Search
`
December 1, 2024

Posted on

Offshore Wind Projected to Save New Englanders $630M per Year

A new analysis prepared for the Sierra Club concludes offshore wind energy would be a money-saver for New Englanders, despite the high cost of construction. 

The six-state region relies heavily on natural gas for power generation, the report explains, and the cost of gas can be quite high, particularly in winter. 

“Charting the Wind” projects that bringing 9 GW of offshore wind online would save $2.79 or $4.61 per month per average residential customer, depending on whether a midrange or high-price gas scenario is used. The total would be $630 million in an average year in the midrange model, the authors write. 

Synapse Energy Economics, which prepared the report, notes there are additional benefits to be gained by shifting from natural gas generation, beyond the savings on utility bills. 

These include the climate and public health improvements yielded by reducing the power sector’s emissions of carbon dioxide, nitrogen oxides, sulfur dioxide and fine particulate matter.  

Also, the average $3 billion spent per year to buy natural gas for power generation in New England goes out of the region. Slashing gas use could keep a significant percentage of that money in the regional economy. 

The Sierra Club, a proponent of offshore wind energy, commissioned the report to counter some of the criticism being leveled at the offshore wind industry as it gains a foothold in U.S. waters — particularly after multiple projects from Massachusetts to Maryland were sidelined or canceled in the past year because of soaring costs. 

“Opponents of offshore wind argue that building out offshore wind infrastructure is too expensive, often without any empirical support for that contention,” Sierra Club staff attorney Sarah Krame said during a news conference June 4. “Recent increases in the cost of offshore wind and the cancellation of contracts for development of offshore wind have further raised questions about the costs and benefits of this renewable resource.” 

Synapse Vice President Melissa Whited said the authors specifically chose the highest recent construction cost as their baseline for calculating the savings for New England offshore wind, even though they hope the current financial pressures will moderate as the industry matures in the United States. 

(That would be $150.15/MWh, the weighted all-in cost of the two most recent contracts agreed upon in New York — Ørsted’s Sunrise Wind and Equinor’s Empire Wind. See related story, Empire, Sunrise Wind Back Under Contract in NY.) 

To calculate a savings of $2.79 or $4.61 per month for each New England family, Synapse modeled 9 GW of wind power feeding into the grid and performed a regression analysis of its impact on supply and demand curves.  

Wind through turbine blades is free, but natural gas prices fluctuate sharply, particularly in New England, where as much as 35% of the supply is imported LNG on peak days. 

“So, once we conducted this regression analysis, we found that adding all that offshore wind and shifting the supply curve would drop the price between 45 and 60% depending on the year,” Whited said. “And we use 23 historical weather years to account for that variation.” 

Josh Berman, a senior attorney with Sierra Club’s environmental law program, pointed out an important confluence of factors: Offshore winds blow strongest in winter, when gas constraints are highest in New England. 

“In addition, on a daily basis, offshore wind is highly complementary to solar power, having its lowest output in the middle of the day when solar generation is high and having higher operation at times when solar power is less available,” he said. 

NetZero Insider asked about the savings calculation. New York state projects Sunrise and Empire would cost utility customers an extra $2.09 a month on average, while the New England report projects monthly savings of $2.79 or $4.61 per customer using the same $150.15/MWh construction cost estimate. 

The answer is volatility, or lack of it. 

“You have different markets and different structures of those markets,” Whited explained. “We also are more gas-constrained in New England. And so what we see is during the winter when the pipelines are operating at capacity, we have very expensive generators and oil-fired generators coming online, and the wholesale electricity market prices just skyrocketing in New England.” 

She added: “You get a slightly different effect, a slightly more muted effect in NYISO because they have a different supply curve.” 

Recent history holds an example in New England that might challenge the savings model projected. 

Rhode Island Energy managed an offshore wind solicitation for Rhode Island in mid-2023, when the cost and supply chain crises were worsening. Only one proposal was submitted, and it was rejected as too costly for ratepayers. (See Rhode Island Energy Rejects Revolution Wind 2 Proposal.) 

Whited said she did not know what the proposed cost of that project would have been. 

In response to multiple contract cancellations along the southern New England coast and the offshore wind industry’s struggles, Connecticut, Massachusetts and Rhode Island joined in October 2023 for the first-ever multistate solicitation, seeking proposals for 6,000 MW of capacity. 

Projects totaling 5,454 MW were submitted by the March 27 deadline for bids. No decision has been announced on the proposals, and no indication has been offered regarding whether the construction costs would be more or less than $150/MWh. (See New England States’’ OSW Procurement receives 5,454 MW in Bids.) 

Posted on

Empire, Sunrise Wind Back Under Contract in NY

Two offshore wind projects have rebounded from the financial turmoil of 2023, finalizing replacement contracts with New York for 1,734 MW of capacity. 

Empire Wind 1 and Sunrise Wind were among a flurry of contract cancellations from Massachusetts to Maryland in the past year as costs soared to the point that construction became untenable. The two New York contracts announced June 4 are informed by the setbacks of the past year, in which developers recorded billions of dollars in impairments and government managers saw development pipelines built over the course of years shrivel in a matter of weeks. 

Importantly for the state, Empire and Sunrise are mature proposals, with key approvals in hand and onshore construction already underway. If built as planned, they will be the largest power generation projects in New York in more than a third of a century and an important piece of the state’s decarbonization and economic development strategies. 

