The Connecticut Department of Energy and Environmental Protection launched two new clean energy solicitations Oct. 27.
The first request for proposals calls for up to 2,000 MW of new offshore wind capacity and includes provisions to avert the problems plaguing the offshore wind industry.
The onshore solicitation is broader: Developers can propose most types of clean energy technology in response, including solar, wind, zero-carbon fuel cells, geothermal, energy efficiency, run-of-river hydropower, and energy storage paired and co-located with a zero-carbon resource.
The onshore solicitation is intended to provide up to 3.975 million MWh, or about 15% of the state’s electricity load.
The two solicitations are designed to move the state closer to its statutory goals of a 100% zero-carbon electric portfolio by 2040 and greenhouse gas emissions at least 80% lower than 2001 levels by 2050.
The offshore solicitation comes at a difficult time for the young U.S. offshore wind industry.
Earlier in October, Avangrid reached an agreement to cancel power purchase agreements for its Park City Wind project, which would send up to 804 MW to Connecticut. Two major offshore projects in Massachusetts canceled their PPAs this year, and three major New York projects are considering doing the same.
The developers will likely attempt to rebid the projects they have invested billions in, but such a move would inevitably increase ratepayer costs and delay start of construction.
The problem in each case is the same: Developers’ costs for building the projects soared after they locked in the income they would receive from operating the completed projects.
Connecticut’s new offshore solicitation gives bidders a cost-indexed option allowing an up-or-down price adjustment of up to 15% based on inflation and other factors between bid submission and financial close.
Also new in this offshore wind solicitation is the option of submitting a multistate bid. In early October, Connecticut, Massachusetts and Rhode Island agreed to coordinate their offshore development efforts. Each state has been having significant difficulties in the sector, and they hope collaborating will increase efficiencies while reducing cost and risk.
The three states have now issued requests for proposals for a combined 6.8 GW of new offshore wind capacity in the space of two months.
Connecticut has included specific environmental requirements in the solicitations:
Onshore proposals must conform to the state’s broader environmental policy goals. Development in core forest is prohibited, as are solar projects on slopes greater than 15% and development on prime farmland, unless a proposal meets specific dual-use requirements.
The offshore solicitation includes a requirement for robust environmental and fisheries mitigation plans and imposes fees of at least $15,000/MW for fish and wildlife monitoring and mitigation.
Bids are due by Jan. 31. DEEP said another request for proposals — this one for energy storage — will be released in draft form this year.
“Grid-scale clean energy projects are critical investments to diversify our grid, which will help protect Connecticut residents and businesses from price spikes linked to global fossil fuel markets and geopolitical events, while making our energy supply more reliable and our air safer to breathe,” DEEP Commissioner Katie Dykes said in a news release. “Continuing to make progress toward a zero-carbon grid is essential, as the public health and economic costs of carbon pollution are now being felt more regularly and severely here at home.”
The PJM Markets and Reliability Committee (MRC) voted Oct. 25 to approve the creation of a fifth cost of new entry (CONE) area for the Commonwealth Edison (ComEd) zone to reflect an expectation that the Illinois Climate and Equitable Jobs Act (CEJA) will shorten the lifespan for combined cycle generators — the current reference resource CONE values are based on.
The vote capped months of discussions of how to reflect particularities at the local and state level that could affect the inputs in calculating the cost to build the reference resource, a subject broached by J-Power USA in a protest to PJM’s 2022 quadrennial review filing. The company argued that new combined cycle resources would be forced into retirement within the 20-year amortization period included in the CONE calculation due to the legislation’s requirement that generators have zero carbon emissions by 2045. (See “J-Power Critiques Amortization Period,” PJM Defends Quadrennial Review Parameters from Generator Protests.)
The vote, which carried 80% support, came after a motion from the Illinois Citizens Utility Board (CUB) to defer the vote by a month failed after receiving 46.7% support against the two-thirds sector-weighted threshold needed to pass. Clara Summers of the Illinois CUB said that the delay would have provided more time to evaluate the effect of the proposal and potentially develop an alternative or amendments to the package. In particular, she expressed concern the proposal had no mechanism for reevaluating whether the ComEd-specific net CONE zone is providing relevant price signals as we near 2045, the expected end date for the combined cycle reference resource.
The proposal was endorsed by the Members Committee following the Oct. 25 MRC vote. A motion to defer the vote made by Summers was rejected by the MC as well.
She argued the legislation could affect inputs used to calculate CONE beyond the reference resource asset life, including the energy and ancillary service (E&AS) revenue offset.
“This proposal focuses on one factor in setting net CONE, asset life, because of CEJA … but CEJA also has an impact on things like the E&AS offsets,” Summers said before motioning to defer the vote.
She also pointed to comments PJM made in support of its quadrennial review filing at FERC stating there hasn’t been a holistic analysis of CEJA’s impact on CONE and that creating a region to account for legislation in Illinois could establish a precedent for creating CONE areas across several states and localities to account for various policies. Instead of establishing a new CONE area to account for specific legislation in one state, she said creating a clear standard for when a new area is warranted would be preferable.
Zachary Callen of the Illinois Commerce Commission said commission staff are not opposed to creating a new CONE area on principal, but he believes it’s a complicated subject that hasn’t had enough stakeholder discussion.
“It does give us pause that this is a really Illinois- and CEJA-specific policy and what we’d like to see more is something more rules-based,” he said.
He said the tightened Base Residual Auction schedule over the next few years would provide little time for policy makers, load and generation to respond to price signals based on a new CONE area. Given PJM’s analysis that the effect would be minimal at first, Callen suggested it may be better to wait until the next quadrennial review to make the change and to use the additional time to conduct more research.
Paul Sotkiewicz, president of E-cubed Policy Associates, said he had brought an alternative proposal that would have automatically created a new CONE area when policies affecting a region affected CONE inputs. He withdrew the package out of a desire to have the reduced asset life implemented in time for the 2025/26 auction. The further in advance the change is made, the less sharp any change in CONE values would be, he said.
“It’s important to send those signals about reliability sooner rather than later, rather than have everything fall off a cliff” and risk a larger rate shock, Sotkiewicz said.
PJM’s Gary Helm said the new area would have a CONE value of $201,714/MW-year, higher than any of the existing four areas. CONE Area 3, which ComEd is a part of, has a value of $197,800/MW-year. The proposal would affect only the reference resource asset life factor, based on the assumption that natural gas resources will retire based on CEJA’s requirement that those generators reduce their emissions to zero by 2045.
Helm said waiting until the next quadrennial review would mean any changes would not be implemented until the 2030/31 delivery year, well into the period that PJM has stated it’s concerned about resource adequacy as loads increase and fossil generation retires. He said that the proposal is part of a larger strategy for maintaining resource adequacy and that making the changes at this time would avoid a sudden change in capacity prices.
The motion to defer was supported predominantly by the electric distributor and end-use customer sectors, with about 90% support in both categories. The other supplier and generation owner sectors were strongly opposed and transmission owners more mixed about the proposal, with 40% support. When the vote shifted to the actual proposal to create a fifth cone area, the transmission owner, other supplier and generation owner sectors were unanimous in their support, while 70% of the electric distributor sector and 46.2% of end-use customers voted in support at the MRC.
ERCOT stakeholders last week agreed with the staff’s decision to table a protocol revision request implementing a new ancillary service that faces a tight statutory timeline.
Kenan Ögelman, ERCOT’s vice president of commercial operations, told the Technical Advisory Committee Oct. 24 that tabling the protocol change would give the Public Utility Commission time to “digest” a recent filing by state lawmakers pushing back against the grid operator.
State Sen. Charles Schwertner (R) and state Reps. Justin Holland (R) and Todd Hunter (R) sent a letter to ERCOT and the PUC objecting to an ERCOT nodal protocol revision request (NPRR1203) that would create the new service, dispatchable reliability reserve service (DRRS), as a subset of non-spinning reserve service. The legislation (House Bill 1500) they helped push through earlier this year mandates DRRS be implemented as a standalone service by Dec. 1, 2024.
