A Northern California port intended as a major staging area for offshore wind development received a $10.5 million grant Wednesday from the California Energy Commission (CEC) to begin work on upgrading its facilities.
The Port of Humboldt Bay is slated to serve the 1.6 GW Humboldt Wind Energy Area. The Bureau of Ocean Energy Management designated Humboldt as one of two California coastal regions for offshore wind development; the other is in Central California near Morro Bay. Leases for both areas are expected to be auctioned this fall.
The funds will help the Humboldt Bay Harbor, Recreation and Conservation District revitalize the historic timber port on the state’s Redwood Coast, beginning with preliminary engineering and design work. The money will also be used to attract matching grants from the federal government.
Eventually, a new marine terminal will be able to handle heavy cargo vessels and floating platforms, the CEC said.
Humboldt call area | BOEM
New CEC Commissioner Kourtney Vaccaro lauded the state’s “opportunity to partner with the [harbor district] in their pursuit of revitalizing their port to support the necessary infrastructure for deploying ocean-based clean energy resources that will benefit Californians.”
Humboldt Bay lacks the bridges and other impediments to developing wind ports in larger deep-water harbors, such as San Francisco and San Diego bays.
“Humboldt Bay has the optimal conditions to serve as the primary port for the offshore wind industry for the entire West Coast,” harbor district board president Greg Dale said in a CEC news release. “We are fully dedicated to prepare our port for this remarkable opportunity.”
The funding allocated by the CEC was originally approved as part of the 2021-22 state budget. Gov. Gavin Newsom has proposed allocating $45 million for investments in waterfront facilities to support offshore wind in his 2022-23 budget plan, now working its way through the state legislature.
The CEC recently started work on an offshore wind strategic plan to help the state achieve its 100% clean energy goal while maintaining a stable grid. Wind off California tends to pick up in the evening as solar power wanes, a critical time in the state’s struggle to keep the lights on during the clean energy transition.
“Offshore wind is an important part of the state’s clean electricity future, providing critical supply at night to complement our abundant solar resources,” Vaccaro said in the CEC statement.
NERC’s Reliability and Security Technical Committee (RSTC) marked a key moment of growth this week, welcoming its first new class of members since the committee’s founding two years ago.
The committee’s initial set of 22 sector representatives and 10 at-large members, plus the chair and vice chair, took their seats at their first meeting in March 2020. (See RSTC Tackles Organization Issues in First Meeting.) The plan was for the members to serve staggered terms of two years each, with half the initial slate to leave in 2022 and the rest departing in 2023.
Nominations for new sector representatives ran from October to November, while at-large nominations were received in December. Each sector selected one delegate except for Sector 7, representing electricity marketers; for this sector two representatives were needed: one for the regular term beginning this year, and the other to replace a retiring member whose term ends next year.
NERC’s Board of Trustees approved the committee’s new membership in February, except for Greg McCauley of Sector 3 (Cooperative Utilities), who was chosen in a special election earlier this month after the resignation of Marc Child of Great River Energy. McCauley, who did not attend this week’s meeting, is expected to be approved at the board’s next meeting in May.
RSTC Chair Greg Ford of Georgia System Operations thanked the incoming representatives as well as the outgoing slate, whom he called the “founding members … who have really worked very hard to bring the RSTC where we are today.”
Among the departing members is ERCOT’s Christine Hasha, a member of the RSTC’s six-person Executive Committee. Members approved the appointment of Christine Ericson of the Illinois Commerce Commission to replace Hasha.
IRPWG Elevated to Subcommittee
The RSTC’s Inverter-based Resources Performance Working Group (IRPWG) will be promoted to a subcommittee following the recommendation of the committee’s Sunset Review Team, which is mandated by the RSTC charter to review each working group every year and determine if their scope needs to be revised, expanded or ended.
The IRPWG, originally called the Inverter-based Resources Performance Task Force, was created under the Planning Committee to “explore the performance characteristics of utility-scale inverter-based resources [IBRs] … directly connected to the bulk power system.” Its remit includes researching the extent of penetration of IBRs in the bulk power system, as well as producing reliability guidelines and standard authorization requests for potential IBR-related reliability standards.