“New York is leading the nation to build the clean energy industry, create good-paying jobs and advance our climate goals,” Gov. Kathy Hochul (D) said in a statement. “Offshore wind is a critical piece of our clean energy blueprint to address the climate crisis, and our investments are building a healthy, sustainable New York so that future generations can thrive.” 

New York has a 2035 goal of 9 GW of installed offshore wind. 

South Fork Wind gave the state its first offshore electricity. What it lacks in size — 132 MW — it makes up in bragging rights as first utility-scale project completed in U.S. waters. 

Lengthy History

Equinor/bp and Ørsted/Eversource Energy were awarded contracts for Empire and Sunrise, respectively, in New York’s 2018 solicitation.  

Inflation and interest rates soared in 2022. The two sought increased compensation from the state in June 2023, had their request rejected in October, were invited to rebid in November and were awarded tentative contracts in February. Those contracts are now finalized. 

Empire Wind 1 has a contracted nameplate capacity of 810 MW and is expected to generate first power in 2026. It received the green light from the U.S. Bureau of Ocean Energy Management in November. Equinor has begun rebuilding the South Brooklyn Marine Terminal as a hub for its own projects and for the industry. 

Equinor and bp have severed their partnership, giving Equinor sole ownership of Empire. It is looking for a new partner and expects to make a final investment decision on the project later this year. 

“Empire Wind 1 is a defining project for Equinor, and the [purchase and sale agreement] is an important milestone in de-risking and ensuring a robust path forward as we work toward delivering first power,” Molly Morris, president of Equinor Renewables Americas, said in a statement. 

Sunrise has a contracted nameplate capacity of 924 MW and also is expected to generate first power in 2026. Ørsted and Eversource announced their final investment decision in the project in late March, on the same day BOEM gave Sunrise the green light. Onshore transmission infrastructure work already has begun. 

Award of a final contract is one of the milestones that would trigger Ørsted’s buyout of Eversource’s half of the Sunrise project. Others — FERC and BOEM approvals — are yet to come. 

The new contracts carry a sharply higher upfront cost for ratepayers along with the promise of an unquantifiable societal benefit from decarbonizing the grid and billions of dollars in economic activity. 

The original contracts had an all-in average development cost of $83.36/MWh in 2018 dollars, with an average residential monthly bill impact of 73 cents. New York said the new contracts carry a weighted average all-in lifetime development cost of $150.15/MWh, with an average monthly bill impact of $2.09. 

This story was updated with additional information about the Ørsted-Eversource partnership.

Posted on

Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats

Stakeholder groups submitted comments to FERC last week in support of ISO-NE’s proposal to create a new longer-term transmission planning (LTTP) process to facilitate more forward-looking transmission investments to meet looming needs (ER24-1978). 

The new process was developed with the New England States Committee on Electricity (NESCOE) and features a default cost allocation method in which costs can be regionalized if the project is expected to bring net benefits. 

LTTP requests for proposals would be issued by ISO-NE at the request of NESCOE, and the RTO would evaluate and select a preferred solution. States then could submit an alternative cost allocation method or decide to terminate the process. (See NEPOOL TC Approves Process for States’ Transmission Needs.) 

The proposal also includes a supplemental process for projects that do not pass the cost-benefit threshold; individual states could agree to cover the costs in excess, while the remaining costs would be regionalized. 

ISO-NE filed the proposal with FERC prior to the commission’s Order 1920, which requires transmission providers to plan at least 20 years into the future, evaluate solutions with a set list of criteria and establish a default cost allocation method to apply if states are unable to reach an agreement on cost. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) The commission issued the order May 13; it goes into effect 60 days after its publication in the Federal Register; and compliance filings are due 10 months after that. 

Advanced Energy United, NESCOE, RENEW Northeast, a coalition of climate nonprofits and the Connecticut Municipal Electric Energy Cooperative (CMEEC) all submitted comments in support of ISO-NE’s proposal, applauding the agreement as an important step in proactive transmission planning. 

United wrote that the proposal is “urgently needed,” noting that “the first Order No. 1920-compliant planning cycle will not start for at least two years, with selection of transmission facilities slated to occur three years after that.” 

However, the clean energy trade association expressed concern the proposal “fails to fully leverage the benefits of transmission competition” by tilting the playing field in favor of incumbent utilities. 

“The proposal makes it very difficult for nonincumbents to offer any solutions that require new equipment on a PTO’s [participating transmission owner’s] existing transmission system,” United wrote. 

Nonincumbent transmission owners “are prohibited from identifying or installing new equipment needed for upgrades on existing lines without partnering with the incumbent PTO,” the organization added. 

These concerns were echoed in comments by RENEW and a joint filing by New Hampshire Transmission and LS Power. The latter two argued the proposal makes the same mistakes as an RFP issued by ISO-NE in 2019 to address reliability concerns associated with the retirement of the Mystic Generating Station. Most of the submissions were disqualified for relying on the land of incumbent transmission owners, which ultimately led to tariff changes intended to fix the issue, the companies said (ER22-733). 

“Under the limitations included in the proposal, only an incumbent transmission owner will be permitted to submit comprehensive solutions to identified needs,” the companies wrote, adding that the proposal contains a “a de facto [right of first refusal] for incumbent PTOs.” 

