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November 8, 2024

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NextEra Transmission Subsidiary Gains Abandonment Approval

FERC last week granted NextEra Energy Transmission (NEET) Southwest’s (NYSE:NEE) request to recover 100% of all prudently incurred costs associated with an $85.2 million competitive project in SPP’s Kansas and Missouri footprint, should the project be abandoned or canceled for reasons beyond the company’s control (ER22-576).

The commission Feb. 7 agreed with NEET Southwest’s contention that the project faces “significant regulatory and siting risks” that could lead to its abandonment. It said the company’s total package of incentives, including previously granted incentives, is reasonable because it addresses the risks and challenges associated with the project’s development.

The NEET subsidiary said more than $20 million is at risk, calling out other planning region-approved transmission projects that were not completed for reasons outside the developer’s control. It said it doesn’t have a rate base or revenue stream against which unrecovered development costs for an abandoned project could be offset and said the abandoned plant incentive will help attract financing for the project.

NEET Southwest is attempting to build a 94-mile, 345-kV transmission line from Wolf Creek in southeast Kansas to the Blackberry substation in Missouri. The project has a January 2025 in-service date, a full year ahead of the request for proposal’s need date.

SPP’s Board of Directors approved the project last October following an industry expert panel’s unanimous recommendation that NEET Southwest be designated the project’s transmission owner. The RTO issued a notice to construct in December. (See SPP Board of Directors/Members Committee Briefs: Oct. 26, 2021.)

The transmission provider must obtain certificates of convenience and necessity from the Kansas Corporation Commission and Missouri Public Service Commission in addition to other regulatory reviews involving federal and local agencies. It said it needs a siting permit from the KCC, which would lead to an administrative evidentiary hearing that could potentially subject the project to “significant” delays or possible abandonment if the in-service date is endangered.

The company also said it faces the risk that Missouri or Kansas state laws could create a right of first refusal or impose other limitations on nonincumbent transmission developers, such as NEET Southwest, to obtain necessary permits or to otherwise develop or own transmission assets in those states.

In Missouri, legislation has been pre-filed for consideration this month that givens incumbent TOs the right to construct, own and maintain a transmission line that has been approved by “the entity with authority for transmission planning” in a FERC-recognized planning region.

KCC staff said Friday that NEET Southwest has yet to begin the process of securing utility status so that it can then apply for a CCN and siting order.

NEET did not respond to a request for comment.

FERC Commissioner Mark Christie concurred with the decision in a separate statement, saying the commission needs to revisit “the array of incentives offered to transmission developers … for projects that never serve consumers.”

“It is imperative that incentives like the abandoned plant and [construction work in progress] incentive are revisited to ensure that all the risks associated with transmission construction are not channeled to consumers while transmission developers and owners stand to gain all the financial reward,” Christie wrote.

FERC Approves Hybrid Storage Model

FERC also approved in a letter order SPP’s request to add the definition of “hybrid storage market resources” and the provisions for their registration to the RTO’s tariff. The order is effective Feb. 19 (ER22-684).

The rule change specifies that an electric storage resource co-located or integrated with a generating resource may register the resources as a single resource in the market and may use the market storage resource model.

The hybrid model was one of 21 recommendations from the Holistic Integrated Tariff Team in 2019, intended to integrate increased renewable energy, boost reliability and improve transmission planning. (See SPP Board Approves HITT’s Recommendations.)

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TVA Defends Rates, CO2 Reduction Plans in House Inquiry

TVA stood behind its emissions goals, renewable plans and rates in responding to questions from the U.S. House of Representatives’ Committee on Energy and Commerce.

The federal utility earlier this month responded to a January letter from the committee that posed several questions regarding TVA’s electricity affordability and investment in renewables and energy efficiency. The committee suggested the agency’s current business practices might be at odds with its statutory requirement to provide low-cost power to Tennessee Valley residents. (See TVA Comes Under Congressional Spotlight.)

“Unlike investor-owned utilities, we do not seek to make a profit each quarter or year,” CEO Jeff Lyash wrote in the agency’s Feb. 2 response to the committee. “TVA’s business model is based on generating the revenue needed to manage our system costs while keeping rates low for our customers — all without receiving federal appropriations.”

