Tri-State Generation and Transmission may finally have in place exit procedures for members leaving the cooperative, but regulatory roadblocks remain for the contract termination payment (CTP) methodology.
FERC issued an order Oct. 29 accepting the co-op’s proposed methodology effective Nov. 1, subject to refund, and rejecting nearly a dozen protests from members. However, the commission said its preliminary analysis indicates that the methodology has not been shown to be just and reasonable and established hearing procedures to address issues not in the record (ER21-2818).
The commission also opened a Federal Power Act Section 206 proceeding so it can establish a just and reasonable CTP-calculation methodology and just-and-reasonable procedures for Tri-State’s utility members to obtain the CTPs and withdraw in an orderly manner. It encouraged the hearing’s presiding judge to expedite the hearing where feasible “to facilitate the … resolution of these longstanding disputes.”
Tri-State’s first CTP methodology filing was submitted in April 2020. FERC accepted it subject to refund but also established hearing and settlement judge procedures. The process was repeated several times as the co-op filed policies and other calculation methods in response to member protests.
In May, FERC rejected the CTP methodology without prejudice, leading to Tri-State’s latest filing in September. Many of the complaints centered on members being able to see the calculations. (See FERC Rejects Tri-State Exit Fee Proposal.)
FERC said Tri-State’s newly proposed procedures allowing members’ access to the modified CTP methodology “appear to satisfy a number of the commission’s concerns.” The co-op proposed providing CTP calculations annually to all utility members at no charge by April 1, whether or not the member intended to withdraw from Tri-State.
Members seeking to terminate their wholesale electric service contracts (WESCs) and co-op membership must provide a two-year advance notice of their intention and pay its CTP to Tri-State on the withdrawal date.
“These procedures are clear and transparent,” the commission wrote.
FERC, however, disagreed with Tri-State’s claims that a CTP methodology must be based on a lost-revenues approach to be just and reasonable. It also said it shared protesters’ concerns that additional mitigation efforts could be used to decrease revenues that the co-op would otherwise be losing upon a member’s exit.
“While we disagree with some of the positions being taken by select parties, we appreciate FERC providing the opportunity for broader participation by all interested members in the case,” Tri-State CEO Duane Highley said in a statement last week. “We welcome the continued engagement of our membership, and we will continue to work to ensure that all members, large or small, have a voice that is heard on these important matters.”
The co-op said the modified CTP tariff ensures remaining members are held harmless if another member decides to terminate its contract early and includes “clear, transparent and objective procedures.”
“At the same time, we are mindful of the questions and concerns expressed by the commission … and will do our best to address them through the hearing process,” Tri-State said.
Tri-State has 45 members, including 42 utility distribution cooperatives and public power district members in four states that supply power to more than 1 million electricity consumers across nearly 200,000 square miles of the West.
The American Council on Renewable Energy held its annual Grid Forum over two days last week. As was the case last year, it was a completely virtual event because of the ongoing COVID-19 pandemic.
The first day of the event, Wednesday, focused on infrastructure policy, transmission planning and energy markets, while Thursday featured discussions on the Biden administration’s agenda.
FERC Commissioner Mark Christie on Wednesday compared the transition to clean resources in the electricity industry to the transition to mobile devices in telecommunications.
The former chair of the Virginia State Corporation Commission, Christie also taught regulatory law at the University of Virginia School of Law. Every year he would ask his students how many of them had a land-line telephone, and every year fewer of them would raise their hands, until the last couple of years, during which not one hand would go up.
But the very last year he taught, one student did raise their hand.
FERC Commissioner Mark Christie | ACORE
“‘So you have a land line?’” Christie said he asked. “And the student said, ‘Well, what is a land line?’”
Regulating the telephone industry is very similar to regulating electric utilities, going by Christie’s description: Smaller companies would file complaints against the incumbent utilities because they were not interconnecting their services. Meanwhile, the utilities need to file rate cases with the state commission for approval.
By the end of his career at the SCC, however, the commission had not reviewed a telephone utility’s rate case in years. “The law hadn’t changed; the technology had changed,” he said. “Wireless technology eliminated” the natural, networked monopolies held by telephone utilities. “And it didn’t happen because of smart regulators. It happened because smart engineers in a lab figured out how to transmit [voice data] wirelessly on a mass scale at a cost that consumers could afford.”
Distributed energy resources — particularly battery storage combined with rooftop solar — could do the same thing in the electricity space. Disputes over net metering rates would “all go away,” Christie said.
“These are the kinds of technologies [that] I’m really optimistic will be transformative. And the challenge is to make sure the regulatory structures are either not behind or not ahead but try to get a rational connection to this transformational technology that I know we’re going to see.”
ANOPR
Rob Gramlich, president of Grid Strategies, moderated a panel on FERC’s Advance Notice of Proposed Rulemaking on transmission planning.
The panelists reiterated a consensus among many commenters in the ANOPR docket that transmission planning in the U.S. is reactive to generator interconnection requests, the queues for which are backlogged because transmission construction is not keeping up. The ANOPR presents an opportunity for FERC to create a forward-looking approach, they said. (See Transmission Industry Hoping for Landmark Order(s) out of FERC ANOPR.)
