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November 14, 2024

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Wash. Looks to Become Supplier to West Coast OSW Efforts

Washington is looking to launch an effort to become an industrial supplier to the offshore wind sector expected to develop off the West Coast.

No specific goals or deadlines have been set for the effort.

“We don’t know that yet,” said Joshua Berger, CEO of Washington Maritime Blue, a coordinating organization for many of the state’s maritime businesses and activities.

Berger, Gov. Jay Inslee and others announced the start of the effort Tuesday in Seattle. The next step is for state agencies, ports, manufacturers and business associations to meet to identify shortfalls and map out approaches and goals for the venture. The venture will also need to address gaps in knowledge about the industry, training needs and getting a handle on needed technologies, Berger said.

“The jobs created in this supply chain could be enormous. … This can create a supply chain that can go in many different places,” Inslee said.

“Training the additional workers must begin now,” said Ryan Calkins, a commissioner for the Port of Seattle.

“The potential jobs this industry can create is mind-boggling,” said Herald Ugles, president of the International Longshore and Warehouse Union Local No. 19.

All the ports along Washington’s coast would need to be involved, said Deanna Keller, a commissioner for the Port of Tacoma, which was represented at the event along with the ports of Seattle and Everett. The ports of Seattle and Tacoma have begun a joint study on the subject, Keller said.

“There’s a lot of research to be done,” Inslee said.

Nationwide, the offshore wind turbine manufacturing industry has the potential to become a $70 billion industry, Berger said.

So far, West Coast offshore wind efforts have focused on the waters off California and Oregon, with the first auctions for leases off the coast of Northern California fetching $757 million last year. (See First West Coast Offshore Wind Auction Fetches $757M.)

While there are no active projects targeting Washington’s shoreline areas, the Bureau of Ocean Energy Management has received two unsolicited proposals for projects off the state’s coast, Berger said.

In a related matter, the Department of Energy has selected an Oregon State University research team to receive $2.5 million to study what coastal communities think of potential offshore wind energy development. The money goes to the Pacific Marine Energy Center, a marine renewable energy group made up of universities led by Oregon State.

Researchers will interview and survey coastal residents to better understand the preferences, concerns and values of local communities where offshore wind development has been proposed, lead researcher Hilary Boudet, an Oregon State associate professor of sociology, said in a press release.

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NY Rejects Inflation Adjustment for Renewable Projects

New York on Thursday rejected inflation adjustment requests for 90 planned wind and solar projects that total more than 12 GW of capacity and constitute much of the state’s contracted clean energy pipeline.

The industry organization that petitioned for most of the adjustments called the move short-sighted, casting the projects into “serious jeopardy” and potentially putting the state’s 2030 statutory clean-energy goal out of reach. Construction has not begun.

But the Public Service Commission said granting the developers’ requests would undercut the competitive energy market as well as the fairness and integrity of the bidding process by which the state is building out its renewable portfolio.

There also is the issue of money: Utility ratepayers already were on the hook for $10 billion worth of renewable energy certificates that would help fund the projects, Department of Public Service staff said. Granting the increases sought would have raised the cost to $22 billion, staff said, with no guarantee that further increases would not be needed.

The developers of four offshore wind projects, five onshore wind projects and 81 solar projects contracted in earlier state solicitations petitioned on the same day in June 2023 for cost-adjustment mechanisms similar to those included in more recent solicitations (Case 15-E-0302 and Case 18-E-0071).

Most of these projects have been in development for several years and recently have seen sharp cost increases — but there was no inflation-adjustment mechanism in their solicitation.

The New York State Energy Research and Development Authority, which is managing the state’s renewable energy procurement, eventually declared support for some form of inflation adjustment.

After Thursday’s PSC order, NYSERDA said it would move to expedite the bidding process.

“NYSERDA recognizes the critical competitive principles articulated in today’s New York State Public Service Commission order,” President Doreen Harris said in a prepared statement. “Based on this order and Governor Hochul’s direction, NYSERDA, as the administrator of the Clean Energy Standard, will act swiftly to continue advancement of large-scale renewable energy projects toward meeting New York’s Climate Act goals.”

Later Thursday, NYSERDA released a new action plan to support renewable energy development and maximize the economic benefits derived from the transition. (See “NY Creates Action Plan for Renewable Energy Development“).

Polarizing Issue

New York has among the most ambitious clean energy/climate protection agendas in the nation and has backed it up with aggressive policy moves.

But it also is known as one of the slowest and most expensive places to develop generation and transmission. And it already has some of the highest electric rates in the nation, particularly downstate.

The June petitions were polarizing: Some comments to the PSC urged approval because the climate crisis is so pressing, or because so many jobs would be supported by the projects. Others urged rejection because the request was unfair and/or expensive. Some commenters merely laid out their organization’s priorities without suggesting how to meet them.

Thursday’s PSC meeting had an abnormally large audience — more than 1,000 people were watching online at one point.

But the sometimes-fractious group of seven commissioners united in criticism of the request and rejected it unanimously.