Lyash said plans to cut carbon 70% from 2005 levels by 2030 and 80% by 2035 won’t affect energy costs, reliability or resiliency.

“Beyond 2035, we aspire to achieve net-zero emissions by 2050 and are actively pursuing and researching the technologies needed to get there,” he wrote.

TVA said it plans to add 10 GW of solar generation by 2035. It also said it would “review and consider” wind generation opportunities. Lyash said the utility will continue growing renewable energy “regardless of our inability to take advantage of renewable energy credits.”

Currently, wind and solar generation account for 3% of TVA’s generation mix, “significantly less than comparable utilities,” the committee said.

Jeff Lyash (TVA) Content.jpgTVA CEO Jeff Lyash | TVA

But Lyash said TVA’s transformation to clean energy must be carefully planned, given many of its 10 million customers subsist on low incomes and live in old, energy-inefficient homes. He also said the seven-state footprint deals with harsh summers and winters and severe weather.

The utility said it’s discussing ways it can accelerate carbon reductions “while maintaining safe, reliable and low-cost power.”

Lyash said residential rates remain lower than 80% of the nation’s large utilities and he said TVA will keep base rates flat until 2030. He also said the agency has shrunk its debt to its lowest level in 30 years.

During TVA’s Thursday Board of Directors meeting, Lyash repeated his congressional response’s talking points. He also announced the addition of a GE Hitachi small modular reactor by 2032 at the Clinch River Nuclear site.

TVA’s response letter backed the grid access charge it rolled out in 2018, calling it “modest” and necessary so that local power companies with distributed energy resources didn’t leave other power companies with higher rates. It said the charge “mitigate[ed] the effects of uneconomic development in DER.”

The utility said the charge has had “essentially no or very limited impact on the adoption of distributed solar installations.”

TVA also defended its energy efficiency efforts and the pace of its coal fleet’s retirement.

From 2014 to 2021, TVA reported annual energy needs served by energy efficiency programs grew from 0.9% to 1.4%. It said all its local power companies participate in at least one of its four energy efficiency programs.

TVA said new building codes and more efficient appliances and products have impacted energy consumption more than “market-driven efforts.” It also said results from a study on energy programs potential, due out later this year, will help determine how it modifies or fashions new programs for energy efficiency, demand response and electrification.

The utility’s response stood behind its 2035 timetable to retire all its coal units. It pointed out that it will have retired 60% of its coal capacity when it shuts down its Bull Run coal plant near Knoxville, Tenn., next year. TVA said it is weighing future retirement announcements for its Cumberland and Kingston coal plants and might replace them with onsite gas units or offsite solar and storage assets.

In response to a question about how it plans to reduce its reliance on natural gas, TVA said that natural gas “currently remains the best available resource that allows TVA to backstop the intermittency of solar generation.”

The authority said it had no ill intentions when it participated in the now-dissolved Utility Air Regulatory Group (UARG), a lobbying organization that fought environmental standards. (See TVA Sued Over Contributions to Trade Groups; FERC Questions Ratepayer Funding of Trade Association Dues.)

It also explained that when it when it hired former UARG attorneys after the lobbying group disbanded in 2020, it intended that they would keep TVA apprised of Clean Air Act regulatory developments, not to engage in litigation.

“TVA contractually restricts its external membership organizations from using TVA funds for lobbying and litigation, unless specifically authorized by TVA,” the utility said.

SACE: Purposefully Misleading Replies

The Southern Alliance for Clean Energy (SACE) lambasted TVA’s response and said the answers “dodge some of the committee members’ key concerns and provide misleading information on several issues.”

SACE said TVA skirted details on reducing its energy efficiency programs and was intentionally vague on its plans to reduce reliance on fossil fuels.

“TVA attempts to dismiss the committee’s concerns about its pullback of energy efficiency by claiming utility energy efficiency programs are no longer needed because building codes and appliance standards have taken over as energy efficiency tools. This argument is problematic on many levels,” SACE Research Director Maggie Shober said. “Better codes and standards do not reduce the customer benefits of the utility incentivizing customers to be more efficient than that baseline.”

Shober said other utilities face the same stepped-up codes and standards yet still create energy savings programs “that put TVA’s to shame.” She said it’s “beyond obvious” that the authority could be doing more for energy efficiency.

