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November 20, 2024

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FERC Directs More Clarity in Order 864 Filings

FERC last week approved NorthWestern Corp.’s (NASDAQ:NWE) compliance filing under a commission order that ensures transmission formula rates properly address excess and deficient accumulated deferred income taxes (ADIT) resulting from current and future tax-rate changes (ER20-1090).

The ruling was one of three FERC issued on Thursday related to Order 864. The 2019 directive required public transmission providers with formula rates under a tariff or rate schedule to make revisions accounting for changes caused by the Tax Cuts and Jobs Act of 2017. The order also directed entities to include a mechanism in their rates that deducts any excess ADIT or add any deficient ADIT to their rate base.

The commission found that NorthWestern partially complied with Order 864’s requirements and directed the company to make a further compliance filing within 60 days.

NorthWestern proposed incorporating two new worksheets addressing Order 864’s requirement for a rate base adjustment mechanism, a summary worksheet and a worksheet specific to each tax change. It also said it would add another worksheet calculating the excess and deficient ADIT.

FERC said NorthWestern’s adjustment mechanism did not fully apply to any future tax rate changes giving rise to excess or deficient ADIT and ordered it to include “deficient ADIT” in the summary worksheet. The commission also directed NorthWestern to include “deficient ADIT” in its tax allowance adjustment mechanism.

That latter mechanism allows a transmission company to decrease or increase its income tax component by any amortized excess or deficient ADIT, respectively. FERC found NorthWestern’s formula description did not accurately reflect the formula in a separate worksheet and ordered it to make revisions.

The commission also ordered the company to include “deficient ADIT” in the notes of its summary worksheets.

PacifiCorp Partially Rejected

FERC also rejected parts of an Order 864 compliance filing by PacifiCorp (NYSE:BRK.A) because of worksheet shortcomings and directed the utility to submit an additional compliance filing in 60 days (ER20-1828).

The commission found PacifiCorp’s ADIT filing did not comply with Order 864’s categories 1 and 2 worksheet requirements.

In category 1, “Order No. 864 required public utilities to include in their permanent ADIT worksheets ‘how any ADIT accounts were remeasured and the excess or deficient ADIT contained therein,’” FERC said.

PacifiCorp’s proposed ADIT worksheets did not demonstrate how any ADIT accounts were remeasured but only showed the “excess and deficient ADIT contained therein, and then allocated the ADIT amounts to transmission without providing additional illustration or explanation of their calculations,” FERC said.

To satisfy the category 1 requirements, PacifiCorp “must provide the pre-tax rate change and post-tax rate change ADIT account balances, in addition to the resulting excess and deficient ADIT already provided,” the commission said. “Further, such information must be provided at a level of detail such that interested parties can identify the source (i.e., the originating accounts) of excess or deficient ADIT in the proposed ADIT worksheet and verify excess and deficient ADIT resulting from the Tax Cuts and Jobs Act and future tax rate changes.”

In category 2, PacifiCorp identified end-of-year balances of excess and deficient ADIT but did not provide the full accounting for any unamortized excess or deficient amounts, FERC said.

“Specifically, the ADIT worksheets do not display the gross-up on unamortized excess and deficient ADIT included in these accounts,” it said. “As such, in the compliance filing ordered below, we direct PacifiCorp to display the gross-up on excess and deficient ADIT included” in two specified accounts.

Duke Partially Approved

Finally, the commission partially accepted Duke Energy Ohio/Kentucky’s (DEOK) (NYSE:DUK) proposed revisions to its transmission formula rate, directing a further compliance filing within 60 days (ER20-1832).

DEOK argued its existing formula rate included a rate base adjustment mechanism for several of its accounts “as adjusted by any amounts in contra accounts identified as regulatory assets or liabilities.” But DEOK proposed adding language to an existing account “to maintain rate-base neutrality in the event of a change to income tax rates” and that the account balance would be derived form the new ADIT worksheet it proposed to comply with Order 864.

The compliance filing proposed adding language to the formula rate “to incorporate the amortization of excess and deficient ADIT into the income tax calculation, in order to return or recover excess/deficient ADIT.” DEOK also proposed incorporating a new permanent ADIT worksheet into its formula rate that would annually track information related to its “protected and unprotected deficient deferred income tax” and to provide an “informational reconciliation of accounts remeasured as a result of federal and state income tax rate changes.”