RENEW urged FERC to accept the filing as is but called on ISO-NE to initiate an additional phase of revisions to address the concerns about incumbents. 

In testimony submitted with its filing, ISO-NE said requiring complete solutions would increase “the likelihood of the process successfully leading to development of transmission solutions, rather than having the process terminate because the submitted longer-term proposals cannot be combined in a manner that addresses the identified needs.” 

CMEEC supported the proposal, calling it “a meaningful step towards the more comprehensive planning approach envisioned by the commission.” 

“The selection of projects through competitive solicitation should allow for consideration of transmission solution proposals that feature joint ownership arrangements with consumer-owned utilities,” which could provide “myriad benefits” including financial benefits for ratepayers, tax exemptions, lower cost of debt and reduced siting risk, CMEEC wrote. 

Posted on

NIA: Cost, Risk Sharing Needed to Grow Advanced Nuclear Pipeline

Speaking in Waynesboro, Ga., on May 31, Energy Secretary Jennifer Granholm celebrated the completion of Units 3 and 4 at the Vogtle nuclear power plant with a call for the United States to “draw up some more battle plans for more reactors” and triple its nuclear capacity by 2050. 

But according to a new report from the Nuclear Innovation Alliance (NIA), significant barriers remain for moving beyond first-of-a-kind (FOAK) projects like Vogtle to the nearly 200 GW of nth-of-a-kind (NOAK) advanced nuclear projects the U.S. will need to reach that 2050 goal. 

The first new reactors built in the U.S. since 2016, Vogtle’s two units have come online seven years late and $17 billion over budget, leaving subsequent projects surrounded by perceptions of risk, whether real or not, and under pressure to show they can execute on budget and on time. While the Department of Energy is funding a handful of advanced nuclear demonstration projects, “material financial commitments (i.e., signed contracts and spending on project development) to additional projects have been slow in coming,” the report says. 

These projects are generally smaller and use different, more advanced and efficient technologies than the existing 94 reactors at the 54 power plants that make up the U.S. nuclear fleet, which provides nearly 20% of the nation’s power. For example, X-energy, one of the developers receiving federal funds from DOE, is working with Dow to install four 80-MW small modular reactors (SMRs) at the company’s Seadrift, Texas, plant, where it manufactures a range of plastics and other products.  

What’s needed for a healthy pipeline of NOAKs will be a clear set of best practices, accelerated permitting, supply chain buildout and innovative approaches to cost- and risk-sharing for project developers and offtakers, the report says. 

“Faster growth and clean, firm energy is key to the growth objectives of large offtakers” and may make them more willing to accept more development risk, said Stephen Greene, a senior fellow at NIA and author of the report. 

“To accelerate commitments to advanced nuclear, energy offtakers may need to accept a greater portion of the project risks than they do through traditional offtake agreements, such as providing part of the capital commitment to address anticipated costs,” Greene said, speaking at a launch webinar for the report June 3. 

Offtakers sharing costs and risks could receive “compensation later, such as an adjustment to offtake costs or participation in project returns,” the report says. “The most impactful private-sector action would be for offtakers to make capital commitments to provide a backstop of project completion costs,” and the Department of Energy also might chip in to cover at least part of any cost overruns, the report says.  

Kreshka Young, Dow’s North America business director for energy and climate, said her company is financing the upfront development of the X-energy SMRs like any “project in our normal course of our capital planning, and it will go through our normal capital approval process.” 

Dow eventually could look for partners, as offtakers or owners, Young said, but she expects the company’s ownership and business models likely will evolve over time. “But again, at this stage, with the risk levels where they are, the perceptions of risk especially where they are, Dow is today the primary owner of the project.”  

“The real emphasis of the report is how to make projects more attractive to capital markets,” Greene said. “Additional financing either from private-sector participants or from new federal capabilities is a kind of assurance that I think capital markets are going to need, especially for initial projects to address … both the perceived and the real risk of cost overruns.” 

Other topline findings and recommendations in the report include: 

    • Due to the higher costs of FOAKs, the only way these projects pencil out is if they are developed as part of “an intended multi-project deployment plan (through which the cost of early projects can be shared among the projects).” Costs also can be shared via an “order book” of a number of projects of the same design. 
    • In the absence of ongoing, widespread nuclear construction, the U.S. must rebuild its supply chain for new plants, in particular, for the high-assay low-enriched uranium (HALEU) used in advanced and small modular reactors. 
    • Reforms are needed to streamline and speed permitting of new projects at the Nuclear Regulatory Commission (NRC). In a separate overview of potential NRC reforms, NIA noted licensing for advanced and small modular reactors “is challenging because the current licensing pathways have been tailored to conventional, large light water reactors.” 

So far, the NRC has certified the design for only one SMR, the NuScale reactor, and authorized construction of a test advanced reactor developed by Kairos Power, according to the report.  

From FOAKs to NOAKs

Throughout its construction, Vogtle’s repeated delays and cost overruns made the project a point of controversy, particularly for Georgia Power customers who will pick up $7.56 billion of the price tag for finishing the two units. A report in The Atlanta Journal-Constitution estimated that paying off that extra cost could increase utility bills by 10%.   

But with the two units completed and online, Granholm and others at DOE have hailed Vogtle as a major success.  

