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September 6, 2024

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California PUC Adopts Stricter GHG Reduction Plan

The California Public Utilities Commission on Thursday ordered a steep reduction in greenhouse gas emissions by the electricity sector over the next decade and adopted a plan to add 40 GW of new resources, at an estimated cost of $49 billion, to get there.

The decision adopting the new preferred system plan completed the second half of the commission’s multiyear integrated resource planning process, which began in 2019.

It called for the electricity sector to meet a new goal of limiting greenhouse gas emissions to 38 million metric tons in 2030 and 35 MMT in 2032. The new 2032 target is 23% lower than the 46-MMT goal that the CPUC set in the two prior years to its current IRP cycle. (See CPUC Triples Resource Projections for CAISO Tx Plan.)

Commissioner Clifford Rechtschaffen, the lead commissioner in the IRP proceeding, said the new target represented a major step forward in the state’s effort to combat climate change.

If California can meet the goal, “it means in 2032, our grid will be 86% greenhouse gas free,” and that 73% of resources in the state portfolio will be renewables, Rechtschaffen said.

“We have been doing extremely well in reducing greenhouse gas emissions in the electricity sector,” he said. “Emissions from that sector have declined by close to 50% over the last decade. This decision ensures that we’ll continue that trend into the next decade.”

The electricity sector, including in-state generation and out-of-state imports, accounts for about 15% of GHG emissions in California. Transportation (40%) and industry (about 20%) are the two biggest polluters.

The state has a legislative mandate to reduce overall GHG emissions, including from transportation and industry, by 40% below 1990 levels through 2030. The state emitted a total of 418.2 MMT in 2019, the latest year for which accurate data are available.

Transmission Planning

The decision also asked CPUC staff to explore, in cooperation with CAISO and the California Energy Commission, what it would take to reach an even lower 30-MMT target.

“Through the study of this case, we hope to learn more about the transmission buildout and cost implications of the lower GHG target, which we may consider for adoption for the years after 2030,” Administrative Law Judge Julie Fitch wrote.

For now, “an important reason that we develop this resource portfolio is to have it considered by the CAISO for transmission planning purposes,” Fitch said. “Adopting the 38-MMT portfolio while continuing to analyze deeper GHG emissions-reduction scenarios allows us to proceed in an orderly, step-to-step fashion to build out the grid infrastructure needed to support future generation and storage projects.”

A preliminary analysis by commission staff showed “there is sufficient space for all of these new resources on the existing transmission system, with only limited transmission upgrades needed by 2032,” the CPUC said in a news release. “This finding will be validated at a more granular level by [CAISO] in its 2022-2023 transmission planning process.”

Rechtschaffen praised CAISO for having identified two storage projects in last year’s transmission planning process that could eliminate the need for new transmission.

“It’s a creative solution, and it’s a cost-effective solution,” he said.

Resource Procurement

California will need a vast increase in generation and storage resources to meet the new GHG target and the state’s goal of serving retail customers with 60% clean energy by 2030 and 100% by 2045, as required by 2018’s Senate Bill 100.

“The 38-MMT target represents a major resource buildout that requires approximately a 40% increase in net qualifying capacity [NQC] of the electric system in the state within less than a decade,” Fitch wrote. “To achieve this portfolio, an average of approximately 4,000 MW of new capacity in NQC will need to be added each and every year through 2032.”

In her decision Fitch estimated the cost of adding 40 GW of new resources at nearly $49 billion.

In adopting the decision, the CPUC approved a resource portfolio that includes 25.5 GW of new renewable resources and 15 GW of new storage and demand response resources by 2032 — “enough clean energy to power approximately 11.5 million homes,” the commission said.

The figures include 11.5 GW of new resources that the CPUC ordered load-serving entities, including the state’s three big investor-owned utilities and its community choice aggregators, to procure by 2026 last June. (See CPUC Orders Additional 11.5 GW but No Gas.)

The commission’s forecasts of resources needed to meet the state’s climate goals have increased significantly in recent years.

In 2020, the CPUC adopted a reference system portfolio in its IRP proceeding that called for 25 GW of renewable energy and storage by 2030. Last year it said the state will need 28 GW of generation and storage by 2031 under the previous 46-MMT target.

The new plan calling for 40 GW accounts for the new 38-MMT target and anticipates a high penetration of electric vehicles by 2032. It includes additional solar power, totaling 17.5 GW, and more battery storage, reaching 13.5 GW. It also incorporates 1 GW of long-duration storage, 1.2 GW of geothermal energy, 1.7 GW of offshore wind and 1.5 GW of out-of-state wind.

Unlike the first phase of the CPUC’s 2019-21 IRP, the second phase took the current and planned resource portfolios of more than 50 LSEs into account to forecast procurement needs through 2032.

