NYISO staff last week selected a proposal by Propel NY Energy to meet the ISO’s Long Island Public Policy Transmission Needs (PPTN) solicitation for transmission lines to export offshore wind energy and unbottle constraints across the island.
Propel, a partnership between the New York Power Authority and NY Transco, proposed three new 345-kV lines on the island. In a draft report released May 8, staff said the proposal would add “a strong 345-kV backbone to the Long Island transmission system that not only allows the delivery of offshore wind power but also will effectuate the efficient transfer of power in the future, providing optionality for resource planning and expansion needed to achieve” the state’s climate goals.
NYISO rankings for top-tier transmission projects from PPTN | NYISO
The goal of the PPTN was to add at least one bulk transmission intertie cable to increase Long Island’s offshore export capability by at least 3,000 MW and upgrade associated local transmission facilities to accompany the growing scale of wind power development off the Long Island coast, according to the report (20-E-0497).
Propel, along with the Long Island Power Authority and Consolidated Edison, would build two lines between Shore Road and Sprain Brook and one between East Garden City and Tremont for $3.26 billion. Propel, however, proposed a soft cost cap of $2.9 billion with a commitment to not recover 20% of included capital costs above the cap from ratepayers, which was one of the major evaluation criteria the ISO considered.
Staff also found that the proposal has a potential economic benefit of up to $3.6 billion over 20 years and, although not required by the PPTN, would relieve the 138-kV Barrett-Valley Stream congestion constraint.
NYISO presented the report to the Transmission Planning Advisory Subcommittee on Thursday.
Mark Younger, president of Hudson Economics, contended that the ISO’s “presented results are not detailed enough” and what stakeholders have seen “has been very high level.” He argued that because NYISO did not conduct a transmission security analysis examining the potential impact on the capacity of neighboring zone interfaces, the ISO’s stated benefits may be overstated.
“It’s like [NYISO] is the old economist, where [you’re] on a desert island and have a can of food but are assuming there is also a can opener,” he said. “It would be kind of embarrassing if after the line goes in that the ISO discovers that you have too much capacity in Zones H through K.”
Independent estimate and voluntary cost cap for PPTN transmission projects | NYISO
NYISO staff acknowledged that although they did not perform that specific analysis, “overall New York state will benefit from this public policy transmission need, and this is our recommendation to our board.”
Doreen Saia, an attorney with Greenberg Traurig, sought clarification on a potential appeals process, which NYISO confirmed was possible but added that the board is not looking to receive any more presentations.
The ISO will present its recommendation to both the Business Issues and Management committees on May 24 and 31, respectively, seeking stakeholder advisory votes before advancing to the Board of Directors for final approval. The board will consider any submitted written comments or requests sent to PublicPolicyPlanningMailbox@nyiso.com.
Gov. Jay Inslee last week signed a bill that requires Washington wind farms to turn off their blinking aviation obstruction lights at night when no low-flying aircraft are around.
“This ensures wind farms are good neighbors,” Inslee said at the signing. There had been some speculation that the governor might veto the measure.
Rep. April Connors (R) introduced House Bill 1173 after residents of her hometown Kennewick complained that blinking lights at a proposed wind farm in the Horse Heaven Hills just south of the city would ruin their nighttime view of the ridgeline. The bill easily sailed through both the state Senate and House with bipartisan support. (See Washington House Calls for Dimming Turbine Lights.)
But Inslee vetoed two sections of the bill.
The first vetoed section would have made the bill effective immediately instead of the more typical date of July 1. Inslee did not say why he vetoed that segment.
The second vetoed section would have given county commissioners the authority to control the amount of light to be emitted.
Scout Clean Energy has proposed building up to 224 wind turbines — about 500 feet tall — on 112 square miles of mostly private land in the Horse Heaven Hills. About 294 acres of that land would also hold solar panels. The wind turbines and solar panels are projected to produce 1,150 MW at full capacity.
At a Jan. 16 hearing before the House Environment and Energy Committee, Connors said the blinking lights on top of the 500-foot towers could be seen across an area with roughly 200,000 residents. Germany has a similar law in effect, she said. Connors noted that Washington already has about 2,000 wind turbines.
Sen. Joe Manchin (D-W.Va.) opened Thursday’s hearing of the Senate Energy and Natural Resources Committee with an urgent call for members on both side of the aisle to put politics aside and hammer out a bipartisan bill to accelerate and streamline permitting of energy and transmission projects.
“No energy sector is immune to permitting roadblocks,” Manchin said. “We all need to sit down and negotiate in good faith. We need to take our names off the bill and go back to a bipartisan permitting reform bill. That’s the only way we can take the politics out of this. It’s not me; it’s not [Ranking Member Sen. John Barrasso (R-Wyo.)]. It’s not any of our colleagues. It’s getting permitting done for the sake of our country.”