Several lashed out at the perception they said some clean-energy advocates had created in the days leading up to Thursday’s meeting — that the PSC with its vote actually would be terminating the contracts, and that the entire clean-energy transition was riding on their vote.

Commissioner Tracey Edwards decried the “audacity” of the request.

“To say, ‘Well, you have to give us 12 billion more dollars or we’re going to walk away?’ Walking away is your choice. And we certainly hope that you do not do that. But that is on you. It is not on us.”

Another point made: The bidders who won state contracts for their projects beat out other bidders who might have submitted more expensive but more realistic bids; to give them more money now would encourage future bidders to submit lowball proposals with the expectation of adjustments after signing the contracts.

PSC Chair Rory Christian said competitive procurement is critical to protect ratepayers in a competitive energy market.

“So, by rejecting this relief, we signal to every vendor that our contracts, our commitments, are worth the paper they are written on. We signal that ratepayer funds are not an unlimited piggy bank.

“To the developers: We have a deal. We expect all developers, no matter how large, to abide by their commitments … New York will continue to lead, but we will not be willingly led onto a path that jeopardizes all our future endeavors.”

Not addressed Thursday was the fate of related petitions by developers of two major transmission projects, Clean Path New York and Champlain Hudson Power Express, both of which sought inflation-related adjustments if the generation projects were granted such an increase.

Commissioner Diane Burman said those petitions should be considered moot because they were predicated on the PSC allowing an inflation adjustment to the 90 generation projects, which it was not going to do.

Stakeholder Reaction

While criticizing the inflation request, some of the commissioners took a moment to say they did not doubt the economic pressures cited in the petitions were real and were damaging.

Multiple developers have said their projects cannot go forward under the financial terms they agreed to years ago.

Among the most visible, because of their sheer size, were the Beacon, Empire and Sunrise offshore wind projects, which total 4.2 GW of nameplate capacity and would provide nearly half the state’s 9-GW offshore wind goal.

Without them, New York has only the 132-MW South Fork Wind project, now under construction east of Long Island.

All Northeast offshore projects not already under construction are struggling, not just New York’s. Power purchase agreements were canceled for three New England projects for the same reasons as are being cited in New York.

Ørsted, the world’s largest offshore wind developer, has been particularly blunt about potentially not proceeding on its U.S. projects without more money.

David Hardy, CEO Americas for the Danish company, told NetZero Insider via email:

“We are disappointed in the PSC’s decision today. The timely development of Sunrise Wind is critical to meeting the state’s 2030 clean energy targets. We believe making available the same inflation-related mechanisms offered to recent offshore wind projects is a reasonable solution for addressing the unprecedented macroeconomic factors challenging first-wave offshore wind farms while also keeping New York’s climate goals within reach.

“We are reviewing the PSC’s order, but Sunrise Wind’s viability and therefore ability to be constructed are extremely challenged without this adjustment. We will evaluate our next steps and communicate the status of the project as soon as possible as our joint venture and board consider the best options going forward in light of this decision.”

The Beacon and Empire projects are a joint venture of Equinor and BP.

Equinor Renewables America President Molly Morris told NetZero Insider via email:

“Equinor and bp are disappointed at the New York Public Service Commission’s rejection of Empire Wind and Beacon Wind’s petition for support to help offset the unforeseen challenges facing our industry today stemming from inflation, supply chain disruptions and high interest rates.

“Equinor and bp’s Empire Wind and Beacon Wind projects are poised to deliver enough renewable energy to power approximately two million New York homes while sparking billions of dollars in economic development, creating thousands of jobs and delivering new infrastructure for the 21st century. At the same time, these projects must be financially sustainable to proceed. Equinor and bp will assess the impact of the State’s decision on these projects.”

The Alliance for Clean Energy New York submitted the petition on behalf of developers of the 86 onshore projects. ACE NY President Anne Reynolds told NetZero Insider on Thursday that the commissioners’ lengthy comments rejecting the petitions skimmed over some key facts:

Not one said canceling and rebidding would be less expensive or more beneficial for ratepayers.

The concept of rebidding previously is unmentioned, and there is no indication how it would work. (NYSERDA could not provide any clarification by late Thursday.)

There are not a lot of viable locations for onshore wind left in upstate New York — if these five projects are canceled, there are few alternatives.

The criticism that ACE NY’s petition does not guarantee the projects would be built even if they got the inflation adjustment is a nonissue. First, the point is moot if they are not built because there will be no RECs to adjust the price of. Second, there are factors beyond the control of ACE NY or the developer that could delay or kill a project, including interconnection and local permitting — so a guarantee would be meaningless.

Reynolds said the developers ACE NY represented in the petition agree their projects are at “serious risk” without the relief sought in the petition. But whether or when a project is canceled likely would depend on the time frame for any opportunity to rebid, and on the timing of costly milestones such as contract deposits or interconnection fees.

She added:

“The question [PSC commissioners] should have been asking today is not the cost of requested relief vs. zero, it should be a question of the requested relief vs. what it’s going to cost New York to get those renewables another way.”