“The first half of this IRP cycle analyzed and adopted an optimal portfolio of electricity resources as a guide for LSEs to use for meeting their GHG, reliability and cost objectives,” the commission said. “The second half of the IRP cycle … is designed to consider the portfolios and actions that each LSE proposes for meeting these goals — to allow the CPUC to review each LSE plan and aggregate LSE portfolios to develop a preferred system plan portfolio, and to consider whether further action by the LSEs, such as additional procurement, is needed to meet state goals.”

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MISO Members to Consider Federal Infrastructure Bill

MISO’s Advisory Committee has set aside time next month for a roundtable discussion on the federal government’s Infrastructure Investment and Jobs Act’s effect on the RTO’s footprint.

The Organization of MISO States requested the time when the committee, comprising member companies, meets March 23 during MISO’s upcoming Spring Board Week in Memphis, Tenn.

OMS Executive Director Marcus Hawkins asked MISO sectors to prepare discussion points on how they plan to address the bill.

“The focus will be on what different sectors are doing in response to the legislation, what their hopes are, and identifying areas where coordination could be useful,” Hawkins said during Wednesday’s Advisory Committee meeting.

He said sectors should come prepared to answer questions on how the bill could impact the MISO footprint and its processes, whether their organizations plan to pursue funding, and how the RTO should participate in the bill.

The $1.2 trillion bipartisan legislation passed Congress in November and was quickly signed into law by President Joe Biden. The bill provides $11 billion in grants for states, tribes and utilities to improve electric infrastructure’s resilience against extreme weather, cyberattacks and other disruptive events. (See Biden Signs $1.2 Trillion Infrastructure Bill.)

It also establishes a $2.5 billion Department of Energy transmission facilitation program to help develop nationally significant transmission lines, increase resilience by connecting regions and improve access to cheaper clean energy sources.

Hawkins said the bill is certain to affect the MISO region with its funds for new transmission, energy efficiency, electric vehicle charging stations, carbon-capture technologies and nuclear fleet preservation.

Stakeholders asked that RTO leadership also come prepared to speak on the grid operator’s preferred role in the bill’s investments and how they envision it could alter the MISO landscape.

“Are MISO’s tariff and business practice manuals ready to handle this?” the Union of Concerned Scientists’ Sam Gomberg asked. He urged MISO to examine its rules to see if they are innovative enough to handle an unprecedented grid refresh.

Registration for the March 21-24 Board Week is now open.

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NV Energy’s Greenlink North Gets Go-ahead

Nevada regulators have approved NV Energy’s $901 million Greenlink North project, a 235-mile power line across northern Nevada that will complete a transmission triangle around the state.

Greenlink North is one piece of NV Energy’s Transmission Infrastructure for a Clean Energy Economy Plan, which was included in Phase IV of the utility’s triennial integrated resource plan (IRP) for 2022 to 2041. The Public Utilities Commission of Nevada (PUCN) voted 3-0 on Jan. 24 to approve Phase IV of the IRP.

Greenlink North will run from Robinson Summit, near Ely in eastern Nevada, to Fort Churchill near Yerington.

The 525-kV transmission line will connect NV Energy’s existing One Nevada line along the east side of the state to Greenlink West, a yet-to-be-built line that will run down the west side of the state. Greenlink West and One Nevada will meet in the Las Vegas region.

PUCN approved Greenlink West in March 2021 and the project is scheduled for completion in December 2026. (See Regulators Greenlight NV Energy’s Greenlink West.) NV Energy expects to complete Greenlink North by December 2028.

An NV Energy spokesperson said engineering and permitting work are now underway for both Greenlink West and Greenlink North.

The Bureau of Land Management’s Nevada State Office will lead the National Environmental Policy Act environmental review process for the projects, the spokesperson said. The BLM plans to issue a notice of intent in April to start the process.

Legislative Requirement

NV Energy was required to file a Transmission Infrastructure for a Clean Energy Economy Plan (TICEEP) as part of Senate Bill 448, a wide-ranging energy bill approved during the 2021 state legislative session.

NV Energy filed an application for TICEEP on Sept. 1, as an amendment to its IRP application filed in June.

In addition to Greenlink North, TICEEP includes a 32-mile, 525-kV line just north of Las Vegas.

The $143 million project will run from the Harry Allen substation to the Northwest substation.

One goal of TICEEP is to expand transmission access to renewable energy zones and promote development of renewable energy resources in the state.

The plan is also intended to assure a reliable and resilient transmission network in the state and support the development of regional transmission interconnections.

In its application for the plan, NV Energy said an interconnected Western grid would give the state access to a wider variety of renewable energy resources. While Nevada’s location gives it a chance to be a key player in that grid, the state has thus far lacked transmission infrastructure, the utility said.