“We’re not really planning for the future now, which sort of raises [the question of] why do we even call it transmission ‘planning’ if it’s not about the future generation,” Gramlich said.
He asked Danielle Fidler, senior attorney with Earthjustice, how she would respond if the D.C. Circuit Court of Appeals questions FERC’s authority “to require these plans and allocate these costs so broadly” under a potential final rule. “Where does that come from?”
“Congress in 1935,” Fidler responded laughing. “The Federal Power Act gives FERC really broad authority … and not just authority but obligation to regulate the transmission system. … So in our view, FERC not only should act; it must act.”
An attendee asked about the timeline of the proceeding, specifically whether the commission would wait for the findings of a joint task force with the National Association of Regulatory Utility Commissioners.
Elizabeth Salerno, FERC’s lead for transmission and technology initiatives, could not say when the commission would act, but she did say that “there’s a sense of urgency to start chipping away at the block. The scope of the ANOPR is huge. I think it’s possible we can’t solve all this in one go. There is a consideration of [if we] try to break these up into pieces and tackle them in a logical order. I’m not sure that’s how we’ll go, but I think that option is on the table.”
Gramlich concluded the panel by speaking to the high expectations of the transmission industry for the proceeding. “I spent a couple years of my life on another major rulemaking that never got finalized, so the last thing I want is for all this work to go in” and nothing to come out of it, he said.
Western RTO, SEEM Face Headwinds
A panel Wednesday devoted to the expansion of wholesale markets in the West and the Southeast shared their thoughts on the possibility of future RTOs but had few answers.
Consultant Rebecca Wagner, a former member of the Nevada Public Utilities Commission, noted the alphabet soup of Western markets and organizations, including CAISO’s EIM and proposed EDAM, SPP’s WEIS market and RTO West, the Northwest Power Pool’s WRAP and the Western Markets Exploratory Group (WMEG). (See Western Utilities to Explore Market Options.)
“There’s always something going on in the West,” she said. “There’s a lot of places to plug in to.”
Rebecca Wagner, Wagner Consultants | ACORE
Wagner said she hopes that, given Western states’ climate and clean-energy policies, a clean, reliable and affordable grid of the future can be built that unlocks resource diversity and maximizes customer benefits.
“There’s a lot of movement. I’m not sure how it’s going to shake out,” she said.
Colorado Public Utilities Commission Chair Eric Blank said an incremental approach makes the most sense for his state in the near term. The legislature has directed the state’s utilities to join an RTO by 2030 — similar to Nevada legislation — and a regulatory study found that participation in a regional market could yield a 5% cost reduction off $6 billion in revenues, or about $300 million a year, he said.
“There are significant unresolved concerns with RTOs: struggles to ration rare interconnects for resources; fights over cost allocation limiting new transmission; challenging governance structures,” Blank said, pointing to SPP’s four-year backlog in its generator interconnection queue. “For us, we need to see either CAISO’s governance improve or SPP solve its interconnection and cost allocation problems.”
She said SEEM is “closer to a bilateral market than anything else,” lacks transparency and is not open to independent power producers.
“It’s being pitched as a software upgrade, rather than physically calling people on the phone,” she said. “It’s not a stepping-stone to competition like we’re seeing in Nevada and Colorado.”
In a report on market design and the Southeast, ACORE said, “Absent many traditional market benefits, SEEM is not necessarily a step toward a wholesale power market, but its introduction provides a helpful lens through which to assess energy market design and the Southeast.”
Biden’s Agenda
On Thursday, Kelly Speakes-Backman, principal deputy assistant secretary for the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy (EERE) spoke with ACORE CEO Gregory Wetstone about the Biden administration’s clean energy goals.
Kelly Speakes-Backman, DOE | ACORE
Speakes-Backman, previously CEO of the Energy Storage Association, oversees her office’s $2.8 billion portfolio of research and development, demonstration and deployment activities in energy efficiency, renewable energy, and sustainable transportation.
“We’re focused on supporting President Biden’s clean energy goals of … achieving a carbon-free electric sector by 2035 and [a] clean-energy economy with net-zero emissions no later than 2050. …
“President Biden placed this particular goal at the center of his agenda, and we know that we are kind of the tip of the spear, if you will, for that. So in order to really sort of support that, in driving research and development, but even more so the demonstration and the deployment of these technologies, we’re really underscoring the fact that this is going to create jobs and economic opportunity. Yes, the climate crisis is an enormous challenge. … But we also see this as a huge opportunity to create millions of good-paying, middle-class jobs, to ensure that there’s clean, affordable, reliable energy options for all Americans.”
Environmental Justice
Thursday’s first panel, “Centering Environmental Justice in the 21st Century Grid,” dealt with the impact of grid investments on low- and moderate-income communities.
Yvonne McIntyre, NRDC | ACORE
Yvonne McIntyre, director of federal electricity and utility policy for the Natural Resource Defense Council, moderated a panel that included Jahi Wise, senior adviser for climate policy and finance in the White House Office of Domestic Climate Policy.
McIntyre asked Wise about Biden’s executive orders to implement his Justice40 Initiative, intended to ensure federal agencies work with state and local governments to “make good on President Biden’s promise to deliver at least 40% of the overall benefits from federal investments in climate and clean energy to disadvantaged communities,” according to the White House.