The expanded plant will be producing roughly 35 million MWh of power per year for the next 80 years, “so that is a multigenerational asset,” said Julie Kozeracki, director of strategy at DOE’s Loan Programs Office, which provided about $12 billion in loans for Vogtle.  

Kozeracki stressed that the lessons learned from the construction of Unit 3 resulted in lower costs and shorter timelines for Unit 4.  

“Many of the challenges faced at Vogtle were true first-of-a-kind issues,” she said. “So, for example, construction began without a complete design, without a mature supply chain, without a trained workforce. But in the course of building Vogtle, we’ve now solved these issues. … 

“Unit 4 was roughly 30% cheaper and more efficient than Unit 3,” she said, and the time needed for testing plant systems went from 94 days at Unit 3 to 42 days at Unit 4.  

“So the worst thing we could do would be to stop after two units,” Kozeracki said. “Vogtle 3 and 4 are a downpayment for everyone to capitalize on.” 

Larger reactors, like the Westinghouse API 1000 reactors used at Vogtle, also can offer economies of scale, which may be particularly attractive to industrial and data center customers looking for large amounts of firm, clean power. 

Many existing nuclear sites have room for additional reactors, she said. Vogtle is the only site in the U.S. with four reactors. “Multi-unit nuclear sites are 30% cheaper to operate than single-unit sites, but we have currently 19 single-unit sites. We have 31 sites with two reactors, three with three reactors … so we have a lot of room to grow.” 

Still, going forward will require a rebalancing of risks, especially for utilities, Kozeracki and Greene said.  

Regulated utilities often cannot recover the high upfront costs of siting, permitting and construction of a new nuclear plant until it goes into operation and “the electricity rates they can charge to customers are not structured to incorporate that degree of risk,” the report notes. 

“Tech companies like Google, Microsoft and Amazon have so much to gain with [nuclear] assets coming online,” Kozeracki said. “And they are growth companies that are in a position to take risk, and they have the cash on hand to take some of that risk. So, I think in order to execute on an effective energy transition, utilities are going to have to learn to become more like growth companies.” 

“The objective is to get over the hump of concerns about risk and get to a point where we’re building these projects more in the regular course,” Greene said. “Then the companies that are building them will have the ability to take those risks.” 

Posted on

Senate Energy Committee Advances Biden’s FERC Nominees

The Senate Energy and Natural Resources Committee advanced all three of President Joe Biden’s nominees to FERC with broad margins in a business meeting held June 3. 

“Two of the five seats on the commission are already vacant, and a third will expire at the end of the month,” committee Chair Joe Manchin (I-W.Va.) said, referring to Commissioner Allison Clements (D). “Confirmation of these three nominations will ensure that the commission has a full complement of five commissioners continuing important work. I believe all three are well qualified and intend to vote for all three.” 

Manchin, while still caucusing with the Democrats, recently left the Democratic Party to become an independent. 

Clements’ term expires June 30; if she leaves before a replacement is approved by a floor vote in the Senate and sworn in, FERC could lack a quorum. Commissioners can stay on past their term’s expiration if a replacement has not been confirmed until Congress adjourns at the end of the year, but Clements has not said exactly when she plans to leave. 

“By one estimate, the commission regulates activities that account for 7% of our nation’s economy,” committee Ranking Member John Barrasso (R-Wyo.) said. “And for that reason, we must fulfill our responsibility to maintain a quorum on the commission.” 

FERC was left without a quorum at the beginning of President Donald Trump’s term for seven months, meaning it could not vote out any orders, and Barrasso said he does not want that situation repeated. He also supported all three nominees. 

Several committee members voted against the nominees, but none were in doubt, with both David Rosner and Lindsay See advancing by a 16-3 vote and Judy Chang by 15-4. 

FERC must have at least two members who are not in the president’s party; the current makeup is 2-1, with Commissioner Mark Christie the lone Republican. 

Rosner is a FERC staffer who was detailed to the ENR Committee and generated opposition from the left, with Sen. Bernie Sanders (I-Vt.) voting against him, despite being backed by the Democrats. 

Chang, another Democratic pick, also faced some opposition from Republicans. She is a longtime industry expert who served as undersecretary of energy and climate solutions in former Massachusetts Gov. Charlie Baker’s (R) Executive Office of Energy and Environmental Affairs. 

The Republicans put forward See, who is the solicitor general of West Virginia, having argued that state’s and others’ cases against the Obama EPA’s Clean Power Plan, which led to the “major questions” doctrine. 

Sen. Josh Hawley (R-Mo.) voted against all three nominees as a protest against the Grain Belt Express transmission line being developed by Invenergy, which could be in a National Interest Electric Transmission Corridor designated by the Department of Energy — giving FERC backstop siting authority over its path through his state. (See On the Road to NIETCs, DOE Issues Preliminary List of 10 Tx Corridors.) 

“FERC has the ability to countermand state authorities, essentially to bypass the state regulatory process and designate the land — including potentially taking it,” Hawley said. 

At their confirmation hearing, Hawley had asked all three nominees to guarantee they would take into account the interests of local farmers and residents and not “rubber stamp” DOE’s corridors. 

“I was particularly disappointed to [hear] the answer of Ms. See, who would not answer my question,” Hawley said. “And I just want to say as a Republican, I’m not going to vote for other Republican nominees who will not stand up to the power grab that is happening all across the country, and of which my state in particular has been a victim.” 

