Arizona regulators have granted a key approval to the SunZia Transmission project, Pattern Energy’s proposal for delivering wind energy from central New Mexico into Arizona.
The Arizona Corporation Commission (ACC) last week approved a certificate of environmental compatibility for the project, which will consist of two 525 kV transmission lines across a 550-mile corridor.
The lines are intended to send energy from the 3,500 MW SunZia Wind project, which Pattern Energy is looking to develop in central New Mexico, to population centers in Arizona. SunZia Wind will be the largest wind project in the Western Hemisphere, the company said in a release.
“SunZia is proof that New Mexico is leading the charge in the clean energy transition,” U.S. Sen. Martin Heinrich (D-NM) said in a statement.
The ACC approval completes the Arizona state permitting process for the transmission project. In addition, the New Mexico Public Regulation Commission granted two separate approvals — in May and in October — related to SunZia Wind, Pattern Energy said.
The company said it is awaiting approval from federal agencies, including the Bureau of Land Management, as well as local jurisdictions. Construction is expected to start in mid-2023.
Amendments Requested
The ACC originally approved an environmental certificate for SunZia Transmission in 2016. In May, SunZia Transmission LLC asked the commission to amend the approval. SunZia asked the commission to split its decision into two separate environmental certificates to allow separate ownership of each line. The move will facilitate financing.
SunZia also asked the commission to approve additional structure types and updated structure design for the project. In addition, the company asked to extend the time to complete the project, from February 2026 to February 2028.
Pattern Energy called the commission’s unanimous decision to approve the requests a “major milestone.”
Critics of the project said it would harm wildlife and questioned the benefit to Arizona, because New Mexico power would be sold to California, according to a draft order to approve the certificate.
A Pattern Energy spokesman said agreements are still being negotiated, so it’s too early to say how much of SunZia’s wind energy would go to California.
Regarding wildlife, Pattern Energy said previously that SunZia Transmission worked closely with wildlife conservation groups to analyze environmental impacts and find the best route for the transmission project.
Supporters of the transmission project pointed to the need for more renewable energy to combat climate change and the economic benefits the project would bring to rural Arizona.
“Our window to combat [climate change] by reducing greenhouse gas emissions is closing quickly,” Adam Stafford, Western Resource Advocates’ managing senior staff attorney in Arizona, said in a statement. “We need to take action now, and building the SunZia lines helps us move in the right direction.”
Kevin Wetzel, Pattern Energy’s senior director of business development, said the SunZia projects would “greatly benefit” Arizona. SunZia wind will complement solar energy produced in the state, he said, helping utilities and commercial customers reach their renewable energy goals.
In addition, “new transmission and diversified generation resources will improve overall WECC reliability and resiliency, which benefits all Western states, including Arizona,” Wetzel said in a statement provided to RTO Insider.
Project Acquisition
In July, Pattern Energy announced it had acquired SunZia Transmission from SouthWestern Power Group. Pattern Energy had previously been awarded the full 3,000 MW of capacity of the transmission line.
SouthWestern Power Group is retaining ownership of a second 500 kV transmission line, El Rio Sol Transmission.
Combined, the SunZia transmission and wind projects form the largest renewable energy infrastructure project in U.S. history, with a total investment of more than $8 billion. Both projects are privately funded.
After initial approval of SunZia Transmission, the route was adjusted in consultation with the Department of Defense and White Sands Missile Range. The modified route partially parallels the existing Western Spirit Transmission line for 35 miles, which reduces environmental impacts, Pattern Energy said.
California regulators on Wednesday released an updated proposal for bringing the state to carbon neutrality by 2045, incorporating changes such as boosting offshore wind development and moving toward net zero without new natural gas-fired plants.
The new version of the climate change scoping plan is a follow-up to a draft that the California Air Resources Board released in May. The CARB board is scheduled to vote on finalizing the plan during its Dec. 15-16 meeting.
The plan would rapidly shift the state away from fossil fuels and toward renewable energy and zero-emission vehicles. It would cut greenhouse gas emissions to 85% below 1990 levels and create 4 million jobs, the agency said.
Gov. Gavin Newsom called the plan “the most ambitious set of climate goals of any jurisdiction in the world.”
“If adopted, it’ll spur an economic transformation akin to the industrial revolution,” the governor said Wednesday in a statement.
CARB revised the draft scoping plan based on changes requested by the CARB board, by the agency’s Environmental Justice Advisory Committee and by Newsom. Other changes are in response to laws passed by the state legislature this year.