“We studied every way we could think of a standalone DRRS delivered by Dec. 1, 2024, and none of those were feasible,” Ögelman told TAC. “I could try to reprioritize as much as I wanted, and there’s just not enough time.”
He said creating DRRS as a standalone service would require market testing “that adds time to the option.”
The lawmakers differed and urged the commission to direct ERCOT to revise NPRR1203 and to establish DRRS as a standalone ancillary service, “even if doing so will cause a delay.”
Combining DRRS into non-spin will create a single clearing price that could have a negative impact on consumer costs and diminish “market incentives to invest in the specific type of dispatchable resources needed to improve reliability,” the lawmakers said.
“The purpose of this provision was to create a targeted ancillary service product that could leverage flexible, dispatchable generation resources to more efficiently manage operational uncertainty within the ERCOT market,” they wrote. “We are concerned the current proposal does not meet the legislature’s goal of creating an ancillary service product designed to meet actual system needs in a targeted, transparent manner and could have a negative impact on consumer costs.”
ERCOT filed a response with the PUC, requesting guidance from the PUC on whether to proceed with implementing DRRS as a non-spin subtype to meet the deadline or to begin developing a standalone product. It said work already has begun on the former option and that “any pause in this work would introduce risk of missing the delivery deadline” (55156).
The grid operator said TAC and its board will need to vote on NPRR1203 and two related binding document revisions (OBDRR049 and OBDRR050), also tabled, during their December meetings to stay on schedule.
The PUC plans to take up the matter during its open meeting Nov. 2.
To be eligible for DRRS, resources must be dispatchable, be off-line and able to come on-line within two hours and capable of operating at their high sustained limit for at least four hours. NPRR1203 would establish a maximum amount of non-spin that can be provided by DRRS as a sub-type of non-spin. HB1500 also requires reliability unit commitment activity be reduced by the amount of DRRS procured.
Non-spin reserves in ERCOT also are off-line capacity that can start up and provide power, usually within 10 minutes.
Representing Reliant Energy Retail Services, Bill Barnes said stakeholders are concerned DRRS delays could push back real-time co-optimization (RTC), a market mechanism that clears energy and ancillary services every five minutes in the real-time market and is scheduled to come online in 2026.
“As stakeholders, when we compare the two, I think we see much more value in RTC in terms of impact to consumers,” he said. “I think we would have concerns if that [DRRS] change in direction would change the implementation and push that back significantly.”
ERCOT’s Independent Market Monitor prefers a standalone product that it says would better address reliability needs and have more accurate pricing.
ERCOT to Propose Price Correction
ERCOT staff told TAC they were investigating a potential price correction after an Oct. 22 problem with the security constrained economic dispatch (SCED) system. Following the meeting, ERCOT made it official by issuing a market notice that said the pricing issue met the grid operator’s initial criteria for the Board of Directors to review the real-time prices before they become final.
Staff will take the price correction to the board’s Reliability and Markets Committee Dec. 18 and then the directors Dec. 19 for their approval. They also will present the potential price correction to TAC during its Dec. 4 meeting.
According to the market notice, SCED was unable to consume specific three-part supply offers (energy offer curves) and real-time energy bids for several resources after an issue with the market management system (MMS). That resulted in SCED failing to produce valid prices for its intervals between 12:15 p.m. and 12:54 p.m. Another related issue caused SCED to fail to run from 12:56 p.m. to 1:09 p.m.
Staff ran into another error trying to process the price correction data and were unable to post the corrected prices before they became final.
Ögelman said an integer field that tracks submissions, each with a unique identifier through the ISO’s systems, exceeded a limit of more than 2 billion submissions. At that point, additional submissions were rejected. That led to price spikes before noon and a little after 1 p.m.
Staff addressed the issue by freeing up some of the numbers and letting market participants resubmit. They then were able to clear the day-ahead market, Ögelman said.
“It is a parameter that dates back to nodal go-live,” he said. “It was not envisioned that we would exceed that number, but clearly, we did. I do think that ultimately, we would need to change that cap.”
Sreenivas Badri, director of grid and market solutions, told members it would take “probably five, six years” before the issue would happen again. In the meantime, he said, staff is working with a vendor to make application changes and implementing a revision that would significantly reduce the growth of unique identifiers.
TAC Endorses RUC Change
TAC approved a revision request (NPRR1172) brought forward by consumer groups that removes the mitigated offer cap multipliers and creates a 100% claw-back for RUCs. The revision’s intention is to encourage generation resources to self-commit.
“It makes sure that the generator that’s committed by ERCOT through RUC, which would have no downside risk because its costs are guaranteed, can’t make money from the RUC,” Eric Goff, who represents residential consumers, said. “It encourages self-commitment because in today’s environment, a generator that is marginal could trade some of their profits in exchange for a guarantee that they won’t lose any money.”
Not surprisingly, the generator segment opposed the measure, casting three of five dissenting votes. The cooperative segment accounted for the other two opposing votes when the NPRR passed, 23-5 with 2 abstentions.
“This is bad policy. I fundamentally disagree with Eric’s assertion that there is no downside risk because costs are guaranteed,” Luminant Generation’s Ned Bonskowski said. “I encourage anyone that is sympathetic to resources having [been] effectively co-opted by many times a load forecast that is in excess of what the market believes and incurring costs … ideally they should have full recovery, but our experience has been that is not always the case.”
The consent agenda, passed unanimously, included two NPRRs and changes to the nodal operating guide (NOGRR) and planning guide (PGRR) that, if approved by the board and the PUC, would:
NPRR1192: Incorporate the other binding document “Requirements for Aggregate Load Resource Participation in the ERCOT Markets” into the protocols.
NPRR1196: Correct and update equations used to determine ancillary service (AS) failed quantity calculations for load resources other than controllable load resources (NCLRs) developed under NPRR1149. Changes would include: calculation updates to account for AS allowances and restrictions that NCLRs can and cannot carry simultaneously with ERCOT contingency reserve service’s (ECRS) implementation; specifying the snapshot components to be used for the “telemetered AS for the NCLRs as calculated” variable; and adding a non-zero check for the “telemetered ECRS responsibility for the resource as calculated” variable.
NOGRR257: Resolve a conflict in emergency response service event-reporting timelines between the operating guide and protocols by striking the guide’s 90-day event-reporting requirement.
PGRR110: Remove a paragraph from the guide to accommodate the release of steady-state planning models in node-breaker format pursuant to a system change request.
The U.S. Department of Energy will put $1.3 billion in federal funds into becoming the anchor off-taker for three interstate transmission projects that together will put 3.5 GW of new transmission capacity online, Secretary Jennifer Granholm announced on Oct. 30.
Under a program set up by the Infrastructure Investment and Jobs Act (IIJA), the department will start negotiating contracts for up to 50% of the capacity on the lines, with the goal of de-risking and accelerating construction of projects that provide vitally needed new interregional transmission, according to DOE.
Located in the Southwest, Mountain West and New England regions, the projects were selected based on regional needs and priorities detailed in DOE’s final National Transmission Needs Study, also released on Monday, according to the department.
Speaking during an advance press call on Friday, Granholm explained that having DOE as an anchor off-taker — an entity that commits to buying a significant amount of power from a project — will minimize upfront financial risk and give “developers the confidence that they can actually build.”
Calling the contracts a “unique and creative solution,” Granholm stressed that “these awards are not for construction costs.” A developer would not receive any cash until a project is completed and online, and DOE will be able to sell its capacity to other off-takers, ensuring funds are available for contracts or other support for additional projects.
Ideally, the risk to the department will also be minimal. DOE’s commitment could draw in other off-takers, so the project is “fully subscribed by other customers before the project is finished and energized,” according to a DOE email.