American Municipal Power (AMP) made several protests of the filing, alleging that DEOK may be retaining a portion of excess ADIT because of the Kentucky corporate income tax rate changing from 6% to 5% in 2018. AMP said DEOK “improperly amortized certain excess ADIT related to that change,” requesting that the commission require DEOK to refund the amounts with interest and recalculate its 2019 annual update “because DEOK has not ensured rate-base neutrality.”

The commission found that the utility’s rate-base adjustment mechanism partially complied with Order 864, saying the mechanism “allows DEOK to deduct any excess ADIT calculated in the proposed ADIT worksheet from rate base, thus preserving rate-base neutrality for that component” and that it may be applied to “any future federal tax rate changes that give rise to excess or deficient ADIT.”

But it also said it agreed with AMP that the mechanism does not reflect the 2018 Kentucky excess ADIT as a “contra” in several accounts “instead of using its proposed rate-base adjustment mechanism.”

The commission said DEOK’s proposal “does not show how much of the 2018 Kentucky excess ADIT ultimately were included in other components” of the rate and how it meets the requirements of the ADIT worksheet.

It directed DEOK to show how its proposal for the state tax rate changes are consistent with the requirements of Order 864, including “how transmission customers will receive the full amount of both protected and unprotected excess ADIT balance to be returned to transmission.”

FERC also found that DEOK’s ADIT worksheet partially complied with Order 864, directing more changes. While the worksheet shows adjustments from the originating ADIT accounts to the regulatory asset and liability accounts, it does not include the beginning balance of the remeasured ADIT amounts, the commission said.

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FERC Weighs in as ISO-NE Prepares for Capacity Auction

FERC on Friday accepted ISO-NE‘s  informational filing for its upcoming capacity auction, turning down petitions by two companies to adjust their offers and taking the opportunity to once again call for elimination of the RTO’s Minimum Offer Price Rule (MOPR).

FERC’s order ahead of the Feb. 7 auction rejected a protest by Borrego for its Wendell Energy Storage Project (ER22-391). The solar and storage company argued that its offer floor price should be adjusted to account for a battery storage investment tax credit (ITC) that could be included in the Biden administration’s Build Back Better Act. FERC denied the request because the bill has not become law.

The commission also turned down a protest from Anbaric and Massachusetts Municipal Wholesale Electric Company (MMWEC) over their Westover Energy Storage Center. They argued that ISO-NE’s Internal Market Monitor inappropriately mitigated their proposed offer floor price to the offer review trigger price (ORTP) for storage.

Another Push on the MOPR

FERC Chairman Richard Glick and Commissioner Allison Clements wrote a separate concurrence to once again urge ISO-NE to remove its MOPR.

The two have been pushing both New England and PJM to get rid of the rules, which they say are uncompetitive and prop up incumbent generators.

The rule in New England, they wrote, makes the RTO’s existing tariff unjust and unreasonable. They argue that the MOPR is overly broad and goes beyond preventing market-side buyer power and into punishing legitimately low capacity offers.

The FERC commissioners deferred to ISO-NE’s process for replacing the MOPR.

“We think it prudent to give the ISO an opportunity to replace the existing MOPR with a solution of its choosing. After all, under the FPA, one size need not fit all and different regions of the country may choose different approaches to addressing the problem of actual buyer side market power,” they wrote.

But they urged ISO-NE to move “expeditiously.”

A proposal to eliminate the MOPR is moving through the NEPOOL stakeholder process and is up for a vote at the Participants Committee next week. (See NEPOOL MC Approves ISO-NE Plan to Eliminate MOPR.)

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Hydrogen Emerges as Crucial Component for Achieving Net Zero

An expansion of nuclear power, as well as more natural gas-fired power generation in developing nations, appear to be two technologies crucial to achieving global net-zero carbon emissions by 2050.

Oil, both as a fuel and chemical feed stock, isn’t going to disappear in the near or medium term, if only because so many of the world’s economies are tied to it.

And hydrogen, perceived as a long shot at the start of the Biden administration, is emerging as the one element thought to be capable of bridging multiple technologies, solving storage for renewable power, for example, while also replacing natural gas and gasoline as fuels.