Sen. John Barrasso (R-Wyo.) | Senate ENR Committee
Manchin’s comments set the tone for a hearing that reflected the current state of play on “permitting reform,” as the issue is commonly referred to. Manchin wants to have a bipartisan bill completed by the time Congress goes into recess for August, but while potential common ground has emerged on some issues, flashpoints remain that will require tradeoffs and compromise.
Potential points of agreement include the need for permitting to be technology- and project-neutral, while also setting predictable time frames both for environmental reviews under the National Environmental Policy Act (NEPA) and for legal challenges to project approvals.
The points of conflict are cost allocation for interstate transmission lines and FERC’s “backstop” siting authority, under which the commission can approve such projects if a state has failed to act on a permit for a year or has denied a permit for a project deemed in the national interest. Both are issues that raise thorny questions about federal authority versus states’ rights on permitting such projects.
The momentum for compromise on these and other issues is being driven by the common agreement that changes are urgently needed. At stake is the country’s ability to leverage the billions of dollars of clean energy funding in the Inflation Reduction Act and Infrastructure Investment and Jobs Act to reach President Joe Biden’s goals of a 100% decarbonized grid by 2035 and net-zero emissions economy-wide by 2050.
Senators on both sides of the aisle talked about key projects in their states that have been bogged down in the permitting process or litigation for years.
Manchin’s is the Mountain Valley natural gas pipeline, a 300-mile-long project running from northwestern West Virginia to southern Virginia, which filed its first permit application in 2014. The pipeline is 94% complete, according to the project website, but remains tied up in litigation, with the U.S. Supreme Court most recently sending a suit filed by landowners in western Virginia back to district court for reconsideration.
Sen. Steve Daines (R-Mont.) pointed to the Rock Creek and Libby mine projects, proposed silver and copper mines to be located in a major wilderness area in his state, which environmental groups have been opposing for at least two decades.
‘Designed to Fail’
Industry stakeholders at the hearing also spoke of the diverse impacts of delayed and canceled projects resulting from the current system.
“The process for planning transmission that spans more than one region is unworkable,” said Jason Grumet, CEO of the American Clean Power Association. “It subjects developers to an impossible triple hurdle, requiring separate approvals by each region and a ‘coordinated’ interregional approval process, which is literally designed to fail because different regions apply different evaluation metrics and have no obligation or incentive to consider full project benefits.”
Jason Grumet, American Clean Power Association | Senate ENR Committee
Growing markets for renewable energy and electric vehicles mean that “demand for [minerals] is expanding exponentially,” Rich Nolan, CEO of the National Mining Association (NMA), said in his testimony. “But we have not seen corresponding actions to support increased production of these critical mined materials.”
Citing an NMA analysis, Nolan said, “In 2022, the U.S. reached its highest level of mineral import reliance. … Each new announcement of a blocked domestic mine locks in our competitive weakness and weakens our national security. Without permitting reform, we will be watching the global competition for minerals and energy control from the sidelines.”
Elizabeth Shuler, president of the AFL-CIO, measured the impacts of permitting delays in terms of potential union jobs lost. The 18 years it took for the recent final approval of the TransWest Express transmission line meant “18 years of lost economic opportunity for workers,” she said.
Elizabeth Shuler, AFL-CIO | Senate ENR Committee
“Every job in every part of the energy sector and the manufacturing sector depends on permitting and siting,” she said.
“Full implementation of the [Inflation Reduction Act] alone will create more than 1 million new jobs and bring down emissions across the economy. But without permitting reforms, job creation will be more modest, and emissions could actually go up.”
Paul Ulrich, vice president of Jonah Energy, a Wyoming natural gas producer, spoke of increasingly long time frames for permitting oil and gas projects, with environmental reviews taking anywhere from six to 12 years.
“The average time to process an [application for a permit to drill] a well has increased by 124% from 2018 to 2022, averaging 271 days,” Ulrich said.
Certainty, Speed, Consistency
In his opening remarks, Sen. Barrasso summarized the three principles that GOP lawmakers and many industry stakeholders are advancing as a basis for reform.
“First, legislation must benefit the entire country, not a narrow range of special interest-favored technologies or a limited group of projects,” he said. “Second, it must include enforceable timelines to ensure environmental reviews don’t drag on for years. Third, it must place limitations on legal challenges to prevent endless litigation intended to kill projects.”
Bills introduced by Manchin, Barrasso and Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee, all have proposed a two-year limit on environmental impact studies, the most intensive level of NEPA review, and one year for lesser environmental assessments. (See related story, Podesta Lays Out Biden’s Priorities for ‘Permitting Reform.’)
Paul Ulrich, Jonah Energy | Senate ENR Committee
They also call for reviews to be led by a single federal agency that coordinates the associated reviews of other agencies and issues a single, final environmental review.