“It’s historic in its scope and scale and trying to orient the federal government around equitable investment in climate and clean energy infrastructure,” Wise said. “Folks who are in this space for a while know that’s not the way that things have historically gone, so the intentionality there is unprecedented.”
Jahi Wise, The White House | ACORE
About 20 federal government programs are covered by the initiative, he said, “and right now those programs are working through their stakeholder engagement plan, their initial implementation and kind of paving the way for the rest of the federal government to begin this investment process. And so we expect in the next few months to see even more programs join that cohort but also more from the initial set of programs.”
He said that Biden “directed a number of White House components and agencies to put out environmental justice scorecards, and so those scorecards are supposed to be like our first accounting of whether or not we’re actually meeting our targets on environmental justice as a component of climate policy. And that will look at everything from Justice40 to the different environmental justice offices at the agencies. So there’s kind of a really robust, whole-of-government effort on this topic.”
The California Public Utilities Commission adopted criteria Thursday allowing it to hold Pacific Gas and Electric (NYSE:PCG) more accountable for starting wildfires or undermining reliability with public safety power shutoffs.
PG&E’s failure to meet the 32 new safety and operational metrics can serve as triggering events in the CPUC’s enhanced oversight and enforcement process. Established as a condition of the utility’s bankruptcy reorganization last year, the six-step process involves increasing oversight and penalties, potentially culminating in the revocation of PG&E’s operating license.
“Each step is triggered by a specific finding or specific events, and the triggering mechanisms include a failure to make specific, sufficient progress on the metrics that we’re adopting today,” Commissioner Clifford Rechtschaffen said of the plan. “It’s a very important part of making sure that we can implement this unique six-step enforcement framework, which we think is very important to holding PG&E accountable.”
PG&E is currently in the first step of the process for failing to prioritize vegetation management around power lines in high-risk fire areas. A tree falling on a PG&E line is suspected of this summer’s immense Dixie Fire. (See CPUC Applies Stricter Oversight to PG&E.)
In August, CPUC President Marybel Batjer warned PG&E it could face additional oversight.
“I have directed California Public Utilities Commission staff to conduct a fact-finding review regarding a pattern of self-reported missed inspections and other self-reported safety incidents to determine whether a recommendation to advance [PG&E] further within the [CPUC’s] enhanced oversight and enforcement process is warranted,” Batjer said in a letter to PG&E CEO Patti Poppe. (See CPUC, Judge Pressure PG&E to Clear High-Risk Lines.)
The new and updated metrics adopted Thursday include injuries and deaths among members of the public caused by PG&E operations, the frequency and duration of unplanned outages, and the number of fire ignitions in high-risk fire areas.
Another factor is the impact on reliability of PG&E’s public safety power shutoffs (PSPS). The intentional blackouts are meant to prevent fires, but PG&E has been criticized recently for using PSPS too often and without warning customers. (See PG&E Expects $1B in Costs from Dixie Fire.)
Starting in March, PG&E must file reports every six months with the CPUC that include data for each metric, a description of progress toward its safety targets and proposed methods for remedying deficiencies.
The measures are part of the CPUC’s Safety Model Assessment Proceeding (S-MAP), a means of applying risk-based, outcome-driven criteria to large investor-owned utilities through their general rate cases. The CPUC on Thursday added metrics for Southern California Edison, San Diego Gas & Electric and Southern California Gas to consider when investing in infrastructure and operations.
“Transparent, risk-based investment decision-making approaches better inform the CPUC and interested parties in evaluating how energy utilities assess, manage, mitigate and minimize safety risks,” the commission said in a statement.
FirstEnergy (NYSE:FE) on Sunday announced $3.4 billion in new equity financing investments from two global investors that the company believes will position it for a long-term earnings-per-share growth rate of 6 to 8%.
The company announced that it will issue $1 billion in common equity to New York City-based Blackstone Infrastructure Partners (NYSE:BX) at $39.08/share and appoint a Blackstone representative to its board of directors no later than its next annual meeting.
FirstEnergy further announced that it had agreed to sell a 19.9% minority interest in its transmission subsidiary First Energy Transmission (FET) to Toronto-based Brookfield Super-Core Infrastructure Partners (NYSE:BAM) for $2.4 billion in cash.
FET is a holding company for FirstEnergy’s three FERC-regulated transmission subsidiaries that operate 24,000 miles of high-voltage power lines across six states. The sale of a minority interest in FET to raise cash has been under discussion for several months.
Under questioning from analysts at FirstEnergy’s third-quarter earnings call two weeks ago, CFO Jon Taylor described the interest in FET as “very strong, and preliminary indications are very supportive of our financial plan and targets.”
The sale, subject to FERC approval and review by the Committee on Foreign Investments in the U.S., is expected to close in the first half of 2022, FirstEnergy said.
The company believes the transactions will enhance its credit profile, which was recently returned to investment-grade, and provide enough cash to address all of its needs for new equity now and in the near future. The company is planning major grid upgrades.
In a statement accompanying the news of the equity sale and minority interest sale, FirstEnergy CEO Steven Strah called the two agreements “key catalysts to fulfill our long-term strategy and drive smart grid and clean energy initiatives for our customers and communities.”
Donald T. Misheff, non-executive chairman of FirstEnergy’s board, said, “The entire board, including our voting and non-voting members, unanimously supports these important actions.