These are some of the assertions that emerged during a four-day series of webinars produced last week by the Atlantic Council to coincide with the annual Abu Dhabi Sustainability Week. The four hours of rapidly paced discussions were also a prelude to the 27th U.N. Conference of Parties (COP27) scheduled for November in Egypt.

The 2022 Global Energy Agenda

Majid Hamid Jafar, CEO of Crescent Petroleum, based in the United Arab Emirates, said the long-term oil supply situation is the larger and more important question because the switch to renewables is going to take many years.

He said “climate activism” has damaged the infrastructure of the oil and gas industry.

“There are always short-term geopolitical impacts and volatility when it comes to energy markets. That’s always been the case and likely always will be the case.

“My bigger concern is the longer-term trends we’re seeing in the underinvestment: 25% lower investment in the upstream [exploration and production] than pre-COVID, but half the level of a decade ago.

“I think there needs to be this realization that oil and gas is still going to be needed,” he said. “It’s just how we produce it will be cleaner, and how we use it will be different.”

He said Crescent has gradually transitioned more from oil to gas. “We’re now at 85% gas. We reduced our flaring to near zero, and by offsetting the remainder we actually declared net zero not in 2050 but last October.

“The gas we actually produced in the region displaces diesel for electricity that actually avoids more emissions than all the Teslas on the planet,” he said.

“I think that impact is underappreciated. Yes, solar and wind power costs have come down, and they’re very promising. But the energy from them can’t be stored. So you need stable background sources like natural gas or nuclear as the U.S. energy policy has demonstrated.

“And on the oil side, even if cars become electric, they’re still made from products of oil, as are solar panels [and] wind turbines, and if we just look at the COVID pandemic, everything we’ve relied on, from smartphones, masks, sanitizers and vaccines, are all made from oil products,” he said.

In response, Francesco La Camera, director-general of the International Renewable Energy Agency, said the global oil industry lacks resilience. But he argued that the solution is moving more quickly toward renewables.

“What are the technologies that today are most competitive and cheapest way to produce energy? What are the technologies that ensure more resilience in the system?” he asked rhetorically.

“What are the technologies that can assure us to be in line with the Paris Agreement goals? What are the technologies that ensure that the energy transition will also … reduce the inequality existing today in the world?

“And as far as I can answer, the only way … is going faster and faster toward renewables.”

Hydrogen: Energy System Integrator?

The role hydrogen might play in decarbonizing transportation, stabilizing electric grids dependent upon increasing amounts of wind and solar generation, and eventually displacing natural gas in heavy industry was the focus of the Jan. 20 discussion.

“Our aim is to look at how hydrogen could become an energy system integrator,” Randolph Bell, director of the Global Energy Center at the Atlantic Council, said in opening remarks “tying together the worlds of electrons and molecules, leveraging the expertise of both the hydrocarbon and renewable energy sectors, and decarbonizing hard-to-abate sectors.”

That hydrogen has stirred global excitement was evident during the discussion.

Marco Alvera, CEO of SNAM, an infrastructure company headquartered in Milan, said the question of hydrogen’s future was “spot on.”

“We’ve had for too long a debate whether it was going to be molecules [or] electrons,” said Alvera, who wrote a book published last year, titled “The Hydrogen Revolution.”

“Because it’s a molecule, [and] you can make it with electrolyzers through electrons, you’re simply bridging the gap and that really helps the sector coupling. …

“Hydrogen allows us to produce great quantities of renewable energy, where there’s no grid, where there’s no market, and we can … produce hydrogen from the renewable energy. And we can easily transport that hydrogen — whether through liquid hydrogen, through [converting it to] ammonia, through methanol, or directly via pipes — we can move it to where the markets are.”

SNAM operates 30,000 miles of pipeline in half a dozen European nations and has already blended up to 10% hydrogen with natural gas. It has also done an engineering assessment of its system, determining that 99% of its pipeline system could run pure hydrogen, he said.

“The quality of the steel that was used in the ’70s, ’80s and ’90s to build our natural gas pipelines [is] exactly the same that we would use today to build a dedicated 100% hydrogen pipeline,” he explained.

The company has plans for enormous expansion.