Robert Reinmuller of Hydro One, in his presentation on the Sunset Review Team’s recommendations, said that given the accelerating transition of the grid to renewable energy sources and the “quite considerable” work planned by the IRPWG, raising the profile of the group by making it a full subcommittee would help it meet its goals.
“The next several years will be critical in the adoption and integration of these resources and making sure that we’re tracking performance [and] we have proper guidelines, standards and so on,” Reinmuller said.
The RSTC’s other working groups will continue in their current form, per the team’s recommendation.
New Guidelines Approved
Other approvals in this week’s meeting included two reliability guidelines, which unlike reliability standards are nonbinding and strictly voluntary. The first, submitted by the Resources Subcommittee, concerns accounting practices to address inadvertent interchange and “provide a method for isolating and eliminating the source(s) of accounting errors.” A draft version of the guideline is already present on NERC’s Reliability and Security Guidelines webpage; the new version adds language regarding the development of metrics.
The second guideline, “DER Forecasting Practices and Relationship to DER Modeling for BPS Planning Studies,” was submitted by the System Planning Impacts of Distributed Energy Resources (SPIDER) Working Group. Like the subcommittee’s guideline, SPIDER’s document modifies the draft version on NERC’s website to add new metrics for use by industry.
Both guidelines have been through the industry commenting process; the revisions are based on the comments received. Having received the RSTC’s approval, they will now be posted to NERC’s website.
Transmission construction and MISO market facelifts can help the Midwest reliably adjust to a new resource reality, panelists said Tuesday during an Energy Bar Association (EBA) teleconference.
“This is a time that is really a seismic shift in the industry,” Ameren Director of RTO Policy Jeff Dodd said during a discussion hosted by EBA’s Midwest chapter.
MISO counsel Michael Kessler said the grid operator is besieged by declining reserve margins as aging baseload units are replaced with renewables. He said even a growing natural gas fleet might not be able to procure enough fuel to keep the grid reliable at times.
Scott Wright, the RTO’s executive director of market strategy, said the changing resource fleet has placed MISO at the doorstep of reliability problems.
“This is not a far and distant problem. This is here now,” he said.
Wright said, “excess reserve margins are a thing of the past” and the grid operator now navigates challenging conditions carefully and with little capacity to spare.
He said MISO must build long-range transmission to bring an additional 120 to 330 GW of additional capacity online by 2040. Those figures are necessary to meet members’ carbon-reduction goals or bring the footprint to net-zero carbon emissions, Wright said.
“It used to be a moderated pace of change. To me, it’s [now] a rush,” Wright said. He also called environmental and social governance awareness “the new kid on the block” that stands to hasten fleet change.
Wright said natural gas generation used to be viewed as a bridge to clean energy. “Now, they’re burning the bridge,” he said, referencing utilities focusing on renewables over needed centralized power.
Wright questioned whether “storage has come along enough” to meet instantaneous load. He said the RTO’s operations will become much more complex in the coming years by optimizing load and managing decentralized resources.
“There’s a lot of different ‘minding of the store’ that’s going to need to happen here,” Wright said. He added that he didn’t mean to sound “defeatist” or “sensational” and said MISO has a solid, well-functioning market in place today that simply requires adaptation.
Dodd said distribution companies, transmission planners and state regulators must engage in a level of coordination that wasn’t necessary a few years ago.
“A lot of utilities are starting to understand we need all these groups in the same room,” he said.
Organization of MISO States President Sarah Freeman, an Indiana Utility Regulatory commissioner, called the path to net-zero emissions a “juggling of the chainsaws.” She said that just as MISO’s geography and resources are diverse, “cultures among governing bodies” are also diverse within the footprint.
“I say Indiana is a red state going green,” she said.
Dodd said in Ameren’s experience, customer preference, not state policy, is driving the clean energy conversion. The company has a 2050 net-zero emissions goal, but Dodd said that target could be accelerated. He also noted Ameren Illinois must cease all fossil generation in the state no later than 2045, according to state law.
Dodd called transmission “a facilitator” in the transition to a cleaner generation portfolio.
“MISO has success with this scenario planning,” Dodd said of the three 20-year planning futures used to justify transmission projects. He said the 2011 Multi-Value Project (MVP) portfolio continues to deliver benefits well in excess of the $6.5 billion cost.