The IIJA provides $2.5 billion for the initiative, officially called the Transmission Facilitation Program (TFP), which is being administered by DOE’s Grid Deployment Office. The money will be used in a revolving fund that can be awarded to projects via capacity contracts, loans or public-private partnerships.
The program webpage says TFP awards are best suited for projects that are nearly shovel-ready, and that no awards will be made to projects that are already fully subscribed or “have a fully allocated source of revenue.”
A second round of funding, for up to $1 billion, is expected in the first half of 2024, DOE said.
The three projects selected for the first round of TFP funding, all in the form of capacity contracts, are:
The Cross-Tie Transmission Line, a 1,500-MW line running 214 miles between Utah and Nevada. The line will improve grid reliability and resilience, relieve congestion on other lines and allow access to low-cost renewables in the region.
The Southline Transmission Project, a 748-MW line stretching 175 miles between Hidalgo County, N.M., to Pima County, Ariz. This project will support ongoing renewable energy development in southern New Mexico while delivering clean energy to areas in Arizona currently dependent on fossil fuels.
The Twin States Clean Energy Link, a 1,200-MW line connecting New Hampshire and Vermont to clean energy resources in Canada. The bidirectional line will also allow New England to export power to Canada from future offshore wind projects. The 185-mile project includes 75 miles of new underground line and 110 miles of upgraded lines in an existing right of way, according to the project website.
The Cross-Tie and Southline projects are expected to break ground in 2025, with the Twin States line to follow in 2026, an administration official said. According to the Transmission Needs Study, all three projects are in regions that will need major amounts of new transmission or interregional transfer capacity by 2030.
In the Mountain West region, the DOE study anticipates a need for nearly 2,300 GW-miles of new transmission as clean energy projects come online, leveraging incentives in the Inflation Reduction Act. The study also predicts 1.5 GW of interregional transmission will be needed in New England.
DOE defines gigawatt-miles as capacity multiplied by distance. The department said the figures in the Needs Study could be met with a mix of projects; for example, the 2,300 GW-miles needed in the Mountain West region could be broken down into nine 200-mile, 500-kV lines, but other configurations are possible, the department said.
Top Need: Reliability
The Biden administration sees high-voltage transmission as critical to reaching its goal of a decarbonized grid by 2035 and net-zero greenhouse gas emissions economywide by 2050.
Speaking on Friday, National Climate Advisor Ali Zaidi noted the TFP announcement follows other administration initiatives on transmission, such as DOE’s recent selection of 58 projects to receive $3.46 billion in IIJA funds for local grid improvements. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
Such federal funding “is doing exactly what it was designed to do,” Zaidi said. “It’s catalyzing the private sector, industry and labor all to step up at this moment of critical need.”
Granholm also hailed the number of jobs the projects could create — 13,500 direct and indirect positions — and the community benefit packages all the projects have negotiated with stakeholders and communities affected by their projects. The Twin States project is providing a community benefits package that includes $60 million to be divided between the nonhost states of Massachusetts, Connecticut, Rhode Island and Maine, according to a DOE fact sheet on the project.
Extreme weather events have also underlined the need for more interregional lines to move power in emergency situations and to allow clean energy produced in remote areas to move to where there is demand for it. The Needs Study calls for the U.S. to double existing regional capacity by 2035 and expand interregional capacity fivefold, according to a DOE press release.
The report’s top takeaways, Granholm said, are, “no surprise, that we need to seriously build out transmission in order to improve reliability and resilience, and of course, to lower energy costs and relieve congestion on the grid.”
Reliability has remained a key driver for new transmission, growing from 44% of new lines in 2011 to 74% in 2020, according to the report. The most pressing and valuable new lines are needed between Texas and all its surrounding regions, and between the Plains and Mountain West, the report says.
The report anticipates that by 2035, Texas will need a median of 9.8 GW of additional transfer capacity with the Plains region, a whopping 1,201% increase over 2020 levels. Slightly less eye-popping, New England will need to expand its interregional lines with New York about 255%, or 5.2 GW, and the Midwest will need a 156% increase, or about 33.8 GW, of new interregional capacity with the Mid-Atlantic.
According to the Needs Study, the proportion of overall transmission installed to address system reliability needs has grown from 44% in 2011 to 74% in 2020. | DOE
Reactions
One of the developers on the Southline project, Michael Skelly, CEO of Grid United, sees the TFP as a kick-starter for interregional transmission growth.
Developers want to sign up off-takers for as much of a line’s capacity as possible before putting steel in the ground to minimize their risk, Skelly said in an interview with RTO Insider. For Southline, getting the line’s 748 MW fully subscribed is “a tall order even in today’s markets. So, this lowers the bar. If we get one customer [taking] a few hundred megawatts and we have DOE, off we go,” he said.
Echoing DOE, Skelly said having the department on board will draw in other off-takers, so its share of the project’s capacity likely will be sold before it goes online. DOE “might actually never put a penny out the door,” he said.
Stephen Woerner, New England president for National Grid, the lead developer for Twin States, said the TFP announcement “is an important step forward … as we work to make the project a reality for the region. DOE has recognized the significant economic and environmental benefits of this project to New England communities, residents and businesses.”
Rob Gramlich, president of Grid Strategies, said TFP “can address the perennial ‘chicken and egg’ problem with transmission,” in which construction may wait upon demand, but demand waits upon construction. Having DOE as an anchor off-taker “promises to work a lot better than the current stalemate,” he said in an email to RTO Insider.
But Gramlich also feels the program’s $2.5 billion pot “only allows [it] to support a very small set of lines. Congress and the administration should prioritize raising that pot in future appropriations.”
GULFPORT, Miss. — The Organization of MISO States took time to celebrate its 20-year anniversary at its annual meeting while exploring familiar themes of restructuring resource adequacy and barriers to large transmission buildout.
OMS was incorporated in mid-2003, two years before MISO’s energy markets went live. Former OMS board members and chairs reminisced about the past two decades of the organization during the Oct. 26 meeting.
Bill Smith, OMS’ original executive director, said he hatched a nascent idea for the organization by scrawling notes on a “too early” flight. He said OMS was formed before cellphones and even conference calls.
“We were working in a different kind of technology,” Smith said.
Founding OMS board member Steve Gaw said state commissions at the time were looking for a way to bridge state matters with RTO and federal matters.
Gaw said commissioners were motivated to form OMS based in part on a worry that if they didn’t do it, someone else might. He said initially, founding members didn’t know how they would conduct meetings and get funding, or whether MISO would object to the organization’s creation and how much information the RTO would share with it.
“I didn’t know if this was going to be a long-lived thing, or if someone would challenge it or in two to three years, [or] it would go away,” Gaw said. “The reason it’s still here is because it’s valuable.”
Gaw said several commissioners involved in OMS still share a spirit of working together and moving past differences.
David Boyd, former OMS board member and Minnesota commissioner, said the Minnesota Public Utility Commission didn’t create staff positions dedicated to RTO matters until funds were freed up with the Emergency Economic Stabilization Act of 2008 (the so-called Wall Street bailout). He said OMS is key to state collaboration and understanding MISO initiatives.
“You felt like you had colleagues all across the country,” former OMS President and Michigan Public Service Commission Chair Sally Talberg said.
Outgoing OMS President and current Michigan PSC Chair Dan Scripps said organization leadership this year focused on making it more unified. He said it was a strategic choice to have OMS’ 20th annual meeting in a MISO South state.
“There are regional differences; there are state differences; but they make us stronger,” Scripps said.
The OMS Board of Directors unanimously elected Wisconsin’s Tyler Huebner to serve as the 2024 president.
Also at the meeting, members created the David Carr Award for Outstanding Staff Contributions, an annual award for regulatory staffers and named for Mississippi Public Service Commission counsel David Carr, who died in late December. Carr’s father, Mississippi PSC Commissioner Wayne Carr, received a standing ovation upon the award’s unveiling.