The new infrastructure included in TICEEP “continues to build a foundation for the state to access diverse renewable energy resources for use within Nevada while increasing the transfer of energy between Nevada and the developing western grid.”

Solar Projects Approved

The approval of Greenlink North comes after PUCN recently approved another part of NV Energy’s IRP, which includes two new solar-plus-storage projects in Humboldt County.

The Iron Point solar project will combine a 250-MW solar photovoltaic system and 200 MW of battery storage. The Hot Pot solar project will include a 350-MW solar system and 280 MW of battery storage.

Both projects are being developed and built by Primergy Solar. NV Energy expects Iron Point to be in service in December 2023, with Hot Pot in service a year later.

The projects will replace NV Energy’s only remaining coal fired power plant, the North Valmy Generating Station, the utility said in a release.

NV Energy said the two new solar projects will join its renewable portfolio of 55 geothermal, solar, solar plus storage, hydro, wind, biomass and supported rooftop solar projects either in service or under development.

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Duke Energy Tout Clean Energy Gains

Duke Energy executives touted the company’s clean energy plans during the company’s fourth-quarter earnings call Thursday, saying the North Carolina-based utility expects to meet its goal of cutting carbon emissions 50% by 2030 through initiatives that include coal plant retirements in Indiana and 750 MW of new solar in Florida.

The utility, which has facilities in seven states, said that having cut emissions by 40% over 2006 levels, it expects that several projects likely to unfold over 2022 will help the company toward its 2030 goal and reaching zero emissions by 2050.

The company’s fourth-quarter performance “capped off a strong finish to a very productive 2021,” CEO Lynn Good told analysts on the call.

“We continue to make progress and are strongly positioned to achieve our clean energy vision,” she said. “We delivered on our commitments while also strategically positioning the company for the future.”

The utility’s future plan includes cutting its share of energy from coal to 5% by 2030 and a complete exit from the sector by 2035, she said. The coal share at present is 22%, a company spokeswoman said. The utility, which at present owns 10 MW of solar and wind energy, expects to increase that figure to 16,000 MW by 2025 and to 24,000 MW by 2030, Good said.

That growth would be driven in part by expenditures of $63 billion in capital expenditures over the next five years, of which 80% will be spent on clean energy investments, she said.

New Emissions Regulations

The company is awaiting the impact of a North Carolina law, H951, that is expected to reshape the state’s energy sector. It requires a 70% reduction in carbon emissions by 2030, a larger cut than Duke’s targeted 50%. The law authorizes the state Utilities Commission to establish performance-based regulation (PBR) that would link utility profits to specific, measurable performance goals, while also decoupling profits from power consumption by residential customers. (See NC Compromise Energy Bill Passes Senate, Heads Back to House.) The bill was signed into law Oct. 13.

Good said the utility is confident that the state “will adopt a balanced set of rules that provide flexibility to implement performance-based rates in a way that achieves policy goals and aligns with customer interests.” She said the company expects to file its carbon-reduction plan in May “after gathering stakeholder input over the next several months,” with a state ruling on the plan by the end of the year. The company in June said the bill would mean the closure of seven coal-fired plants in North Carolina by 2030 and replacing them with energy storage and a 900-MW simple cycle natural gas plant.

“The plan we submit will have multiple portfolios that weigh the costs and benefits, including reliability and affordability of various resource types,” she said. “We will also evaluate with stakeholders and our regulators the full range of potential risks and opportunities related to new clean energy technologies. We expect an order on the carbon plan by the end of this year.”

The coming year will see the start of a three-year program to add 750 MW of solar power in Florida after the state’s Public Service Commission approved a stipulated agreement to the Clean Energy Connection (CEC) program crafted by subsidiary Duke Energy Florida. The program allows customers to subscribe to blocks of solar power, each equal to 1 kW, from the CEC program and in return receive credits against their energy bill.

Yet the company’s solar sector also is facing challenges, in the form of modest supply chain disruptions that have forced it to consider using alternative suppliers of solar panels and other equipment.

“Certain suppliers have said, ‘We can’t meet the time frame,’” said Good. Faced with that scenario, which can extend the procurement time and make equipment more expensive, the utility opted to delay a few projects from starting in 2022 to beginning in 2023, totaling about 400 to 500 MW, the company said.

Coal Plant Closures

The solar sector growth comes as the company’s drive to cut coal plants is expected to continue unfolding in 2022, the company said. In December, the company submitted an integrated resource plan to the Indiana Utility Regulatory Commission that said the company would close its six coal generating plants in the state four years earlier than outlined in the previous IRP, in 2018. Duke has said it will reduce its Indiana carbon emissions by 63% from 2005 levels by 2030 and 88% by 2040, and triple renewable energy levels to about 7,200 MW. Good said the company expects to issue a request for proposals for companies interested in developing the renewable energy facilities this month.