In response, Barrasso read off a written answer See had given to that question that will sound familiar to anyone who follows FERC, where its members take pains to avoid stating their opinions on specific cases that come before them to avoid having parties file recusal motions against them. 

Hawley “accurately asked” See to exercise caution when approving transmission lines, and she responded she would follow the law, Barrasso said. 

“She went on to say, ‘Sensitivity to how federal actions affect state and local communities is essential when making policy decisions,’” Barrasso said. “And she added, ‘I would consider a proposal’s consequences for local landowners important to the public interest analysis.’” 

Posted on

ACEG Report Lays out the Case for Proactive Planning in PJM

PJM should adopt a more proactive transmission planning process to deal with the changing resource mix and growing demand on its system in the coming 15 years, according to a report released June 4 by Americans for a Clean Energy Grid (ACEG). 

“Transmission Planning for PJM’s Future Load and Generation” was written by Grid Strategies and David Gardiner and Associates. 

“This report takes a deep dive into some of the inputs that PJM needs to take a closer look at in conducting more holistic scenario planning,” ACEG Executive Director Christina Hayes said in an interview June 3. “PJM has been making progress in evolving its transmission planning in recent months, and we’re excited about those efforts. We know that more will be required in implementing Order No. 1920, and we believe this report provides a road map to doing so.” 

Skeptics of proactive planning argue that transmission plans are full of uncertainty and speculation, but ignoring the massive changes impacting the energy industry and continuing to plan reactively will not address those concerns, the report says. Uncertainty is best addressed by incorporating the best data on the future resource mix and running different scenarios to determine the optimum set of solutions, as Order 1920 requires. 

The report forecasts demand will be higher than the forecast PJM released early this year by about 8% in its “Expected” scenario and 18% for a high-growth scenario. Even those scenarios might be conservative given the continual announcements of new manufacturing facilities and data centers. 

“We find PJM will need an additional 623 TWh of annual energy generation by 2040 to meet this resource gap under our Expected scenario — equivalent to 76% of PJM’s 2023 generation,” the report says. “Under the High scenario, PJM faces a larger resource gap in 2040 and will need to nearly double current energy generation by adding 798 TWh. The increase is driven by higher electrification estimates leading to larger load growth and higher amounts of generation retirements due to shorter plant lifespan assumptions.” 

The biggest difference between PJM’s load forecast and the two scenarios in the report is the latter assume higher demand from electrification and higher generation retirements. The electrification estimates in the report are based on projections from the National Renewable Energy Laboratory, while the report says PJM’s Independent Market Monitor has estimated higher retirements than the RTO itself. 

“I think the one thing we can be certain of with every single demand forecast we have seen recently is that they will all be wrong. Right?” Hayes said. “Nobody is going to forecast the future with 100% certainty.” 

But one thing that is certain is that several factors are leading to higher demand, and it makes sense to ensure transmission is ready to meet that on time, she added. 

“We do need to be thoughtful and measured in how we plan for it,” Hayes said. “But in doing so, we need to take the long view because if we wait until it’s upon us, we’re either going to have outages, or resources that we want to keep in the United States are going to end up being located outside the United States, which is a national security problem. Or we’re going to develop the grid in a more expensive way.” 

The Regional Transmission Expansion Process in place now includes a short-term reliability process looking out five years and another reliability planning process that looks out 15 years, both using base cases based on power flow models that includes capacity cleared in the market and only announced retirements. Retirements require only 90 days’ advance notice. 

Better anticipating retirements can help significantly, as seen recently with the Brandon Shores coal plant in Baltimore. PJM found the grid would need $785 million in transmission upgrades for it to retire reliably; those will take until 2028 to complete, 3.5 years from the plant’s desired retirement, the report says. A reliability-must-run deal for the plant might cost consumers an additional $250 million a year, which could have been avoided or lowered with proactive planning. 

“In Order 1920, FERC did a good job of identifying the various factors, looking at fuel costs and market impacts and likely resource retirements, and doing a deep dive on what the generation resource mix is likely to be in five to 10 to 20 years, and rolling those factors into multivalue, holistic planning,” Hayes said. 

Another issue in PJM is a growing share of renewables as state and federal policies, lower costs and consumer demand push more and more onto the grid. While some states have policies driving that transition, others are not interested in it at all. Hayes argued that holistically planning the entire grid would even benefit the latter. 

“There’s a lot of flexibility in FERC’s rule to allow states with additional goals to assume part of the costs and ensure that states that also partake in the economic/reliability benefits contribute as well,” Hayes said. “It’s the idea of a region being seen as a region rather than a loose collection of states; it is just more cost effective for the region to plan transmission together and then allocate the costs.” 

Posted on

Pathways Backers Advance WEIM/EDAM Governance Proposal

Backers of the West-Wide Governance Pathways Initiative will move quickly on a proposal to alter the governance of CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM) after voting to approve the plan May 31. 

The initiative’s Launch Committee unanimously endorsed step 1 of the “stepwise” proposal the group issued in April. The proposal calls for CAISO to revise the WEIM charter to elevate the oversight position of the market’s Governing Body over WEIM/EDAM matters to “primary” authority, rather than the “joint” authority it currently shares with the ISO’s Board of Governors. (See Western RTO Group Floats Independence Plan for EDAM, WEIM.) 