Werner Roth, an economist at the Public Utility Commission of Texas who helps chair multiple MISO stakeholder committees, is the award’s first recipient.
Reconsidering Resource Adequacy
Sixteen years after OMS helped shape MISO’s first comprehensive resource adequacy plan, regulatory staffs are again rethinking the RTO’s RA construct and invited experts to speak at the meeting on what they would prescribe.
National Association of Regulatory Utility Commissioners staffer Elliott Nethercutt said with 72% of the nation’s dispatchable, on-demand generation expected to retire by 2040, the entire industry must reconsider RA. He predicted state regulatory organizations like OMS are going to become even more critical as states test approaches to decarbonization.
Kelli Joseph, of the University of Pennsylvania’s Kleinman Center for Energy Policy, called for “coordinated, reliability-informed” RA and operating reliability planning in which states and RTOs alike have a role. RTOs should assess states’ resource plans collectively and advise on red flags, she said. That way, states could understand the effect of their resource planning decisions on other states.
“The lack of this type of planning is a reliability risk,” Joseph said.
In addition to operating reserves, Joseph said grid operators need resources that meet public policy goals alongside “balancing resources,” or quick-start, fast-ramping resources in the form of either gas or batteries.
Joseph said scarcity pricing “has never been a sufficient investment signal to meet reliability targets”; that’s becoming especially apparent in the resource transition. She said LMP is helpful only to encourage short-term dispatches, and “using a price alone” to incent the entry of certain types of resources is flawed.
“I think we’re at the point where we need to have conversations about what we’re doing: … what is the public good, and what are we doing to manage this public good of a reliable electric system?” she said. “It’s too essential to get this wrong.”
“It’s hard to have long-term market signals,” agreed former Arkansas Public Service Commission Chair and Energize Strategies founder Ted Thomas. The system needs a “sharing of responsibility and sharing of costs” when it comes to operations reliability.
“Who wants to be the regulator to put in a gas plant with carbon capture with a per-unit cost of a gazillion? Who here wants to do that?” he asked rhetorically.
Joseph said RTOs could help states determine if they want to divvy the costs of building critical but seldom-used resources.
Thomas said MISO’s filing at FERC for a sloped demand curve in its capacity market exemplifies the consequences of states’ inaction. From 2015 onward, states protested MISO’s suggestion to use a sloped demand curve in the auction, insisting it would impede states’ authority on resource planning — that is, Thomas said, until the 2022/23 Planning Resource Auction cleared Midwestern zones at a $240/MW-day cost of new entry. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) He said after that, states asked MISO, “‘What are you going to do about this?’” resulting in the sloped curve’s rebirth.
“We have to get in front of this if we want jurisdiction. Because we have a problem, and if we don’t get ahead of it, we’re going to get the sledgehammer and, with it, a chunk of our jurisdiction [taken away],” Thomas said.
North Dakota Public Service Commissioner Julie Fedorchak said that while she isn’t worried about RA in the long run, she is worried about the next five years “because everyone is really eager to get going on these goals” and shift the resource mix without enough attention on how demand will be met at all times.
“This is not a place for experimentation. This is the foundation of our society, and we have to get it right,” Fedorchak said.
Thomas also said he wished EPA would reread MISO’s comments raising the alarm on the agency’s new proposed emissions standards for power plants. The RTO said the proposal would supercharge retirements so they outstrip the commercialization of new technologies like green hydrogen and carbon capture. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.)
He also said there is currently a lack of balance in political power over energy decisions, as the left has taken the lead over decisions on the energy transformation.
“The right has no credibility because they’re on a hangover from climate denial. They have no credibility right now to say the science might be exaggerated,” Thomas said.
Overcoming Transmission Planning Challenges
Regulators also touched on the venerable subject of stumbling blocks to transmission planning while the federal government pushes for a sturdier system.
Grid United CEO Michael Skelly said he views new transmission lines as essential to maintaining RA while dealing with load growth, two topics on his mind lately.
Panelists agreed that long-distance buildouts are useful to dodge blackouts during extreme events.
“Look at [Winter Storm] Uri: We’re paying no matter what we do. I don’t know about the rest of the world, but in Texas, we’re paying $9/month for pretty much ever,” Skelly said.
MISO long-term planning studies and revived federal studies like the National Transmission Planning Study to pinpoint beneficial line routes embody the Hippocratic Oath of “first, do no harm,” Skelly said. “I think if you look at all these studies and squint, it’ll point the way.”
“Projects are not shockingly hard to come up with. We’ve seen the same lines come up time and time again,” MISO Senior Vice President of Planning and Operations Jennifer Curran said of interregional transmission needs under MISO’s Joint Targeted Interconnection Queue (JTIQ) portfolio of 345-kV lines. The $2 billion portfolio has received $464 million from DOE under the Infrastructure Investment and Jobs Act. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)
Curran said that while line needs are relatively easy to deduce, how to share the costs of those lines is a major sticking point that slows the transmission planning process. MISO is trying to reproduce a JTIQ-style study for its seam with PJM, but Curran expressed reservations over the differences between the RTOs’ planning styles.
“SPP and MISO think about transmission planning very similarly. PJM and MISO do not. We’re going to try, but I have my optimism a little tempered,” she said.
Serving as moderator, OMS President Scripps joked that sometimes when he looks at the overlays of prescribed transmission line opportunities and thinks of all the permitting and cost allocation obstacles that can topple them, he is sometimes “bullish” on a future with high distributed energy resources instead.
“This is a very exciting time to be doing this,” Skelly countered. “This must have been how it felt to develop infrastructure in the ’60s. Because people want so much of it.”
But Skelly said too much is heaped on the transmission siting process, including environmental concerns, land acquisition, some cost allocation details and landowner concerns.
“We really burden the siting process with a lot of stuff,” he said. “That’s a lot to put into one process.”
Skelly said Grid United is trying to “de-pancake” siting by isolating risks to development and handling land acquisition of routes first before moving onto other steps of the process.
When FERC convened the New England Winter Gas-Electric Forum in Portland, Maine, in June of this year, the commissioners grilled ISO-NE executives, government officials and company representatives about how they will meet the impending electricity demand from electrification. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.)
As weather-dependent renewables replace legacy fossil fuel units, how will the region ensure it has enough power during extended winter periods when the wind dies down and there is little sunlight to draw upon?
While others highlighted the uncertainty associated with predicting the future resource mix past 2030, Richard Paglia of the gas pipeline company Enbridge was quick to point to a simple solution: more natural gas.
“To me, the glue that holds all of this together [is] the gas plants that are highly dispatchable and can solve that problem,” Paglia said. “But we don’t have the supply to allow those plants to run when needed.”
In September, Enbridge followed up on its prescribed solution and announced a project to significantly expand the capacity of the Algonquin gas pipeline into New England, which the company hopes to complete by the end of 2029. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.)
But this solution would not come without major tradeoffs: Five of the six New England states have set strong decarbonization goals, and natural gas is one of the major sources of carbon emissions and air pollution in the region. Meanwhile, climate and environmental justice groups have vowed to fight the expansion and hold climate-focused politicians to their rhetoric.
At the same time, early-stage clean energy companies are scrambling to address this energy reliability gap, hoping to fill the firm generation role that has historically been dominated by fossil fuel resources.
Form Energy, a company started in 2017 and headquartered in the city of Somerville, Mass., is developing long-duration iron-air batteries that it hopes to pair with renewable energy to firm up that generation across extended stretches.
Form’s batteries are built to provide 100 hours of energy and charge by converting rust to iron, a process that is reversed when discharging to produce electricity.
“The technology is quite ready,” Marco Ferrara, Form’s co-founder and senior vice president of analytics and software, told RTO Insider. While the company has made significant scientific advances in getting high capacity out of the batteries, “the technology is inherently simple.”