The MVP portfolio had a “Field of Dreams: if you build it, they will come” approach, Dodd said. With MISO’s long-range planning, there’s now little doubt that new lines will be useful, he said.
“Those lines were fully subscribed as soon as they were built,” he said of the MVP’s success. “I think MVPs laid the groundwork for the long-range transmission plan.”
Governance Changes for TAC, Stakeholder Process Remain Unclear
ERCOT’s Board of Directors left the grid operator’s top stakeholder committee, the Technical Advisory Committee, in a bit of limbo this week as it continued to debate governance and stakeholder coordination.
The directors on Tuesday first deferred confirmation of the TAC’s leadership, normally a routine matter, until the board’s April 27-28 meeting. That meeting was rescheduled from April 12 and would have conflicted with a TAC meeting. However, the committee moved its April 27 meeting up to April 13 to help push an urgent protocol revision request through the stakeholder process.
The directors then approved the creation of a board-level meeting committee to oversee ERCOT’s core functions. As proposed by staff, the Reliability and Markets Committee would focus on markets, planning, reliability and resilience. The scope would also include information technology and project delivery.
Both actions followed an extensive executive session that began Monday and ended Tuesday.
TAC Chair Clif Lange, with South Texas Electric Cooperative, said the delayed vote on his confirmation caught him by surprise and wasn’t telegraphed by ERCOT staff. He said he only became aware of the board’s actions when he started receiving texts from TAC members Tuesday morning.
“We didn’t see that coming,” Lange told RTO Insider. “Nothing had been communicated to us.”
He said nothing in the meeting materials indicated to him that the TAC would answer directly to the board and said that further modifications to the committee could be in the offing.
The board, which has met with all 11 members just twice since December, has been vocal in its previous meetings about the time it takes protocol revisions to clear the stakeholder process. The TAC is responsible for vetting and endorsing protocol revisions that come up from the working groups, while market participants’ heavy involvement in ERCOT’s governance has drawn attention since the February 2021 winter storm.
The TAC, for its part, has discussed the potential changes to the stakeholder process several times in recent months. (See “TAC Members Look for Direction on Governance Structure, Stakeholder Process,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)
“I know we on the TAC are a little concerned that not engaging stakeholders and shutting them out will result in suboptimal products for ERCOT,” said Lange, who added that he plans to take his concerns to interim CEO Brad Jones.
ERCOT officials say the eight new independent board directors are grappling with their new responsibilities.
Chris Ekoh, interim CEO of the Office of Public Utility Counsel (OPUC) and the only non-independent voting board member, read a memo into the record that expressed his concerns for the stakeholder process and with the new board committee. He asked whether the TAC will be disbanded or made “subservient” to the new board committee.
“It is not clear to OPUC how the creation of the new Reliability and Markets Committee will impact or coexist with the current stakeholder process,” he said. “How will the proposed Reliability and Markets Committee interact with TAC? How does the committee and TAC work together, if at all? How does it impact the protocol revision process?”
Ekoh also asked whether there were compliance concerns for ERCOT if the revision process is modified.
“Those are questions everybody has about how TAC is going to interact with the board,” Lange said.
There was no public discussion of Ekoh’s comments among the board members.
Upward Pressure on Admin Fee
CFO Sean Taylor told the directors that ERCOT’s costs are projected to continue to grow at a rate faster than shown in its current 2022-2023 budget, which was approved last year. He said additional demands placed on staff as a result of last year’s winter storm include new regulatory requirements, protocol and planning revisions, and increased IT support costs for new or improved services that were not expected.
“There is upward pressure on the 2023 budgeted system administration fee rate,” Taylor said. “That fee will not be as adequate as previously thought.”
ERCOT has maintained a system admin fee of 55.5 cents/MWh since 2016. It had projected increasing the fee to 66.5 cents/MWh in the 2024-2025 budget.
Staff reported a preliminary negative net variance of $25.5 million for 2021, with system admin fees coming in $10.9 million under expectations because of less energy sold. The grid operator had projected 413.1 TWh of energy sales in 2021, only to see 393.3 TWh of energy sold.
Expenditures were $14.4 million overbudget, primarily because of outside legal services, hardware and software support and maintenance, higher insurance premiums, and professional consulting.