Grumet said ACP supported the basic concepts such proposed reforms with the caveat that “none of these changes will undermine the bedrock protections of our environmental law.”
But, he said, “while NEPA reform is necessary, it is not sufficient” to accelerate the buildout of the interstate transmission needed for rapid clean energy deployment and to ensure adequate energy transfers between regions in emergency situations.
Rich Nolan, National Mining Association | Senate ENR Committee
Grumet’s written testimony details ACP’s “discussion framework” for changes to NEPA permitting and FERC backstop siting authority that could cut transmission approvals to three years. Under this framework, project developers could apply to the Department of Energy for a designation of a National Interest Electric Transmission Corridor for their projects, with the department issuing a decision within 90 days. FERC would undertake a NEPA review, with a two-year time limit, while the project developer could simultaneously file for state approval and begin the pre-application process for FERC backstop siting. (See DOE Rolls out New Process for Designating Key Transmission Corridors.)
“Congress [would] codify FERC’s proposed policy for simultaneous state and FERC review,” according to Grumet’s statement. “This would continue to recognize the primacy of the states’ role in siting transmission infrastructure but would help remove a year off the backstop siting authority process, as the FERC prefiling process takes that long and would likely be completed by the time a state made its decision on whether to permit a line, saving a year in the overall permitting process.”
Shuler also advocated for accelerated permitting timelines “that [do] not come at the expense of the rights of states, tribes, communities or other stakeholders to have an effective voice in the process or to intervene informally.”
Her three must-haves were certainty (“We need to know when a final decision will be made, and that it is in fact final.); speed “to deploy a full range of clean energy technology”; and consistency, meaning “a standardized process that can apply to all forms of permitting for all technologies.”
Ulrich and Nolan both called for clear timelines on permitting and legal challenges, and a prohibition on moratoriums on either coal or natural gas leasing, or pipeline approvals.
Federal vs. State Primacy
While Democrats and Republicans spoke of the need for speed on permitting, the sharpest questions of the hearing came on the issues of cost allocation and FERC’s backstop siting authority.
Sens. Cindy Hyde-Smith (R-Miss.) and Josh Hawley (R-Mo.) pushed Grumet for his position on federal versus state primacy on permitting and whether states should pay for transmission that provides no direct economic benefits to their residents.
While first established in the Energy Policy Act of 2005, Grumet said, “the backstop authority enabling federal action to permit projects of national significance has been used successfully exactly never, and if it were employed, it would take a decade or longer to permit a long-distance line.”
But using the backstop authority does not mean cutting states out of the process, Grumet said. “Instead of having to wait for states to move forward, we can use the backstop authority that was already put into law, give the states a chance to move forward with that permitting but have the federal government have a response if the states fail to act,” he said. “It is not taking them out of the process; it’s just requiring them to work within the process.”
Answering a question from Hawley on states’ jurisdiction in transmission permitting, Grumet said, “States have a role to play and have to have a role. But that role has to be guided with the same kind of deliberate national interest that we’ve been talking about … that there [are] transmission interests that [are] in the national interest. …
“Electricity moves very quickly, covers far distances, and we have to be able to bring that larger vision so that we actually protect ourselves as a nation and as a community,” he said.
Similarly, on cost allocation, Grumet said regions have a role to play, but “they have to play it. They can’t rope-a-dope the nation into energy insecurity.”
Projects must be justified on the basis of the economic benefits they provide, he said, “but we have to recognize that there are benefits greater than what you’re paying per kilowatt-hour. It’s a benefit for your lights not to go out. It’s a benefit for your region to be able to be saved with power if you have a terrible storm. It’s a benefit for you to have the capacity to bring new industries into your region. It’s a benefit to have lower-cost power brought to you from other parts of the country.”
Herding Cats
The calls for a “regular order” of bipartisan negotiations notwithstanding, the chances are mixed for a substantive bill being negotiated by August recess.
Manchin is calling for concessions on both sides. “We can’t let the perfect or the politics be the enemy of the good and continue to live with an outdated permitting system that kills much needed projects across the spectrum,” he said at Thursday’s hearing.
But ClearView Energy Partners sees only limited overlap between the GOP bills and Manchin’s, as well as a bill that EPW Chair Tom Carper (D-Del.) hopes to have finished by Memorial Day.
Capito’s bill could undercut NEPA authority by allowing de facto approval of projects if an environmental review is not completed within the proposed two-year time frame. Further, legal challenges to such approvals would be severely limited.
Manchin has promoted his bill, which he reintroduced this year after failing in December, as the only one currently on the table that has drawn demonstrated bipartisan support, with 40 Democrats and seven Republicans voting for it.
One of its key provisions is a requirement for the president to designate a list of 25 key energy projects that would be prioritized for permitting. The list would be periodically updated and would have to represent a “balanced” mix of technologies: “critical minerals; nuclear; hydrogen; fossil fuels; electric transmission; renewables; and carbon capture, sequestration, storage and removal.”