“This represents a pivotal moment in the company’s trajectory and positions FirstEnergy to drive shareholder value.”
The Texas comptroller’s office said last week the financial fallout from February’s Winter Storm Uri could be as high as $130 billion, as earlier estimated by the Federal Reserve Bank of Dallas.
Texas Comptroller Glenn Hegar said in October’s Fiscal Notes report that the storm resulted in between $80 billion and $130 billion in financial losses to the state’s economy.
Glen Hegar | Texas Comptroller
The Dallas Fed estimated the losses based on “a result of power loss, physical infrastructure damage and forgone economic opportunities.”
The storm knocked out power for nearly 70% percent of Texans and disrupted water utilities, leaving many Texans without heat or running water for extended periods. The state has also attributed 210 deaths to the storm.
“The exact impact on Texas energy customers is still difficult to discern,” the comptroller’s report said. “What we do know is that all major sources of energy in the state experienced failures.”
According to the report, the Texas A&M AgriLife Extension Service assessed agricultural losses at more than $608 million and ranchers’ economic losses at nearly $228 million. The service also estimated citrus farmers’ losses of at least $230 million.
500 MW to Depart Market
ERCOT will lose almost 500 MW of capacity if the cities of Austin and Garland suspend operations at two aging resources.
Austin Energy said last week it will retire its 44-year-old Decker Creek 2 natural gas-powered generator after the winter season. The utility said the unit has “aged past its useful life” and has become more expensive to operate. It submitted a notice of suspension of operations (NSO), effective March 31, 2022, to ERCOT on Nov. 1.
The Austin City Council in 2017 approved Decker 2’s retirement as part of a comprehensive resource plan and reaffirmed that decision in March 2020. The plant’s four 50-MW peaking gas turbines will continue to operate.
On Thursday, Garland Power & Light also filed an NSO notifying ERCOT that the utility will indefinitely suspend operations at a 78-MW gas turbine at its Ray Olinger power plant. The unit dates to 1967.
Market participants have until Nov. 29 to submit comments before the ISO makes a final decision on the NSOs.
The House of Representatives’ Friday night passage of the bipartisan Infrastructure Investment and Jobs Act (H.R. 3684) quickly set off a chorus of praise from clean energy groups and equally fervent calls for both of houses of Congress to finish the job by passing Democrats’ $1.75 trillion budget package, the Build Back Better budget bill.
Parsing the $1.2 trillion in the infrastructure bill, many of the groups zeroed in on the specific provisions and programs for which they had lobbied hard during negotiations in the House and Senate.
A statement from the Alliance to Save Energy (ASE), for example, included a fact sheet with a detailed listing of the bill’s energy efficiency provisions that it had supported, such as Section 40502’s allocation of $2.5 billion over five years for commercial and residential energy audits, with up to 25% going to low-income homeowners. Section 40503, also supported by the alliance, follows up with $40 million over five years for energy auditor training programs.
“While at times the Washington gridlock can feel insurmountable, [Friday’s] votes show that Congress still has the keys,” ASE President Paula Glover said. “This is a moment to celebrate: lawmakers saying ‘yes’ to a more efficient energy future, ‘yes’ to a more consumer-friendly energy system and ‘yes’ to a robust clean energy workforce.”
But Glover also pledged continued action on Build Back Better, to ensure “the final version fully recognizes that efficiency is the fastest, most cost-effective method to decarbonize our economy.” ASE is pushing for restoration of a tax credit to help homeowners pay for energy-efficiency upgrades, she said.
The final vote Friday was 228-206, with 13 Republicans joining all but six Democrats in support. The latter are progressives who had wanted a simultaneous vote on the budget. The trade-off to get the vote on the infrastructure bill was a subsequent procedural vote setting up the budget vote for mid-November, pending an analysis from the Congressional Budget Office that some moderate Democrats had held out for to ensure the bill is completely paid for.
Speaking on Saturday, Biden framed the infrastructure bill’s passage as a big step for the U.S. to deliver on its carbon reduction commitments made at the U.N.’s 26th Conference of the Parties (COP26) in Glasgow, Scotland, last week, and to assert its leadership in global clean energy markets.
“It will get America off the sidelines on manufacturing — manufacturing of solar panels, wind turbines, battery storage, energy and power for electric vehicles from school buses to automobiles,” he said.
Biden also noted he had not signed the bill immediately over the weekend because he wants to have the Democratic and Republican lawmakers who negotiated the package at the ceremony. It should occur “soon,” he said.
The top line figures for the bill, as reported by Axios’ Sarah Mucha and Andrew Solender, include $73 billion for grid infrastructure, and $7.5 for transportation electrification split evenly between EVs and chargers, low-emission buses and ferries.
A major portion of the bill’s spending covers more traditional infrastructure, for example, to fix the country’s aging roads and bridges ($110 billion), water infrastructure ($55 billion) and rail ($66 billion).
On the more nontraditional side, broadband gets $65 billion, while $47 billion in “resiliency” spending targets flooding, wildfires and coasts.
Getting ‘Steel Underwater’
While $73 billion in grid infrastructure spending looks impressive, Rob Gramlich, president of Grid Strategies, cautioned that the bill’s allocations for new transmission are considerably less, with most of the money going to upgrades and improvements on existing lines.