Using information obtained from the U.S. Energy Information Administration, SACE put TVA’s cumulative energy savings from a peak of 0.31% in 2014 down to 0.02% in 2019; TVA claims a 0.9-1.5% range since 2014.

The clean energy advocate said TVA’s savings performance was among the worst in the nation. “There’s a lot of room to increase from near zero,” Shober said.

She said TVA is engaging in “some seriously Orwellian math” when it paints its carbon reduction plans as in sync with President Biden’s call for 100% carbon reductions by 2035.

SACE said by its count, TVA’s target of 10 GW of solar by 2035 needs to at least double to achieve completely clean energy.

The organization also said the utility wasn’t upfront about its grid-access charge being a means to suppress distributed solar adoption. “TVA brings up the old boogeyman myth that distributed solar on homes and businesses shifts costs to customers without solar, and yet it doesn’t present any evidence of such a cost shift,” Shober said.

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PG&E Plans to Spend $25B to Bury Lines

Pacific Gas and Electric’s plan to underground 10,000 miles of power lines in high fire-threat areas would cost more than $25 billion, even assuming costs per mile decline over time, the company said Thursday.

It was the first time the utility has put a price tag on its proposal, which CEO Patti Poppe announced in July. (See PG&E Proposes Undergrounding 10K Miles of Distribution.)

“Today we’re providing the first look at the next five years of our undergrounding plan.” Poppe said during PG&E’s fourth-quarter earnings call. “It’s big and it’s bold. We’re moving on our commitment to underground 10,000 miles of power lines in our high fire-risk areas. Undergrounding is a strong long-term solution for PG&E to reduce wildfire risk in certain parts of our service area.”

California’s largest utility (NYSE:PCG) expects to spend $3.75 million per mile to bury 175 miles of lines this year, but Poppe said it could bring the cost down to $2.5 million per mile by 2026 through efficiencies of scale and technical advances.

PG&E equipment has been blamed for a series of catastrophic wildfires starting in 2015 and extending through last year’s Dixie Fire, which burned close to 1 million acres. The fires included the 2018 Camp Fire, which leveled the town of Paradise, killed 84 people and drove PG&E to file for bankruptcy reorganization in January 2019.

As part of its plan to prevent future fires, PG&E intends to underground 3,600 miles of line by 2026, with sizable increases year over year, including 400 miles in 2023, 800 miles in 2024 and 1,000 miles in 2025.

PGandE Line Burial Plan (PGandE) Content.jpgPG&E hopes to bury 3,600 miles of lines through 2026 while cutting costs by a third. | PG&E

The full plan has not been considered by PG&E’s regulator, the California Public Utilities Commission. Asked about that by an analyst, Poppe said the CPUC had approved some of PG&E’s undergrounding work under prior wildfire mitigation plans. (The utility buried 70 miles of line last year.)

PG&E will seek additional approval for its “game-changing investment” in its 2022 wildfire mitigation plan, due Feb. 25, and as part of its 2023 general rate case, she said.

If approved by the CPUC, PG&E’s capital expenditures would increase over the next four years, but long-term cost savings “will reflect a minimal impact to customers relative to our previous filings,” Poppe said.

“Undergrounding is a great example of our simple and affordable model in action,” she said. “We invest in really high value capital infrastructure and reduce our spend on temporary repairs and annual recurring expenses.”

“We will protect our customers from energy bills they cannot afford with a cost discipline that many of you would expect,” she said.

CPUC commissioners have expressed concern about PG&E rate increases, driven by infrastructure upgrades and high natural gas prices.

During the call, PG&E reported GAAP fourth-quarter income of $472 million, or $.22/share, and full-year losses for 2021 of $102 million, or $.05/share. In comparison, PG&E reported full-year losses of $1.3 billion, or $1.05/share, and Q4 earnings of $200 million, or $.09/share, in 2020.

After Thursday’s earnings call, PG&E’s beleaguered stock price dropped from $12.08 at 9:45 a.m. ET to $11.20/share by midafternoon, then rebounded to $11.38/share just before trading closed for the day. In August 2017, before the worst of the fires ignited by its equipment began, PG&E’s stock traded for more than $70/share.

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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.