ERCOT has operated with a biennial budget since 2014, at the Public Utility Commission’s request. Its filed budget includes four additional years of forecasted numbers.
Board Approves Firm Fuel Product
The board approved three revision requests that cleared the TAC with dissenting votes, including a nodal protocol revision request (NPRR1120) that creates a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather. The NPRR also compensates generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption.
The PUC has directed that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.
OBDRR039: removes FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation.
PGRR095: establishes minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.
The directors also approved eight additional NPRRs, a Nodal Operating Guide revision (NOGRR), three more OBDRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and three system change requests (SCRs).
NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
NPRR1097: creates reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
OBDRR037: caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
OBDRR038: updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
SCR819: improves dispatch of base points to resources to account for ramping un-curtailed IRRs.
A bill is headed to Washington Gov. Jay Inslee to create a new state office to support development of green hydrogen and other alternative fuels.
The state Senate unanimously approved Senate Bill 5910 on Wednesday, after the House passed it Monday 96-2 with some minor tweaks.
“Renewable hydrogen is an exciting part of our future,” bill sponsor Sen. Reuven Carlyle (D) said prior to Wednesday’s floor vote.
The bill appears to boost Washington’s prospects to receive money from the federal Infrastructure Investment and Jobs Act to create one of four regional hydrogen hubs in the nation. (See Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)
The proposed Office of Renewable Fuels in the Washington Department of Commerce would collaborate with other state agencies to accelerate market development of renewable fuel and electrolytic hydrogen projects along their full life cycle, in part by supporting research and development around production, distribution and end uses. It would also identify ways to best deploy the fuels to support the state’s climate change mitigation and adaptation efforts.
The new office is also expected to help boost job creation while partnering with “overburdened” communities to ensure they benefit from clean fuels development. It would also review the state’s existing renewable fuels and hydrogen initiatives and support public-private opportunities that encourage adoption of clean fuels. The office is expected to coordinate its efforts with local state and federal governments, the private sector and universities.
The bill would also allow proposed hydrogen production projects the choice of applying for permits from the state Energy Facility Site Evaluation Council, rather than local governments. (See Bill to Expand Powers of Wash. Siting Council Passes Senate.) It would also authorize municipal utilities and public utility districts to produce, use, sell and distribute hydrogen and other renewable fuels.
The legislation could help Washington land one of the four hydrogen hubs outlined in the IIJA, enacted last year. The federal law allocates $8 billion for the creation of at least four hydrogen hubs across the country, as well as $1 billion for the domestic manufacture of the electrolyzers needed to convert water to green hydrogen. The U.S. Department of Energy will solicit proposals for the hubs until May 15 and select the four sites a year later.
Washington has one hydrogen production plant under construction near East Wenatchee, which will use Columbia River water as its source. The plant, to be operated by Douglas County Public Utility District near the Wells Dam, is scheduled to go online late this year. A hydrogen fueling station is on the drawing board for near East Wanatchee, and another is in the works for public transit buses in Lewis County, about 25 miles south of Olympia.
The battle over federal rules controlling power plant emissions is heating up again as the Biden administration’s EPA prepares to issue revised regulations by the end of the year.
The agency is developing the rule even as the Supreme Court considers an appeal of rules issued by the Trump administration and thrown out by the D.C. Circuit Court of Appeals. The high court listened to oral arguments two weeks ago and is expected to issue an opinion in June. (See Supreme Court Hears Arguments on EPA Authority Over GHGs.)
Some of the same issues that cropped up in the Obama administration’s Clean Power Plan (CPP), finalized in 2015, may persist: “beyond the fence line” emission rules, generation shifting, and the even trickier standards promulgated in the Affordable Clean Air Energy (ACE) rule issued by the Trump administration in 2019 for heat rate efficiency.
In a webinar produced Wednesday by D.C.-based OurEnergyPolicy, four of the industry’s top legal minds examined some of these issues.
“I think [among the] things that are being discussed even while we wait for the decision is what should EPA base the standard on,” said Carrie Jenks, executive director of Harvard University’s Environmental and Energy Law Program.
