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November 8, 2024

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Virginia AG, SCC Staff Question Costs on Dominion’s OSW Project

Dominion Energy’s (NYSE:D) proposed offshore wind project in Virginia has run into some stiff headwinds as it seeks state regulators’ approval.

In testimony filed with the Virginia State Corporation Commission (SCC), commission staff and the state attorney general’s Division of Consumer Counsel questioned the cost of the 2.6-GW Coastal Virginia Offshore Wind (CVOW) project and called for ratepayer protections (PUR-2021-00142). A consultant for Synapse Energy Economics also questioned Dominion’s ability to bring the project in on budget, citing its lack of experience with offshore wind.

The filings were made as the SCC prepares for hearings on the project beginning May 16. In November, Dominion announced that the projected cost had increased by more than 20% to $9.8 billion, citing “commodity and general cost pressures.” (See Dominion’s OSW Project to Cost $9.8B, up from $8B.)

Based on testimony by consultant Scott Norwood, the Consumer Counsel filing says that the project is not needed to serve the company’s system capacity requirements through at least 2035; that the capital costs are about twice or three times the cost of solar resources; and that the company is overstating the forecasted economic benefits.

The filing acknowledged that the legislature’s Virginia Clean Economy Act of 2020 (VCEA) “declared that utility-owned offshore wind electric generation facilities are … in the public interest” and directs the commission “to give due consideration to economic development and social cost of carbon benefits of the project.”

But given the high fixed cost of CVOW and the “significant risks” to customers, if it is approved, Norwood recommended that the SCC hold Dominion strictly to the $9.8 billion cost figure; that the SCC hold the company to minimum standards on capital, operations and maintenance costs, and operating performance; and that the agency have “the company publicly commit to in-service dates.” Moreover, the company should “be required to file periodic status reports … that address the performance and cost of the project through the construction period and for at least the first year of commercial operations.”

If Dominion finds that an in-service date is going to be delayed by more than six months or that it will overrun the $9.8 billion estimated cost by 5% or more, the filing says, the SCC “should require that the company make an immediate filing with the commission that provides notice of the delay or cost increase, provides an explanation of the reasons for the delay or cost increase, and which reopens the question of prudence” of the project as a whole.

Presumption of Prudence in Jeopardy

Katya Kuleshova, of the SCC’s Division of Public Utility Regulation, testified that levelized cost of energy (LCOE) sensitivity analyses show scenarios in which the project’s cost exceeds 1.4 times the cost of a conventional simple cycle combustion turbine — which would eliminate the project’s “presumption of reasonableness and prudence” under the VCEA.

Kuleshova said staff also were concerned that the project’s energy production is expected to be at its highest during shoulder months and at its lowest during summer afternoons, when it is needed the most.

“In the absence of the statutory presumption of prudence, staff does not take a position on the prudence of the project,” she said, recommending the commission order a performance guarantee and cost overrun protections to mitigate risks to ratepayers.

In an email to RTO Insider on Thursday, a spokesperson for Virginia Attorney General Jason Miyares said that his office cannot comment on “pending litigation.”

Dominion responded to the filings with a statement saying, “Offshore wind’s zero fuel cost and transformational economic development and jobs benefits are needed now more than ever.”

Company spokesperson Jeremy Slayton also noted that none of the parties intervening in the docket had opposed the project’s approval. “We are pleased all parties to the case have focused on ways to have the best possible project, and none have opposed it,” Slayton said.

Testifying for activist group Clean Virginia, Maximilian Chang, principal associate with Synapse Energy Economics, recommended that the SCC “conduct an assessment to evaluate if the current utility-owned model for the CVOW is the most appropriate mechanism for the second 2,600 MW of offshore wind for Virginia, as outlined in the Virginia Clean Economic Act legislation. As part of this assessment, the commission may consider other forms of offshore wind procurement, including but not limited to power purchase agreements and/or offshore renewable energy credits.”

The problem, in Chang’s view, is that outside of CVOW, Dominion’s project team appears to have limited direct offshore wind project experience that would show its ability to complete the project on time and within budget. Like the consumer counsel, he recommended that the SCC impose a capital cost cap for the project, but he also suggested that the cap exclude the $500 million the company is requesting for financial hedges and contingency. If the project’s capital costs increase beyond $9.8 billion, Chang said, the commission should set clear guidance that Dominion could be on the hook for overruns. The utility should also be required to submit regular progress reports, and to hire an independent monitor, he said.

In addition to 176 14.7-MW wind turbines, the project includes 3 miles of submarine transmission; a new Harpers Switching Station, located on the grounds of Naval Air Station Oceana; three new overhead 230-kV transmission lines between the new Harpers station and the existing Fentress Substation; the expansion of the Fentress station; a partial rebuild of Line 271; and a rebuild of Line 2240. Dominion estimated a cost of $774 million for transmission and $374 million for substation work, for a total of $1.15 billion.

Dominion requested a final order by Aug. 5, which would allow onshore construction to begin in the third quarter of 2023, followed by offshore construction in the second quarter of 2024, with construction finished in mid-2025. Commissioning of the turbines would begin in August 2025 and continue through the end of 2026.

Economic Impact

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 and almost $210 million annually during its operation.

Norwood said Dominion’s cost-benefit analysis is flawed because it compared total production costs of the system in a scenario with the project, to costs of the system under an alternate scenario that assumes the company would not replace CVOW’s capacity and energy with other renewable resources. The utility’s modeling created “illusory benefits” for the CVOW project, he said.