Its key sticking point is its provisions that would expedite the completion of the Mountain Valley pipeline and severely limit any legal challenges to final permitting.
The apparent consensus at the Senate ENR hearing was far from universal, as environmental organizations, absent from the hearing, have advanced a different strategy for accelerating permitting, based on early engagement with communities and tribal groups and “smart from the start” planning.
Speaking at a recent EPW hearing on permitting, Dana Johnson, senior director of strategy and federal policy at WE ACT for Environmental Justice, said, “We really need to start community engagement much earlier in the process. … Advocates in that space noticed that when industry comes to them, when they are able to negotiate, when we have community meetings before a permitting process even begins, we are able to work in partnership to solve the challenges of bringing a project to fruition.”
Federal support for such engagement was a central provision of Biden’s permitting reform priorities, which the White House released last week. Biden specifically calls for federal agencies to designate a chief community engagement officer and provide funding to help small communities and groups build the resources and expertise to participate in federal permitting processes.
In direct opposition to GOP bills, the president’s priorities put a stronger focus on clean energy, calling for legislation to accelerate interconnection of solar, wind and storage projects sitting in interconnection queues. Rather than limits on NEPA reviews, Biden supports increased interagency cooperation and the use of “programmatic environmental reviews” to speed up permitting in transmission corridors or in specific areas of federal lands.
ClearView characterized Biden’s priorities more as “trying to find a middle ground” between Manchin’s bill and Sen. Ed Markey’s (D-Mass.) “progressive priorities” released in March, which call for increased funding for NEPA reviews and for engagement with environmental justice communities.
“Herding proverbial cats within one’s party may be a prerequisite to successful negotiations with the other side,” ClearView said. “But we would suggest it falls well short of bridge building between Republicans and Democrats at this time.”
BOSTON — Massachusetts lawmakers and climate advocates held a legislative briefing Wednesday on a set of bills looking to spur the decarbonization of the state’s heating sector.
The overarching goal of the legislation is to redirect investment away from natural gas infrastructure and toward clean energy technology like heat pumps and networked geothermal.
“We need to stop powering our homes and household appliances with gas,” said Senate Majority Leader Cindy Creem, who also serves as the chair of the Senate Committee on Global Warming and Climate Change. “It’s simply not compatible with our climate ambitions, and it’s not good for our health.”
Massachusetts is lagging behind its 2050 net-zero goal for its buildings sector. While the number of electric heat pump installations in the state has rapidly increased — from about 500 in 2020 to about 18,000 in 2022, according to the Boston Globe — a 2020 report commissioned by the state found that the commonwealth needs to electrify about 100,000 homes each year for the next 25 to 30 years to meet its climate goals.
Aiming to address this issue and spur the transition to electrified heating systems, Senate Bill 2105andHouse Bill 3203 (An Act Relative to the Future of Clean Heat in the Commonwealth), contain a wide range of provisions that would transform the role of gas utilities in the state and incentivize non-emitting clean heat technologies.
The bill would authorize the state’s gas utilities to replace gas pipes with electric heat pumps and networked geothermal systems, and allow gas companies to sell electrified home appliances. While National Grid (NYSE:NGG) and Eversource Energy (NYSE:ES) are currently collaborating with the Home Energy Efficiency Team (HEET), a clean energy nonprofit, on networked geothermal pilot projects in the towns of Lowell and Framingham, they currently are limited in their ability to expand their programs to meet demand outside of the pilot projects.
The legislation would also create a “thermal transition trust fund” within the Massachusetts Clean Energy Center (MassCEC) to provide funds for residents to replace gas appliances with electrified alternatives, with priority given to low- and moderate-income residents. It would also provide funding to utilities to train and retain workers in the transition away from gas. The fund would be paid for in part by gas customers at a cost of 1.5 cents/therm, which advocates estimate would total about $20 million annually, about half of the total.
The bill would also require gas utilities to provide the state’s Department of Public Utilities (DPU) with detailed plans to transition entirely off emitting energy sources by 2050, while also retaining gas workers, by the end of 2025.
Advocates also addressed the plans presented by gas utilities in the DPU’s 20-80 proceedings, which would decarbonize the gas system using “fossil-free fuels” like green hydrogen and biomethane. Climate groups have pushed back on these plans, arguing that these alternative fuels are scarce, expensive, hazardous and ultimately still damaging to the climate.
The gas utilities “have submitted plans that claim to decarbonize the system, but the reality is that it’s just business as usual,” said Rep. Steven Owens, one of the bill’s cosponsors in the House of Representatives.
The act would prohibit the use of hydrogen gas for heating buildings and limit the use of biomethane to gas with net-zero lifecycle emissions.