“We have committed to our investors to have a hydrogen backbone to be able to move green hydrogen molecules from North Africa into Europe before 2030,” he said.

Pipeline companies in the U.S. will probably have to replace existing gas lines because the steel in the lines is harder than what was used in Europe in recent decades and could become brittle transporting hydrogen, Alvera said.

But that would not likely be as expensive as it sounds, he added, because the new lines could run in existing rights of way, side by side with the gas line, or even inside the old lines.

Wind to Hydrogen to Liquid Fuel

Houston-based Highly Innovative Fuels (HIF) is a company with big plans to make liquid fuels from hydrogen produced from water in electrolyzers using power produced by wind.

HIF has a project planned for Texas where site selection is underway, one planned for Australia and another in Chile where a plant is already under construction.

In Chile, the capacity factor of wind turbines is 75% (compared to 45% in Texas), said Meg Gentle, the company’s executive director. That means the wind farm will not have to be overbuilt to compensate for as much down time. And that means less expensive power to run the electrolyzers producing the hydrogen.

“We will be combining the hydrogen with CO2 that we will capture from the atmosphere,” Gentle said. “And when you do that recombination, you have methanol, which can easily be synthesized into gasoline, eventually into jet fuel or, in fact, used by the shipping industry simply as methanol. So, it creates a way to convert electricity into liquid fuels.”

Hydrogen Production in the Middle East

HIF will likely find itself competing with Middle Eastern companies, including one headquartered in Abu Dhabi that has similarly big plans.

“We have been a country that relied for decades on the rich hydrocarbon resources. This [hydrogen] gives us an opportunity to transition to a clean energy supply system,” said Alexander Ritschel, head of technology at Masdar Clean Energy.

He said his company will use the expertise and infrastructure it developed to move oil and refined products to instead transport hydrogen-based products, including aviation fuel.

He added that the company will make both green hydrogen with electrolysis and blue hydrogen, made from methane. And it has begun projects to make hydrogen from renewable methane made from municipal waste.

Moving the hydrogen out of the Middle East won’t be a problem, he said. “We have a lot of international sea routes, leaving from the UAE, going to all destinations in the world.

“But most importantly, the UAE is known as an aviation hub; we have one of the largest airlines in the world. We have launched a pilot project now … producing sustainable aviation fuel, purely made with solar electricity, [hydrogen] and recycled CO2,” Ritschel said.

Pathways to Net Zero

Friday’s webinar looked a little more closely at the range of strategies that nations, by resource necessity or for reasons of security, are expected to choose on the way to achieving net-zero carbon emissions.

“Our panelists will explore how different geographies, resource endowments, politics, financing and so on can impact a country’s net-zero strategies,” the Atlantic Council’s Bell explained in opening remarks.

Moderator Ryan Heath, a senior editor at POLITICO, noted that governments appear to be ahead of companies in figuring out exactly what net zero means and how they might reach it.

Quoting a recently released PricewaterhouseCoopers global CEO survey, Heath noted that when all business sectors are included, rather than just energy companies, only about a quarter of companies have actually created a net-zero target.

Melanie Nakagawa, special assistant to President Biden and senior director for climate and energy on the National Security Council, said governments are “trying to shape a policy landscape that can help enable other companies and entities to put forward their own net-zero targets.”

“We can create a demand pool for … innovative technologies, and we can be the enabling environment in many countries around the world for investment.”

One administration effort to create that “enabling environment” that garnered a lot of attention at last fall’s COP26 in Scotland was a commitment to immediately work to reduce “fugitive” methane emissions, the majority from oil and gas operations, by 30% by 2030. More than 100 nations formally agreed to the commitment.

Alain Ebobisse, CEO of Africa50, the infrastructure investment platform capitalized by the African Development Bank and more than 20 African nations and central banks, echoed Nakagawa and the Biden administration’s goals but stressed that solving energy shortfalls immediately is just as important as figuring out a future net-zero strategy.

Noting that Africa as a continent “contributes roughly 4% of global emissions” and that the majority of Africa50’s energy investments are already developing renewable technologies, Ebobisse stressed that many African nations are in the middle of an energy crisis, partly because of a global natural gas shortage.

Arguing that more natural gas infrastructure must be developed, Ebobisse said cooking gas prices in many African nations have nearly doubled, from $9 to $17, for a 12.5-kg canister and that people are switching to firewood and charcoal, which is adding carbon pollution.