“We’re thrilled to be able to move forward with step 1 and start to engage with … CAISO in a different way,” committee Co-Chair Kathleen Staks, executive director of Western Freedom, said after the vote. 

The Launch Committee now will submit step 1 of the proposal to CAISO Board Chair Jan Schori and WEIM Governing Body Chair Andrew Campbell to kick off a stakeholder process at the ISO this month. 

Pathways backers anticipate CAISO will hold an initial public stakeholder call — with the Launch Committee presenting — in mid-June. That would be followed by a three-week comment period, a committee response period and a public meeting for a joint decision by the board and Governing Body in late July or early August. 

“Let me start by really thanking the Launch Committee for taking up the concept that the regulators had put forward last summer, fleshing it out and producing such an astonishing work product,” Oregon Public Utility Commissioner Letha Tawney said. 

Tawney was among the group of Western state energy officials who launched the Pathways Initiative last July to increase the potential for creating a single day-ahead electricity market for the region that expressly includes California and leans on the technical capabilities of CAISO. 

Arizona Corporation Commissioner Kevin Thompson, another initial supporter, commended the Launch Committee’s progress despite conflicts that arose at a previous private meeting of the committee in Phoenix. 

“There was some tension there in the room a little bit here and there,” Thompson said, “but to see where the stakeholders have moved the conversation to get us toward independent governance, and giving prior primary authority to the EIM as the governing board, is a step in the right direction that gets us away from the joint authority and starts moving us really closer towards independent governance.” 

The Pathways Initiative’s final proposal included a handful of changes from the original version, including expanding the responsibility of the Governing Body to respect both state and “local” policies in its decisions and highlighting the existing right of the body to institute a governance review process with the ISO board in the event of a mass withdrawal of EDAM entities from the market. 

The proposal also clarified the workings of the dual filing — or “jump ball” — process that would occur in the event the CAISO board disagrees with a tariff filing approved by the Governing Body and decides to submit a parallel filing with FERC.

Next Steps and Phases

The Launch Committee also voted to continue developing step 2 of the proposal, which will seek to transfer governance of the WEIM — and its associated future EDAM — to an independent “regional organization” (RO) that the Pathways group expects to establish next year. 

Step 2 poses greater challenges than the first step because it requires convincing the California legislature to pass a bill authorizing CAISO to transfer its authority over a large part of its market to the RO. While the Launch Committee itself will not be participating in those efforts, many of its members will be in their capacities as individual organizations with interests in the change. 

Launch Committee member Spencer Gray, executive director of the Northwest & Intermountain Power Producers Coalition, said step 2 also must address the “core tension” between the two options being considered for the structure of the RO, which relates to “the degree of institutional independence of the regional organization and the financial liability and responsibility that comes along with institutional independence.” 

Gray pointed to the series of “work streams” the Launch Committee has identified for its Phase II work plan, which focuses largely on issues embedded in step 2. The committee has appointed two leads to deal with each stream, which include:  

    • exploring the stakeholder process for the RO, including examining sector-based approaches and how to frame policies; 
    • dealing with CAISO-related issues; 
    • analyzing the existing CAISO tariff, which could entail identifying the functions of a balancing authority under a new market arrangement; 
    • addressing public interest issues, including considering the evolution of the WEIM’s Body of State Regulators; and 
    • addressing RO formation and governance, which would range from incorporation to board nomination to securing funding sources. 

Committee member Lisa Tormoen Hickey, a senior regulatory attorney with Interwest Energy Alliance, told meeting participants the Pathways Initiative will need to secure about $450,000 in funding for its Phase II activities through the end of the year. Those activities will include additional legal review for RO options, proposing an RO stakeholder process, making a final step 2 recommendation, and gathering and publishing stakeholder feedback on the recommendation. 

She said the committee estimates an additional $636,000 will be needed to complete Phase III activities, which will include establishing an RO “formation” committee, developing tariff amendments and bylaws, retaining a placement firm for selecting a board and management team, and monitoring California legislative and CAISO actions. 

Posted on

SERC Reports Sufficient Resources in Summer Assessment

The SERC Reliability region is positioned to meet peak demand under normal conditions this summer, although extreme heat and a busy hurricane season could cause concerns for grid operators, the organization said in its 2024 Summer Reliability Assessment released May 30.

SERC produces its summer assessment each year as a complement to NERC’s annual SRA, which the ERO released last month. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) The report focuses on four key areas relevant to SERC and its subregions — demand, capacity resource adequacy, reserve margins and transmission adequacy — but “does not predict events or weather conditions” during the summer months.

In addition, SERC’s report “focuses on normal summer conditions,” or conditions with a 50% likelihood of coming to pass, while NERC’s assessment also considers an extreme “90/10” scenario (indicating a situation the ERO expects has only a 10% chance of happening). SERC’s assessment does include its summer transmission reliability study, which examines both 50/50 and 90/10 load projections.

In its assessment, the regional entity observed that its “footprint is susceptible to extreme heat, droughts, floods, tornadoes and hurricanes during the summer months.” The region has experienced an average of six heat waves per year over the past decade, compared to two per year in the 1960s. According to the National Oceanic and Atmospheric Administration’s weather forecast for June through August, the 16 states covered by SERC have a 43 to 50% chance of experiencing above-normal temperatures this summer.