“The power sector has changed [since] the Clean Power Plan was designed and also when ACE was designed. And how does EPA look at that what has happened with technologies? What’s the basis for the standard? What should companies and states be allowed to do in terms of complying with that standard?” she said.
Emily Sanford Fisher, general counsel for the Edison Electric Institute, also noted that technologies have changed since the CPP was introduced.
“Actually quite a lot has changed. One way to think about it is that the Clean Power Plan was aiming to achieve a 32% reduction in industry-wide emissions by 2030. And at the end of 2020, as an industry we were at 40% below 2005 levels.
“So obviously something that EPA in 2015 thought we wouldn’t be able to achieve until 2030 we accomplished without the Clean Power Plan and actually before it even would have taken effect,” she said, adding that the Obama administration gave the industry until 2022 to achieve the lower emissions.
The growth of renewable energy, which Sanford-Fisher noted “is a very competitive form of generation,” and state renewable portfolio standards have also been responsible for making the industry cleaner, she said.
Another factor that changed total emissions was the Obama administration’s decision to issue the final Mercury and Air Toxics Standards, which led to the retirement of about a third of the coal fleet, she said, adding that about 50 of the 65 member companies in EEI have long-term commitments to continue to reduce emissions.
Ben Longstreth, senior attorney with the Natural Resources Defense Council, said he “concurred entirely” with Fisher but added that the emphasis should not be taken off the power sector because it will become even more important as the number of electric vehicles grows.
He also said that EPA is facing mandates that Congress put into the original law.
“NRDC always had a program thinking about the conventional air pollutants — the SOx, NOx, mercury — and while the sector has improved a lot, [the pollutants] remain significant,” he said.
WECC is planning to resume in-person meetings at its Salt Lake City headquarters, asking for “grace” as it plots a way to accommodate all stakeholders, CEO Melanie Frye said Wednesday.
“March 23 actually marks the two-year anniversary of us closing the WECC office,” Frye said during a quarterly meeting of WECC’s Board of Directors.
She pointed out that the regional entity’s last in-person event was the March 2020 board meeting, held just before the COVID-19 pandemic drove office workers into quarantine and established widespread use of remote working and virtual meetings.
WECC will retain elements of that now well-established practice in its approach to stakeholder gatherings, adopting a “hybrid” model of face-to-face meetups with the continued option of participating virtually, Frye said.
“Beginning May 1, we’ll start to consider on a case-by-case basis moving to hybrid meetings, which probably will be our new normal at work,” she said. “We know that many companies are still in limited travel arrangements, so as we contemplate having technical committee meetings, we know there will probably always be an element that is hybrid, with people remotely participating and, [for] those who are able to travel, in person.”
In a roundtable discussion during a meeting of the WECC Member Advisory Committee on Tuesday, stakeholders expressed a desire to get back to in-person meetings as their states and employers begin relaxing pandemic restrictions.
“Our policy is allowing for travel where appropriate, and we would love to see it happen,” MAC member Brian Evans-Mongeon, president of Utility Services, said.
Russell Noble, reliability compliance manager at Cowlitz County Public Utility District in Washington, said the “last vestiges” of his state’s COVID regulations would be expiring March 12. “We are looking towards getting back to normal and definitely be allowed to make necessary travel arrangements for necessary meetings.”
But WECC’s Canadian members still face uncertainty about crossing the border into the U.S., said Diana Wilson, director of enterprise risk management and compliance at the Alberta Electric System Operator. “I think it’s going to really have to be a matter of how things unfold,” she said.
Frye asked for forbearance as WECC attempts to transition to hybrid meetings.
“The final point I’ll make is just to really ask grace as we start to implement hybrid meetings,” Frye said. “We’ll be evaluating the technology that we have in our meeting rooms, [and] it will be something new and different to have a combination of in-person participants and remote participants. So there may be some technology bumps along the way, and we’ll keep learning and evaluating what we might need on our end to provide the best experience for all of our stakeholders.”
Restrictions Relaxed, FlexWork Begins
Frye on Wednesday also informed the board that WECC will begin welcoming all staff to return to the Salt Lake City office on April 4, relaxing existing limits on the number of people allowed to work in the building on any given day.
“We have announced to our employees that we think now is the time to start to transition to our FlexWork — new normal — that we’ve developed,” Frye said.