Norwood also criticized Dominion for failing to include sensitivity analyses to assess the impact of uncertainty in forecasted commodity prices, carbon emissions prices or PJM energy prices. “For example, the commodities price forecasts used for all CBA scenarios assumes that Virginia remains as a member of the Regional Greenhouse Gas Initiative and that federal CO2 legislation becomes effective in 2026,” he said.

The commission will hear public testimony via phone May 16 and hold an evidentiary hearing in Richmond beginning May 17. Both hearings will be webcast. Those wanting to speak as a public witness must register by May 12.

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Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation

SPP and MISO began gathering stakeholder feedback Friday on ways they can pass the hat for the projected $1.65 billion in transmission projects that resulted from their joint targeted interconnection queue (JTIQ) study.

RTO officials began their meeting by acknowledging uncertainties over how much additional generation could be connected as a result of the new transmission, comprising seven projects that are projected to resolve 48 reliability constraints and deliver about $724 million in adjusted production costs savings to MISO and $247 million to SPP.

Andy Witmeier 2022-03-31 (RTO Insider LLC) FI.jpgMISO’s Andy Witmeier speaks at the Gulf Coast Power Association’s MISO South/SPP Conference in March. | © RTO Insider LLC

While MISO’s model estimated a total of 28 GW (10.5 GW in SPP and 17.5 GW in MISO), SPP’s model estimated almost twice as much benefit, a total of 53 GW (11.1 GW in SPP and 41.9 GW in MISO).

Andy Witmeier, director of resource utilization for MISO, said the discrepancies may have resulted from how SPP’s model dispatched MISO generation to serve MISO load and the impacts on loop flow.

To simplify the cost allocation, the RTOs said they settled on using each RTO’s model for its own generation: 11.1 GW in SPP and 17.5 GW in MISO, for a total of 28.6 GW.

“MISO knows how they dispatch their generation … and similar for SPP,” Witmeier said. “Let’s just use the SPP number based on how they’re serving their own load with their generation to try … and remove some ambiguities.”

Cost allocation (MISO) Content.jpgTo simplify cost allocation discussions, MISO and SPP said they will use SPP’s model for SPP’s generation and MISO’s for MISO: 11.1 GW of generation in SPP and 17.5 GW in MISO for a total of 28.6 GW. | MISO

In an example offered by the RTOs, generator interconnection requests with a 5% or greater DFAX (solution-based distribution factor) impact on the JTIQ portfolio could pay a charge of $35,000/MW. So, a 270-MW generator with a 10% DFAX impact would pay $945,000 (27 MW x $35,000).

Rafik Halim of National Grid Renewables asked the RTOs to share the details of their modeling. “There needs to be a study that’s transparent” before decisions are made, he said.

Stakeholder-driven Methodology Sought

Neil Robertson 2022-03-30 (RTO Insider LLC) FI.jpgSPP’s Neil Robertson at the Gulf Coast Power Association’s MISO South/SPP Conference in New Orleans. | © RTO Insider LLC

Neil Robertson, SPP’s coordinator of system planning, emphasized that the per-megawatt charge and DFAX threshold were used to illustrate the concept and not a firm proposal, saying the RTOs seek a “stakeholder-interactive approach” to developing the methodology.

“SPP and MISO did not intend to come up with a fully developed methodology and then simply ask for stakeholder input,” he said. “We want to take stakeholder input on key concepts and use them as building blocks to build out this methodology.”

“We are not naive enough to think we have all the answers,” added David Kelley, director of seams and tariff services for SPP.

The actual cost multiplier will be designed to collect all of the costs of the portfolio “while, at the same time, fully utilizing the capacity, not underselling or overselling the capacity that we are creating,” Robertson said. Whatever the methodology, “prior to executing a GIA [generator interconnection agreement], you would know what the JTIQ charge would be, just like you would know any of the other upgrades involved in the generation interconnection process.”

Robertson said RTO officials are seeking a balance between a subscription-based model and one in which load would initially pay for the projects and generation would reimburse as it interconnects. Such a balance could involve the requirement of a “critical mass” of generator agreements: for example, 50% of total JTIQ portfolio funding agreed to by GI customers in signed GIAs. Funding for the other 50% could come from local transmission owners or be regionally funded and later reimbursed as additional generators sign up.

Steve Gaw of the Advanced Power Alliance, which represents wind, solar, and energy storage companies, expressed concern that the critical mass approach could delay interconnections of projects already in an open study.

Robertson acknowledged that while the model could mitigate risk to “any particular segment of the stakeholder base,” it could also “increase the uncertainty” for some generators.

Brenda Prokop of LS Power said she agreed with the concept of a critical mass. “I think it’s pretty necessary to set some kind of threshold for proceeding with projects.”

But she said MISO and SPP should not “assume that the JTIQ projects would be reserved for local TOs and eligible to be funded by them” because not all of the projects would be in states that permit TOs a right of first refusal (ROFR). The projects would be built in Minnesota, North Dakota and South Dakota, which all have ROFR laws, as well as in Nebraska and Kansas.

Antoine Lucas, SPP’s vice president of engineering, closed the meeting by acknowledging that the two RTOs had forgone the “certainty” of their existing cost allocation processes in seeking an “ad hoc” methodology for JTIQ.

“But we felt like it was worth it to have the flexibility to be able to craft a mechanism customized to fit the specific projects and specific circumstances that we would see from the JTIQ,” he said.

Next Steps

The seven projects have a projected cost of $1.65 billion, but the JTIQ cost allocation likely won’t apply to two of the projects, which MISO has included in its tranche of long-range transmission projects. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)

MISO and SPP hope to submit their cost allocation formula to FERC by the end of this year, with RTO approvals of the JTIQ projects by the second quarter of 2023.