“The main point that I would like to make is that we believe that natural gas should be part of the transition fuel solution, because of course it’s the cleanest burning fossil fuel, but also because it can … provide baseload power that works well with intermittent renewables,” he added, echoing an argument often made by the gas industry.

Brice Raisin, head of sales for GE Gas Power in Europe, the Middle East and Africa, built on Ebobisse’s assertion.

He said utilities and power generators face a “trilemma”: a growing demand for electricity; the obligation to provide reliable, affordable and sustainable power; and now net-zero targets.

Gas generation, he said, can provide the fastest solution to the problem while the buildout of solar and both on- and offshore wind continues and small modular nuclear reactors are deployed.

And, in a nod to the potential of hydrogen, Raisin added, “When you invest in a gas plant, you don’t invest in a plant that will always emit CO2. You invest in a plant that technologically is able to burn all the types of fuel.”

Tim Holt, a member of the executive board and labor director at Siemens Energy, agreed with Raisin, adding that the ability of the industry to quickly build new gas turbine power plants would give renewable technologies the time to continue efficiency improvements.

Adam Sieminski, a senior adviser to the King Abdullah Petroleum Studies and Research Center’s board of trustees, further buttressed the argument for continued use of fossil fuel.

“Hydrocarbons and net zero are not incompatible,” said Sieminski, a long-time energy analyst, former U.S. Energy Information Administration administrator and National Security Council member under President Barack Obama.

“Net zero does not mean no hydrocarbons. What it means is controlling the carbon from those hydrocarbons. I think at some point, we’re going to go to below zero. Right? We want to have negative emissions, but that still doesn’t mean [no] hydrocarbons.

“Alain mentioned that in Africa, natural gas is a good solution. Look, there’s more than a billion and a half people who don’t have clean cooking fuels. Propane might be [an] answer to that,” he said.

“Let’s figure out a way to deal with the carbon associated with the propane. Carbon is not the enemy. There’s living carbon … trees and breathing. There’s durable carbon that locks up the carbon, and it doesn’t create a climate problem. The problem is fugitive carbon. The problem is not the fuel,” he argued.

“Concentrate on the solutions: Direct air capture and nuclear and green initiatives are a way to accomplish that. We just have to push the cost down.”

Completing the circle of that argument, Sama Bilbao y Leon, director general of the World Nuclear Association, noted that energy technologies are rapidly changing.

“I think that the energy systems of the future are not really going to look very much like the energy systems that we are used to right now. We are trying to electrify a lot of things. We are going to see a lot of coupling between electrical grids and mobility. Hydrogen is going to play a role.

“I think there’s a real need for political leadership and pragmatic leadership. We really need to be very much technology-neutral. We need to put in place both policies and market structures. We need to look at what technology can support the system,” she said.

“Obviously, we are really going to need all proven low-carbon technologies, including of course, nuclear. There is not going to be not one size that fits all. Countries are going to pick the energy mix that fits best: their natural endowments; their socioeconomic situation; their cultural preferences. So obviously, there’s going to be a huge diversity,” she said.

“I think that advanced economies are going to have to focus on decarbonizing; however, when I look at emerging economies, I think their focus needs to be energizing.”

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Overheard at USEA State of the Energy Industry Forum

The U.S. has a broad and diverse range of energy resources, and all of them — from coal and gas to nuclear and renewables — are critical to the nation’s clean energy future.

That was the message coming out of the U.S. Energy Association’s 2022 State of the Energy Industry Forum on Thursday, where industry leaders said the sector also creates thousands of well-paying jobs that support families and communities.

Those leaders were mostly buoyed by passage of the bipartisan Infrastructure Investment and Jobs Act and individually supported various energy provisions in the stalled Build Back Better Act, which they say have broad, bipartisan support.

Another common theme during the day-long forum: the need to collaborate across industry sectors and with regulators and lawmakers.

Julia Hamm, CEO of the Smart Electric Power Alliance, said that almost 70% of U.S. consumers are now served by an electric utility that has committed to a 100% carbon reduction target. But the utilities making the most progress toward those goals are the ones partnering “outside the four walls” of their organizations and engaging with stakeholders “in a way in which it’s never happened before.”