The company’s slideshow presentation also noted that that in 2021 it submitted an IRP to Kentucky regulators that moved the date for closure of its East Bend plant to 2035, from the previous date of 2041. The IRP attributed the accelerated closure to expected operations and maintenance cost increases from increased regulation, an increased fuel supply risk and the declining costs of renewables.

The company reported full-year GAAP earnings of $4.94/share, compared to $1.72 in 2020. Adjusted earnings for the year were $5.24/share, compared to $5.12 a year ago. It reported fourth-quarter GAAP earnings of 93 cents/share, compared to a loss of 12 cents/share a year ago.

Adjusted earnings exclude the impact of certain items that are included in reported earnings, the company said in a press release. The main difference stemmed from an impairment charge related to the South Carolina Supreme Court decision on coal ash and insurance proceeds, as well as workplace and workforce realignment costs, the release said.

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Senate Committee Looks Deeper into Clean Hydrogen

Sen. Joe Manchin (D-W.Va.) made it clear Thursday that he not only supports the Biden administration’s clean hydrogen programs but also wonders why there is no production tax credit for the fuel.

“Let me tell you what’s happened for credits in the last 10 years — production tax credits for wind and solar. Twenty-five to $30 billion we’ve invested. Hydrogen? Zero production tax credits,” Manchin, chairman of the Senate Energy and Natural Resources Committee, said during a hearing concerning hydrogen’s potential as a fuel.

“We have got to get off the dime and start doing something or we’re going to be left behind and be totally, totally subservient to China, I believe. I believe we’re putting ourselves in one hell of a mess,” Manchin said.

A hydrogen production tax credit was included in the administration’s ill-fated Build Back Better bill, which Manchin refused to support, partially because of the cost of the social programs the legislation would have also created.

Manchin also said he believes West Virginia, rich in shale gas, would be an ideal location for one of the Biden administration’s planned hydrogen and carbon hubs.  The administration’s plan would be to produce low-cost hydrogen from plentiful shale gas and inject the leftover carbon dioxide into geological formations.  Using funds authorized by the bipartisan Infrastructure Investment and Jobs Act passed by Congress last fall, Biden allocated $8 billion for the creation of four hydrogen hubs around the nation.

The administration wants to lower the price of “green” hydrogen produced from the electrolysis of water powered with renewable energy to $1/kg by the end of the decade, compared with $5/kg today, according to the Department of Energy, and as much as $14/kg according to other sources. “Blue” hydrogen produced by steam reforming of methane, with carbon capture, costs about $2/kg to produce.

Sen. James Lankford (R) from Oklahoma, another state rich in natural gas, also expressed support for using hydrogen as a fuel, but said questions of infrastructure and regulatory oversight must be addressed.

The committee also examined using existing natural gas pipelines to move hydrogen. Sunita Satyapal, director of hydrogen and fuel cell technologies office within the U.S. Department of Energy, said hydrogen can cause embrittlement of some pipeline metals. Noting that the question is being studied here and globally, she said the current consensus is that hydrogen can be mixed with natural gas at a ratio between 5 and 15%.

“There are now over 40 companies along with our other consortium to look exactly at what types of materials should be used. The flame is hotter with hydrogen,” Satyapal said. “In terms of looking at our safety codes and standards, our R&D is really helping to inform the right codes and standards, [and] having the right injection standard, both in terms of the pipelines [and burner tips]. We’re working with [the Department of Transportation], the pipeline and hazardous materials safety authority that regulates safety of pipelines.”

Other experts testifying said pipelines carrying pure hydrogen use different metals than those used in gas pipelines. 

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Glick Aiming for Final Transmission Rule by End of Year

WASHINGTON — FERC Chair Richard Glick said Wednesday he is hoping to issue a final rule out of the commission’s Advanced Notice of Proposed Rulemaking (ANOPR) on transmission planning and cost allocation by the end of the year or early 2023 (RM21-17).

Speaking at the National Association of State Energy Officials’ (NASEO) annual Energy Policy Outlook Conference at the Fairmont Hotel in Georgetown, Glick gave attendees eating their lunches a high-level overview of what the commission is examining as part of the proceeding, which began last July. The commission received hundreds of comments by mid-October, most agreeing that U.S. transmission planning needs to be more proactive as more renewables seek to interconnect to the grid. (See FERC Tx Inquiry: Consensus on Need for Change, Discord over Solutions.)