NOAA also has predicted an above-normal 2024 Atlantic hurricane season, with 17 to 25 total named storms with winds of at least 39 mph, including up to 13 hurricanes (with winds of at least 74 mph). By comparison, 20 named storms occurred in the 2023 hurricane season, including seven hurricanes. In an average hurricane season, 14 named storms develop, and seven of these become hurricanes. SERC’s report noted the “risk of physical damage and disruption” to power facilities from hurricanes and other extreme weather events.

Along with these risks, the report also highlighted above-normal precipitation predicted across much of SERC’s footprint this summer. The RE warned that heavy rainfall can result in rapid vegetation growth, potentially interfering with transmission lines.

Despite these challenges, SERC emphasized that all its subregions have reported sufficient reserves to meet demand under normal circumstances.

Across the region, total internal peak demand — defined as the projected sum of metered generator outputs and metered line flows into the system, minus metered line flows out of the system — is projected at 262 GW. Total net internal demand — the total internal demand less controllable and dispatchable demand response — is predicted to be 252 GW. By contrast, last year’s actual system peak was 262 GW, against a forecast of 249 GW.

To meet this demand, SERC’s regionwide anticipated resources, including power transfers, stand at 328 GW, with all seven subregions also reporting sufficient internal resources to meet their expected loads. The smallest margin between resources and demand is found in MISO-Central — comprising parts of Illinois, Iowa, Kentucky and Missouri — where 20 GW of resources are available to meet 17 GW of net internal demand.

The region’s generation mix is varied, but SERC expects natural gas to account for just under 50% of generation capacity this summer with 161.4 GW. Coal is next with 64.2 GW at 19.9% of capacity, followed by nuclear energy — including the recently completed third and fourth units at Plant Vogtle in Georgia — at 42.7 GW and 13.2%. (See Southern Credits Strong Southeast Economy for Earnings Growth.)

The RE said fuel availability for gas and coal plants within the region constitutes a potential reliability risk for utilities in the region. SERC also noted severe weather poses a moderate risk of transmission impacts, though it also said its transmission reliability study projected only “localized thermal overloads and no voltage constraints in the SERC region” for both the 50/50 and 90/10 forecasts.

Posted on

Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market

The Independent Market Monitor filed a complaint May 31 asking FERC to reject all energy efficiency (EE) offers into PJM’s capacity market, alleging that none of them meet the Base Residual Auction (BRA) participation requirements (EL24-113). 

The complaint argues that EE programs that seek to help consumers buy more efficient appliances by entering into agreements with distributors and retailers — known as mid- and upstream programs — are not obtaining consumer-level data or entering into contracts with individual end users. It took aim at the measurement and verification reports of a dozen EE providers, stating they had not included information to demonstrate that installations of more efficient products occurred in a manner that would allow PJM and the Monitor to conduct audits. 

“The reports fail to provide adequate evidence to demonstrate that the included EE measures meet the requirements to be approved and to receive payment. It is unjust and unreasonable to require PJM customers to pay a total of $128 million in the BRA alone for EE MW that have not been demonstrated to meet the requirements to be paid,” the Monitor wrote. 

The complaint asks the commission to either bar the EE providers from receiving capacity market revenues in the 2024/25 delivery year or order PJM and the Monitor to open an investigation to determine eligibility. 

Following the filing, PJM emailed EE market participants that it plans to delay signing off on all post-installation measurement and verification (PIMV) reports supporting EE offers until after the complaint is resolved, which also holds up capacity market payments to EE resources. 

“Delay of PJM action on the PIMV reports provides FERC the opportunity to consider the merits of the IMM complaint,” the email said. “As a result, no payments, deficiency charges and nonperformance charges associated with energy efficiency resources for the 24/25 delivery year will be invoiced to energy efficiency providers until FERC has ruled on the merits of the IMM complaint and PJM approves or rejects the PIMV reports. All replacement transactions associated with energy efficiency providers will be terminated and may be reentered depending on the outcome of this matter at FERC.” 

PJM spokesperson Jeff Shields said the delay affects all EE offers, including components not related to midstream and upstream programs. 

A representative of one of the entities named in the Monitor’s complaint, who spoke on the condition of anonymity, said it’s alarming that PJM opted to withhold capacity market revenues with less than a day’s notice before the start of the delivery year because of a complaint still pending before the commission. 

“From our vantage point, it is hard to see this as anything other than the IMM unilaterally suspending energy efficiency and, for reasons kind of unknown, PJM going along with that and supporting that,” they said. 

They said it fits squarely in the Monitor’s role to scrutinize a particular market participant; however, the complaint appears to target an entire class of resources and enact a policy change through a FERC complaint. They noted that there’s an ongoing stakeholder process focused on the rules around EE measurement and verification that the complaint seeks to sidestep. (See “Stakeholders Regroup on Energy Efficiency Rules After MRC Rejection of Proposals,” PJM MIC Briefs: May 1, 2024.) 

“It’s entirely reasonable and within the IMM’s discretion to take as close a look as he wants at any capacity resources … but to approach it in this fashion, especially in the midst of an ongoing stakeholder dialogue on how to make the rules better — it seems entirely inappropriate,” they said. 