“We really need to see utilities partnering together with technology companies, with their customers, with environmental groups and other stakeholders in order to get where we need to go,” Hamm said.

For Mike Sommers, CEO of the American Petroleum Institute, cooperation is necessary “to ensure the supply of U.S. energy, including solar, wind and nuclear and, yes, petroleum products.”

Sommers said that even if every Paris Agreement signatory meets their 2040 commitments, the International Energy Agency projects that natural gas and oil will still account for almost half of all energy used.

“The only real decision here is where natural gas and oil are produced,” he said.

The Case for Fossil Fuels

Fossil fuel associations made up more than a third of the speakers at the forum, reflecting the sector’s continued economic and political power. And like Sommers, each of their representatives offered up a range of statistics underlining the pragmatic and economic need for their products and services now and in the future.

“We’ve got 187 million Americans that are using natural gas in their homes as we speak,” said Karen Harbert, CEO of the American Gas Association. “So, we are a fuel of choice and a fuel in demand. Five-and-a-half million businesses are using natural gas right now in their industrial applications, making the things that life revolves around; so, we really see ourselves as foundational to the energy system and foundational to our way of life.”

“There are 200 million cars and trucks on the road, and they consumed more than 140 billion gallons of gasoline in 2019,” said Andrew Black, CEO of the Association of Oil Pipelines. “Together we Americans make 20 million visits to a gasoline station each day. There are other ways to deliver all this energy like trains and trucks, but none of them can handle this volume. Over 13 trains each a mile long with 100 rail cars are needed to equal the volume one large pipeline delivers on a single day.”

At the same time, Black and others also stressed their commitment to sustainability and cutting emissions.

“Pipelines deliver liquid energy using the least amount of greenhouse gas emissions with the lowest impact on the environment,” Black said. “Trains and trucks both emit more GHGs than pipelines, 42% more from rail, 467% more for trucks. … Liquid pipelines are the sustainable energy delivery choice.”

Amy Andryszak, CEO of the Interstate Natural Gas Association of America, cited research from the National Bureau of Economic Research showing “a correlation between the growth of natural gas for power generation and the increased deployment of renewables.”

“If we want to expand the use of renewable energy, natural gas is the answer,” Andryszak said. “The Biden administration has made a major commitment to expanding the use of renewable energy in the United States, particularly wind and solar. But we all must recognize that these technologies are complementary to natural gas, and they require a robust natural gas infrastructure to ensure affordability and reliability.”

Michelle Bloodworth, CEO of America’s Power, a coal industry trade organization, more aggressively argued that clean energy expansion poses significant challenges to an electric grid that “hangs in a fragile balance that requires not just close monitoring and care, but thoughtful and good energy policy.”

Energy markets need to put a value on the attributes of coal and send a signal to participants that those attributes are needed, she said.

“Rather than working to eliminate fossil fuels from the mix … [the Biden administration] should work hand-in-hand with the fossil fuel industry, including the coal sector, to make fossil fuels even more environmentally sustainable,” Bloodworth said.

Gas Experts: ‘Plenty of Supply’

At the same time, natural gas industry leaders countered current perceptions of a winter supply crunch, saying natural gas production has rebounded following a pandemic dip, and prices should return to pre-pandemic levels in the spring.

Natural Gas Supply Association CEO Dena Wiggins said domestic gas production is up 4 billion cubic feet per day compared to 2020, while Charlie Riedl, executive director for the Center for Liquified Natural Gas, said global demand hit a record high of 12.2 Bcf/d in December.

During the most restrictive phase of the pandemic in summer 2020, Wiggins said the U.S. had about 9,000 drilled but uncompleted wells, but in recent months, thousands of those wells have begun producing.

“We think there’s plenty of supply to meet demand, and we think that there will be plenty of supply to meet demand,” Wiggins said. “We get a lot of press when it’s a cold day in January and spot prices are high. … It gives people pause and makes people talk about high prices.”

Wiggins said not much gas typically sells at those prices in frigid weather; rather, those buying at those prices likely have not secured contracts.

“If you wait until the day before Christmas Eve to buy a plane ticket to go home and see mom, that is going to be an expensive plane ticket,” she said.