WECC announced its decision to implement the new FlexWork program last June. The program is designed to give most employees the option to work from home, while also holding out the requirement that they might need to put in “core hours” at the office to attend trainings, committee meetings, regulatory audits and board meetings. FlexWork was postponed in September as the Delta variant fueled a surge in COVID cases.
“Our FlexWork program is a strategic business initiative that provides flexibility in work schedules that best fits WECC’s business objectives and expectations, and fulfills individual and team needs on the job in a collaborative and flexible work setting,” Julie Booth, WECC manager of communications and outreach, told ERO Insider Wednesday.
With the rollout of the program next month, WECC will lift current pandemic-related restrictions, including the 50% cap on attendance, the requirement to use the ClearPass application to sign in to work a day in advance to provide a health attestation and the need to wear a mask.
“For FlexWork, we will keep in place extra cleaning measures, hand sanitization stations and mask wearing when requested,” Booth said.
Consumers, environmentalists, utilities, developers and labor organizations expressed support for New York’s plan to expand state solar incentives by $1.5 billion through 2030, but many are concerned with who pays, how much, and how often (Case No. 21-E-0629).
The groups filed comments in response to the Public Service Commission’s roadmap for achieving 10 GW of distributed solar by the decade’s end. Installed distributed solar and projects under development already total more than 93% of the previous state goal of 6 GW by 2025. The roadmap defines distributed solar as including residential, non-residential and commercial/industrial projects, including community distributed generation, distinguishing them from utility-scale projects (greater than 20 MW). (See New York Issues 10 GW Solar Roadmap for 2030.)
McGowan Southworth, a solar advocate and consultant said owners of small buildings that have taken out solar loans tied to the value of solar production under the NY-Sun program will not be able to make monthly loan payments if Con Edison doesn’t distribute value stack credits accurately and consistently.
“This would in turn harm their credit [and] also erodes fragile trust between the end customer and all parties related to solar, utility and PSC included,” Southworth said. “Would the PSC allocate funds for auditing community solar accounts on behalf of subscribers who are otherwise bearing this cost and administrative headache?”
Cost Concerns
New York utility customers already are overburdened and contribute billions of dollars annually to a large and rapidly growing list of customer-funded programs and initiatives, said Multiple Intervenors (MI), an ad hoc group of more than 50 large commercial, industrial and institutional energy consumers.
The state’s economy is continuing to experience the disruptive impacts of the COVID-19 pandemic, as well as energy prices that have skyrocketed this year, the group said.
“The solar roadmap fails to demonstrate why certain proposed costs, such as supplementing the labor costs of solar developers, even should be funded by utility customers,” MI said. “The commission … should evaluate such proposals collectively with the other programs and initiatives that customers already are being required to fund. This type of comprehensive evaluation is long overdue and should be undertaken expeditiously.”
C/I projects sized between 1-5 MW occupy an important space in New York’s solar portfolio, with economies of scale producing lower development costs compared to residential rooftop and small commercial sectors. | NYSERDA
New York City said it supports expanding incentives, noting that for Con Edison customers, the average bill impact in 2024 — the year of highest impact — is estimated to be 0.52% for residential customers and 0.97% for commercial and industrial (C&I) customers.
“The estimated bill impacts are modest and reasonable when weighed against the benefits that customers should realize in return for their investment,” the city said. Solar developer Ecovis Group said the rules requiring the payment of prevailing wages for distributed energy resources over 1 MW will tax the finances of small local companies.
“We are asking the PSC to add requirements for monthly progress payments to the contractors for work completed the previous month. This will help to offset cash flow changes,” Ecovis said. “Developers are going to receive additional funds through [New York State Energy Research and Development Authority] grants; however contractors will bear the brunt of the cash requirement.”
Climate Jobs NY, a coalition of labor unions representing 2.6 million workers in the state, said it supports the program expansion, which the state says should create 6,000 new jobs.
Developer Incentives
The New York Power Authority said it supports the roadmap, but that uncertainty around the availability of future incentives has caused customers working with NYPA to hesitate on committing to new projects.
“This observation is particularly pronounced amongst customers in Con Edison’s service territory, where project economics are challenging due to high labor and installation costs, along with the siting constraints inherent to the region’s dense urban environment,” NYPA said.