Monitor Joseph Bowring told RTO Insider the complaint addresses a longstanding issue with EE participation in PJM’s capacity market and is meant to ensure consumers are not overpaying for EE under the current rules. He said the complaint is unrelated to stakeholder discussions looking at how the capacity contribution of EE resources is measured and verified. On the approach PJM and stakeholders should take in that forum, Bowring said he believes the tariff does not support the resource class being a part of the capacity market.  

“EE does not belong in the capacity construct at all,” he said. 

Many of the Monitor’s arguments in the complaint echoed those made by PJM as it drafted a proposal to tighten the measurement and verification requirements for EE. During the May 1 Market Implementation Committee meeting, PJM’s Pete Langbein argued it has not been demonstrated that capacity market revenues flowing to EE participants is incentivizing consumers to buy more efficient devices they otherwise would not have. 

“They shouldn’t be able to claim things that are naturally going to occur. … If I’m making a decision to purchase a high-efficiency air conditioner, an EE provider shouldn’t be able to claim that unless they can prove” they incentivized the purchasing of that unit over a less efficient product,” Langbein said in May. 

Stakeholders representing EE providers pushed back, stating that the resource class efficiently provides a guaranteed reduction in consumption over PJM’s load forecast. 

The complaint argues that the party seeking to enter energy savings into the capacity market either must directly control the load reduction or hold a contract with the consumer granting rights to the capacity associated with the energy savings. Without contracts between EE providers and the consumers buying efficient devices, the Monitor also raised the possibility that multiple EE market participants could attempt to include the same load reduction in their capacity offers. 

“There is no evidence that Indicated Energy Efficiency Sellers through midstream and upstream programs provided legally required consideration to any end users for the rights to their projects or products. The Indicated Energy Efficiency Sellers therefore are not the owners of the requisite contractual rights required by the PJM tariff to be eligible to receive revenues from the PJM capacity market,” the Monitor said. 

The Monitor also argued that EE programs that contract with retailers and distributors may not lead to lower costs for consumers buying more efficient devices and that no change in consumer behavior has been demonstrated. 

Posted on

$1B Committed so far to Floating Offshore Wind Shot

The U.S. Department of Energy has issued an update on federal efforts to speed up development and deployment of floating wind turbines. 

The DOE progress and priorities report lays out more than 50 milestones reached since the Floating Offshore Wind Shot was launched in September 2022. 

The initiative is part of the Biden administration’s Energy Earthshot program. The departments of Commerce, Energy, Interior and Transportation are collaborating in the hopes of reducing the cost of floating turbines by 70% and installing 15 GW of total floating wind capacity by 2035. 

Floating wind turbine technology is more expensive and complex than the widely used fixed-bottom turbine designs. Also, the first large-scale floating wind projects are in planning stages in other countries. There is no operational history at scale in U.S. waters, nor is there the specialized infrastructure to build it.  

Most of the 50-plus milestones listed in the report are research and/or funding initiatives intended to change this.  

With large swaths of U.S. coastal waters too deep to affix turbine foundations to the seabed, the Floating Offshore Wind Shot is designed to allow fuller use of this emissions-free power source. DOE reports that more than $950 million has been devoted to the initiative in the past 20 months. 

Near-term priorities summarized in the report include: 

    • cost reduction — by researching resource assessment, design, modeling, manufacturing, operations and maintenance; 
    • supply chain development — by identifying gaps and solutions to inform decision-making, and mobilizing investment through federal programs and lease bidding credits; 
    • expanding just and sustainable development — by increasing the involvement of tribal leaders, fishers and communities while increasing workforce development; 
    • transmission development — with in-depth offshore wind transmission studies, improved planning tools and advancing critical components; and 
    • developing co-generation opportunities — with analyses of hydrogen generation and energy storage options, and effective designs and demonstrations. 

Featured accomplishments include: 

    • DOE announced $38 million for six projects to develop floating offshore wind designs through the Aerodynamic Turbines Higher and Afloat with Nautical Technologies and Integrated Servo-control (ATLANTIS) Program. 
    • DOE launched the $6.9 million Floating Offshore Wind ReadINess (FLOWIN) prize to develop the domestic supply chain. 
    • DOE provided more than $18 million to support research and development of HVDC voltage source converter systems and standards, controls and curricula. 
    • DOT awarded $427 million to establish the first West Coast offshore wind terminal, through the Humboldt Bay Offshore Wind Project. 
    • DOE funded research to model and analyze the levelized cost of hydrogen for de-centralized offshore-wind-to-hydrogen systems. 
    • DOI held the first floating offshore wind lease auction off the coast of California in 2022 and designated wind energy area lease auctions off the Maine and Oregon coasts in 2024. 
    • DOI and DOC expanded the Sea Grant Offshore Wind Liaison Program to the West Coast to ensure continued engagement with the communities there. 
    • DOE completed a study on the impacts of developing a floating offshore port network on the West Coast that will inform future collaboration efforts. 
    • DOE convened local stakeholders to discuss key transmission needs on the West Coast. 
    • DOE-funded projects along the Pacific Coast began collecting data to support monitoring the presence of birds, bats and marine mammals in areas where wind turbines may be sited, and to develop autonomous monitoring for marine organisms and the seabed. 

DOE concluded its report by saying much more is needed if floating wind goals are to be met and said continued collaboration by stakeholders is important. It said regular summits are planned, along with periodic updates as needed to the summary report.