“I’m very hopeful that in the very near future, we’ll have a Notice of Proposed Rulemaking, which is the next step in the regulatory process, and then hopefully a final rulemaking by the end of the year,” Glick said. “We’ll see if we get there. We have a lot to do, but there really is a pressing need here to act. Sometimes the regulatory process seems to take years, and with the way the law works, sometimes it’s important that it does take years. But we’re seeing how much we can expedite the process and move forward with the rulemaking.”

Asked about Glick’s timeline at a Northeast Energy Bar Association panel discussion Thursday, former FERC Chair Joseph Kelliher was skeptical, citing data that “the average time from the first step to a final rule … was 23 months.”

“It’s taken a maximum of 34 months in one case, and the fastest of the rules [Order 890] was 17 months,” he said.

Kelliher also noted that the ANOPR resulted in three separate statements, two of which he said “read like dissents.”

“I find that looking at history, it’s impossible, frankly, for the commission to issue a [broad] final rule by December or January,” he said. “So I think it’s either going to take longer, or the scope has to change and has to be narrowed, or perhaps has to be broken up into different orders.”

Much of the NASEO conference was focused on how states will use the federal dollars they are going to receive from the Infrastructure Investment and Jobs Act, enacted in November. But tucked into the law, with its billions for energy and transportation infrastructure, was a provision giving FERC backstop siting authority over transmission projects, which Glick called “the elephant in the room.”

Under the law, if state regulators deny them approval for a project, utilities can file a petition with FERC asking it to overturn the ruling. Many long-distance, interstate transmission project proposals have failed because of a single state rejecting them. Transmission policy experts have long argued for backstop siting authority, as there is wide agreement that interstate lines are needed to meet urban demand for renewable energy from rural areas.

Glick downplayed the significance of the authority, but the audience was dubious.

“We’re going to wait to see how this works out,” he said, which prompted nervous laughter from the audience. Glick paused with a smile, before saying, “I understand that there’s a lot of angst about it at the state level. … But I kind of question whether you’re going to see utilities out there come to FERC and say, ‘I want you to reject what my state commission just did.’ I think it’s going to be difficult for utilities to do that.”

At that there was a wave of murmurs through the audience.

Glick emphasized that FERC and the states are working together on transmission issues. He pointed to the Joint Federal-State Task Force on Electric Transmission, formed by the commission and the National Association of Regulatory Utility Commissioners. The task force will hold its second meeting, focused on cost allocation, at NARUC’s Winter Policy Summit next week.

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MISO: DER Aggregations Must Wait Until 2030 for Market Participation

MISO on Thursday said that aggregations of distributed energy resources lining up for its wholesale markets must wait until the end of the decade before gaining entry.

The announcement at a Distributed Energy Resources Task Force meeting left some stakeholders in disbelief.

The RTO said its systems won’t be ready for full FERC Order 2222 compliance until 2030. It said several software changes are needed before it can register and settle DER aggregations. It also said it faces an uphill battle to create market systems dynamic enough to “accommodate dynamic changes and communications.”

“MISO anticipates completing all improvements by 2029, enabling a 2030 launch of market functions,” the grid operator said.

The RTO said aggregator registration won’t likely become available until late 2029, with a launch of aggregator participation in the energy and ancillary services near the end of the first quarter of 2030.

DER Program Manager Kristin Swenson acknowledged that MISO “is thinking about an implementation date well into the future.”

MISO plans to file its compliance plan with FERC on April 18. Swenson said it hopes to have “pencils down” by mid-March and only make minor edits after that.

Director of Settlements Laura Rauch said full Order 2222 compliance requires MISO to shift from a “static to a dynamic paradigm.” She said its current processes for registration and market participation generally assume that resources’ output remains about the same over time.

Rauch said MISO envisions work to accommodate the registration and settlements of DER aggregations stretching into 2026. She said that work will provide a “solid foundation” for more dynamic future markets.

She also said Order 2222 will require building extensive communication channels with new parties that must be “safe, secure and confidential.”

“That’s something that factored heavily into our design here,” she said.

Stakeholders said MISO’s proposed postponement will throw sand in the gears of states and regions that want to develop robust DER participation programs.

“Obviously, 2030 is too far out,” Voltus consultant Rao Konidena said. He urged MISO to trade off some of the “bells and whistles” initially to at least get some aggregators phased into the markets before the next decade begins.

Other stakeholders also called for a “light” rollout of aggregation participation that would be less time-consuming.

But Rauch said MISO wants to avoid “putting out a market product with unintended consequences.”

“You want to do each piece well so it builds on itself and makes a cohesive whole,” she said.

“We’re looking at an eight-year implementation. How does that square with FERC telling RTOs to implement it in a reasonable time frame?” asked the Coalition of Midwest Power Producers’ Travis Stewart.

Rauch said MISO has communicated its proposed timeline with FERC staff.