Advocates made the case that strategically shifting investments away from replacing gas pipes, which could quickly become stranded assets, and into clean heat technologies would also benefit ratepayers, who are facing a multibillion-dollar bill for the state’s Gas System Enhancement Program (GSEP). Estimates of GSEP’s total costs range from $13.4 billion to about $40 billion.
Making up for Bad Math
In Massachusetts and across the country, climate advocates have long made the case that greenhouse gas inventories based on EPA accounting methods dramatically undercount the scale and impact of methane emissions, which are responsible for about 30% of climate warming.
“The problem that we’re solving is even bigger than it appears today because we are using outdated science,” said Zeyneb Magavi, co-founder of HEET.
To update the state’s accounting methods, the Making Methane Accounting Truthful Helps (MATH) Act (Senate Bill 2092 and House Bill 873) would require the state to calculate the warming impact of its methane emissions on a 20-year timescale, along with the 100-year time frame currently used. Methane is a short-lived gas in the atmosphere, and the magnitude of its warming impact depends on the timescale used to calculate it. Over a 20-year period, the global warming potential (GWP) of methane is about three times larger than its GWP on a 100-year basis.
The state’s inventory would need to account for all gas leaked in the process of transmission, storage, distribution and end use. The bill would also require a review of accounting methods every three years, looking at the best available science.
However, as the bill is currently written, it does not target the full scope of issues in the state inventory identified by experts and climate advocates. The legislation does not address the state’s chronic underestimation of methane leak rates from the gas system: A 2021 study by Harvard University researchers found methane emissions from the gas system in the greater-Boston area to be about six times higher than the estimates from the state’s Department of Environmental Protection (DEP).
The bill also would not address how the state calculates lifecycle emissions from biofuels like biomethane, which the state essentially considers to be net-zero but are typically associated with some level of climate impact, though the impact can vary significantly based on the fuel’s source. The bill also doesn’t contain language considering out-of-state emissions associated with gas consumed in Massachusetts.
Advocates said that they hoped to address these issues in future legislation.
Democratizing the DPU
The presenters also spoke about the importance of updating the intervener process at the DPU. House Bill 3137 would require the DPU to allow municipalities, groups of ratepayers and nonprofits with utility law expertise to intervene in department proceedings.
“The DPU’s intervenor process is in desperate need for democratization,” said Rep. Jennifer Armini, the bill’s sponsor. “If we’re going to have safe, clean communities, and fight climate change, we need to change the processes that are preventing progress.”
The legislation would also require utilities to provide information to ratepayers and municipal officials about pipeline characteristics and risks, and return streets to good condition after conducting pipeline work.
“Municipalities just don’t have enough information about the gas system, and we have no authority to require that information,” said Lise Olney, chair of the Wellesley Select Board.
Next Steps
Advocates called on state legislators to sign on as co-sponsors of the three bills, which will all face scrutiny in the state’s powerful Joint Telecommunications, Utilities and Energy Committee.
A similar bill to the “Future of Clean Heat” failed in the previous legislative session. National Grid, the state’s largest gas utility, lobbied against the bill, while Eversource, Unitil and Berkshire Gas (a subsidiary of Avangrid) registered their lobbying on the bill as “neutral,” as they did for nearly all other bills.
National Grid did not respond to requests for comment. An Eversource representative wrote that the company was still reviewing the bills but noted that it will “continue to explore an array of solutions to responsibly decarbonize our natural gas system, while still providing safe and reliable heating service to all of our customers at the lowest cost possible.”
The May revision of California Gov. Gavin Newsom’s proposed budget, released Friday, anticipates a deficit that is $9 billion more than his January forecast, resulting in additional cuts across many programs.
But the governor refrained from further cuts to major initiatives on climate and energy, including billions of dollars in funding for zero-emission vehicles and wildfire prevention.
Fearing deeper cuts, environmental advocates said they were relieved.
“A budget is a statement of values, and the governor’s May revision continues to showcase California’s climate leadership,” James Pew, a climate policy fellow with advocacy group NextGen Policy, said in a statement. “Given the significant economic headwinds on the horizon, we were pleased to see that the governor’s May revision climate proposal does not make further cuts to last year’s climate commitment.”
The governor’s January budget plan for fiscal year 2023/24 proposed eliminating $6 billion in funding for clean transportation and other climate initiatives from the 2022/23 budget because of a projected plunge in tax revenues. (See Calif. Governor Proposes $6B in Climate Budget Cuts.)
The May revision retains those proposed cuts without suggesting further reductions, even though the budget shortfall in FY23/24 grew from a forecast $22.5 billion in January to $31.5 billion in May.
If adopted by the California State Legislature, the proposed cuts would reduce last year’s $54 billion, five-year commitment for climate initiatives to $48 billion, maintaining 89% of last year’s historic funding levels. Even reduced, the amount represents the world’s largest climate pledge at a “sub-national level,” Newsom said in January.