Additional joint stakeholder meetings are tentatively scheduled for 10 a.m. to 12 p.m. CT on May 20, June 27 and July 29. Comments may be sent to GI-AFS@misoenergy.org and interregionalrelations@spp.org.

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NACFE: Electric Vans Have Arrived

The North American Council for Freight Efficiency (NACFE) makes the case in a report released this week that electric versions of vans and step vans used by delivery companies and small businesses are not only competitive with gasoline and diesel vehicles but are “a perfect fit” for the market segment.

The conclusion is based on data collected from three battery electric vans and step vans operated last fall by companies participating in real-world testing of the vehicles, as well as interviews with their staffs of participating, including the vehicles’ drivers and maintenance crews. Members of the NACFE team also interviewed vehicle manufacturers.

The number of small commercial vehicles is expected to grow. NACFE estimates that there are about 4.2 million vans and step vans used commercially in the U.S. and Canada. Many of the vans are involved in deliveries of products purchased through e-commerce sales, which amounted to $218.5 billion in 2021.

Citing statistics from the Bureau of Transportation, NACFE noted that the tonnage delivered in the top 50 delivery routes is expected to increase from 2.4 million tons in 2022 to 3 million tons in 2030.

Data collection from the vehicles participating in the real-world testing was done electronically and appears to have been rigorous.

“All three vehicles were instrumented with a Geotab telematics device. The vehicle operations were continuously digitally tracked, and their metrics updated daily via a public website with the ability to view results by day or over a span of days. Metrics such as daily range, speed profiles, state of charge, charging events, amount of regenerative braking energy recovery and number of deliveries were shown in near real time. Information on weather conditions also was observed,” the report said.

Drivers were enthusiastic about their experience, the report states, because of the ease of operation and the considerably less noise and vibration that left them less fatigued at the end of a shift.

Interviews with maintenance crews found them to be positive, with far less to do, as the engines, transmissions and related emission controls had been replaced with an electric drive and battery pack.

The vehicle battery packs were designed to be charged at 240 V overnight, meaning even a fleet would not pose an extra heavy load on utilities.

Despite the positive results, the report points out that there will be challenges as the delivery industry switches over as predicted, gradually replacing their existing vehicles with electrics in pilot programs.

Total cost of ownership is one way fleet managers approach the problem, the report said.

“Fleets utilizing vans and step vans, especially in the parcel and package delivery space, currently expect the equipment to last 15 to 20 years and accumulate 300,000 to 400,000 miles in that time span.

“Although manufacturers believe battery life can meet design lives of five, seven and 10 years depending on the OEM choices, long-term performance of electrified vehicles in this market segment still needs to be validated by fleets,” the report cautions.

On the plus side, maintenance costs are expected to be considerably less than with conventional engines and transmissions that required steady preventive maintenance. One performance aspect on the side of the electrics is the cost of fuel.

A NACFE analysis based on the price of gasoline at $2.98/gallon and the delivered cost of electricity at the national average rate of 11.2 cents/kWh and 250 days of operation delivered an estimated annual fuel cost for the gasoline-fueled vehicle at $10,065 and $1,958 for the electric version.

“We expect that this work [the real-world testing] will encourage fleets to explore the deployment of commercial battery electric vehicles (CBEVs) in their operations where they make sense, for manufacturers to improve their products for quicker return on investment and for others to better support the efforts of the trucking industry to progress the use of CBEVs,” the report explained.

“NACFE considers this market segment to be 100% electrifiable,” the report concludes, “which would result in the avoidance of nearly 43.5 MT CO2e annually.”

“As recently as five years ago, I would have questioned the feasibility of electrifying North American van and step van fleets,” said Mike Roeth, NACFE executive director. “The transition to cost parity happened quicker than most of us expected, and I am surprised to announce today that the electric market has arrived.”

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NYPSC OKs 2 Huge Clean Energy Projects for New York City

The New York Public Service Commission on Thursday voted 5-2 to approve separate 25-year state contracts to buy electric power from the 1,300-MW Clean Path New York (CPNY) and the 1,250-MW Champlain Hudson Power Express (CHPE) projects that will bring solar, wind and hydropower from upstate and Canada into New York City (15-E-0302).

Rory Christian (NYDPS) Content.jpgNYPSC Chair Rory Christian | NYDPS

The two transmission projects, Tier 4 renewable resources under the state’s Clean Energy Standard, are projected to cut New York City (Zone J) fossil-fired generation by 51% and to bring up to $5.8 billion in social benefits, including greenhouse gas (GHG) reductions and air quality improvements and $8.2 billion in economic development across the state that will benefit disadvantaged communities.

“New York City relies heavily on aging fossil fuel generation — simply put, if we can’t deliver renewable energy to New York City we can’t reduce emissions from that fossil fuel fleet,” said PSC Chair Rory Christian. “Based on the over 30 proposals received, these options are the best available.”

The projects, he said, support the goals set by the Climate Leadership and Community Protection Act and align with the New York State Constitution supporting each person’s right to “clean air, water and a healthful environment.”

Diane X Burman (NYDPS) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

CPNY, developed by the New York Power Authority (NYPA) and Forward Power, a joint venture of Invenergy and energyRe, will be tied to 23 generation facilities and bring upstate solar and onshore wind into the city from its origin point in Delaware County with a start date of June 30, 2027. The constant rate contract over 25 years pays $129.75/MWh for 7,870,865 MWh/year for a total contract price of approximately $25.5 billion.