Ameren’s Justin Stewart asked if MISO might complete work before its 2030 finish date.

“These are the estimates we believe we can commit to. If we go faster than that, fantastic,” Rauch responded.

MISO similarly asked for a yearslong compliance delay with FERC Order 841, claiming that it needed to embark on lengthy software improvements first. Last year, FERC twice denied MISO’s request to give it until 2025 to fully bring storage into its markets. (See MISO: No Choice but to Double Up on 841 Compliance.)

The RTO’s envisioned Order 2222 deferral is several years after its goal to have its new market platform fully operational by 2024. Staff have repeatedly touted the new platform as able to host more complex market offerings.

MISO plans to rely on its electric storage resource commitment statuses to let DER aggregations participate in the wholesale market. The RTO will leave it up to distribution companies or regulatory authorities to conduct interconnection analyses. MISO also decided that aggregations must be limited to a single pricing node and must self-commit. It will not provide output forecasts for aggregations. (See MISO Draws on Storage Model for DER Aggregations.)

In late 2021, MISO’s Richard Doying said that when staff began reaching out to distribution companies to begin collaboration on Order 2222 compliance, some had just a vague inkling of the RTO’s role in the power grid.

During a Jan. 18 workshop on MISO’s Order 2222 filing, Swenson said there was probably going to be a persistent “time horizon disconnect” over how quickly aggregators can update offers to MISO after a DER is unable to respond to dispatch instructions.

Swenson also said it’s up to distribution utilities to define the scope of their technical reviews on aggregations’ reliability impacts, which will be submitted to MISO. The RTO plans to model aggregations as generation at the transmission level and will require telemetry.

MISO’s Michael Robinson said that just like with its generation, the RTO must trust the values that distribution utilities and aggregators provide to it. He said there are tariff mechanisms in place if an entity is furnishing inaccurate numbers.

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Clean Energy, Equity Goals to Reshape Oregon IRP Process

States grappling with how to incorporate ambitious clean energy and social equity goals into utility resource planning might do well to keep tabs on a proceeding that Oregon regulators kicked off Wednesday.

The Oregon Public Utility Commission launched the effort (UM 2225) in response last year’s passage of House Bill 2021, which set the most aggressive clean energy standard in the country. The law directs Oregon’s investor-owned utilities to reduce their greenhouse gas emissions by 80% by 2030, on the path to achieving 100% GHG-free generation by 2040. (See West Coast Could be Net Zero by Midcentury.)

HB 2021 also calls for utility decarbonization strategies to provide economic benefits to residents while preventing any burdens from falling disproportionately on communities of color, low-income and rural communities, and tribes.

One provision of HB 2021 requires that, “to the maximum extent possible,” the move to emissions-free electricity create “meaningful living wage jobs,” promote “workforce equity,” and increase “energy security and resiliency.” Another calls for utilities to examine the “costs and opportunities” of procuring electricity from community-based renewable energy resources intended to contribute to local economic development and resiliency.

The law stipulates that all those objectives be reflected in utilities’ clean energy plans (CEPs), which must be “based on or included in” their integrated resource plans (IRPs), submitted every two years for approval by the PUC.

At Wednesday’s meeting, the commission acknowledged the open-ended nature of its “investigation” into how it will integrate HB 2021 goals into its existing utility planning and procurement processes — and how the law will likely alter those processes.

“[HB 2021] makes GHG reductions a clear driver [of planning and procurement] and asks us to unpack and capture community benefits, and it prioritizes equity for those who participate in the transition and who shoulder its costs,” PUC Chair Megan Decker said.

“The only way for us to implement such a big and broad vision — full of new concepts — successfully will be to adopt a learning orientation, to recognize that we’ll be iterating, taking up some things and saving others for later, making decisions, evaluating what worked and adjusting,” Decker said.

The PUC chair said she foresees a “lengthy period of evolution” for developing the new planning framework.

“IRPs are not built in a day, and CEPs are even harder with all of the integration of other planning processes that have emerged and new issues that are introduced,” she said.

“I appreciate the framing of both the continuous learning mindset that we will have to adopt here and the scale of the evolution in regulation that is envisioned by this whole package of legislation, and the need for it all to integrate and work with each other,” Commissioner Letha Tawney said.

Increasing Complexity

Caroline Moore, administrator of the PUC’s Strategy and Integration Division, said the commission’s most pressing objective is to provide utilities with the “near-term” guidance needed to craft their first CEPs, likely to be filed in March 2023 along with updated IRPs.

“That’s why we’re being really intentional about this scoping effort and trying to tease out what is critical to establish now [and] what’s the best way to establish it,” Moore said.