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Focused Strategies Needed to Electrify ‘Frontline’ Communities

SACRAMENTO — To decarbonize homes in low-income communities, agencies need to remove administrative barriers, consider all types of housing and prepare for a hotter world, experts said at the Summit on Building Electrification co-hosted by the California Energy Commission and the Electric Power Research Institute, held at the California Natural Resources headquarters in Sacramento.

While a deluge of incentives from the Inflation Reduction Act and various state and utility programs is making home electrification more affordable than ever, renters and owners of multifamily, manufactured and mobile homes face challenges, and in some cases opportunities, when it comes to building electrification. While much of the building electrification work is about removing gas appliances from homes, areas such as unincorporated parts of the San Joaquin Valley that never had gas infrastructure can leapfrog to electrified buildings.

Following are three key takeaways from the event.

It Takes a Wide Lens to Look at Frontline Community Housing

Phoebe Seaton, Leadership Counsel for Justice and Accountability | © RTO Insider LLC

As building electrification is considered, buildings themselves need to be defined broadly to catch the range of living situations low-income households may face. Incentives and programs that work for single-family owner-occupied homes may need to be substantially rethought for multifamily dwellings, manufactured and mobile homes, and renter-occupied homes.

“It’s important to support different housing types and tenures,” said Jennifer Gress, chief of the Sustainable Transportation and Communities Division at the California Air Resources Board. “Making sure that vulnerable renters can remain in their homes as we embark on building decarbonization efforts is one of the biggest worries that we hear from stakeholders.”

“We’ve learned that mobile homes and manufactured homes have significant and particular and unique obstacles because of ownership and infrastructure and require unique interventions,” as do renter-occupied homes, said Phoebe Seaton, co-founder and co-executive director of the Leadership Counsel for Justice and Accountability. “In terms of reaching the most vulnerable, if we can figure out a deployment strategy to decarbonize renter-occupied manufactured and mobile homes, then we can decarbonize the whole state.”

Protecting tenants is a critical piece of the puzzle, Seaton said. “In terms of policy, we really need to make sure that all investments, especially for leased homes, come with tenant protections so we don’t have what we see time and time again in our housing work: funding comes in for upgrades and six months later the tenants are out.”

Habitability Needs to be Redefined as Temperatures Rise

As climate change leads to more extreme heat events, housing standards have to address acceptable indoor temperatures, Seaton said. Housing standards have long focused on ensuring homes don’t get unacceptably cold in winter; however, the potential for 100-degree-plus temperatures indoors is changing the parameters that need to be considered in housing for frontline communities.

“The Department of Housing and Urban Development with many other stakeholders and agencies are developing policy recommendations to address extreme heat in homes right now in California,” she said. “There is no rule that homes can reach or maintain a healthy temperature. There are rules on the low side — there needs to be sufficient heating to make sure that homes are habitable — but there’s nothing on the high side,” Seaton said. In California, building codes require heating but not cooling, the Sacramento Bee reported last year that a quarter of homes in California lacked air conditioning.

Bundling and Streamlining are Critical for Adoption

“With all the IRA programs and all the other various programs coming down the pike, we have to be aware that the landscape is already very challenging to navigate,” said Andy Brooks, senior director at the Association for Energy Affordability. “We need to make sure that we’re doing everything that we can to avoid making it any more complicated.”

Brooks said that in multifamily housing, it is important to wrap as many upgrades into a program as possible, given how time-consuming the application and implementation can be. “They’re probably not going to go through another program for quite a while and may not go through another program at all, so I try to push to do as much as we possibly can with that one touchpoint, because whatever scope gets dropped from that project may never actually get done.”

Gress said the range of programs and incentives can create a barrier, and called for not only streamlining application processes, but also ensuring money is not needed upfront. Thinking about housing upgrades for a whole home is better than taking a piecemeal approach with separate incentives for individual upgrades. “Make sure the incentive programs can fund a variety of different home improvements, like energy efficiency, energy storage, panel upgrades and electric appliances, but also home repairs and other health and safety needs, so the home can really be upgraded completely,” she said.

Seaton said bringing more funding into existing programs rather than adding to the already-sizeable number of programs would avoid further complicating an already-challenging maze of incentives and programs.

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MISO Agrees to Dial Back Tx Service Requirements for Energy Storage

CARMEL, Ind. — MISO this week said it agrees with its stakeholders it has onerous transmission service requirements for energy storage resources charging from the grid and should relax requirements.

Until now, the RTO has operated under the assumption that storage resources would secure long-term, firm, point-to-point transmission service before they began charging.

Members of MISO’s Environmental Sector argue FERC’s Order 841 doesn’t require storage to obtain firm, point-to-point transmission service and instead allows as-available transmission service. After reviewing Order 841, MISO agreed it should loosen its requirement that storage secure yearly, firm point-to-point transmission service. (See Stakeholders Puzzled by MISO Transmission Service Requirements for Battery Storage.)