Major cuts proposed in January and carried through in the May revision include a $1.1 billion reduction in the state’s $10 billion, five-year commitment to funding for light-, medium- and heavy-duty ZEVs. The budget proposal maintains $8.9 billion, or 89%, of the planned ZEV investments, which are intended to support the state’s transportation decarbonization mandates, including a requirement that all new passenger vehicles sold in California be zero emitting starting in 2035.
The May revision also maintains $2.7 billion over four years to “advance critical investments in restoring forest and wildland health to continue to reduce the risk of catastrophic wildfires in the face of extreme climate conditions.”
Pacific Gas and Electric, and to a lesser degree Southern California Edison, have faced multibillion losses in recent years from wildfires sparked by their equipment that exploded out of control because of forest and climate conditions.
California expects that federal funds — including $100 billion in the Inflation Reduction Act for state clean energy and climate programs — could offset some of the proposed cuts.
The governor has also proposed a $1.1 billion bond that would pay for some climate programs, such as water recycling, that would otherwise see sizable funding reductions.
The legislature has until June 15 to adopt a budget plan, allowing for a month of negotiations with the governor’s office. Some lawmakers are unhappy with the governor’s proposal and support alternatives developed by the legislature.
State Sen. Josh Becker, chair of the budget subcommittee that oversees climate and energy spending, said in a statement that he would continue to push a Senate proposal that “protects many programs and prepares the state to access federal climate dollars through matching and technical assistance, which are absent in the governor’s proposal.”
“My colleagues and I will continue to advocate and work with the Newsom administration to enact responsible ways to maintain critical investments and prevent backsliding on our climate progress,” Becker said.
With deepening concerns over climate change, politicians, policymakers, electric utilities and environmentalists are advocating the idea of electrification: the replacement of fossil fuels with electricity for direct end uses like transportation and water and space heating. But most of these champions of electrification fail to consider its downsides.
Proponents want electrification to occur sooner than later, to be accelerated by subsidies and other governmental inducements. Some even advocate for mandated electrification and natural gas bans to avoid alleged climate catastrophe. Others point to the less lofty goal of revitalizing the electric industry, although electrification could cripple the natural gas and oil industries with significant job losses. Another group argues that electrification is already economical for end uses, like water and space heating. If that is true, why then do we need subsidies to induce energy consumers to switch to electric vehicles and heat pumps?
Many of the arguments supporting aggressive climate actions portray those actions as a free lunch. How could any reasonable person oppose them? Aren’t we facing a climate apocalypse that demands a full-court effort, regardless of the cost, to prevent it from happening? Anyone opposing electrification must be climate deniers or just plain wrongheaded. Proponents’ problem is that they view electrification at the 40,000-foot level, along with the false narrative that electrification can have more than a nominal effect on climate change.
Well, as with most things, there are two sides, and electrification is no exception.
Instead of artificially bolstering electrification with subsidies and mandates, which proponents of electrification would have us do, we should wait to see where electric technology takes us. Technology will determine the ultimate success of electrification — not subsidies and other governmental actions that are largely politically driven.
For electric vehicles, the challenges are still daunting: infrastructure investments — chargers, customer and utility upgrades in their distribution systems, rapid direct-current charging, education and outreach, range anxiety — limited battery storage capability, the availability of charging stations across the country and demands on the electric grid.
For heating, economics seems to be the toughest hurdle, as most electric heat pumps are only cost-effective in areas that have low electricity prices and moderate winters, at least in comparison to natural gas. Further technological improvements will make heat pumps more economically viable and markets — not government handouts — can best achieve that.
Whether energy consumers rely on fossil fuels or electricity for their transportation or space-heating needs comes down to a rational choice of what source of energy would best satisfy those needs. With few exceptions, consumers express their choices and make the best decisions for themselves.
We can say with confidence that accelerating electrification with government subsidies and mandates is a win-win for electric utilities and environmentalists but a loser for society as a whole.
The problem of new electric technologies subsidized by utility customers and taxpayers with only a distinct minority benefiting is hard to ignore, both politically and economically. It would likely have a regressive effect by disproportionately benefiting higher-income households while being funded by all income groups.
Before moving ahead with any action, policymakers should ask themselves what benefits electrification offers relative to the costs. It is unlikely that any justification would realize net benefits if the intent of accelerated electrification is solely to mitigate greenhouse gas emissions. It is somewhat puzzling, for example, why a state on its own, without cooperation from other states or the federal government or other countries, would overhaul its energy sector (which massive electrification would do) at a high transition cost for something that would largely benefit the rest of the world, namely, the mitigation of climate change.
Policymakers need to do their homework before extolling the wonders of electrification. They should especially place more trust in markets in assuring that when electrification occurs, it will be for the good of society — not just for special interests.
Kenneth W. Costello is a regulatory economist and independent consultant.