Wiggins reassured attendees that the U.S. has enough natural gas supply for the domestic market and exports. She said gas exports remain important for other countries to meet their own emissions reductions goals.

‘A Healthy, Growing Sector’

While fewer in number, renewable energy groups also sent a message of ongoing growth and sustainability that can weather the uncertainties of politics, supply chains and COVID-19.

Even during the administration of former President Donald Trump, the private sector pumped $56 billion into renewables in 2020, said Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE).

Noting that the U.S. added an estimated 46 GW of renewables in 2021, Wetstone said, “This is a healthy and growing sector.”

Utilities and corporate buyers are a major part of that growth, with 17 GW of clean energy contracts announced and “a record 110 GW of clean power under construction or in advanced development,” said Heather Zichal, CEO of the American Clean Power Association.

While 2021 was pivotal for solar, wind and storage, Zichal said 2022 will determine whether they “accelerate progress” or “plateau.” To be successful, she said, the industries need Congress to pass the Build Back Better Act, and everyone must be engaged in regulation and policy at the federal, state and local levels.

Erin Duncan, vice president of congressional affairs for the Solar Energy Industries Association (SEIA), focused on her industry’s priorities in the bill, including the 10-year extension of the solar investment tax credit and advanced manufacturing credits that would cover essential parts of the solar supply chain, such as inverters and racking.

A 10-year ITC will provide the “long runway” manufacturers say they need “so that they [know] there would be demand for solar,” Duncan said. A complementary manufacturing credit “would help offset some of the costs of bringing domestic production back to this country,” she said.

“You can’t just snap your fingers overnight and suddenly have a hotline to [solar] cell plants; those take time to build,” she said. “We’re going to need to continue to import materials from abroad, and so it’s a balance of how you continue to build out domestic supply chains … and [drive] demand.”

SEIA wants solar to grow from its current 4% of the U.S. energy mix to 30% by 2030, a target that will require the industry “to deploy more than we’ve ever deployed in prior years every year to reach the 850 GW of capacity we’re going to need,” Duncan said.

ACORE estimates that scaling the industry to that extent could mean an annual private sector investment of $93 billion through 2029 to keep the world on track for net-zero emissions by 2050, Wetstone said.

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FERC Accepts SEEM Revisions on Transparency

FERC on Friday approved changes to the Southeast Energy Exchange Market (SEEM) that will bring it in line with promises the market’s supporters made last year (ER22-476).

SEEM’s founding members — a group of utilities including Southern Co. (NYSE:SO), Dominion Energy South Carolina (NYSE:D), LG&E and KU (NYSE:PPL), the Tennessee Valley Authority and Duke Energy (NYSE:DUK) — first proposed the modifications in June before the commission approved the SEEM agreement. The utilities were responding to a deficiency letter from FERC that expressed concerns about market power and sought assurances about the transparency of the planned market.

SEEM supporters say the expansion of bilateral trading across 11 Southeastern states will reduce trading friction through the introduction of automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions, while also promoting the integration of renewable resources. The market is expected to launch in the third quarter this year. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

FERC approved changes including:

  • weekly submissions of confidential market data to FERC and the market auditor, and periodically providing additional information publicly;
  • disclosure of regulators’ questions and answers, as well as market auditor reports, to participants, subject to restrictions on access to confidential information by marketing function employees;
  • clarification that available transfer capacity calculated by participating transmission providers must be provided to the SEEM administrator and must be used in the algorithm for each leg of any contract path to ensure transmission will not exceed available capacity;
  • updating market auditor functions to clarify that the auditor will verify compliance with market constraints;
  • use of randomization to resolve ties or ambiguities between multiple bids or offers;
  • prohibiting market-based rate holders from providing false or misleading information to the SEEM administrator or market auditor; and
  • implementing a posting requirement for complaints submitted to the market auditor.

The changes would also ensure that most SEEM rules would fall under the “just and reasonable standard” rather than the lower Mobile-Sierra public interest standard as proposed in the original agreement, an issue that became a sticking point for both FERC Chair Richard Glick and Commissioner Allison Clements.

Glick, Clements Unswayed on SEEM

Glick and Clements filed concurrences to Friday’s opinion asserting that they still had misgivings about SEEM.