There are two immediate questions “at play” in the proceeding, Moore said. The first revolves around how to incorporate CEP requirements into current processes, while the second delves into how the commission can streamline those processes to help utilities meet the fast-approaching deadlines for their clean energy targets. The commission hopes to have more clarity on those issues by the end of the third quarter of this year, she said.

Elaine Hart, a consultant the commission hired to survey Oregon IRP stakeholders (including utilities, consumer advocates, local governments and community groups) on PUC processes, said many survey respondents expressed concern that CEPs will increase the technical complexity of questions already being dealt with in the planning process.

“It’s hard to plan for a low-carbon system, and it’s hard to plan with the geographical granularity that you need to make decisions that are informed by community input that are meaningful,” Hart said. “These are technically challenging problems, and they don’t always nicely fit into the buckets that our existing processes provide in terms of information analysis and decision making.”

Hart said that while survey respondents lauded Oregon’s planning process for the ability to influence utilities, IRP engagement is “typically limited” to a “relatively small number” of stakeholders.

“So, the question of whether the utility has provided adequate opportunity for public input across the IRP, the [distribution system planning] and the CEP may look different in an HB 2021 world, where there’s a greater emphasis on local impacts,” Hart said.

Comments from the Field

During Wednesday’s virtual meeting, participants commenting in the “chat” area of the meeting screen provided an indication of what some stakeholders hope to see in a planning process reshaped by HB 2021.

Heide Caswell of PacifiCorp and Nidhi Thakar of Portland General Electric (NYSE:POR) both expressed hope that the commission will integrate the CEP process with its distribution system planning process.

Norm Cimon, a founding member of Oregon Rural Action, wrote that his group’s “key issue” is how the residents in the 25% of the state “where the sun shines brightest and the wind blows hardest — can be full participants in the transition to an economy powered by distributed generation of renewable energy.”

Max Greene, regulatory and policy director at Renewable Northwest, said his organization wants “to establish a process that honors HB 2021’s equity considerations and gets us on a path to a zero-emissions grid ‘as soon as practicable’ and no later than the act’s binding GHG targets.”

Oregon Solar + Storage Industries Association Executive Director Angela Crowley-Koch said she agreed with Greene’s comment and “also would like to see community resilience included in plans, not just grid resilience. This includes incorporating the goals of HB 2021 to create economic development opportunities for Oregonians with projects built here.”

“We would like see how to make the clean energy plans meaningful and make sure that they work in tandem with the current planning processes in Oregon and the region rather [than] a separate process,” Irion Sanger wrote on behalf of the Northwest & Intermountain Power Producers Coalition. “We are interested in seeing how the CEP will also ensure that the procurement process allows for diverse ownership of renewable energy sources.”

For all the complexity it introduces into Oregon’s IRP process, HB 2021 may have just accelerated the inevitable, said Tawney.

“I think in some ways, our IRP processes have been straining a bit there at the seams to try to cope with the way the grid is changing, and the way customer preferences are changing — and on and on,” she said.

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Overheard: NECA Asks Experts ‘What to Do with All This CO2’

In the global effort to reduce greenhouse gases, companies are advancing technologies that capture and store carbon dioxide emissions as a viable way to decarbonize energy.

On Wednesday, the Northeast Energy and Commerce Association’s Fuels Committee invited experts to explore the current carbon capture and sequestration (CCS) market and its place in the global decarbonization effort.

Here’s a look at some of the experts’ insights from that panel discussion.

CCS vs. Alternatives

Understanding the current role of CCS for climate and energy requires looking at the technological alternatives, according to panel moderator Michael Stern, a chemical engineer at consulting firm Exponent.

Renewable energy, he said, is an “obvious” alternative that has its “merits” and “limitations.”

The reliability of clean generation resources could become uncertain as the effects of climate change worsen, Stern said. Energy storage as a means of balancing uncertain renewable output also has limitations, he added.

There are mature programs that allow companies to compensate for emissions through the purchase of offsets, but they are “not without significant challenges,” Stern said. Some people are concerned that such programs, which include forest carbon offsets, for example, overestimate the amount of CO2 that is stored and the lifetime of that storage.

Direct air capture (DAC), which pulls CO2 from the air, has a measure of flexibility that is not available with CCS, Stern said. CCS grabs CO2 at the source of the emission, so it must be transported, potentially over long distances, to a storage location or secondary market.

A DAC developer, on the other hand, can site a plant near a renewable energy facility to access clean power or near a geological formation for storage. But Stern said that air is a “very dilute source of CO2” compared with point-source emissions, making the economics of DAC more challenging.

Advanced Tech

Cryogenic carbon capture (CCC) is at the leading edge of CCS, providing a path forward for the market that improves cost and efficiency, according to Sustainable Energy Solutions cofounder Larry Baxter.