For new construction, the Department of Energy gets $2.5 billion to support new, non-federal transmission projects by entering into capacity contracts or providing loans to developers, according to Gramlich’s analysis of the bill. DOE’s Smart Grid Investment Matching Grant Program gets $3 billion, which can be used for the purchase and installation of grid-enhancing technologies.
Another key provision requires DOE to consider the integration of renewable energy resources and lower costs to consumers when designating transmission corridors of national interest. It also allows FERC to issue permits for construction or modification of certain interstate transmission facilities if a state commission denies or fails to process an application seeking approval for the siting of such transmission facilities.
The 30% transmission investment tax credit in the Build Back Better bill is probably going to be the main catalyst for new projects, Gramlich said. But he said the funding in the infrastructure bill is a strong signal to developers to begin planning for the buildout of transmission, including for offshore wind.
“With some of these loans and grants, we could go to … the states from Mid-Atlantic through New England and say, ‘Hey, you have 30 GW of offshore wind [planned], but nowhere near the transmission needed to collect it [and] bring it to shore. How about we use some of these new loans and grants?’” Gramlich said in a phone interview with RTO Insider. “We’ll pay for some of it through federal dollars if the states and RTOs can agree on allocating the rest of the costs.”
While getting to “steel underwater” might take a while, he said, the funding “might be the critical link needed to get everybody together to do what’s needed by the end of the decade.”
Urgency to Decarbonize
A sampling of other energy provisions in the 2,740-page bill includes:
$500 million through 2026 to help states develop energy conservation plans that incorporate transmission and distribution planning, as well as broad vehicle electrification to reduce carbon emissions in transportation sector.
$140 million for a demonstration project for the mining and refining of rare-earth minerals, using feedstock from mine wastes and drainage, and another $3 billion to be used for grants to support advanced battery manufacturing and recycling. This section also calls the departments of the Interior and Agriculture to work on streamlining permitting for the mining of rare-earth minerals on federal land.
more than $300 million through 2026 for grants to carbon-utilization projects, and another $100 million in the same time frame to support the design and development of carbon transport systems.
more than $3.2 billion for DOE’s advanced nuclear demonstration projects through 2027, and $6 billion, split over five years, to support continued operations at existing nuclear plants threatened with closure.
“As the urgency to decarbonize grows, the next generation of nuclear reactors is essential to reaching our ambitious climate goals,” said Maria Korsnick, president and CEO of the Nuclear Energy Institute. “Through continued support for nuclear energy innovation and funding of the Advanced Reactor Demonstration Program, Congress has signaled its commitment to accelerating the deployment of innovative reactor technologies over the next decade while bolstering U.S. technological leadership globally.”
Similarly, Madelyn Morrison, external affairs manager for the Carbon Capture Coalition, said the bill’s carbon capture provisions mark “a major step forward in fostering economywide deployment of carbon management technologies to achieve net-zero emissions by midcentury, while ensuring the long-term viability of key domestic industries and safeguarding high-wage jobs that sustain families and communities.”
The bill’s support for offshore wind is more indirect, according to Liz Burdock, CEO and president of the Business Network for Offshore Wind, pointing to its investments in the grid, ports and innovation research. But, Burdock said, “achieving the ambitious offshore wind goals set by the Biden administration requires accelerating the development of a local supply chain as explosive growth in global markets draws investors’ attention away from the American market.”
The next step is passage of Build Back Better, she said, “which includes mission-critical investments in U.S. manufacturing and component development, further port investment and expanded transmission funding. All elements are critical for the full deployment of offshore wind in the U.S.”
Despite the House vote on Friday setting up possible passage for mid-November, the budget bill must still navigate continued in-fighting among House Democrats and further trims and revisions by conservative Democrats in the Senate. But the Democrats’ electoral losses last week in Virginia and narrow gubernatorial victory in New Jersey have increased the pressure for action. (See related story, GOP Wins in Va. Raise Questions About State’s Climate Policy.)
Answering a reporter’s question Saturday on the elections, Biden said, “The one message that came across was: ‘Get something done. It’s time to get something done. You all stop talking. Get something done.’”
Dominion Energy (NYSE:D) said Friday the projected cost of its 2.6-GW Coastal Virginia Offshore Wind (CVOW) project has increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.”
The company announced the projected cost increase on the day it reported a near doubling of third quarter profits and filed a request for approval and certification of the CVOW project with the Virginia State Corporation Commission.
In September 2019 Dominion announced a “pre-engineering” estimated cost of about $8 billion.
“Since that time through the process of detailed engineering and, most importantly, through competitive solicitations for all components and services, we’ve now developed a detailed budget of approximately $10 billion,” CEO Bob Blue told analysts during the third quarter earnings call. “The cost increase can be attributed to, among other things, commodity and general cost pressures — as seems to be the case across a number of industries right now — and the completion of the conceptual design phase for the onshore transmission route.”
Blue said the company has meet the three tests required for Dominion to qualify for cost recovery via a rider on customers’ bills: using competitive procurements; a projected levelized cost of energy (LCOE) below the $125/MWh maximum set in the Virginia Clean Economy Act (VCEA), and a projected start to construction before 2024.