Most current grid-scale batteries have comparatively short durations, sitting in the two- to four-hour range. The U.S. Department of Energy defines inter-day long-duration energy storage (LDES) as the ability to shift power 10 to 36 hours, and multiday LDES as shifting power for a period greater than 36 hours.
According to a DOE report on LDES released in March, the U.S. could need between 225 and 460 GW of LDES capacity to reach net-zero by 2050, which would require about $330 billion in capital investment.
The report found that LDES could replace the need for over 200 GW of new natural gas capacity by 2050, and that LDES reduced the need for natural gas in all modeled scenarios.
“Analysis shows that by 2050, net-zero pathways that deploy LDES result in $10 billion to $20 billion in annualized savings in operating costs and avoided capital expenditures compared to pathways that do not,” the DOE report concluded. To achieve this, LDES deployment capacity must reach 10 to 15 GW per year by 2030 and 30 GW per year by 2040, the report found.
Form does not have any utility-scale batteries in operation but has several pilot and demonstration projects in the pipeline. The company is currently developing a 1.5-MW pilot project with Great River in Minnesota, two 10-MW projects with Xcel Energy in Minnesota and Colorado, a 5-MW project with Dominion Energy in Virginia, a 10-MW project with the New York State Energy Research and Development Authority and a 15-MW project with Georgia Power. The expected in-service dates range from 2024 to 2026.
The two projects with Xcel will be located at the sites of two retiring coal plants, chosen in part because of the ability to charge the project with nearby renewable power, existing water-supply infrastructure and the ability to upgrade grid interconnection infrastructure.
The company performs most of its research and development in its Somerville lab, where engineers test all sorts of variables in thousands of battery cells lined up in long rows, separated by grocery store-style aisles.
While the company does not have any projects in development for New England, it sees great potential for the technology in the region. A white paper published by the company in late September found that by adding 23 GW of multiday storage capacity by 2050, the New England grid would see a 33% reduction in the cost of eliminating fossil fuel generation and reduce clean energy curtailment by 83% compared to a scenario with no multiday storage.
“Pairing sufficient multiday storage with offshore wind can create a firm zero-carbon energy resource that would support grid reliability during all times of the year for a cost that is 80% less than with short-duration storage,” the report found.
The study modeled the grid during all days of the year under different weather scenarios. Ferrara emphasized that modeling weather and load across all hours of the year, instead of short representative stretches, is essential to understanding the true reliability attributes of a resource.
“Methodology matters,” Ferrara said. “If you solve a capacity expansion problem with that richness of information, you come up with a portfolio that is truly robust across weather years.”
Along with portfolio planning methodologies, Ferrara highlighted several key challenges to scaling up Form’s technology. He said the company’s ability to rapidly increase manufacturing would likely be the limiting factor as it works to meet growing demand.
“We don’t see any particular blockers on the supply side; we see a lot of opportunity on the demand side for our technology; and we’re there in the middle,” Ferrara said, noting the relative availability of the battery’s key components: iron, water and air. The company is fast-tracking construction on a large manufacturing facility in Weirton, W.Va., and is hoping to begin operations at some point in 2024.
Ferrara also pointed to the need for appropriate compensation mechanisms to account for the grid benefits that long-duration storage could provide. At a meeting of ISO-NE’s Consumer Liaison Group in June, a Form representative said the company is interested in bringing projects to the region but is limited by the RTO’s current market structure. (See Activists Want ISO-NE to Push for Renewables.)
Currently, ISO-NE does not differentiate between short-term and long-term battery storage systems in its capacity accreditation system, although the RTO is working to change this dynamic in its ongoing Resource Capacity Accreditation (RCA) project.
“Determining how to account for the reliability attributes of storage systems, which have different sizes, durations, etc., is a major component of the RCA project,” an ISO-NE spokesperson told RTO Insider in a statement. They added that while the region currently relies on stored fuels like oil and LNG when other resources are not available, “in light of the ongoing clean energy transition, it is clear that the region will need to explore alternative resources to provide these essential services.”
ISO-NE’s 21-day energy simulator — used to study future resource adequacy — only models two-hour batteries and pumped hydro. The RTO denied stakeholder requests earlier this year to look at long-duration storage in its Operational Impacts of Extreme Weather study, saying that developing a tool to model this could not be completed to fit the timeline of the study.
The inability to study a wider range of storage durations “is problematic for system modeling and transmission planning, where energy storage can act as a transmission-enhancing technology, as well as for the [alternative resource] sector’s larger goals of seeing energy storage markets advance in ISO-NE,” said Alex Lawton of Advanced Energy United, a clean energy association whose membership includes Form Energy and other storage types.
In future analyses, ISO-NE said it plans to continue improving its modeling capabilities, including adding the ability to model long-duration and multiday storage.
FERC recently approved an ISO-NE proposal to allow energy storage to serve as transmission-only assets to solve transmission issues. These new rules will allow batteries to function as transmission assets for the first time, but they impose strict limits on their use, including largely prohibiting them from participating in the RTO’s markets and limiting their total capacity on the grid to 300 MW. (See FERC Accepts ISO-NE Filing to Allow Storage as a Tx-Only Asset.)
In a filing prior to the commission’s ruling, United called the changes a “first step” while recommending that the RTO develop guardrails to allow transmission-only storage assets to participate in ISO-NE markets and consider lifting the capacity limits as it gains operational experience with them.
As the region sits on the precipice of major new investments in fossil fuel generation and infrastructure, Ferrara said he hopes ISO-NE considers investing in and incentivizing zero-emission reliability solutions like long-duration and multiday storage. He advocated for reforming the capacity markets to account for differences in storage durations, as well as the establishment of a “zero-carbon capacity product.”
In January, Massachusetts released a proposal for a forward clean energy market (FCEM), which included a “clean capacity certificate” product aimed at incentivizing non-emitting capacity resources. However, this proposal has failed to gain traction with the other New England states.
ISO-NE has indicated that it is up to the states whether to pursue an FCEM, telling RTO Insider that “the New England states have communicated that they are not interested in pursuing this market design at this time. As a result, we have not conducted further analysis.”
A spokesperson for Massachusetts’ Executive Agency of Energy and Environmental Affairs told RTOInsider that the state is “committed to exploring new long-durational energy storage technologies that not only could reduce our dependence on the grid and our carbon footprint, but also offer savings for residents and businesses.”
With the dual challenge of impending state decarbonization targets and electricity demand increases, Ferrara said it is important to start developing projects in the region as soon as possible. He noted that the company’s white paper found that the least-cost 2030 storage portfolio to prevent outages would include about 3 GW of multiday storage.
“If we’re really serious about goals in 2040 and 2050, and we’re building assets that last 20 years, we need to build them now,” Ferrara said.
ALBANY, N.Y. — Last week’s clean energy conference rounded out a very eventful October for the renewable industry in New York.
Developers, contractors and their advocates were still reeling from the state’s decision to not grant cost increases to 90 renewable projects totaling more than 12 GW — and still digesting the state’s announcement of 25 new projects totaling more than 6 GW.
Against this backdrop, the mood was restive as the Alliance for Clean Energy New York opened its annual fall conference in Albany on Oct. 25.
One speaker compared it to a roller coaster ride, but with none of the thrills and all the scares.
“We know a lot of work is not starting in ’24,” CS Energy CEO Matthew Skidmore said.
The mood was markedly different a year earlier. The 2022 edition of the ACE NY conference opened days after New York voters approved a $4.2 billion environmental bond act.
“At this time last year, the IRA was still news, and great news, but inflation has continued to be a problem since then,” ACE NY Executive Director Anne Reynolds told NetZero Insider on Oct. 26.
She described the prevailing mood at this year’s event as “anxiety” — developers who have said they can’t start construction without more money must decide the least bad way to proceed now they’ve been denied that money.