FERC this month accepted an unexecuted facilities service agreement (FSA) between SPP, Southwestern Public Service (SPS) and Ponderosa Wind II, finding it to be “just and reasonable and not unduly discriminatory or preferential” (ER23-672).
The FSA replaces an unexecuted generator interconnection agreement (GIA) filed by SPP in July and amended in September. In accepting the substitute agreement May 5, the commission said it conformed to the SPP tariff’s pro forma GIA.
The original agreement included a 20-year default term and allowed SPS to recover the return on and of the capital investment through a network upgrade charge that continued for the FSA’s term. Ponderosa protested the 20-year term, arguing that the FSA would double the overall amount paid for upgrades under the GIA. Instead, the developers proposed a three-year term to pay the money back faster.
The commission found the 20-year term to be just and reasonable because it will allow SPS to recover upgrade costs over a time period based on the utility providing interconnection service to Ponderosa. It said it was reasonable to expect interconnection service under the GIA to match or exceed 20 years.
Ponderosa II will add an additional 100 MW of capacity to the existing 200-MW facility in the Oklahoma Panhandle. The wind farms are subsidiaries of NextEra Energy Resources.
Evergy Compliance Filing OK’d
FERC also this month accepted Evergy Kansas Central’s compliance filing after protests from several transmission customers challenged the utility’s implementation of its transmission formula rate (ER22-1205).
The commission on May 5 found that Evergy had complied with its directives in a December order by correcting its formula rates’ application in its 2022 annual update. It said the filing details how the revised formula rate billings’ calculations reduced its annual revenue requirement by more than $15 million.
Evergy also said it will provide refunds with interest in the next rate year’s annual projection.
FERC denied the utility’s rehearing request but granted its clarification petition.
Kansas Electric Power Cooperative, Kansas Municipal Energy Agency and Kansas Power Pool challenged Evergy’s initial filing last year, arguing that it incorrectly applied its formula rate according to its own instructions. They also contended that Evergy double-counted its undistributed subsidiary earnings in the formula’s equity capitalization component.
The transmission customers requested that FERC direct Evergy to correct the formula rate’s implementation and refund excess amounts collected in previous years. The commission in December granted in part and denied in part the formal challenge.
MISO said the sunsetted working group was effectively functioning as a user group because it did not make policy recommendations to the Reliability Subcommittee. It said policy decisions on power restoration processes have largely been handled through the subcommittee and the nonpublic Reliable Operations Working Group.
The OTUG will still serve as an outlet for discussions on operator training, system resilience, emergency preparedness exercises and restoration drills. When appropriate, the group will advise MISO and stakeholders on mitigating reliability risks through improved training.
User groups are not defined in MISO’s Stakeholder Governance Guide and therefore aren’t bound by the usual committee guidelines. User groups do not have to elect leadership. The grid operator said the new group will allow it to exert the same influence while having greater flexibility.
The OTUG will continue to report to the Reliability Subcommittee. Members will present a new mission statement, meeting dates and management plan to the subcommittee during its May 23 meeting.
WASHINGTON — FERC’s enforcement powers have been impacted by some recent court cases, and the commission itself has some new priorities, experts said at a panel Friday during the Energy Bar Association’s Annual Meeting.
The commission for a long time had four main priorities when it comes to enforcement: market manipulation; serious violations of reliability standards; threats to transparency; and anticompetitive conduct, said Jones Day partner David Applebaum, a six-year FERC veteran and former director of the Division of Investigations. But in late 2021, it added a fifth: threats to the nation’s infrastructure and associated impacts on the environment and neighboring communities.
“I wouldn’t categorize the addition as any indication that we were investigating or penalizing conduct that had previously gone unaddressed, but rather as an indication that we had seen a compliance concern in this area,” FERC Office of Enforcement Director Janel Burdick said. “And specifically, I’m talking about violations of hydroelectric licenses, as well as certificate orders associated with [Natural Gas Act] Sections 3 and 7.”
While so far the new policy only applies to dams and natural gas infrastructure — with FERC getting some expanded authority over electric transmission in National Interest Electric Transmission Corridors — the commission could start to pursue similar cases in the power industry. Burdick, however, said those issues are still being hammered out by the commission, so it is unclear how this would play out.
One example of its new focus was a $700,000 settlement FERC approved with the natural gas storage facility outside Houston called Tres Palacios because it failed to conduct sonar surveys of its salt caverns as required in its certificate, said Bracewell partner Charles Mills. The firm admitted that it had not done the survey and even asked for an extension, which was denied (IN21-3).
“The things that can somewhat be taken away from it are: There was no finding of negligence, no finding harm, in order to find a violation,” Mills said. “It appears to be somewhat strict liability; if that certificate says you must do something, then you’ve got to do it.”