Dominion asked the SCC to classify many of the details of its filing as “extraordinarily sensitive,” citing the commercial value of its negotiated contracts and terms with vendors. The filing includes information on “costs, contractor selection, project components, transmission routing, capacity factors and permitting.”
The company said the filing keeps it on its scheduled timeline to leap from its current two-turbine, 12-MW pilot project in federal waters off Virginia Beach to the planned 2.6 GW wind farm.
Last December, Dominion submitted the plans for the larger project to the Bureau of Ocean Energy Management, which is expected to complete an environmental study and reach a decision by June 2023. The company is also expecting a final order approving the project from the SCC in the third quarter of next year. If all goes as planned, onshore construction will begin in the third quarter of 2023, followed by offshore construction in the second quarter of 2024 with construction finished in late 2026.
The company says the project will create approximately 900 jobs and have $143 million in economic impact annually during construction, increasing to approximately 1,100 jobs and almost $210 million in economic impact annually during its operation. On Oct. 25, Siemens Gamesa held a ceremony at the Portsmouth Marine Terminal celebrating the launch of the first offshore wind turbine OEM blade manufacturing facility in the U.S. The plant’s initial output will go to the Dominion project. (See Virginia Builds out OSW Supply Chain with Turbine Blade Plant.)
News of CVOW’s $1.8 billion cost increase sparked criticism on social media. A ProPublica-Richmond Times-Dispatch investigation last year reported that Dominion lobbied for changes to the VCEA that increased the maximum cost of CVOW from $7.3 to $9.8 billion.
“Dominion lobbyists snuck in an extra $2 billion on the wind cost cap in the VCEA at the last minute. Now all of the sudden their costs include an extra $2 billion…?” tweeted Brennan Gilmore, executive director of Clean Virginia.
“Lo and behold: The ceiling for rate base is the price of the project,” responded former Montana regulator Travis Kavulla, now vice president of regulation for NRG Energy (NYSE:NRG).
Blue said the LCOE of the offshore wind farm is estimated at $87/MWh but could be reduced to $80/MWh if Congress approved proposed OSW tax credits included in the $1.8 trillion spending bill pending before the House. (See related story, Energy Groups Quick to Praise Infrastructure Bill Passage.)
Although construction costs are higher than anticipated, Blue said that — based on data from the pilot turbines — the company now assumes a lifetime capacity factor of 41.5% for CVOW, up from an earlier estimate of 43.3%.
When asked about the potential impact of the Republican victory in last week’s Virginia elections on these plans, Blue said Dominion Energy “has maintained constructive relationships with members of both parties,” and that there is “a bipartisan commitment to jobs and economic growth.” Referring to the Siemens Gamesa announcement, he added: “Both parties deserve credit for that kind of job creation in Tidewater Virginia. We would expect that that’s going to continue going forward.”
Dominion Energy also recently filed a rider with the Virginia SCC that included about 1,000 MW of solar and battery storage, Blue said. The company expects a final order from the agency for this project, with its planned $1.4 billion capital investment, by the second quarter of next year.
Q3 Results
In addition to highlighting its offshore wind and solar projects during the earnings call, Dominion officials said that the utility company is nearing its pre-pandemic normal in electricity sales.
The company expects to see electric sales in its Virginia and South Carolina service territories rise by 1% to 1.5% per year, similar to growth rates before COVID-19 struck, CFO Jim Chapman said.
Dominion Energy reported $654 million ($0.79/share) in net income, nearly double the $356 million ($0.41/share) in the third quarter of 2020.
Chapman said the company expects to grow its earnings per share at a rate of at least 6.5% annually through 2025, thanks to a $32 billion, five-year growth capital plan, more than 80% of which is focused on decarbonization. Going forward, he added, investors should expect to see “compelling earnings and dividend growth combined with the largest regulated decarbonization opportunity in the industry, and an unyielding focus on extending our track record of successful projects, regulatory and financial performance.”
Assuming normal weather for the rest of 2021, the company says, it expects full-year results to be above the $3.85/ share midpoint of its 2021 estimated guidance.
The SCC is due to review a comprehensive settlement agreement in the company’s pending triennial base rate case, now that stakeholders have weighed in. Blue said a decision is expected by the end of the year. If the commission approves it, the agreement will resolve the ongoing review of the company’s earnings over the past four years, while generating $330 million in one-time refunds on customer bills, a $309 million offset as part of the Customer Credit Reinvestment Offset (CCRO) mechanism, and a $50 million rate reduction going forward. The CCRO “offsets the customer bill credit amount that the utility has invested or will invest in new solar or wind generation facilities or electric distribution grid transformation projects for the benefit of customers,” according to Virginia statute.
Vistra (NYSE: VST) CEO Curt Morgan on Friday celebrated his organization’s recovery from the $1.6 billion in losses suffered in the wake of February’s Winter Storm Uri by saying he was excited to share details of the long-term capital allocation plan.
“It’s hard to believe we are still in the same year where we experienced the significant effects from Winter Storm Uri,” Morgan said during a conference call with financial analysts. “We are beginning to execute on our strategic priorities … that have begun prior to Uri but accelerated greatly immediately on the heels of the storm.”