The CHPE, developed by Transmission Developers and Hydro-Québec’s U.S.-based subsidiary HQUS, will run from the state’s border with Canada to Queens, with portions of the line running underneath the Hudson River. Its contract begins Dec. 15, 2025, and increases by 2.5% per year. Starting at $97.50/MWh for 10,402,500 MWh/year, the 25-year total contract price is approximately $34.6 billion.

The actual program payments will be calculated at those strike prices minus reference energy and capacity pay prices as defined in each contract, with the renewable energy credit (REC) payments dependent on future energy and capacity commodity prices, said Marco Padula, an economist at the state’s Department of Public Services. “The petition presents ratepayer impacts that are projected as the net REC costs over time under a range of projected energy and capacity price forecasts.”

City Lights

New York City filed a notice in November stating its intent to enter into a 25-year contract with the New York State Energy Research and Development Authority (NYSERDA) to procure Tier 4 RECs, which, when combined with the city’s load share-based allocation of offshore wind RECs, would be equivalent to its entire load, said Robert Rosenthal, general counsel for the DPS.

Robert Rosenthal (NYDPS) Content.jpgRobert Rosenthal, NYDPS | NYDPS

The city is taking a lead to reduce GHG emissions by backing up its policies with a significant financial commitment, providing a model for other branches of state and municipal governments to follow, Rosenthal said.

On April 9, the state Office of General Services (OGS) filed a letter of intent stating that it would also be entering into a contract with NYSERDA for Tier 4 RECs associated with energy used by all state agencies located in the city.

“DPS sees this all-of-government approach as a significant development that will meaningfully reduce utility ratepayer impact of implementing the CLCPA, and it will strongly encourage other branches of government to make commitments under Tier 4 similar to those made by New York City and OGS,” Rosenthal said.

The city’s efforts are encouraging signs that future investments will not solely be borne by ratepayers but spread out equitably through a more expansive all-of-government approach, Christian said.

David Valesky (NYDPS) Content.jpgNYPSC Commissioner David Valesky | NYDPS

“Many comments received, including those from the Real Estate Board of New York, highlighted the growing demand for RECs through voluntary corporate and consumer action as another potential source for savings,” he said. “It is likely that many building owners will procure Tier 4 RECs, potentially a very significant quantity of RECs, for compliance with various local laws, such as local law 97 in New York City,” Christian said. (See NY Stakeholders, Residents Split on HVDC Tx Projects.)

Commissioner David Valesky quoted from the comments filed by the largest property owners in the city who “are eager to explore participating in this voluntary market to determine how purchasing these RECs can enhance our corporate goals and local law 97 compliance strategies.”

Regarding voluntary participation versus mandates, “the reality of local law 97 cannot be understated and is significant to say the least, so I think these are important commitments,” Valesky said. “They’re meaningful commitments in terms of reducing the impact of these projects on ratepayers across the state.”

Ratepayer Concerns

The commission had to vote on the projects based on the record, which shows the known cost to ratepayers “are unacceptably high,” said Commissioner Diane X. Burman, who voted against the order.

Commissioner John B. Howard also voted no, concerned that the projects received little publicity and discussion west of the Hudson River.

John B Howard (NYDPS) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

“In fact, of those entities who commented from central and western New York, they were by and large opposed to this order,” Howard said. “While this petition received extensive press coverage from the New York City-based media, nary a word was written about it in the upstate media, so in any discussions I had with individuals upstate, they had little or no awareness of the impacts to customers in their region.”

He urged the commission to more aggressively seek the opinions of those customers who will pay most of the bills, since electricity customers outside of the city will pay 60% of the Tier 4 cost for the contracts.

“Even today, we have heard over and over again that the vast majority of benefits to this proposal accrue to New York City because customers pay for Tier 4 on a pure kWh basis,” Howard said. “Combined with a relatively lower cost retail electric cost outside of New York City, particularly upstate, the percentage of increase on customers’ bills will be higher upstate.”

The contracts, he said, will have a “disproportionate impact” on large customers and “we cannot sacrifice upstate New York economic competitiveness as we decarbonize our economy.”

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CAISO Sets 98% Renewables Record

CAISO said Thursday it set a record for renewables on its grid earlier this month when nearly all the ISO’s electricity came briefly from clean, renewable resources.

The peak of 97.6% happened at 3:39 p.m. PT on April 3 and broke the previous record of 96.4% set a week earlier on March 27. Even higher numbers are possible this month, the ISO said.

CAISO has been adding more renewable energy to its grid in support of the state’s goal of achieving 100% clean power for retail customers by 2045.  

“When we see renewable energy peaks like this, we are getting to re-imagine what the grid will look like for generations to come,” CAISO Board of Governors Chair Ashutosh Bhagwat said in a news release. “These moments help crystallize the vision of the modern, efficient and sustainable grid of the future.”

CAISO’s installed renewable energy mix consists of about 57% solar, 30% wind and smaller amounts of geothermal energy, small-hydro resources and biofuels. About 32% of California’s energy mix came from renewable power in 2020, the most recent year for which figures are available, according to the state Energy Commission.

The ISO also set a new solar peak of 13.6 GW early in the afternoon of April 8 and an all-time wind peak of 6.2 GW shortly before 3 p.m. March 4.

“Renewable peaks typically occur in the spring due to mild temperatures and the sun angle allowing for an extended window of strong solar production,” the news release said. “ISO analysis forecasts a potential for more renewable records in April.”

SPP reached a similar milestone last month when it became the first multistate grid operator to temporarily serve more than 90% of its demand with renewable energy. (See SPP Stuns with 90.2% Renewable Penetration Mark.)