A group of environmental organizations including Scenic Hudson, Natural Resources Defense Council and the Sierra Club said that NY-Sun should include an incentive for projects that include agrivoltaics — the co-location of solar-powered projects and agriculture — similar to those for landfill, brownfields and parking canopy projects.
“Providing such incentives in the NY-Sun program will have several benefits, including achieving distributed solar targets, supporting the agricultural economy, and promoting community acceptance of projects in rural and farming communities that might otherwise object to projects as a threat to farmland and community character,” the environmentalists said.
The Joint Utilities, representing the investor-owned utilities in New York, said they are developing a pilot to bring more solar energy to underserved communities in support of the state’s expanded target.
“In addition, the mid-point review should explore more funding sources and evaluate incentive levels so that necessary modifications can be made before funding is exhausted,” the utilities said.
New York City said Con Edison deserves a bigger slice of the incentive pie, given its outsize share — 39.6% — of total electricity sales in the state.
The city supports the proposal to segment Con Edison incentives based on system size, which will ensure that smaller projects can continue to be built.
The city recommended, however, that the commission modify the roadmap’s proposals for Con Edison and create three tiers of incentives for non-residential projects versus the proposed two tiers. The city also called for reducing the base incentives for non-residential projects to encourage up to 568 MW of new distributed solar in Con Edison’s territory. It also said the state should re-allocate some of the base incentive dollars to increase the proposed community adder for community solar projects in Con Edison’s territory.
Community organizers WE ACT for Environmental Justice said that “a proposal of this size, without comprehensively planning for equitable outcomes, could do more harm than good,” and that the investment must comply with the statutory requirement that disadvantaged communities receive 40% of overall benefits of state spending on clean energy and energy efficiency programs.
“Right now, the only benefit being accounted for and attributed to disadvantaged communities is bill discounts of 10%. The benefits of distributed solar are plentiful, and bill discounts are one very small piece of that pie,” said WE ACT policy director Sonal Jessel.
MISO’s subregional cost-allocation plan for its long-range transmission projects had both fans and critics at FERC this week.
The RTO has proposed a 100% postage stamp allocation to load for the long-range projects, limited to two of its subregions, in a filing at FERC. Entities had until Monday to file comments, protest or intervene (ER22-995).
Industrial customers denounced the cost recovery plan, arguing against the sub-regional allocation for yet-to-be-determined projects. Consumers Energy said it was concerned that the grid operator hadn’t yet shared specific calculations of benefits for actual projects.
Others said the RTO’s separate-but-equal allocation application is inherently unequal.
MISO hopes to have the allocation plan, limited to its Midwest and South regions, in place by mid-May. The first long-range projects, all in MISO Midwest, are targeted for board approval in June.
WPPI Energy said if FERC accepts the filing, it should “prevent” MISO from violating the commission’s cost-allocation principles by requiring the RTO to explain when it will use a subregional versus region-wide cost recovery. The grid operator should also defend its strategy to use a different allocation design for the final two cycles of projects in its long-range transmission plan, WPPI said. The utility said it might be unfair to employ a different cost allocation once MISO begins planning long-range projects in its South subregion.
The recovery design relies in-part on a Brattle Group analysis that shows Midwestern projects are unlikely to produce benefits that seep into MISO South unless the subregional transmission transfer capacity limit is increased. Multiple stakeholders have said they’re hopeful that the long-range planning effort’s third and fourth cycles produce a project that broadens transfer capability between Midwest and South.
Staff have repeatedly said the RTO’s postage stamp rate separated by subregion is meant to be temporary and only applies to the first two project cycles. The grid operator has already begun stakeholder talks on a more permanent allocation design. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)
Other stakeholders told FERC the plan represents the best option for now.
Americans for a Clean Energy Grid said the cost allocation design will confront an “existing roadblock to regional transmission development.” The group said FERC should permit flexibility in cost allocation “if it enables regions to gain stakeholder support for new transmission expansion.”
NextEra Energy said it “strongly supports” the proposal because it’s a step toward developing necessary transmission infrastructure.
The Organization of MISO States said it supported both the bifurcated postage-stamp approach and the plan to create a new allocation methodology for the second half of long-range projects.