Vistra plans to strengthen its business model, which includes both generation and retail sales, through investments in its fleet and fuel supply and improved risk management practices. Morgan said that involves $2 billion in share repurchases through next year, just over 60% of its market capitalization, “for as long as our stock remains at what we believe is such a meaningful discount to its fundamental value.”
The company’s quarterly results excluded a net $10 million “benefit” related to Uri, including in ERCOT resettlements and revenue true-up of $43 million net of $33 million in bill credits applied to large commercial and industrial customers that curtailed during the storm. Vistra also expects to receive about $500 million in proceeds when the grid operator begins securitizing the market’s uplift balance in the first quarter of 2021.
Morgan said the company has already completed about 85% of the $500 million “self-help” initiatives it announced after Uri, including monetizing certain commercial positions, generation savings from lower operations and maintenance project work, retail savings, and reduced administrative expenses. “All of that done without really impacting any future periods,” he said.
Vistra reported third-quarter ongoing operations of adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $1.177 billion, down slightly from last year’s third quarter of $1.183 billion.
The company uses adjusted EBITDA as a performance measure because it believes that external analysis of its business is improved by visibility to both adjusted EBITDA and net income prepared in accordance with generally accepted accounting principles.
Vistra’s share price gained $1.25 Friday and closed the week at $20.46. It dropped to $17.25 in February after the company’s Uri losses were disclosed. (See Vistra Stock Plunges After Market Losses.)
CenterPoint Profits Surge
Another Texas company hammered by the winter storm, Houston’s CenterPoint Energy (NYSE: CNP), said its profits surged during the third quarter.
The utility delivered third-quarter earnings of $195 million ($0.32/diluted share), nearly triple 2020’s third-quarter performance of $69 million ($0.13/diluted share). That beat analysts’ expectations of $0.28/diluted share compiled by Thomson Reuters.
“We now have six quarters of meeting or exceeding expectations, but we believe that there is much more to come,” CEO Dave Lesar said.
He said the company has mechanisms in place to recover the storm’s gas costs in its various jurisdictions and recently reached a settlement on prudence proceedings supporting securitization of 100% of gas costs in Texas.
CenterPoint has also begun recovery in Minnesota and is “working with stakeholders … to reduce the impact on our customers,” Lesar said.
The utility’s share price finished the week at $26.67, a 40-cent gain following the earnings announcement.
OGE Energy Maintains Status Quo
OGE Energy (NYSE: OGE) released quarterly earnings Thursday of $252 million ($1.26/share) as compared to $177 million ($0.89/share) in the third quarter last year. The utility narrowed its year-end guidance to $1.79-$1.83/share.
Oklahoma City-based OGE has reached a joint settlement that would, with regulatory approval, allowing it to securitize $875 million over 13 years and recover 99% of the fuel and purchased power costs incurred during Uri.
The company’s share price gained a penny over its per-earnings close, finishing the week at $34.60.
Two key components of the decarbonized grid of the future — distributed energy resources, and the clean, firm power needed to back them up — were the topics of two panels at the two-day American Council on Renewable Energy’s Grid Forum.
The central question for Wednesday’s panel on integrating DERs — both wind, solar, storage and demand response, and their various “hybrid” combinations — across power markets was what’s needed to bring them on the grid in a way that maximizes their multiple value streams while ensuring system reliability.
Taking in a 20-year horizon, MISO is “looking at various ratios of wind to solar to DERs to storage and hybrids,” said Renuka Chatterjee, the grid operator’s executive director of system operations. “As we look at those futures, the thing that we are learning is it’s pretty similar. So, to the extent you can see these resources as similar in the sense that they provide a service, be it energy or ancillary services, you get a lot of common ground.”
In the example of storage, Chatterjee said, MISO treats storage the same as it treats oil or gas, letting “storage manage its own fuel, which is the battery. … So, that allows us to key in [a] market signal that is consistent and unique while enabling the features of these new resources.”
But Jamie Link, vice president for solar and storage at EDF Renewables North America, said such a technology-neutral approach may not be the best for optimizing the value of utility-scale solar and storage projects. With more than 2 GWh of storage under contract in the West, EDF is “quite closely” following CAISO’s implementation of storage integration, Link said.
“CAISO’s resource adequacy market is a bilateral capacity market, which is very strong both on the system and local level in providing value to storage, and storage can also capture value in the energy and ancillary markets in California,” she said.
She pointed to CAISO’s aggregate capacity constraint (ACC) proposal as a model for other grid operators to follow, as increasing amounts of solar, storage and other DERs come online. The proposed rule would allow the ISO to set multiple capacity constraints for co-located solar and storage projects sharing a common interconnection point, so that output from any one project does not exceed the limits of its interconnection agreement.
“So, instead of the project owner having to worry about making sure a dispatch doesn’t violate their contract and having to make a decision on whether to be available, those two things are synched up,” she said.
CAISO submitted the ACC proposal to FERC in September (ER21-2853).
Leveraging the value of DERs at the residential level is even more complex, said Suzanne Leta, head of policy for SunPower. “There is a fundamental right when it comes to distributed technologies, which is consumer choice,” she said. “But in order to enable that choice, we have to have the policy tools in place and the incentives in place for customers to take that leap.”