SPP’s footprint includes high-wind regions of the Dakotas, Kansas, Missouri, Nebraska, Oklahoma and Texas, and its resource mix includes about 31 GW of installed wind capacity.

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SPP to Phase Out WEIS as New Market Offerings Expand

SPP said Wednesday it plans to eventually close its Western Energy Imbalance Service (WEIS) after current members join either its expanded RTO West or its Markets+ program, now under development, that will offer a bundle of RTO-like services.

“We don’t intend to have three different offerings in the West,” Kara Fornstrom, SPP director of state regulatory policy and a staff member working on Markets+ design, said in a briefing for the Western Interstate Energy Board.

The webinar gave Western utility regulators the chance to ask questions about the Markets+ program. Fornstrom made her comments while answering a question from Colorado Public Utilities Commission Chair Eric Blank.

“I just realized this a few days ago, that the WEIS market, the energy imbalance market, is at some point in the future going to sunset as entities join the RTO and the Markets+ day-ahead,” Blank said.

“I was just surprised that WEIS is going away,” he added.

Blank asked if Markets+ would also “sunset” or would be a “permanent option.”

Fornstrom said most of the WEIS’s current members “will have moved already to the RTO expansion … before Markets+ launches, so the WEIS will have shrunk before we get to Markets+, and the remaining entities in WEIS that we have today have expressed their interest … to go to Markets+ rather than just the [WEIS’s] real-time service.

The move is “based on [WEIS members’] interest level on adding the [Markets+] day-ahead service,” she said.

Markets+ will be a “long-term durable solution” in the West, Fornstrom said.

Later, Joe Fina, a stakeholder member of the Markets+ design team and assistant general counsel at the Snohomish County Public Utility District, said: “The WEIS will be replaced by Markets+.”

And SPP spokeswoman Meghan Sever said in an email to RTO Insider that it is “SPP’s intention to only provide one market offering in the West in order to provide maximum benefits for Western utilities. Current WEIS participants will have the option to join the RTO or participate in Markets+. Until then, SPP remains fully committed to continue providing Western reliability coordination and operating the WEIS market.”

Toe-to-toe with CAISO

SPP launched the WEIS, a real-time interstate trading market, in January 2021, making it the first RTO with energy markets in both the Eastern and Western interconnections. It intended for the WEIS to compete with CAISO’s larger and well-established Western Energy Imbalance Market (WEIM).

SPP has had some success competing with CAISO. In January, three Colorado utilities that had planned to join the WEIM instead decided to join the WEIS. Public Service Company of Colorado, Platte River Power Authority and Black Hills Colorado Electric followed Colorado Springs Utilities in switching allegiance from CAISO to SPP. (See Colorado Utilities Choose WEIS over WEIM.)

The WEIS, however, has gained fewer members than the WEIM, which was launched in 2014.

CAISO’s imbalance market has attracted 22 current or planned participants, including major utilities such as Arizona Public Service and NV Energy, while the huge Bonneville Power Administration is scheduled to go live next month. The WEIM has produced $1.93 billion in economic benefits for its members in the past eight years and is expected to cross the $2 billion mark with its next quarterly report. (See Western EIM Nears $2B in Total Benefits.)

With the addition of the Colorado utilities, WEIS has 14 current or future members including Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Guzman Energy and the Western Area Power Administration’s Upper Great Plains West and Rocky Mountain regions and its Colorado River Storage Projects.

CAISO has been working to develop an extended day-ahead market (EDAM) as an additional offering to the WEIM, a real-time interstate market that was the first of its kind. CAISO also provides reliability coordination services through its RC West to most of the Western Interconnection.

The ISO, however, is limited by its one-state governance from becoming a Western RTO.

SPP also offers RC services in the West and is administrator for the Western Power Pool’s Western Resource Adequacy Program (WRAP). Once fully implemented, the WRAP will help Western balancing authorities respond to potential generation shortages during critical hours as the region addresses the retirement of thermal resources and its growing reliance on variable renewable resources. (See NWPP Rebrands as Western Power Pool.)

Unlike CAISO, SPP can offer full RTO membership to Western entities. It intends to expand its RTO footprint and develop a Western market system that is fully integrated with its existing market system.

The Markets+ program is aimed at utilities that do not want to join an RTO but need a range of services normally provided by an RTO, including day-ahead and real-time unit commitment and dispatch. SPP says Markets+ will provide easy transmission service across the footprint and set the stage for the reliable integration of renewable energy’s growth.

SPP presented the Markets+ model to interested participants during a virtual meeting in December and plans to hold in-person forums throughout the West. The RTO is gathering information from interested parties, including WRAP participants, as part of an extensive process leading up to the program’s launch. Wednesday’s WIEB briefing on program governance and other matters was part of that process.

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US Interstate Highways: A NIMBY-free Corridor for Grid Expansion?

An exhaustively researched report examining the use of the U.S. interstate highway system as a ready-made corridor for expansion of the nation’s high-voltage transmission system, as well as a broadband internet access, concludes it can be done relatively quickly and at a lower cost than siting new transmission corridors.

Prepared for the Minnesota Department of Transportation by Seattle-based NGI Consulting and The Ray, an Atlanta nonprofit, the 81-page analysis offers national conclusions. It argues that “NextGen Highways” ought to include buried HVDC transmission lines co-located with fiber-optic cables.

The recommendation to open interstate rights of way (ROWs) is in line with policy changes issued in 2021 by the U.S. Department of Transportation giving state DOTs the option to allow utilities to site energy infrastructure, including pipelines and even renewable energy projects, within interstate ROWs.