Manager of Resource Utilization Kyle Trotter said battery storage should be treated like any other intermittent load in MISO.

Speaking at an Oct. 11 Planning Subcommittee meeting, Trotter said MISO agrees storage resources should be afforded the option to use either non-firm, point-to-point transmission service or its Network Integrated Transmission Service under any length of time.

“You’re not restricted to firm, you’re not restricted to duration,” Trotter said during an Oct. 11 Planning Advisory Committee. He said MISO expecting long-term, firm, point-to-point is an “overly restrictive transmission service requirement” for charging storage resources.

“Operationally, batteries do not charge 24/7; nonfirm is available down to the hour and provides more flexibility to the customer,” Trotter said.

Trotter said MISO believes storage resources in charging mode are willing to be curtailed when prices are high from transmission congestion or emergency conditions. He said the RTO doesn’t require other capacity resources to acquire firm fuel supply or firm station service load, so storage shouldn’t be treated differently. He also said long-term service is unnecessary for storage because their charging behavior is mostly price-driven and occurs off-peak.

“I think this is really important to straighten out for energy storage resources,” Southern Renewable Energy Association’s Andy Kowalczyk said.

Trotter said he will return to the Nov. 15 Planning Advisory Committee meeting with suggested revisions to the business practice manuals to strike the requirement.

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FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough

MISO cannot wait until 2030 to roll out the welcome mat for DER aggregations in its markets, FERC ruled Tuesday.

FERC said MISO must submit a new date to achieve Order 2222 compliance in a more “timely manner.” The commission also ruled MISO has more work ahead of it to be fully compliant with its order unlocking participation in wholesale markets to distributed energy resource aggregations (ER22-1640).

MISO requested FERC allow it until Oct. 1, 2029, to register DER aggregations, with the first offers to follow in the first quarter of 2030. The RTO explained it first needed to replace its market platform before it has the technological capability to register, enroll and facilitate offers from DER aggregations. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)

FERC said while MISO “persuasively explained” why its new market engines are a prerequisite for DER aggregator software and participation systems in its markets, the RTO didn’t justify the need for an additional five-year gap between completion of the new market platform in 2024 and the first DER aggregation registrations in late 2029.

“We find that MISO’s proposed effective date of Oct. 1, 2029, is not timely because, once MISO implements the [market platform replacement] project, MISO proposes to defer Order No. 2222 implementation for several years,” FERC said.

FERC said while it understood MISO wants to create a multiple configuration resource modeling, it said that shouldn’t also keep the RTO from opening its markets to DER aggregations for multiple years. MISO had said it should prioritize introducing a multi-configuration resource participation model before it tackles offers from DER aggregations because the former will yield more economic and reliability benefits.

However, FERC said, “facilitating distributed energy resource participation … will provide many of these same benefits.”

Single or Multiple Pricing Nodes?

FERC sent MISO back to the drawing board on several other aspects of its Order 2222 compliance.

Notably, FERC said MISO’s plan to limit aggregations to a single pricing node rather than across multiple nodes might be counter to the order’s directive that the locational requirements of DER aggregations be geographically broad as technically feasible.

MISO’s DER aggregation proposal specified that DER aggregations be at least 0.1 MW, be wholly located within MISO and limited to a single pricing node and self-commit their output in the MISO markets based on their own forecasts.

FERC said it understood MISO has concerns about congestion management challenges that could arise if DERs are aggregated at the opposite sides of a transmission constraint; however, it said “MISO has not demonstrated that it is not technically feasible for DERs to aggregate across a broader geographic area than a single node, at least for some nodes or groupings of electrical facilities that have similar impacts on the same transmission constraints.”

FERC told MISO it should better explain whether a broader aggregation is technically infeasible, not just challenging. It also said MISO’s potentially incomplete compliance with the locational requirements of Order 2222 raises the question of whether MISO must establish market rules that address distribution factors. MISO originally said its single-node pricing framework would not require distribution factors.

Commissioner Mark Christie said he thought MISO’s proposed pricing was fair and that pricing aggregations at more than one node would create a different compensation method for one category of resources and thus, undue preference.

“MISO’s proposal to price [aggregation] compensation at the node is technically feasible and is economically efficient, non-discriminatory and fair because it treats all resources similarly,” Christie said in a concurrence.

Christie said FERC should accept MISO’s pricing proposal “right now rather than make MISO produce more paperwork.” He said he only wrote a concurrence instead of a dissent because FERC didn’t outright reject MISO’s pricing plan.

Danly: A ‘Good Faith Effort’ on a Daunting Task

In a concurrence again lambasting Order 2222’s “micro-management” of RTO activities, Commissioner James Danly said MISO made a “good faith effort” to comply with the order but came up short.

“While I continue to disagree with Order No. 2222 itself, I agree that MISO failed to fully comply with its scores of dictates. I do not envy MISO the task we imposed upon them. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt. We shall see,” Danly wrote.