The Tres Palacios case was straightforward, but other cases involving the new priority could involve more litigation, such as when FERC pursues enforcement against a pipeline for its post-construction cleanup activities, in which whether that work was done properly can be a matter for debate, Mills said.
FERC has long pursued market manipulation cases, and some of those have worked their way through the courts after years of litigation and have set some precedent.
The commission alleged that BP manipulated natural gas prices in the Houston Ship Channel following Hurricane Ike in 2008 to benefit its positions elsewhere. In a decision last October, the 5th U.S. Circuit Court of Appeals agreed with BP on jurisdiction, said William Barksdale, energy regulatory counsel with Skadden, Arps, Slate, Meagher & Flom.
Most of the transactions in question were intrastate, and while FERC claimed authority because they impacted markets it regulates, the court disagreed and threw those out. The court told the commission to recalculate the fine based on the much smaller group of transactions it did have jurisdiction over, Barksdale said.
Another case where FERC managed to dodge having precedent set against some of its powers of disgorgement came in litigation with Coaltrain Energy, which is one of the firms that allegedly manipulated PJM’s market in the summer of 2010, said Mills. It and other firms used otherwise unprofitable up-to-congestion transactions to maximize marginal loss surplus allocation (MLSA) payments.
Coaltrain argued that FERC did not have the authority to order disgorgements, and the court agreed with the firm. The case was getting ready to go to trial, but FERC settled with Coaltrain for the $4 million in disgorgement alone, dropping significantly higher civil penalties it had initially sought, and got the court to vacate its opinion.
“So that’s over $50 million in fines [removed] from the case, but disgorgement is preserved,” said Mills. “To me, this indicates the importance that FERC places on disgorgement as a remedy but also [the] concern that its jurisdiction is being challenged, and they’re losing that jurisdictional point, and they don’t want that.”
Another one of the firms that allegedly engaged in the UTC-for-MLSA scheme back in 2010, Powhatan Energy Fund, recently wrapped up the litigation in a default judgment after it declared bankruptcy. That decision issued in March was important because it shows the commission has been winning on jurisdictional arguments, said Seema Jain, branch chief of Enforcement’s Division of Investigations.
“This is an important decision, because it’s the only final judgment on an enforcement case under the Federal Power Act,” said Jain. “So, you know, I want to highlight that. And the court granted FERC’s motion for default judgment against Powhatan and ordered disgorgement of $3.4 million, as well as $16.8 million in civil penalties. As part of that order, the court found that the commission’s well pleaded complaint and penalty order established that Powhatan committed market manipulation.”
Entergy (NYSE: ETR) said Wednesday its Texas subsidiary has struck a rate case settlement with state regulators to recover $2.3 billion for grid-modernization improvements it has completed.
Entergy Texas last year filed for base rate and rider revenues designed to collect $1.3 billion per year in non-fuel retail, an 11.2% ($131.4 million) increase on average across all customers classes. The settlement provides for a $54 million increase in base rate revenues, exclusive of incremental to costs being realigned from various riders and recovery factors, resulting in a non-fuel revenue requirement of $1.23 billion (53719).
The Texas Office of Public Utility Counsel, Texas Industrial Energy Consumers, Sierra Club, Kroger, Federal Executive Agencies and Walmart all signed on to the agreement, which is pending final approval from the PUC.
Entergy Texas spokesperson Kendra James said the settlement boils down to regulators agreeing to find that the company’s investments were prudent, reasonable and made for the customers’ benefit.
“It’s important to note that this amount is not an amount by which Entergy Texas rates will change. A portion of the cost of these investments will be recovered annually over the period in which they serve customers, which is decades for most large assets,” James said in an emailed statement to RTO Insider.
Entergy included the 993-MW Montgomery County Power Station, which went into commercial operations in January 2021 north of Houston, as part of the recent infrastructure upgrades. The plant was attributed as part of the reason MISO ultimately withdrew support for the only competitive transmission project it has ever recommended for MISO South. (See FERC Rejects Last-ditch Effort to Save Tx Project.)
The utility also pointed to its recent $41.3 million acquisition of the gas-fired, 146-MW Hardin County Peaking Facility from East Texas Electric Cooperative.
“Entergy Texas is continuously investing in customer-driven solutions to build a more reliable and resilient energy future for Southeast Texas communities,” Entergy Texas CEO Eliecer Viamontes said in a press release. “We are committed to balancing customer affordability with critical investments to help reduce outages and continue to strengthen the power grid.”
The company said it will also spend more than $2.5 billion by 2025 to continue replacing aging generation and harden infrastructure. It received the PUC’s approval last year to build the 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station. Entergy recently broke ground on the project and expects it to be in service by 2026. (See Entergy, NextEra Tout Clean Energy Efforts.)
Entergy said the settlement’s terms will help ensure it stays “financially healthy and able to make the significant capital investments required to provide affordable, reliable and sustainable power.”
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