There’s no expectation the spiraling cost of materials will ever return to pre-inflation levels, Reynolds said, but interest rates will come back down eventually. How soon a developer must make their next payment to NYISO or the New York State Energy Research and Development Authority may determine whether they’re willing to wait for lower interest rates.
NYSERDA is a lead agency in the state’s clean energy transition, and its president, Doreen Harris, delivered a keynote at the conference.
Speaking to industry managers and leaders, Harris offered a more nuanced message than state leaders typically deliver to the public.
“I know the last months and indeed, for some of us, years have been extraordinarily challenging,” Harris said. “I believe our industry will rebound quickly from these challenges.”
Turbulent Times
Rising costs and limited supplies of materials, rising interest rates, regulatory delays and interconnection constraints are problematic for renewable developers everywhere, particularly in the offshore wind sector.
But New York has had a particularly rough October.
In June, developers who had secured state contracts for 90 projects in earlier solicitations said they might not be able to proceed to construction without more money. They petitioned for some form of relief, such as through the inflation adjustment mechanisms offered in more recent solicitations.
The Public Service Commission rejected the request Oct. 12, putting much of the state’s renewable project pipeline at risk of cancellation.
A week later, Gov. Kathy Hochul (D) vetoed a bill that would have allowed the proposed Empire Wind offshore wind farm to run a high-voltage cable under a city park. The cable has sparked resident pushback in the seaside city where it would be located, and Hochul said renewable developers must cultivate local support rather than seek legislative permission to do an end run around local opposition.
In some ways, the veto was just as worrisome to conference attendees as the PSC rejecting the cost adjustments — there are NIMBYs everywhere, and the veto may set a precedent giving them even more control over large-scale renewable development than they already have under the state’s home-rule laws.
In addition, the hydrogen hub proposed by New York and six other states was not among those tentatively chosen for up to $7 billion in federal support.
All of this complicates New York’s progress toward a looming milestone in its landmark 2019 Climate Leadership and Community Protection Act — 70% renewable energy by 2030.
Against this backdrop, Hochul in late October has made a series of announcements to emphasize the state’s commitment to clean energy development: a 10-point action plan to expand the renewables industry, contracts for 25 new renewable projects totaling 6.4 GW and an expedited process for the next onshore and offshore renewable solicitations, which will be open to rebids by the 90 previously contracted projects, should they opt to cancel their existing contracts.
The nation’s first offshore wind turbine nacelle and blade factories are part of the package, and the overall economic impact is estimated in the $20 billion range.
All of this has a nice ring — but most of the 10 points already were in place, the 25 new contracts still must be negotiated and the economics of rebidding up to 90 older projects are unclear.
Also, the full $20 billion does not materialize unless everything falls into place in sequence.
Then there is the regulatory structure in New York, which is known as a slow and expensive state in which to carry out large-scale renewable development.
Some panel discussions at the conference became forums on this, with developers complaining and state regulatory employees explaining or even apologizing.
Gripes
Ben Brazell, director of environmental services at EDR, said now that the state Office of Renewable Energy Siting is more than two years old, it’s time for it and the industry to devise a more efficient protocol.
“It was mentioned this morning that the goal was to have one [notice of incomplete application] issued and move forward,” he said. “I’d like to push the envelope a little bit and have none. Other jurisdictions, other siting boards that have similar responsibilities do that, and do it frequently. … The culture can’t be, submit an application, assume it’s deficient and then move forward.”
VC Renewables Senior Vice President Wendy DeWolf said there needs to be more nuance at the regulatory level.
Every tree has value, she said, but so does the project that would be sited where those trees once stood. The impact on the site and its immediate neighborhood needs to be balanced against the climate benefits over the horizon.
“There’s no such thing as a perfect site,” DeWolf said.
“One of the main questions I get when I engage with community members is, why here? It often comes down to, this is the place that I felt that, given all the data analysis that we have, the interconnection is going to work and where I can permit this project.
“You’re never going to find a site that doesn’t have some environmental impact.”
Wesson Group President Tim Delaney said the pressures affect him as a construction contractor differently than they affect developers. But they’re rooted in the long wait for shovels to hit the ground after a project wins a state contract.
“When they bid a job as a developer it takes NYSERDA six to nine months, sometimes a year, to make an award,” he said. “Then you’ve got a year-plus in permitting and regulatory — if you’re lucky. So now your estimate of cost is two years old. And then in addition you start adding in the other legislative and [environmental regulatory] changes. It just makes it really hard.”
He cited as an example a new specification for the gravel used to build temporary roads, which would raise the cost of building a 150-MW wind farm by $3 million to $4 million.
The potential delay or cancelation of the 90 projects would be a new level of hurt.
“We probably had a half-billion dollars’ worth of work in the pipeline that essentially went to significantly less than that,” Delaney said.
Responses
Representatives of ORES and NYSERDA offered some impressive statistics: ORES has permitted 14 major projects — more in the two years the office has existed than in the preceding 10 years — and awarded those 14 permits just eight months after application, on average. NYSERDA has awarded 114 contracts in six solicitations since 2017.
But only one of the ORES projects has started construction, its pre-application process can take much longer than eight months, and it’s a new agency that has had to gain experience and build staff.
Meanwhile, only 26 of the NYSERDA projects have reached commercial operation; 88 are still in development.
ORES Deputy Counsel Hayley Carlock acknowledged criticism that the preapplication review process has become a pinch point in an agency created to eliminate pinch points.
“We agree. We also see that the completeness process is an area where we can improve. And we are striving to do that every day.”
In defense of ORES, some applications come in with glaring omissions, Carlock said. Developers should take the pre-application process more seriously, she said.
“The office is not here to put up walls and slow down projects … [but] it’s a fair critique and one we’re working hard to address.”
NYSERDA Director of Large-Scale Renewables Abbey DeRocker said the authority has attempted to expedite the process. One example is the Build-Ready program created in 2019, under which NYSERDA advances a project through the planning and review stages before requesting proposals to build it.
“The intent is to have difficult sites that could have more risks than typical sites build-ready for private renewable energy developers to construct and operate,” she said.
Initial applications are due in early December for NYSERDA’s first such project, which would be a 12-MW solar farm on a tailings pile at a defunct iron mine. Formal proposals will be due in March, and NYSERDA hopes to select a developer by mid-2024.
This timeframe — five years from launch of the program to its first potential contract — is not unusual. Much of the landmark CLCPA still is being hashed out more than four years after it was signed into law. Some projects can take a decade or longer to progress from site selection to commercial operation.
This is what may derail the 90 at-risk projects: Their revenue was locked in long before their cost of construction.
DeRocker acknowledged the potential for complications when a project spends so much time in development.
“A lot can change over that time period,” she said. “And we have the changing landscape of state priorities at the same time. For those of you who have been around since 2017, you’ve noticed we’ve never run the same solicitation twice. Some of that is because we’re trying to effectuate policy changes. … we’re learning as we go along.”
Zachary Smith, vice president of systems and resource planning at NYISO, said the state’s grid operator is preparing a set of reforms under FERC Order 2023 that would greatly streamline the interconnection process, which has bogged down as the volume of applications rose.
In five years, the queue has grown from 175 projects totaling 20 GW to more than 500 totaling 120 GW.
“In today’s process, admittedly, there is a lack of certainty,” Smith said.
“We are changing that. If FERC approves our reforms as we are proposing them … a major objective of mine is to provide certainty. You may not agree with the amount of time it is going to take, but we’re going to codify that in our procedures, and we’re going to stick to that.”
When Hochul announced the 6.4 GW of new renewable contracts earlier in the week, she struck a celebratory tone and made only oblique references to the 12 GW of existing contracts that recently had fallen into danger of cancellation. But she was speaking to the general public at an appreciative gathering of dignitaries supportive of the new projects.
Given the audience at the ACE NY conference, Harris could not do the same in her keynote. She acknowledged the setbacks and commiserated with the audience.