Sustainable Energy started out commercializing CCC a decade ago, and Chart Industries purchased the company last year. The company is demonstrating the technology around the world with a variety of CO2 sources, Baxter said.

CCC has many applications, such as energy storage and hydrogen production, but Baxter said it is “a game-changing carbon-capture technology.”

The CCC system takes flue gas from any source to produce a liquid CO2 product for sequestration or use downstream. In the cryogenic process, CO2 cools down and forms a solid.

“We separate the solid from the gas and warm everything back up again,” Baxter said. The solid, he added, is pressurized before it warms up so it can form a liquid CO2 as it melts.

That process is not like traditional refrigeration that results in a cold product. “We just use the cold as part of the separation technology,” Baxter said.

One benefit of the CCC system is that it does not require any modification at the point source, Baxter said.

“We think it’s probably the easiest retrofit carbon capture technology we know of, as it requires literally no change of systems upstream,” he said.

It also produces high-purity CO2, potentially meeting beverage-grade standards, which Baxter said are the highest for CO2 purity.

Large-scale CCS

Enbridge (NYSE: ENB), one of the largest pipeline infrastructure companies in North America, is collaborating with companies to develop integrated solutions for CO2 capture, transportation and storage.

Enbridge is working with Capital Power and Lehigh Cement on the Wabamun Carbon Hub Project in Alberta, Canada. That project, according to Enbridge, will be one of the largest integrated CCS projects in the world, potentially avoiding 4 million metric tons of CO2 emissions.

Alberta has good geology for CO2 storage, according to Freddy Sanches, technical manager of market innovation at Enbridge. Having nearby underground pore space where CO2 can be injected “helps with the economics,” he said.

Enbridge is studying geological formations for CO2 storage capacity in Ontario, Canada, and in the U.S. Gulf Coast and Midwest.

“We’re trying to de-risk the geology and learn more about it to see if it’s suitable for CO2 storage because that’s one of the biggest unknowns,” he said.

On the storage front, Enbridge is also studying its gas storage facilities to see if they are suitable for conversion to CO2 storage.

“We’re not converting any of those storage facilities yet, as we still need them for natural gas production, but that is something that we are looking into,” he said.

CCS in Canada

The International CCS Knowledge Center in Canada has reported that the Western Canadian sedimentary basin, which is the epicenter of oil and gas supply in Western Canada, has the largest potential for storage, according to Mark Demchuk, national director of strategy and stakeholder relations for the center.

Canada has almost 400 gigatons of storage capacity, primarily centered in that Western basin, Demchuk said. The Northeast U.S., he added, has similar geologic characteristics for large-scale storage capacity, primarily in the Appalachian and Michigan basins.

De-risking large CCS projects and improving the business case for projects to move forward is a “hot topic” in Canada, Demchuk said. A large-scale project that stores a million metric tons of CO2 per year might cost in the range of $1 billion, depending on the site or industry. For Canada to meet its 2030 CO2 emission reduction target, he said, the country would need a minimum of 15 projects at that scale and cost.

There is no positive investment case for those projects at this time, Demchuk said.

“All levels of government … and all the companies involved recognize that we need to develop the components to support an investable business case if those projects are actually going to happen in the time frame we’re talking about,” he said.

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ISO-NE Lists New Projects for 2022 in Budget Report

ISO-NE’s plans for new capital projects this year include infrastructure upgrades for the Next Generation Markets (NEM) platform, enhancements to its weather forecasts and a switch away from the nearly obsolete Internet Explorer browser.

The grid operator laid out changes in its plan for 2022 in a budget report filed with FERC on Thursday.

It spent $27.5 million on capital projects in 2021, $500,000 under budget in part because of FERC’s rejection of the Energy Security Improvements plan and a deferred cybersecurity improvement project.

Its biggest new capital expense for 2022, about $4.5 million, is Phase II of a project designed to prepare the RTO’s hardware and software for the new market clearing engine that General Electric is developing as part of the NEM project. The RTO is also purchasing a cloud-based cybersecurity package for protecting enterprise applications and resources.

Also added to the budget for this year is enhancements to ISO-NE’s weather forecasting. The project will expand its forecasts from eight to 23 cities in New England and add new weather concepts to try to improve its load forecasts, the document says.

Some of the other new budget items include improvements to the RTO’s Solar Do-Not-Exceed dispatch processes; a new physical security system to replace obsolete cameras at control centers; and a move to cut down the number of internet browsers ISO-NE uses from four to two, timed to coincide with Microsoft cutting off support for Internet Explorer this June.

In other changes to the 2022, budget ISO-NE will save $1.5 million because of its decision to delay elimination of the minimum offer price rule and $400,000 because of a delayed project to migrate its public website from internal servers to the cloud.