review before FERC against two protests from the generation sector (ER22-2984).
The major changes proposed in the quadrennial review filing include shifting the reference resource from a combustion turbine to a combined cycle generator, updating the calculation of the gross cost of new entry (CONE), revising the adjustment of CONE in the years between reviews, steeping the variable resource requirement (VRR) demand curve, and shifting from a historical energy and ancillary service (EAS) offset calculation to a forward-looking approach.
The changes detailed in the Sept. 30 filing would be effective for the 2026/27 Base Residual Auction, scheduled for November 2023. The PJM proposal was endorsed by the Markets and Reliability Committee with limited support at its Aug. 24 meeting over stakeholder and Independent Market Monitor proposals. (See No Consensus on PJM Capacity Parameters.)
P3 Protests Transparency, VRR Curve and Forward-looking EAS
The PJM Power Providers Group (P3) argued that the proposed changes in PJM’s filings are not just and reasonable because of insufficient transparency in the data and models used to derive the market parameters. It also said the adoption of a steeper VRR curve will disincentivize construction of new generation needed for reliability.
In the shift to a future-looking EAS, PJM would rely on “paywalled” data from private exchanges and proprietary algorithms, which P3 argued obscures the mechanisms of the market, while historical prices are a “reasonable proxy for future prices” and are easily calculated and understood.
“As currently structured, this information will not be available, and therefore, it will be challenging, if not impossible, for stakeholders (whether supply or load) to fully understand how future revenues are being calculated. The ‘black box’ approach to such a critical component of future capacity market performance will inject needless uncertainty into decisions related to future investments in PJM,” P3 said.
It also argued that shifting the reference resource to a combined cycle generator will increase volatility in the capacity market by further exposing it to the fluctuations in fuel prices.
P3 President Glen Thomas said in an interview that together, the changes would increase capacity market volatility, curbing investment in generation.
“When you go to [combined cycle], you’re going to expose your reference technology to those vagaries, which is going to expose net CONE to significant shifts, which will lead to significant swings in capacity prices. Yes, our organization represents suppliers, but ultimately they’re going to be more motivated by stability and predictability; it’s tough to sell investors on boom-bust markets, which is exactly what this capacity market is heading towards,” he said.
Thomas noted that PJM President Manu Asthana made remarks at the Organization of PJM States Inc. Annual Meeting and the RTO’s own Annual Meeting that laid out reliability concerns over the next decade should the introduction of renewables lag behind growing load. Thomas said those concerns clash with the RTO’s proposed changes in the capacity market.
J-Power Critiques Amortization Period
The central argument of the second protest, from J-Power USA, is that PJM’s calculation of the gross CONE could create a scenario where the combined cycle reference unit cannot be constructed in some regions without having a lifespan shorter than the 20-year amortization period because of climate legislation. It referenced the Illinois Climate and Equitable Jobs Act (CEJA), which requires that all generating units reduce carbon emissions to zero by 2045.
J-Power posits that PJM should create adjusted CONE values for the Commonwealth Edison locational deliverability area (LDA) that reflect the possibility for shortened unit lifespans in that region.
“Reliability requires the CONE values for any modeled LDA to reflect the realities faced by developers of the new resources or owners of existing resources,” J-Power wrote. It added that PJM therefore “has an obligation to reflect the reduced asset life due to CEJA in ComEd when applying the CONE values to modeled LDAs.”
PJM Defends Proposed Changes
PJM argued that the forward-looking EAS offset and the methodologies used in both its derivation and the calculation of CONE are commonplace in the practices of market participants and have precedent in past FERC orders.
Shifting to a forward-looking offset can better “reflect the expected range of possible supply, demand and export conditions prevailing in future delivery periods,” PJM said, while a historical lookback can create “disequilibrium” under certain circumstances. The response gives the example of a lookback at a period of scarce supply, which would create a high EAS offset, reducing net CONE and scaling down the VRR curve, ultimately leading to less capacity being purchased when more is needed.
Because the market data and algorithms PJM is seeking to use under the proposal can be purchased for use by anyone, and they are already in widespread use, the RTO argued they are sufficiently transparent.
PJM also defended the proposed shift to a combined cycle reference unit by noting that no combustion turbines are currently under construction and none have been built since 2018.
“The proposal to move to a CC reference resource is consistent with current generation development trends, offers flexibility in operational parameters and produces net CONE reflecting the most economic technology. These results depart significantly from the findings underlying the 2018 quadrennial review,” PJM said.
In regard to J-Power’s concern about a 20-year asset life, PJM argued that it would be inappropriate to make “one-off” adjustments to an LDA through the quadrennial review.
Two Western governors speaking at the COP27 climate change summit said they see U.S. states leading the federal government in tackling climate change measures on the ground.
Washington Gov. Jay Inslee and New Mexico Gov. Michelle Lujan Grisham, both Democrats, shared their views during two panel discussions at the summit being held in Sharm El-Sheikh, Egypt.
Inslee said the states are positioned to move faster on climate change measures than the federal government.
“There’s nothing wrong with that,” he said.
Those measures include permitting, distributing grants and attracting the right skills to the appropriate alternative energy ventures within a state.
“None of this gets done until you get the state really engaged,” Inslee said.
States currently face a shortage of staff to handle the permitting of new alternative energy resources. “The least romantic thing in the climate change environment … is getting enough people to run the permitting process,” Inslee said, adding that he plans to seek extra money from Washington’s legislature in its 2023 session to hire the needed permitting staff.
New Mexico Gov. Michelle Lujan Grisham | U.S. Climate Alliance
Grisham said individual states need to coordinate with each other to develop similar regulations governing matters related to climate change and the environment.