The release of the massive study also comes a year after the Biden administration announced the availability of $5 billion in loan guarantees to encourage the expansion of the grid, noting that decarbonizing transportation will require the grid to double or even triple in size.

The transportation sector accounted for 29% of carbon emission in 2019, more than power generation did, according to EPA, making transportation decarbonization a priority issue.

The report argues that state departments of transportation should:

      • “site and build fiber in a way that allows for buried HVDC transmission to be co-located at a later date;
      • “develop and invest in their relationship with utilities, public utilities commissions and other state agencies with transmission siting jurisdiction; [and]
      • “determine the amount of operational funding required to support the co-location of electric and communications infrastructure in their ROW.”

The report’s recommendation of underground HVDC power lines is no accident. HVDC power lines can move power long distances without line losses and without inducing currents in nearby conducting materials. And unlike AC lines, HVDC lines can connect systems operating at different AC frequencies. Yet few HVDC lines have been built in the U.S., according to the report.

“Unlike the U.S. Interstate Highway System, the U.S. power grid is composed of many discrete regions. Modeling study after modeling study has shown that connecting these regions is critical to cost-effective grid decarbonization,” the report states. “It is also critical for grid reliability and resiliency.

“Despite the importance of connecting the electric grid regions using interregional transmission lines, project after project has failed in the U.S. Since 2014, the U.S. has not built a single gigawatt of interregional transmission capacity. Meanwhile, China, Europe, South America and India have collectively built nearly 350 GW of interregional transmission capacity.

“Most recently, the construction of the New England Clean Energy Connect transmission line was stopped indefinitely by a public referendum in November 2021. This was an incredible result given that the New England Clean Energy Connect had already received the required regulatory approvals and was in the process of being built.”

One of the most important conclusions of the study is that decarbonizing the grid itself — moving clean power to where it is needed, particularly for charging electric vehicles — will be less costly using HVDC transmission lines.

“As seen in Europe and now in New York state, buried HVDC transmission is being used to build the interregional transmission required to cost-effectively and reliably decarbonize the electric grid,” the report said.

And in one of the dozens of supplemental documents attached to the report, the analysts explain in more detail that “many of the richest wind and solar resources are located far from the urban load centers where most of the country’s energy is consumed. The nation’s transmission infrastructure must at least double to accommodate the exponential growth of wind and solar that will accompany decarbonization.

“Without the addition of significant multiregional transmission, system planners will need to overbuild local renewable resources in order to manage weather patterns and meet demand, resulting in extreme curtailment of local wind and solar resources, even if high levels of storage capacity are available, dramatically increasing costs.”

Additionally, the expected development of solid-state converters to replace conventional transformers will allow for the development of medium- and high-voltage charging stations, the report postulates, further arguing that the buildout of HVDC converter stations will create “economic development zones … logical locations to site fleet and over-the-road EV charging infrastructure and data centers.”

While the study makes national recommendations, its analysis initially focuses on state DOTs because they control highway corridors and ROWs.

Most states, including Minnesota, have not permitted overhead transmission lines to run along highways because of the possibility of vehicular accidents. Many states limit transmission line intrusions to crossing over highways, the report found.

Wisconsin is one of the few states that does allow transmission lines to parallel highways inside the ROW and, according to the report, has permitted the construction of an overhead line to run inside an ROW after state lawmakers approved the practice in 2003.

That legislation requires utilities and grid companies building new transmission to first consider existing utility corridors and then highway and railroad corridors and even recreational trails before seeking to establish new utility corridors. The Wisconsin Department of Transportation (WisDOT) then amended its policies to reflect the new law, as did the state Public Service Commission (PSCW).

“In 2009, as a result of Act 89, WisDOT’s updated utility accommodation policy, and the development of new transmission infrastructure, WisDOT and PSCW entered into a cooperative agreement ‘to ensure that whenever practical, WisDOT and PSCW shall utilize existing transportation or transmission corridors instead of creating new corridors for electric transmission facilities.’ …

“The legislation, policy and agreements described [here] have fostered a collaborative and trusting relationship between Wisconsin utilities and WisDOT and have resulted in the efficient, cost-effective and successful siting of over 800 miles of transmission infrastructure in and along interstate and highway ROW in Wisconsin,” the report notes, adding that “Wisconsin has the playbook for siting transmission in DOT ROW.”

The Great Plains Institute, based in Minneapolis; Satterfield Consulting in Madison, Wis.; 5 Lakes Energy of Lansing, Mich.; and consultant Tracy Warren in D.C. assisted with the research and release of the report.

In a statement, Morgan Putnam, founder of NGI Consulting, announced the release of the report and what the team expects to do next.

“Given the positive findings from this study, we will be launching a NextGen Highways Coalition later this year. The coalition will facilitate conversations between state DOTs, transmission developers and governors to support the co-location of buried fiber and transmission in highway and interstate ROW.”

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SERC Urges Industry Effort on Facility Ratings

A new report released Wednesday by SERC aims to help “registered entities … reduce the risk of facility ratings challenges, resulting in a more reliable and secure” bulk power system.

The report, “Facility Ratings Themes and Lessons Learned,” was inspired by the “hundreds of individual instances” of violations of NERC reliability standard FAC-008-5 (Facility ratings) and its predecessors that SERC has logged since 2017. SERC based its analysis on data from those violations, as well as information “gathered through [its] various voluntary outreach and training activities.”