For example, Leta said, while only 3% of U.S. homeowners have rooftop solar, and only 2% of all car sales are electric vehicles, 40% of EV drivers have rooftop solar. “There’s this automatic connection on the customer end about the relationship between these technologies, and we have to transfer that into getting the rules in place, so the regulators are able to value them in the same way that customers are,” she said.
Allowing Failure and Positive Collisions
The forum’s closing panel on Thursday looked at what many in the cleantech sector believe will be essential for decarbonizing the U.S. grid by President Biden’s target of 2035: the emerging and still-to-be-developed technologies that can provide clean dispatchable power.
But Debra Lew, associate director of the Energy Systems Integration Group, an educational organization, said as levels of renewables on the grid increase, the real need on a day-to-day basis will be flexibility to balance out intermittent wind and solar.
She believes demand-side management is the low-hanging fruit here. “We can do tons of stuff on the demand side, especially today in the advent of electric vehicle charging and [smart] thermostats,” she said.
Building out the grid to allow for cross-region aggregation is another must-have. “Imagine having solar in the Southwest shipped over to the East to help provide for peak hours, or wind from the Midwest being shipped over to the West. There’s a lot you can do with aggregation by building out more transmission.”
The outer edge of flexibility — the days or weeks when sun and wind power may not be available — is where other technologies, such as long-duration storage, come in, though they face considerable obstacles to commercialization, said Thomas Jarvi, director of defense contractor Lockheed Martin’s flow battery program. The company has spent several years developing its new GridStar flow battery, which is in the final stages of verification testing, he said.
Technology developers need “to think about kind of the transactional end state: Who are their customers, and what are their contract considerations? And what does that transaction look like?” Jarvi said. “What are the customers’ buying factors, risk considerations? Can you buy down risk by virtue of government incentives, rate structures, market structures and so forth?”
The investment needed to develop such new technologies is yet another obstacle. While capital markets are “flush with money,” said Lee J. Peterson, senior manager at cleantech investment banker CohnReznick, tax equity markets are still hesitant to invest in emerging products and processes.
“The comfort level with wind and solar is so large that to get tax equity interested in something other than wind or solar is really a challenge,” Peterson said.
His solution is “total optimization of the U.S. tax code for renewables and clean energy in particular,” he said. “I can go through the code and find you a dozen or more little … ‘glitches’ or stops [that] are really holding back the clean energy economy.”
The federal government also needs to play a more active, “first mover” role in de-risking new technologies to help them scale and get to market, Jarvi said. “Other governments understand the implementation of early technology as a key role for the government … because we’re competing in energy technology, always, against massive incumbencies that have volumes baked in already.”
Adria Wilson, U.S. policy and advocacy manager at Bill Gates’ cleantech venture group Breakthrough Energy, pointed to funding in the newly passed bipartisan infrastructure bill for an Office of Clean Energy Demonstrations in the Department of Energy as a step toward that more active role. But, she said, “there should be a more acceptable culture for the government’s projects to fail. I wouldn’t want them all to fail, but I think we would want them to be taking risks and creating knowledge that stakeholders and private industry could use to build on.”
She called for government “convening with people who are more active in the grid space or other sectors who really know what the market needs are. If you can create moments of collision, positive collision between those two groups, it can help direct the flow of innovation funding in a more productive way.”
MISO last week said its Independent Market Monitor was reasonable in proposing four market changes in the 2020 State of the Market report, though two improvements must wait years for the RTO’s new market platform to be brought online.
IMM David Patton, Potomac Economics’ president, suggested four changes:
Creating a new uncertainty capacity product that can be deployed instead of out-of-market commitments;
better matching emergency procedures and pricing of transmission versus capacity emergencies;
disqualifying wind generation from providing ramping services; and
developing individual effective load carrying capabilities (ELCCs) for more specific capacity accreditations for distributed resources, load-modifying resources (LMRs), solar generation, and battery storage.
MISO Director of Market Design Kevin Vannoy said some of the recommendations were already in MISO’s five-year plan and market redefinition outline.
He said uncertainty management is a high priority at MISO, evidenced by the grid operator’s development of a 30-minute short-term reserve product and work on a better ramping product. Vannoy said staff will continue to work on a look-ahead commitment tool for generators.
“We’re looking at how we can leverage and align our existing products to manage uncertainty,” he told stakeholders during a Thursday Market Subcommittee meeting.
However, Vannoy said additional market products to temper uncertainty would probably need to wait four years so that they can be hosted on MISO’s new market platform. Staff has repeatedly said the RTO is severely limited on market offerings in the current platform’s 1990s era technology.
Vannoy also said MISO will likely have to wait until 2025 to remove wind generation’s eligibility to provide ramping services. He said the change is dependent on MISO moving its market operations to the new platform.
The grid operator has already drawn a clearer distinction between pricing during capacity emergencies and transmission emergencies, Vannoy said, pointing to an August FERC filing that specifies its $3,500/MWh value of lost load applies to capacity emergencies only, not those caused by felled transmission towers (ER21-2801).
MISO agreed that it could use more tailored ELCCs for its non-traditional resources.
“MISO agrees with further evaluation and development of accreditation methodologies for [LMRs], intermittent resources and other resource types with high level of variability and uncertainty,” Senior Manager Lynn Hecker said.
The RTO said it will probably file with FERC sometime next year to create more specific ELCCs.