She cited New Mexico and Texas as an example. Eastern New Mexico and West Texas share the same aquifers and are both homes to oil fields, but New Mexico does not allow drilling into freshwater aquifers, while Texas does. That leads to Texas drilling into aquifers it shares with New Mexico, hampering the latter state’s environmental goals.
“We need to think of this like an interstate highway. Everything has to be connected,” she said, but coordinating regulations is difficult.
The federal government can help states meet their objectives through the provision of tax credits, the two governors said. Grisham said appropriations from the Inflation Reduction Act provide extra money to the states, which encourages them to try out new climate change measures. “The legislation makes every governor and policymaker less risk adverse,” she said
Inslee added that even the most seemingly benign climate measures will encounter pushback, citing Washington residents who object to the visual impacts of proposed solar and wind farms. “The NIMBYism we face will be prolific,” he said. (See Hearing Shows Solar Conflict in Sun-soaked Eastern Wash.)
Inslee argued that this issue, along with improving permitting, needs to be addressed soon. “We do not have time for 10-year arguments,” he said.
The Pennsylvania Public Utility Commission is reviewing the state’s cybersecurity regulations for utilities, with the goal of identifying whether they need to be revised to “address public utility fitness in the current and anticipated future cybersecurity threat landscapes.”
In a 5-0 vote Thursday, the PUC agreed to issue an Advance Notice of Proposed Rulemaking regarding two main groups of cybersecurity regulations: those that govern reporting of cyberattacks, and those related to self-certification. The ANOPR seeks comments from industry stakeholders, including regulated utilities, advocates and members of the public, regarding whether the existing regulations need to be revised.
Pennsylvania’s self-certification regulations, introduced in 2005, require jurisdictional utilities in the state “to develop and maintain written physical, cyber security, emergency response and business continuity plans to … ensure safe, continuous and reliable utility service.”
Entities that are counted as “jurisdictional utilities” include public electricity and gas utilities — along with public telecommunications, water, and steam utilities; air transportation utilities; motor vehicle common carriers; and railroad carriers — but not non-public electric and gas suppliers.
The cyberattack reporting regulations likewise apply only to public electric, gas, water, and steam utilities. They require affected utilities to report any physical or cyberattacks that cause an interruption of service or over $50,000 in damages, or both. The $50,000 threshold was chosen because the PUC considers it “high enough to prevent reporting minor everyday occurrences but still [allowing] the PUC to have knowledge of incidences that result in a significant expense.”
Self-Certification Leads Concerns
The ANOPR listed several potential justifications for revising both sets of regulations, mostly in the realm of self-certification.
First, the age of the existing regulations means that since they were drafted the list of cyber threats facing utilities has “increased in number, type, and sophistication.” For example, ransomware attacks, in which an aggressor threatens to delete important data or reveal embarrassing information to the public, have targeted critical infrastructure in recent years to a degree that was not anticipated in 2005. In addition, as public utilities integrate their information technology (IT) and operational technology (OT) systems, the risk that adversaries will be able to disrupt operations has grown as well.
The PUC noted that “industry and government have continuously reviewed, expanded, and improved cybersecurity standards for entities of all kinds,” pointing to the National Institute for Standards and Technology’s (NIST) cybersecurity framework as a “model and a process to increase cybersecurity maturity in any organization.” It also held up NERC’s Critical Infrastructure Protection (CIP) reliability standards as an illustration of a “prescriptive” approach to addressing “the evolving nature of cyber-related threats to the bulk power system.”
The ANOPR suggests that the PUC has “at a minimum, five potential regulatory approaches to ensure that public utilities have adequate cybersecurity plans in place,” including:
a similar approach to existing regulations that would see the PUC set criteria for utilities’ cyber plans and require entities to report that they have such plans and are updating them annually;
having entities self-certify that they have plans that comply with appropriate federal or industry standards;
requiring utilities to have a third-party certify that it has a plan that complies with relevant federal or industry standards;
modifying the PUC’s public utility management audit process to include onsite reviews of cybersecurity plans and programs; and
requiring public utilities to file confidential copies of their cybersecurity plans and procedures with the PUC so that it can comment on their adequacy and require modifications where needed.
Stakeholders are asked to comment on the “relative merits and weaknesses” of each approach and which one, or combination, would best address the cyber threat landscape. In addition, the PUC asked for comment on whether the self-certification provisions should be expanded to include other types of entities besides public utilities, and whether some public utility types should be wholly or partially exempt from the requirements in order to ease their regulatory burdens, or for other reasons.
Reporting Criteria Updates
The requested comments on the cyber reporting regulations mainly relate to the type of incidents that the PUC expects utilities to encounter in the future.
Commissioners believe the current standards “focus on interruption of service” — and therefore utilities’ OT networks — “as a criterion for reporting.” But with IT and OT systems increasingly integrated, there is growing risk that cyber threats affecting the IT environment will create disruptions in the OT space as well. As a result, the PUC has a vested interest in having “advance warning of threats emerging in the IT environment.
The commission is seeking comment on how it might revise the reporting criteria to bring in new requirements for reporting IT incidents, along with the relevance of the $50,000 threshold for damages. Noting that the regulations currently do not address several elements of a potential cyberattack, including how damages should be attributed, when the damages calculation should be performed and how the availability of insurance should be factored in, the PUC asked whether the threshold should be revised or done away with.
Finally, the PUC is wondering whether it should merge the self-certification and reporting requirements. Commissioners suggest that bringing all of the PUC’s cyber regulations together would give utilities a single point of reference and help eliminate “unintended or unjustified inconsistencies in the existing regulations.”
Comments on the ANOPR are due 60 days after its publication in the Pennsylvania Bulletin.