Other Compliance Shortcomings

FERC asked MISO to clear up several other aspects of its plan, including the role of relevant regulatory authorities over distribution systems. The commission said although regulatory authorities can choose to conduct their own distribution technical reviews and establish other rules that can override aggregators’ operations, MISO didn’t explicitly describe that role in Tariff revisions.

FERC also ruled MISO must add Tariff language that requires DER aggregators submit attestations that their aggregations comply with the operating procedures of distribution companies and the rules and regulations of their regulatory authorities. MISO’s plan should include an instruction to aggregators to provide a list of the individual DERs in their aggregations, FERC added.

The commission rejected MISO’s proposal to use a 10-MW threshold for aggregations before applying some market mitigation rules. FERC pointed out that MISO doesn’t use a size-based threshold for mitigation rules for any other class of resources.

FERC said MISO’s compliance plan didn’t explicitly spell out that aggregators will submit offers up to 30 minutes to the operating hour to reflect capability and must update offers in real time if DER availability changes.

FERC told MISO its proposed double-counting and technical review process of DER aggregations exceeded Order 2222’s 60-day limit. It also said MISO didn’t specify how it would share information about specific DERs provided to it by a distribution utility with aggregators as part of the distribution utility review process.

FERC also said MISO should be clearer on its protocols for sharing metering and telemetry data and should explain how such protocols will minimize costs while addressing privacy and cybersecurity concerns.

Beyond that, the commission said MISO needs to define how it will handle possible disputes over the potential impact of DER aggregations’ interconnections on the transmission system. MISO additionally must clarify how it will manage dispute resolution under its proposed distribution utility review process. The commission said while it agreed with MISO that many disputes are best left to the relevant regulators of DER aggregations, some disputes — especially those concerning information sharing during distribution utility review — will need to be resolved by MISO.

Finally, FERC said though MISO proposed that distribution companies could perform eligibility reviews, that section didn’t contain any criteria or standards distribution companies might use to establish whether a DER is capable of participating in an aggregation. The commission ordered MISO to explain whether it would incorporate additional eligibility criteria beyond those related to the required double-counting review.

FERC similarly said MISO’s proposed distribution utility review process to determine whether a DER will pose harm to the distribution system lacked criteria.

The commission said MISO should continue to coordinate with distribution utilities on those processes. It gave MISO 60 days to address its compliance imperfections.

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In West, Proposals for Tx Planning Proliferate Faster than New Lines

SEATTLE — The state-led Committee on Regional Electric Power Cooperation (CREPC) should spearhead an effort to boost development of new transmission in the West, according to the findings of an initiative that included contributions from former FERC Chair Richard Glick.

The findings were the product of the Western States Transmission Initiative (WSTI), a partnership between CREPC and decarbonization nonprofit Gridworks formed to gather input from electricity sector stakeholders on what actions the committee can take to help give Western transmission planning a more interconnection-wide perspective.

The WSTI proposals came just two days after the Western Power Pool (WPP) floated a plan to create a new group intended to spur the kind of interregional transmission development envisioned in the WSTI effort. (See Plan Seeks to Boost Prospects for New Transmission in the West.)

Key among the WSTI recommendations: CREPC should create a Transmission Working Group that would seek federal funding to hire staff and consultants to examine the state of the Western grid with an eye to fostering a shift from the region’s current “bottoms-up” approach to transmission planning, which favors smaller projects that satisfy local needs, to a process that prioritizes meeting the needs of the wider West with larger-scale projects.

The group also would be tasked with identifying specific interregional projects and possibly could seek National Interest Electric Transmission Corridor (NIETC) designations for some of those projects. That would allow them to reduce investment risk by tapping federal funding, Glick pointed out during an Oct. 4 discussion of the WSTI recommendations at the fall joint meeting of CREPC and the Western Interconnection Regional Advisory Body (WIRAB) on Seattle’s waterfront.

“There’s also one other element to it that people may not agree with, especially state regulators: It would also give FERC backstop siting authority for those particular routes that were essentially rejected by one or more states,” Glick said.

The Transmission Working Group also would focus on potential approaches to allocating costs for interregional projects and seek to coordinate approaches among Western states.

The WSTI also recommended the group host a Western transmission conference that would include multiple stakeholders, including officials from U.S. states and Canadian provinces.

“I think the idea of hosting a conference is to get input from … various stakeholders,” Glick said. “Not just utilities and [independent power producers] and transmission developers, but also other entities as well — voices that are normally not heard, whether it be communities, consumer groups, the business community [and] big industrial customers.”

The Transmission Working Group’s other “potential actions” could include encouraging “independent” planning processes; promoting “forward-looking and inclusive” planning; monitoring and participating in FERC transmission planning and cost allocation rulemaking and compliance proceedings; and participating in other regional transmission planning efforts.

‘Meaningful’ Planning

Sharing the dais with Glick at the CREPC-WIRAB meeting, Gridworks Director Kate Griffith said the WSTI recommendations were the product of a six-month project that included interviews with 40 organizations, which included state agencies, non-governmental organizations, utilities, tribes and other stakeholder groups from across the West.