DTE Electric said the establishment of two separate cost-sharing subregions is appropriate because it follows FERC’s “roughly commensurate” benefits standard for allocation.
DTE also asked that MISO include tariff language that ensures staff and members also consider customer affordability when planning new transmission.
“Customer affordability metrics should be established and used as a tool in the planning process to ensure that transmission investment is financially feasible for customers across the entire MISO footprint,” DTE wrote.
Entergy, which accounts for the lion’s share of MISO South, also supported the filing. The utility said although the plan was “not perfect,” it characterized a compromise among stakeholders. Entergy also noted that MISO Midwest “is clearly at the forefront of the portfolio transition that MISO describes as a driving force behind” its long-range transmission plan.
Chairs of the Senate and House energy committees in the Minnesota legislature wrote to “stress the urgency of MISO’s long-range transmission planning process to affordably allow carbon-free energy to be built at the scale required and demanded in Minnesota.” They said the state’s utilities, including Xcel Energy, Great River Energy and Minnesota Power, “are some of the most forward-looking utilities on clean energy in the country.”
Capacity prices in Southeast New England fell to $2.639/kW-month in Forward Capacity Auction 16, a 34% decrease from last year’s auction, ISO-NE reported Wednesday. The total cost of the FCA 16 was $1.04 billion, a $320 million (24%) drop from 2021.
ISO-NE said the auction procured 32,810 MW of capacity for the 2025/26 period.
Prices were mostly flat outside of the Southeast zone, coming in at $2.531/kW-month in Northern New England and Maine, and $2.591/kW-month in Rest of Pool.
“New England’s clean energy transition is well underway, and the region’s wholesale markets are playing a vital role by sustaining a reliable power system, maintaining competitive prices and creating opportunities for the resources that will be the backbone of our clean energy future,” said Robert Ethier, ISO-NE’s vice president for system planning.
Nearly 5,000 MW of renewables, energy storage and demand resources cleared the auction, making up 15% of the total capacity, ISO-NE said. That includes more than 700 MW of energy storage, 500 MW of solar generation and 275 MW of existing wind generation.
Resources worth 256 MW submitted retirement bids, all of which cleared, and 1,540 MW worth of generation was delisted.
No Delist for Merrimack Power
The owner of New England’s last active coal plant, Merrimack Station, submitted a static delist bid, seeking to remove its two units from the capacity auction if prices dropped below a certain point (the dynamic delist bid threshold).
But the bid was rejected by ISO-NE’s Internal Market Monitor, which reviews delist requests, and subsequently withdrawn by the operator of the plant.
Resources successfully submitting retirement bids included Potter II, a 96-MW combined cycle plant owned by Braintree Electric Light Department; two units at Schiller Station in New Hampshire, which shuttered in 2020; and two units burning kerosene and gas at the West Springfield Generating Station.
Information about which individual resources cleared the auction will be published when ISO-NE sends its filing to FERC, expected to occur as early as next week.
A Disjointed Process
The results were delayed by several weeks because of the uncertainty over the Killingly Energy Center, which won a last-minute stay from the D.C. Circuit Court of Appeals allowing it to temporarily take part in the auction. (See Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)
ISO-NE ended up tallying results both with and without Killingly participating, and when the Connecticut natural gas plant under development by NTE Energy ultimately lost its appeal at FERC and forfeited its financial assurance, the grid operator was able to confirm that it would be using the results without the plant.
Killingly’s exit from the market had an effect on the auction’s outcome, said Dan Dolan, president of the New England Power Generators Association.
Prices dropped sharply in Southeastern New England in FCA 16 vs. FCA 15, pushing overall costs down by nearly one-quarter. | ISO-NE
“We saw with the removal of Killingly less supply than the prior year’s, and when matched with the lower demand this year versus FCA 15, it led to relatively flat pricing overall,” Dolan said. “There are continued historically low capacity prices across the board.”
NEPGA’s members have been frustrated with the uncertainty created by the Killingly delay, Dolan said, but they are relieved that the results have been released and that the grid operator is working quickly to start the process for next year’s FCA 17.
“There is a feeling of ‘we can make this work.’ This is now a manageable timeline and process overall,” he said.
Humboldt call area | BOEM