Improper facility ratings are a frequent source of compliance issues in SERC and other regions: FERC last year approved a $570,000 penalty leveled by ReliabilityFirst against American Electric Power over misratings at nearly 600 facilities. (See AEP to Pay $570K in NERC Penalties.) WECC also lodged a $265,000 settlement with Public Service Company of New Mexico over facility ratings issues last year, and SERC settled with the Tennessee Valley Authority for the same reason in March. (See FERC OKs $265,000 PNM Penalty.)

At SERC’s Board of Directors and Members meeting last month in Savannah, Ga., the regional entity’s vice president of operations, Tim Ponseti, said the frequency of facility ratings violations was becoming a source of concern for the ERO Enterprise and prompted the report. (See SERC Board of Directors/Members Briefs: March 30, 2022.) With the growing risk of extreme weather from climate change, as well as the ongoing adoption of new generation resources, the RE felt it was necessary to address the reasons behind the issues.

“Facility ratings have a far- and wide-reaching impact [on] daily operations: real-time analysis, next-day planning, long-term planning, modeling … and the list goes on,” Ponseti said. “All these areas are making critically important decisions, and at their fundamental basis is a reliance on an assumption of accurate facility ratings.”

Utilities Lack Awareness of Own Systems

The report identified three major themes associated with the majority of the FAC-008 violations encountered by SERC in the last five years. Each theme was considered the primary cause of about a third of the infringements studied. While the document identified “potential mitigation strategies” for each issue, SERC emphasized that these should not be considered binding requirements or directives for industry.

The first theme, accounting for 28% of violations, was lack of awareness, which SERC defined as the absence of “an accurate physical accounting or understanding of the current-carrying equipment” within a utility’s system. Failure to develop and implement a facility ratings program also falls under this category.

When this occurs, entities tend to rely on rating information provided by equipment manufacturers, nameplate ratings or outdated field inspection reports. Without frequent inspections, inaccurate ratings may “go undetected for a long duration.”

SERC suggested addressing this issue by enhancing the engagement and oversight of senior management, urging leaders to “set a positive ‘tone at the top’ by creating a culture … that treats facility ratings as a program — like safety — and not like a one-time project with a finite start and end date.” This approach includes establishing a level of engagement with the entity’s RE and with NERC; the report noted that the ERO Enterprise has performed “a significant amount of outreach” to industry regarding facility ratings and that keeping up with these efforts could help utilities build awareness of potential deficiencies in their programs.

Periodic field validations are an essential component of a facility ratings program that is too often neglected, SERC said. As equipment is replaced in the field during restoration from extreme weather events, entities must ensure that they are not simply reusing the same ratings, which may not apply to the new items. Physical walk-downs can also help to spot equipment that an entity may have lost track of after a merger or acquisition.

Asset, Data and Change-management Challenges

Another theme identified in the report, and comprising 34% of violations, is inadequate asset and data management. Asset management is defined as the identification, management and tracking of physical facility ratings assets, while data management is the collection, validating and storage of ratings-connected data.

Managing assets and data can be challenging, because physical assets can range in size from very large to extremely small and may also be located in places that are physically difficult to inspect; data are often stored by the same departments that use them, for which storage is not necessarily a priority. This means that when data are needed during an audit or review, a utility may face delays tracking them down.

Mitigation strategies for asset and data management include periodic field verification programs, as well as effective data capture and verification strategies and spreadsheets or databases to store information properly. Entities must also include contractors in their strategies and make sure they are also trained in the proper data management schemes.

The third theme is inadequate change management, which SERC said enables “facility and equipment rating changes to be captured, coordinated and implemented throughout the entity in a timely manner.” Failure to properly track changes to an entity’s equipment can create an inaccurate assessment of its system, leading to breakdowns at critical moments.

SERC described a case when a generator owner and transmission owner installed a new transformer at a facility, replacing a transformer that had been the most limiting element there. The new component had a higher rating and was therefore no longer a limiting element; however, the utility failed to account for this by updating its facility rating. In another case, a transformer was shared between two units. The utility retired one of the units and reconfigured the high-voltage bus, but nobody thought to adjust the facility ratings.

The report’s authors recommended implementing a strong change-management process that provides “clear roles and responsibilities,” as well as a quality assurance review process for each change. The process should be communicated to personnel through regular training and verified through field inspections, they said.

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E-ISAC Warns of Escalating Russian Cyber Threats

Staff at the Electricity Information Sharing and Analysis Center (E-ISAC) warned this week that Russia’s electronic warfare teams are becoming more aggressive, both in their attacks against Ukraine and in their willingness to punish the country’s perceived allies worldwide.

“They will use a number of tools in their toolkit, including dis- and misinformation, as well as cyber and physical attacks against critical infrastructure, including the grid in North America,” Matthew Duncan, director of intelligence at the E-ISAC, said during Thursday’s regular Talk with Texas RE webinar. “We know this because they have done it before, whether it was in Ukraine in 2015 and 2016, or this week.”

By “this week,” Duncan was referring to the revelation on Wednesday of a new breed of malware with the ability to gain full access to a wide range of industrial control system (ICS) and supervisory control and data acquisition (SCADA) devices. The threat was first publicized by cybersecurity firm Dragos, which called the new malware “Pipedream” and its developer “Chernovite”; the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency.

Pipedream makes use of “custom-made tools for targeting ICS/SCADA devices,” CISA said in its advisory; in particular, the malware targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.

The malware is deployed once attackers have established a foothold in an operational technology (OT) network. Attackers can use the bug to look up details on the target device, upload malicious configurations and code, backup or restore its contents, and modify its parameters. They can also “move laterally within an IT [information technology] or OT network and disrupt critical devices or functions.”