But she also segued into a pep talk, sounding like a football coach trying to rally the team back onto the field after getting mauled in the first half.
“The phoenix is rising here,” Harris said. “It is rising because of each of you … I want to take a moment to reaffirm the incredible contributions of everyone in this room today.”
“Who will the historians be writing about? What courageous visionaries in this room will be shaping that next chapter?” she asked. “They won’t be writing about the ones who decide to pull up stakes and move to the next market, where the grass may appear greener.”
When she finished, Harris left briskly through a rear exit rather than wading through the crowd she had just tried to rally.
Moving Forward
The 460-plus attendees at the ACE NY conference have a wide range of perspectives and roles in the clean energy transition — developer, builder, regulator, facilitator, advocate.
What they almost certainly have in common is a desire for the transition to continue and to succeed, if not for the sake of the planet, then for the sake of their bottom lines.
It’s hardly the first challenge they’ve faced, Reynolds reminded the crowd, and they’ve overcome many setbacks.
NRDC Climate and Clean Energy Program Director Kit Kennedy said New York needs to maintain its momentum, not just for its own benefit but because it’s a leader influential beyond regional and even national borders.
“There’s no sugarcoating the impact of some of New York state’s recent decisions,” she said. “This was a setback — if these projects or even some of these projects are canceled, New York will be regressing rather than progressing toward its 2030 goals.
“We need a continued and unremitting commitment to the successful projects, getting steel in the ground, building the transmission lines we need, and continuing grid investments.”
Cordelio Power CEO John Carson said his board asked if he thought New York was still a viable market. He does, but “it’s going to require a lot of patience.”
Some see the 70% by 2030 goal as aspirational, he added, but he still finds it inspirational.
“We’ve had a terrible bump in the road. I believe we’re going to get back on our feet. So, I’m saying we’re still doing business in New York.”
Delaney said: “We’re certainly still bullish. We live here, we work here during the season. … This industry has been really cyclical since its inception.”
Whatever their frustration with New York’s execution of the clean energy transition, no one faulted its intentions: “Just the fact that we have an Office of Renewable Energy Siting is reflective of what’s going well in New York state,” DeWolf said.
Hochul’s deputy secretary of energy and environment, John O’Leary, urged attendees to step back from the nettlesome details and remember the larger picture — the “why” of the energy transition.
“The work that everyone in this room is doing is making a livable planet possible. … I know it’s a difficult time and I’m hoping that this week marks the beginning of a new chapter.”
CAISO stakeholders have voiced multiple concerns about a straw proposal to revamp the ISO’s interconnection process, with some cautioning that the timeline to draw up a final plan is too ambitious given the lack of progress on the effort so far.
Stakeholders shared their views at an Oct. 24 meeting of CAISO’s Interconnection Process Enhancements Working Group. Top among their concerns: the ISO’s plan to introduce scoring criteria designed to rank requests to join the grid based on project readiness, as well as a proposed interconnection cap to limit any one developer’s ability to dominate the queue.
Stakeholders expressed frustration over a lack of information on how to implement the scorecard, including uncertainty about in which transmission zones projects would be developed, how open access and equal competition would be upheld and fears that the initiative’s timeline was rushed.
CAISO’s 2022-2023 Transmission Plan, developed in coordination with the California Public Utilities Commission and the California Energy Commission, outlined action items that could help transform the process of connecting new resources to the grid.
Key among the items, also discussed in the ISO’s Interconnection Process Enhancements straw proposal, was the introduction of designated geographic zones that should be prioritized for resource development. The approach would prioritize projects in areas where there are planned capacity additions approved in CAISO’s transmission planning process.
According to the plan, the CPUC would direct load-serving entities (LSEs) to focus energy procurement in those zones, and the ISO proposal will use the scoring criteria to select projects once the resources in a transmission zone reach 150% of the available or planned capacity in that zone. But some stakeholders contend that the straw proposal contains insufficient information regarding the location and details of the zones.
“If we’re going to move forward with this scoring criteria, it needs to be absolutely clear to both the CAISO and developers what locations are in and out of a zone,” Bridget Sparks, interconnection policy manager at AES Clean Energy, said. “If you’re asking developers to invest millions of dollars in land and other development activities, there shouldn’t be any uncertainty on whether or not a certain point on a transmission line is in or out of a zone.”
Cathleen Colbert, director of CAISO market policy at Vistra Corp., echoed that concern, saying that CAISO hadn’t provided enough data transparency on zone locations. She asked the ISO to use the heat maps requested in FERC Order 2023 (RM22-14-000) to provide more clarity, and that they be available in time to inform the next opening of an interconnection cluster window. Sparks also suggested CAISO provide line diagrams to identify zones.
Anish Nand of the Northern California Power Agency asked that CAISO provide line diagrams before the release of the draft final proposal, but Danielle Mills, the ISO’s principal of infrastructure policy development, said the grid operator could not commit given the strict timeline.
Approval, Pushback on Scoring Criteria
In a presentation at the meeting, Southern California Edison pushed back on a few key aspects of the scoring criteria, including the proposal to include demonstrated interest from off-takers as part of the scorecard. Because letters of interest from off-takers are non-binding, SCE proposed instead to include a bonus point system in which LSEs are given a certain number of points based on their load share. This modified process, according to the utility, would allow LSEs to better identify projects that serve their mandated needs, increase the scrutiny of projects and, in turn, decongest the queue.
The utility also proposed adding the procurement of long-lead equipment that could indicate commercial readiness as one of the scoring criteria.
“I think something like the bonus points concept is appropriate,” said Lauren Carr, senior market policy analyst at CalCCA. “It would be a good way to get some more granularity around LSE interest, where there can be a range of points assigned based on how interested an LSE is on a particular project.”
Some independent power producers (IPPs) expressed support for the proposal, but others, such as Terra-Gen LLC, were concerned that the addition of an LSE bonus points system could hinder open access and equal competition.
“We also believe that doing a load-ratio type share would unfairly favor larger LSEs,” said Terra-Gen Director of Energy Market Policy Chris Devon. “This addition of another bonus point criteria for LSE interest would further give more negotiating power to the LSEs and reduce competition.”
Interconnection Caps
Another key element in the straw proposal was the introduction of an interconnection cap. CAISO proposed that each developer be limited to only submitting projects that would take up 25% of available transmission across the footprint to address market power and domination of the queue by a small group of developers.
However, in a presentation to the working group, AES highlighted that the ISO provided no evidence or data to prove that market power is a current issue.
AES also raised concern over an interconnection cap leading to discriminatory treatment between IPPs and utilities, since non-CPUC jurisdictional utilities are automatically accepted into the queue without capping and included in the studied 150% of available transmission. On the flip side, IPPs would be subject to both the developer cap and the scoring criteria within the studied 150% of available transmission.
Strict Timeline
The draft final proposal is set for Nov. 15, leaving some stakeholders frustrated by the lack of solid progress with the initiative despite the strict timeline in which to move forward.
“It seems like CAISO isn’t really giving enough time for the stakeholder process to work and [is] so wedded to a specific end timeline, and you’re considering such a radical change in the way that the interconnection process is done,” Sparks said. “We would rather get this right the first time than to rush through a process that has a lot of unintended consequences or hasn’t been thoroughly thought through.”
CAISO acknowledged the frustration.
“I know the pace is exhausting,” Mills said. “We’re just really trying to push it as fast as we can for you, not because we don’t care what you think.”
Several Midwestern states on opposite ends of the political spectrum have taken steps this year signaling receptiveness to small modular reactor (SMR) development while a factory in Ohio has begun producing uranium tailored to the smaller plants.
Most recently, Maryland-based Centrus Energy opened a uranium enrichment plant this month in Piketon, Ohio, to produce high-assay, low-enriched uranium (HALEU).