The plan calls for meeting the increased demand for electrification without new gas-fired plants, while maintaining reliability. It includes the development of 20 GW of offshore wind by 2045. Both strategies were requested by Newsom in July. (See Newsom Calls for ‘Bolder’ Climate Action in Calif.)
The scoping plan sets a goal of 6 million electric heat pump appliances installed in the state by 2030. All-electric appliances would be required in new homes starting in 2026 and in new commercial buildings beginning in 2029. Appliance sales for existing homes would be 80% electric by 2030 and all electric by 2035.
The plan relies on carbon removal and sequestration, which it calls “an essential tool to achieve carbon neutrality.” Carbon capture and sequestration would be used in sectors such as electricity generation, cement production and refining.
The plan is projected to reduce greenhouse gases by 48% below 1990 levels in 2030, surpassing a mandated 40% reduction by 2030.
The scoping plan is a framework for the state to reach carbon neutrality by 2045. But further action, such as the adoption of regulations, is needed to move toward the plan’s goals.
“Hitting the targets — from the required build out of renewable resources to putting tens of millions of zero-emission cars and trucks on our roads and highways — will require implementation on a very ambitious timeline,” CARB said.
David Weiskopf, senior policy advisor with NextGen Policy, said the plan’s ambitious goals have the potential to offer major benefits.
“But until we take action, it is just a report,” Weiskopf said in a statement. “It is our job as an advocacy community to turn seemingly impossible goals into realities and to prevent outcomes that continue the legacy of environmental racism at the hands of polluting fossil fuel companies.”
NEW ORLEANS — The 2022 annual meeting of the National Association of Regulatory Utility Commissioners covered ground on rate design, energy storage and reliability as the energy portfolio undergoes renovation.
The meeting, which began Sunday and concludes Wednesday, continued NARUC’s multiyear theme of innovative and disruptive technology and regulation.
“The energy transition poses the greatest threat to reliability,” said NERC Director of Legislative and Regulatory Affairs Fritz Hirst during a briefing Sunday on the reliability organization’s 2022 Winter Reliability Assessment.
Hirst called NERC’s summer assessment a “sobering report.”
“And the winter assessment is no exception,” he said, adding that a large portion of the country will confront reliability risks should severe winter weather strike.
Hirst said Texas, MISO, SERC and New England are particularly exposed to winter risk, due to generation retirements, fuel supply and generator vulnerability to the elements.
He added that the Pacific Northwest’s hydropower conditions have improved since last year and SPP has added enough natural gas and wind generation to manage winter resource adequacy, likely keeping them off the season’s hot seat.
Hirst said it’s “cold comfort” that the National Oceanic and Atmospheric Administration is predicting a mild winter for much of the country.
“It matters not what the predictions are because all it takes is a cold snap lasting several days in a region,” he said.
Hirst also said an ongoing nationwide shortage of transformers might mean longer restoration times. He said that though NERC cannot mandate resource adequacy, the “energy sufficiency challenge” is top of mind for staff. The agency’s consideration of a standard for forward-looking energy reliability assessments seeks to tackle the burgeoning issue, he said.
“The system needs flexible, dispatchable resources, whether that’s coal or natural gas,” Hirst said. “Natural gas is probably your best bet … and that will be the case until we have some breakthrough in storage at scale or in hydrogen.”
Michelle Bloodworth, CEO of coal lobbying group America’s Power, said she’s alarmed by the pace at which dispatchable resources are exiting the grid. She said operators are “vastly underestimating” the amount of coal resources poised to exit the system.
Utilities have announced the retirement of more than half of the nation’s 200 GW coal fleet by 2030, Bloodworth said. She said the industry should “do a better job of publicly recognizing” that coal resources have reliability attributes that are essential for the foreseeable future. America’s Power has filed a letter with FERC, asking the commission to acknowledge those attributes.
“Every coal plant that leaves puts more and more pressure on the natural gas system,” said Bloodworth.
She added that she hoped carbon capture and sequestration investments on the nation’s existing coal plants are given an assist by the Inflation Reduction Act.
“It takes time and sustained investment. We’ve seen more subsidies on the intermittent generation to date,” she said.
State regulators also wrung their hands over natural gas price increases.
During a Monday roundtable, Colorado Public Utilities Commission Chairman Eric Blank said customers will see increases north of 60% on the natural gas portions of their bills.
“It’s just enormous, enormous,” Blank said. “I would say the regulatory options are very limited. We’re just struggling.”
He said “it’s a lot more fun” to regulate when fuel prices are stable. He asked other regulators for ideas on limiting bill increases.
Regulators suggested prohibiting utilities from earning a return on natural gas power purchases, customer charge suspensions, and more robust energy efficiency programs that hedge high commodity prices.