Dragos believes Pipedream has not yet been deployed in the wild, calling it “a rare case of accessing and analyzing malicious capabilities … before their deployment and … a unique opportunity to prepare in advance.” The same cannot be said of another threat exposed this week by Ukraine’s Computer Emergency Response Team (CERT), an apparent sequel to the Industroyer malware used by Russian attackers to devastating effect against Ukraine’s energy sector in 2016.

In the first Industroyer attack, hackers managed to knock about 20% of Kyiv’s power grid offline for about an hour; the U.S. Department of Justice later brought criminal charges against six Russian military intelligence officers believed to be involved in the attack. (See Six Russians Charged for Ukraine Cyberattacks.) Unlike the earlier incident, this week’s hack — dubbed “Industroyer2” — was apparently foiled before any outages were caused. However, Duncan warned that the incident shows the seriousness of the ongoing threat.

“Analysts reported clear similarities between the components of [the first] Industroyer and the sequel that was announced this week, and they have high confidence that the new malware was created by the same authors: this Sandworm team [from] the Russian military intelligence,” Duncan said. “But the exact capabilities of this new grid-focused malware specimen remain far from clear, and I suspect we will see more information coming out about this in the coming days.”

Against the rising threat level, Duncan praised the U.S. government for ramping up its efforts to disrupt operations against domestic targets; in particular, he pointed to the FBI’s announcement last week that it had shut down a Russian government-operated botnet — a group of thousands of devices with malware that allows hackers to use them for coordinated cyberattacks — before it did any harm. He urged private sector organizations to work with each other and with the government to ensure that threats are spotted quickly.

“It’s good to see that the government is being proactive and engaging the adversary on this, and that’s why it’s really important to share information with government partners [and] with the E-ISAC to make sure we’re [connecting] those dots,” Duncan said.

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Ariz. Regulators Reject Expansion of SRP Gas Plant

Arizona regulators have rejected Salt River Project’s proposed expansion of the Coolidge Generating Station, a gas-fired power plant in Pinal County, citing concerns about the impacts on the nearby Randolph community.

The Arizona Corporation Commission voted 4-1 on Tuesday to deny a Certificate of Environmental Compatibility for the project.

The expansion would have added 16 gas turbines to the Coolidge plant with a combined capacity of 820 MW. The generating station’s current capacity is 575 MW from 12 single-cycle turbine units, according to SRP’s website.

SRP said the project is needed to meet growing energy demand as more residents, manufacturers and industrial users move to the area. The utility is forecasting growth in peak demand of about 16% by 2025, or roughly 1,200 MW.

In addition, the expansion would provide reliability to support the addition of renewable energy, SRP said.

Commissioner Sandra Kennedy agreed that additional capacity is needed but said it doesn’t have to come from “a polluting fossil-gas facility.”

“An investment of $1 billion … on fossil-fuel infrastructure in 2022, when that money could instead be used to accelerate clean energy technology, is a tragic displacement of funds,” Kennedy said.

Incomplete Info Alleged

Commission Chair Lea Márquez Peterson said SRP didn’t provide complete information on the project.

SRP did not issue an all-source request for proposals for the expansion, saying it had previous RFPs that provided enough data, according to an order approved by the commission. But data from the past RFPs allegedly were not submitted as part of the record in the application.

A required power flow and stability study also wasn’t provided to the commission, according to the order.

And even though SRP contracted with E3 to see how much solar plus storage would be needed to provide the same reliability as the natural gas expansion, the utility didn’t provide the complete study to the commission’s Line Siting Committee or to the SRP board before a vote to move ahead with the project, the order stated.

Commissioner Justin Olson was the lone “no” vote on denying the expansion. He said natural gas is a key component in the expansion of renewable energy because it provides reliability at times when renewable energy is not available.

“If we are going to eliminate any natural gas energy generation, or any expansion of it, we are not going to have the ability to meet the energy demands of Arizona residents,” Olson said. “We’ve seen this happen in California.”

SRP didn’t respond to a request for comment on Thursday. But following Tuesday’s vote, SRP said on its website that it would “continue to evaluate what generation and market options to pursue in the near term to address the resource challenge this decision creates for serving our customers with reliable, affordable, sustainable energy.”

Historic Community

Construction of the Coolidge Generating Station was completed in 2011. SRP bought the plant in 2019.

The power plant is near the community of Randolph in unincorporated Pinal County.

Commissioner Anna Tovar noted the historic significance of Randolph, which she described as a Black community founded in the 1920s by people who came from Arkansas and Oklahoma to pick cotton. Because they weren’t allowed to buy property in nearby Coolidge, they settled in Randolph instead.

“I do not believe it is wise to put further pressure on this community to relocate,” Tovar said. “The history is important, and we shouldn’t lose that.”

And even though SRP had made progress in mitigating impacts of the proposed project, Tovar said it wasn’t enough.

“The increase in emissions, when combined with the pre-existing environmental and air quality issues, will result in an unacceptable total environment for the Randolph community,” she said.

Reaction from environmental groups to the commission’s vote was positive.

Adam Stafford with Western Resource Advocates called the decision “a win for climate action and environmental justice in Arizona.”

“It’s time for SRP to find clean alternatives and revisit its sustainability goals to adopt mass-based emissions reduction targets in line with what scientists say is needed to avoid the worst effects of climate change,” said Stafford, who is WRA’s managing senior staff attorney in Arizona.

Ellen Zuckerman with the Southwest Energy Efficiency Project also applauded the decision.

“At a time when far too many Arizonans are making painful economic decisions and falling behind on their bills, we simply cannot rubber-stamp $1 billion for improperly rushed and poorly vetted projects.” Zuckerman said in a statement.