The Department of Energy awarded Centrus a competitive, cost-shared contract in 2022. The company was required to begin production of HALEU by the end of 2023 under the agreement. HALEU is tailored for types of SMRs and contains between 5% and 20% fissile uranium, while large nuclear reactors use fuel with up to 5% fissile uranium.
“We hope that this demonstration cascade will soon be joined by thousands of additional centrifuges right here in Piketon to produce the HALEU needed to fuel the next generation of advanced reactors, low-enriched uranium to sustain the existing fleet of reactors and the enriched uranium needed to sustain our nuclear deterrent for generations to come. This is how the United States can recover its lost nuclear independence,” Centrus CEO Daniel Poneman said in a press release.
Deputy Secretary of Energy David Turk said that for the first time ever, “an American company is producing HALEU on American soil.”
The 16-centrifuge cascade produces only about 900 kilograms of HALEU per year, but Centrus said it could expand the Ohio operation to 120 centrifuge machines if it secures enough offtake commitments and funding.
Centrus has TerraPower and Oklo Inc. lined up to execute fuel supply contracts; both are trying to get their own SMR designs certified with the Nuclear Regulatory Commission (NRC). Oklo plans to build two of its liquid metal-cooled, metal-fueled fast reactors in Piketon to supply energy for Centrus and the surrounding area. The plants will be situated on land owned by the Southern Ohio Diversification Initiative, a community reuse organization. The plans are part of the Department of Energy’s push to re-industrialize the area around the Portsmouth Gaseous Diffusion Plant.
Elsewhere in Midwestern states, utilities were in the early stages of development while bills meant to assist SMR progress were drafted.
Early this year, a bipartisan group of Minnesota Senate lawmakers backed a bill that would direct the state’s Department of Commerce to conduct a study exploring the feasibility of SMRs (SF 1171). The Minnesota House and Senate also mulled allowing the Minnesota Public Utilities Commission to issue certificates of need to build new nuclear plants less than 300 MW in capacity (SF 2824). Both bills have been referred to the Climate and Energy Finance and Policy Committee.
Minnesota’s nuclear moratorium is nearly three decades old, but some environmental organizations are rethinking their stance on new nuclear as a zero-carbon, baseload backstop to renewable power. Minnesota law mandates that the state reach 100% clean energy by 2040.
In general, SMRs are designed to yield anywhere from 50 to 300 MWs of electricity, as opposed to the typical 1 GW from traditional, large-scale reactors. They can be built indoors and then shipped to sites to be assembled. The U.S. doesn’t have any SMRs in operation.
Meanwhile, Xcel Energy is exploring whether it wants to become operator of a NuScale VOYGR SMR under development at the Idaho National Laboratory. That plant isn’t expected to be commercially operational until 2030.
NuScale’s VOYGR is the first SMR design to win certification from the NRC.
Dairyland Power Cooperative, based in western Wisconsin, has partnered with NuScale Power to evaluate use of small-scale nuclear reactors in Wisconsin.
NuScale also is planning to build a dozen 77-MW pressurized water SMRs for Ohio and Pennsylvania in order to energize two Standard Power data centers by 2029.
If passed, Michigan’s House Bill 4753 would create tax credits of 15% for qualified research and development expenses related to the “design, development or improvement” of SMRs and activities that will hasten them to market. The bill was referred to the House Committee on Tax Policy.
“Per capita, Michigan employs the highest number of engineers in the country,” said state Rep. Pauline Wendzel (R), who introduced the bill. “We have the talent, and we have the capability. Now we need to put our foot on the gas to develop this safe, clean and reliable form of energy.”
Efforts to resurrect the Palisades nuclear power station in southwest Michigan also involve SMRs. Last month, Wolverine Power Co-op signed an agreement with owner Holtec International to buy power, hoping Palisades reopens in 2025. That agreement includes a contract expansion provision to include up to two small modular reactors onsite.
Last year, Indiana Gov. Eric Holcomb (R) signed S271 into law, which mandated that the Indiana Utility Regulatory Commission work with the state’s Department of Environmental Management to devise rules around granting of certificates of public convenience for the construction, purchase or lease of SMRs. Those rules were adopted at the end of June.
Purdue University and Duke Energy have recommended that Indiana consider public funding of studies dedicated to new nuclear and issuing state tax credits for advanced nuclear technology. Those recommendations were in an interim report of a joint study issued midyear.
Purdue and Duke are exploring the feasibility of using SMRs to meet the energy needs of Purdue’s main campus.
Finally, the Missouri legislature this year weighed HB 225, which would have allowed utilities to file with FERC to raise rates to pay for SMRs. The bill, which cleared the house but failed to gain traction in the Senate after a public hearing, would have modified the state’s 1976 law that prevents utilities from raising rates to pay for the construction of new projects.
Whether SMRs are economical enough to compete in the market remains untested. This month, researchers published a cost analysis of SMRs in the peer-reviewed international journal Energy. They analyzed the levelized cost of electricity among 19 SMR designs and said the costs to generate electricity from SMRs seems to be “non-competitive when compared to current costs for generating electricity from renewable energy sources,” even when accounting for system integration costs that double renewable energy’s price tag.
Researchers also concluded that manufacturers’ cost estimates for SMRs “are mostly too optimistic compared to production theory” and that a Monte Carlo simulation showed “that no concept is profitable or competitive.”
Xcel Energy management told financial analysts last week that it has made “significant progress” on what it calls “industry-leading clean energy transition plans.”
“Given that the regions where we serve customers are the most resource rich in wind and solar,” CEO Bob Frenzel said during the company’s third-quarter earnings call Friday, “we believe that we can lead this clean energy transition for our customers more cost-effectively than almost any other company.”
The Minneapolis-headquartered company is relying on its Steel for Fuel 2.0 program, which builds on its plan to swap fossil generation for fuel-free wind and solar that the company rolled out seven years ago. Xcel has increased its capital investment plan through 2028 to $34 billion, with another $10 billion potentially necessary after state regulatory approval of clean energy projects. (See Earnings Up, Xcel Touts ‘Steel-for-Fuel’ Strategy.)
In September, Xcel’s Colorado subsidiary filed what it called the largest clean energy transition effort in the state’s history. The plan includes shutting down its remaining Colorado coal plants with approximately 6.5 GW of renewable energy and battery storage, doubling the state’s renewables, and about 600 MW of natural gas resources to ensure reliability during times of low wind or solar conditions.
Including about $3 billion in required transmission investments, Xcel will invest nearly $11 billion in the state. The company expects Colorado’s regulatory commission to rule on the proposal early next year.
In Minnesota, Xcel has received regulatory approval to add 250 MW of new generation at its Sherco Solar project, bringing the facility’s capacity to over 700 MW. The project will use existing interconnections from the Sherco coal plant, which is retiring by 2030.
Its Southwestern Public Service Co. (SPS) subsidiary filed a resource plan in New Mexico earlier this month that lays out a need for between 5 GW and 10 GW of new generation by the end of this decade. SPS already has proposed 418 MW of company-owned solar and battery projects that are pending commission approval.
“We have the potential to deploy [15 GW] to [20 GW] of new clean generation on our systems by 2030, dramatically lowering our emissions profile,” Frenzel said.
The company said it will appeal a Colorado district court decision Wednesday that awarded CORE Energy $26.5 million in damages for a breach of contract and mismanagement of Xcel’s Comanche 3 unit. CORE owns a 25% share of the plant, which has averaged 91 days of unplanned shutdowns a year since the unit went online in 2010.
“We have a strong legal basis for challenging that $26 million award,” Xcel CFO Brian Van Abel said.
The company reported earnings of $656 million ($1.19/share), compared with $649 million ($1.18/share) for the same period in 2022. The results reflect the effect of increased recovery from infrastructure investments, higher sales and demand, and lower operating and maintenance expenses, partially offset by increased interest charges and depreciation, the company said.
Its share price lost 2.4% Friday, closing down $1.46 at $58.31.