Key themes emerging from those interviews included the “insufficient” pace of transmission development in the West, the lack of “meaningful” interregional and interconnection-wide transmission planning, and the impediment to development caused by the lack of agreement over cost allocation.

Interviewees also said most utilities lack the resources to build major projects on their own and that state/provincial coordination could play a key role in transmission development but would need more resources.

Oregon PUC Chair Megan Decker | © RTO Insider LLC

“Today’s presentation and discussion really just starts a conversation at CREPC,” Griffith told the audience at the Seattle conference. “After today’s conversation, CREPC co-chairs will be encouraging you all to share your feedback with them, and we’ll be scheduling a follow-up conversation about whether or not to pursue these recommendations.”

If CREPC decides to advance on the recommendations, Griffith said, Gridworks plans to announce the formation of the Transmission Working Group by the end of October and begin efforts to identify transmission corridors and seek consultants to engage in the effort.

State officials attending the conference largely seemed to support a larger role for CREPC in transmission planning.

Washington Utilities and Transportation Commissioner Ann Rendahl said it is “critical” to bring the states together to participate in the process. Rendahl described her experience with NorthernGrid, the Northwest’s planning entity, as one in which the group tells regulators, “‘We’ll check in with you and see if you have any thoughts’ — and that doesn’t really feel like being included in the process and having a perspective.

“With changes in state policies across the board in the West, it’s important to … get everybody’s views as to what’s important and what’s needed for the states to accomplish” their goals, Rendahl said.

“What happens next depends on the feedback we get from all of you today and over the course of the rest of the conference … and the follow-up conversation that we have,” Megan Decker, CREPC co-chair and chair of the Oregon Public Utility Commission, told meeting participants.

Dare to Dream

“I know how much CREPC enjoys an October surprise,” WPP CEO Sarah Edmonds joked during an Oct. 5 panel at the conference as she described why she released WPP’s “concept paper” for the Western Transmission Expansion Coalition (WTEC) two days ahead of the Seattle meeting.

“I posted that for all of you on [Oct. 3] knowing that we could really leverage this opportunity to be together knowing what the Gridworks recommendations were going to be and what we’re trying to do as well, where I see a lot of potential overlap,” Edmonds said.

Edmonds explained that the WTEC concept took shape after Bonneville Power Administration CEO John Hairston told her he saw a need for BPA to be a strong leader for transmission development in the Northwest but thought the conversation should be held in a forum bigger than what the agency offered.

Sarah Edmonds, Western Power Pool | © RTO Insider LLC

“I said to him I was interested in it as long as it was a West-wide, inclusive activity,” said Edmonds, whose organization operates the Western Resource Adequacy Program (WRAP) and facilitates the functions of NorthernGrid.

WTEC would intend to take a “top-down” approach to Western transmission planning, one that would include the Southwest transmission planning entity WestConnect, CAISO, BPA and the Western Area Power Administration, and not seek to upend the region’s transmission planning groups, Edmonds said.

“This is not a proposal that fits under FERC-jurisdictional activities,” she said, calling it “an exploratory effort” to engage in a new approach to planning, with FERC-related processes possibly addressed further in the future.

Edmonds also sees the potential for partnership between the WTEC and the WSTI. She said engagement between the two efforts could identify “a range of things we could shoot for” while avoiding coming into conflict or harming each other.

“We might dare to dream of harmonizing, but what about synchronizing?” Edmonds said. “I’m really open for discussion on all those points because I know, and I also would say because BPA … knows, how important the state partnership is on these decisions. The entities that will build transmission and seek cost recovery also understand that critical part of the relationship. It would be new and different to think of a partnership like this, and I know the devil is in the details.”

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Wash. Weighs Joining California-Quebec Cap-and-trade Program

Washington state officials expect to soon decide whether to join the California-Quebec cap-and-trade program.

The decision could come later this month or in early November, Joel Creswell, climate pollution reduction program manager at the Washington Department of Ecology, told the state’s House Environment and Energy Committee Monday. 

Washington’s decision to join the program would require approval by California and Quebec, setting the stage for a final contract to be signed in 2025.

Creswell said joining the bigger program would likely reduce Washington carbon allowance prices from the high levels seen in this year’s quarterly auctions. Critics of Washington’s cap-and -invest program blame it for the state having the highest gasoline prices in the U.S this past summer.

Carbon prices in the Washington auctions have climbed steadily in the first year of the program, clearing at $48.50 in the first quarter, $56.01 in the second quarter and $63.03 in the third. Republican critics of the program believe the increases have driven up prices at the pump. 

The Oil Price Information Service has estimated that a $50 allowance price would translate into a 40- to 50-cent increase in gasoline prices. The state’s oil sector has acknowledged it has passed the price of allowances to consumers to account for its extra costs. 

However, the gas price tracking service GasBuddy showed that prices in Washington and Oregon (which does not have a cap-and-trade program) had been roughly the same from 2014 to 2022. On Jan. 1, 2023, about two months before the first cap-and-trade auction, Washington’s average price was 10 cents higher than Oregon’s, with the gap expanding to 36 cents by Sept. 27. That 26-cent increase could be theoretically linked to cap-and-invest, Ecology Department spokesperson Andrew Wineke said. 