Some regulators said while surging natural gas prices will strengthen some commissions’ commitment to electrification, renewable energy and hydrogen substitution, others will concentrate on how to blunt the price hikes.
“It’s going to be an ugly time for ratepayers in Georgia in the next few months,” Georgia Public Service Commissioner Tim Echols predicted.
“Is the final word from this session, ‘This job sucks?’” Blank joked. “Is that the takeaway?”
Rate Design Considerations
Debbie Lew, associate director of the Energy Systems Integration Group (ESIG), said zero marginal cost renewable resources and looming, immense electrification loads mean that regulators will have to introduce more dynamic pricing that incentivizes demand when supply is plentiful.
“New electrification loads are a double-edged sword — they can help or stress both the distribution and bulk power system,” Lew said during a Sunday panel. “We know we’re going to need more than time of use rates.”
But Lew said time-of-use rates are beneficial today. She said Sacramento Municipal Utility District’s TOU rate created on a $5 million investment averted the need for a new, more expensive 150-MW resource to meet peak demand.
Lew said if regulators want demand flexibility, they will need to expose some customers or load-serving entities to price signals that “reflect cost causation and grid needs.”
“If all demand were price-sensitive, we might not need … reserve margins. Obviously, we’re a long way away from that,” she said.
Brattle Group principal Sanem Sergici focused on electrifying heating with heat pumps. She called their adoption “a key component of state and city climate action plans” but said adoption hinges on their installation and operating affordability compared to natural gas.
Sergici said regulators must design new rate structures that balance customers’ payback periods, fixed charges and incentives under the IRA. She said it’s possible to use cost-based rates and avoid subsidies to foster heating electrification.
“With the right rate design, adoption is possible. It’s time to stop discouraging electrification of heating,” she said, adding that rate design can be “a constant evolution” if the bulk electric system becomes winter peaking.
Storage Makes an Entrance
Jason Burwen, American Clean Power Association’s vice president of energy storage, told regulators to expect 10 GW of new storage annually nationwide for the foreseeable future if transmission system planning is updated, regulatory and permitting processes are revamped, and supply chain issues stabilize.
He predicted the IRA will counteract some of the recent inflation-based price increases of storage facilities.
PJM Manager of Market Design Danielle Croop said PJM has 40 GW of hybrid generation projects and 54 GW of standalone energy storage in its interconnection queue. She said the amount of storage projects likely means that storage is becoming cost effective.
Greg Geller, Enel North America’s head of U.S. and Canada regulatory affairs, said storage is a key component of decarbonization plans. He said regulators can take three steps to stimulate storage additions: collaborate with utilities and grid operators, allow storage to compete to solve grid issues, and give consumers as much cost-causation transparency as possible so they can fire up distributed resources when they stand to save the most.
Geller said Texas, in particular, has an alluring regulatory environment. Enel’s storage projects in the state usually make it through the interconnection queue in one or two years, he said. Elsewhere, the wait is upward of three years. Geller said that storage solutions might help avoid decades-long stranded costs on more permanent assets.
BOSTON — Negotiations will continue on two Massachusetts offshore wind projects that developers have declared financially unviable.
Commonwealth Wind and Mayflower Wind in October requested the state Department of Public Utilities pause its review of the power purchase agreements they had struck with Eversource Energy, National Grid and Unitil for two planned wind farms. The developers said inflation, supply chain problems and other factors had altered the economics of the projects, which are rated at a combined 1.6 GW.
In a notice to the DPU on Nov. 7, Mayflower withdrew its motion to suspend review and said it will seek to resolve the financial issues through conversation with the state and the three electric distribution companies.
Commonwealth filed a similar notice Nov. 14, saying if the DPU would not support a pause, the appropriate course of action would be to continue with the proceeding and discuss contract changes or other ways to make the project financeable and economically viable.
Eversource, National Grid and Unitil told the DPU on Nov. 1 that they have no intention of renegotiating the PPAs.
Commonwealth, the larger of the two projects at 1.2 GW, is being developed by Avangrid (NYSE:AGR). In a statement late Monday, the company said, “We have been transparent and committed, at all times, to doing everything we can to move the project forward, including coming to the table with all parties to find a solution to the unprecedented economic challenges facing this major infrastructure project. …
“Ensuring Commonwealth Wind is able to move forward is squarely in the public interest and the best possible outcome for Massachusetts and its ratepayers, and we look forward to continued engagement so this project can deliver on its immense economic and environmental benefits and help the state achieve its ambitious 2030 climate target.”
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.”