On Monday, state Sen. Liz Lovelett (D) asked: “Why would California want to link with us?”

Creswell said that Washington joining with California and Quebec would boost the manufacture and sales of green technologies in all three areas as industries seek to trim their carbon emissions.

California conducted its first cap-and-trade auction in November 2012, with prices clearing at $10 per allowance. Prices hit $14 by the third quarterly auction before declining.

In 2014, Quebec joined California to create a cap-and-trade market that is six times the size of Washington’s. California-Quebec prices increased from $19 in 2021 to $36.14 this summer, according to data from the California Air Resources Board.

One reason Washington’s carbon prices have exceeded those in California is the comparatively steeper rate of carbon reductions in the Evergreen State, said Jessica Spiegel, Northwest Region senior director at the Western States Petroleum Association, to NetZero Insider.

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EIA, DNV Lay out Progress, Headwinds in Energy Transition

Two new reports released Wednesday document the progress and challenges in the global effort to reduce greenhouse gas emissions.

DNV issued the 2023 edition of its Energy Transition Outlook, concluding that the transition is still at the starting line, with new renewable generating capacity growing at the same rate as demand.

The outlook is not sunny — the report projects global warming well beyond the 2100 target of 1.5 degrees Celsius — but there are some points of optimism: It predicts slight reductions of emissions starting as soon as next year and dropping 4% lower by 2030. It predicts a 46% reduction in emissions by 2050, when it expects non-fossil energy to supply 52% of world demand.

The Energy Information Administration covers some of the same ground in its annual International Energy Outlook.

The two reports are not directly comparable, as EIA extrapolates future models from an unchanging 2023 policy baseline. It projects global fossil fuel consumption and carbon dioxide emissions would rise through 2050 without major policy adjustments to the current trajectory.

DNV Outlook

An introductory message from DNV Group President Remi Eriksen begins with a simple assessment: “If ‘energy transition’ means clean energy replaces fossil fuel in absolute terms, then the transition has not truly started.”

High prices have had opposite effects on energy industry sectors, making oil and gas exploration more lucrative and complicating the buildout of renewables, he said.

But DNV projects that emissions from oil will peak in 2025 and from natural gas in 2027.

Policy changes already are showing results in the US and EU, where per-capita greenhouse gas emissions are among the highest in the world, it said. However, in the next decade, transmission constraints and supply chain shortfalls pose a threat to progress.

Another trend playing out now is the rise of oil and natural gas prices, which tarnished the status of gas as a bridge fuel during the transition and prompted an increase in coal-fired generation in several countries. But increased fossil use in lower-income countries is gradually balanced over the next decade by increased renewables in wealthier countries, DNV projects.

Advanced economies will drive development of the technologies that will help to enable the transition, but that will not bring as much benefit to medium- and low-income regions, which need de-risked funding to accelerate the transition.

Overall, the energy mix is projected to transition from 80%/20% fossil-renewable in 2023 to 48/52 renewable by 2050, with a 10-fold increase in wind generation and 17-fold increase in solar power.

Energy security has become a motivating factor since Russia invaded Ukraine, disrupting energy supplies and prices. Local energy production is now a priority in many countries, whether it be renewable, nuclear or coal.

So while progress is being made, DNV concludes, it is not being made fast enough. Global emissions would need to be cut 50% by 2030 to achieve a net-zero energy system by 2050, but the report does not project a 50% emission reduction even by 2050.

The global target held out by some activists and scientists — keep the planet from warming more than 1.5 C by 2100 — keeps getting harder to reach, DNV said. It calculates a 2.2-degree increase through 2100 under the emissions forecast in the outlook.

EIA Outlook

EIA said its projections in the IEA conclude that while zero-carbon technology such as renewables and nuclear would meet the bulk of new demand through 2050, that is not enough to counter the increase in other sources of CO2 emissions. These include global population growth, increased regional manufacturing and the push for higher standards of living.

The projections are not forecasts, nor are they even likely scenarios; they assume the policies in place as of late 2022/early 2023 will remain unchanged for the next 27 years. (In fact, the authors note, some policy changes already have occurred as of late 2023.) Rather, the projections are a policy-neutral baseline against which future policy decisions can be considered, the report says.

EIA highlighted three main takeaways from the report.

All cases modeled show global energy consumption rising, with the fastest growth coming in the residential and industrial sectors and the greatest increase in use of liquid fuels coming in industrial applications. As more electric vehicles hit the road, applications such as chemical production account for a greater share of the liquid fuels used.

Global electric generation capacity grows anywhere from 55 to 108% from 2022 to 2050, depending on the case modeled, and actual electricity generated rises 30 to 76%. Renewables, nuclear and battery storage account for most of the increase in both metrics, but renewables grow fastest in cases that assume high economic growth and greater electricity demand.

Energy security is a driving concern in both directions: It hastens the transition away from fossil fuels in some countries and prompts increased fossil consumption in others.

“IEO2023 fills an important niche among global outlooks by focusing on a plausible but sober assessment of global energy trends through the first half of the century,” EIA Administrator Joe DeCarolis said in a news release. “There is considerable uncertainty in the energy landscape over the next 30 years, and the IEO provides a set of policy-neutral baselines that will help guide sound decision-making.”

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IMM Presses MISO for New Rules After DR Market Gaming

MISO’s Independent Market Monitor is angling for demand response offer floors and attestations of expected levels of energy consumption in the wake of an Arkansas steel mill’s gaming of the MISO demand response market.

Meanwhile, a second demand response resource in MISO might be under fire for promising load reductions and not delivering them.

In late August, FERC accepted a $35 million total settlement between Big River Steel in Osceola, Ark., Entergy Arkansas and FERC’s Office of Enforcement, of which $21 million will be returned to MISO customers. The steel mill for years collected payments from MISO for demand response while not actually reducing electricity use. (See FERC OKs $21M Settlement in Arkansas Steel Mill’s DR Scheme in MISO.)

Carrie Milton, of the Independent Market Monitor’s team, said the IMM is advising MISO to reinforce its rules for demand response resources (DRRs) “to prevent similar gaming in the future.”

“After seeing this kind of conduct, we have recommended [that] MISO establish an offer floor for DRRs and that DRRs indicate their forecasted, pre-curtailment expected consumption,” Milton said during an Oct. 5 Market Subcommittee meeting.

Milton said IMM staff recently referred another MISO DRR to the Office of Enforcement for offering “phantom load reductions” similar to Big River Steel. In this case, the unnamed company collected more than $35 million in payments from MISO.

Neither MISO nor the IMM revealed the name of the company involved with the possible new investigation. MISO said the IMM’s screening first uncovered the “information that led to FERC’s investigation” of Big River Steel.

Milton said the IMM team is working with MISO to gain support for the DRR rule changes.

MISO did not say whether it agrees with the IMM’s proposal but said it is open to exploring with stakeholders what improvements might be necessary.

“Following any situation like this, MISO is closely collaborating with the IMM and FERC to evaluate potential enhancements to help prevent similar conduct in the future, which will be vetted through MISO stakeholder process in an open and timely fashion,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.

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Michigan Energy Siting Bills Set off Opponents and Backers

LANSING, Mich. — Michigan’s Public Service Commission would oversee siting of major renewable energy projects under a package of legislation introduced in the state’s House of Representatives, which immediately drew praise from supporters and outrage from opponents.

The bills were introduced Oct. 10 after weeks of anticipation and referred to the House Energy, Communications and Technology Committee. (See Mich. Senate Passes First Renewable Bill; Talks on Package Continue.)

HB 5120 and companion bill HB 5121 would preempt local zoning and give the PSC authority for siting of wind, solar and energy storage facilities of 100 MW or more. HB 5122 and HB 5123 are identical except that they would apply to solar energy storage facilities between 50 and 100 MW. No hearing has been set on the legislation at this time.

An official with the Michigan Townships Association (MTA) immediately blasted the legislation as an “authoritarian” attempt to force small, rural areas to accept large energy facilities and bar local voter referendums on the projects.

“Yes, renewable energy facilities can be contentious in some communities. But the answer is not — and is never — to silence the voices of the impacted residents and communities,” said Neil Sheridan, executive director of the association.

Also opposing the package is the Michigan Farm Bureau, which has said the legislation could harm Michigan’s agriculture industry, as well as the Michigan Association of Planning and the Southeast Michigan Council of Governments (SEMCOG). SEMCOG represents all the city and county governments in Michigan’s largest population area, including Detroit and Wayne, Oakland and Macomb Counties (though those entities also have their own lobbyists).

Not taking a position on the bills thus far are two other significant local government interest groups: the Michigan Association of Counties and the Michigan Municipal League. The Municipal League represents the state’s cities and villages, including Grand Rapids and Ann Arbor (the second- and fifth-largest cities in Michigan, respectively), two communities that have been more aggressive in dealing with climate change issues.

The Municipal League also recently supported HB 5028, which would prohibit homeowners’ associations from barring solar panels on houses.

The MTA represents the more than 1,200 townships in the state — ranging from Canton Township in Wayne County, with a population of greater than 90,000, to Pointe Aux Barques Township in Huron County, population 15 — where most of the major disputes about building renewable energy projects have taken place.

Backing the bills is a coalition of industrial groups that work on and for renewable energy, including the Michigan Energy Innovation Business Council and the American Clean Power Association. Erika Kowall, director of Midwestern Affairs for the ACP, said the legislation showed Michigan was “taking a meaningful step to help counter project delays and ensuring that a clean energy future will unlock economic investment and jobs across the state while protecting the environment.”

Peder Mewis with the Clean Grid Alliance said Minnesota and Wisconsin have systems similar to what Michigan is proposing that maintain local oversight on smaller projects while having state oversight on larger projects.