In Glick’s filing, the chairman applauded SEEM members “for standing by their previous commitments on transparency.” However, he reiterated his stance that “applying [Mobile-Sierra] to any provisions of the Southeast EEM agreement is contrary to well-established commission precedent” that the standard can only apply to contracts that have “certain characteristics that justify the presumption.” Because the SEEM agreement contains “generally applicable” provisions that “bind not only the parties to the contract, but also any prospective future signatories,” Glick said Mobile-Sierra is inappropriate.

Clements’ concurrence asserted that SEEM members still had not dealt with “the underlying fundamental flaws with the [SEEM] agreement,” which remains “unduly discriminatory, unjust and unreasonable” in her eyes. But because “the scope of [FERC’s] review is limited to the amendments proposed in this proceeding,” she said she had no choice but to give her assent.

FERC ordered the revisions to take effect Nov. 25, 2021, one day after SEEM members filed the proposal, as requested by the utilities.

SEEM Moving Forward with Implementation 

Despite SEEM members’ pledge to update the agreement to address the commission’s concerns, the agreement that took effect in October did not include their proposed changes. This was because of the way the commission approved the agreement. At the time FERC had only four members, which split 2-2 on whether to accept the proposal; under Section 205 of the Federal Power Act, the agreement therefore became effective “by operation of law.”

Opponents of the market had warned that the lack of a FERC order could allow SEEM’s supporters to move forward without any of the promised transparency enhancements. However, in their November filing, the utilities claimed they “have always intended to fulfill the commitments” they made in June both because “it is the right thing to do and … to do otherwise might raise questions” about the market’s legitimacy.

Despite the divide among commissioners over approving SEEM, FERC has accepted the existence of the market as a fait accompli since the agreement took effect. Last month commissioners rejected requests for rehearing filed by several environmental and clean energy organizations on the grounds that they submitted their requests too late. FERC has also approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.)

SEEM has also continued to move forward since receiving FERC’s approval in October. Earlier this month, members announced that South Carolina-based Santee Cooper had agreed to join the market; the following week, the Municipal Electric Authority of Georgia announced that it would join as well. (See Santee Cooper Joins SEEM.)

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FERC Denies Co-ops’ $79M Complaint vs. SPP

[EDITOR’S NOTE: A previous version of this story incorrectly said the two cooperatives alleging SPP “misapplied” tariff provisions requested that the “grid operator be assessed $2.2 million in reliability unit commitment penalties.” The sentence now correctly reads, “The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.”]

FERC last week denied a complaint by a pair of electricity cooperatives that SPP “misapplied” tariff provisions by de-committing their generation resources that went on outage during last February’s extreme weather event (EL21-90).

The commission ruled Thursday that Basin Electric Power Cooperative and North Iowa Municipal Electric Cooperative Association (NIMECA) had not met the Section 206 requirement proving that SPP violated its tariff.

Basin and NIMECA filed their complaint in July, asking the commission to direct SPP to refund them $79.3 million in revenue they claimed they would have received if the RTO had abided by its tariff terms. The cooperatives also requested the grid operator assess them $2.2 million in reliability unit commitment penalties.

The co-ops asserted SPP was in violation because it de-committed several of their resources that were committed through its multiday reliability assessment (MDRA) process for reasons other than addressing an emergency condition.

The commissioners pointed out that the outage resources were issued commitment instructions as part of the MDRA, but the cooperatives reported that the resources were on outage through SPP’s outage scheduler. The RTO reflected the outage status as an input to the day-ahead market.

“The fact that the outage resources were not awarded positions in the day-ahead market does not amount to SPP de-committing” them, FERC said. The commission said because SPP correctly included the resources’ status as a day-ahead input, the resources were unable to be awarded positions in the market, even if the RTO had previously sent commitment instructions for the resources resulting from the MDRA.

FERC also agreed with the grid operator that its tariff requirements to reflect resource outages as inputs to the day-ahead market, day-ahead RUC and intra-day RUC do not depend on whether the resources were previously committed as part of the MDRA as long lead-time resources or during conservative operations.

GI Backlog Plan Approved

The commission on Jan. 14 also accepted SPP’s tariff revisions modifying its generator interconnection procedures to mitigate the backlog in its GI study queue. It directed the RTO to make an informational filing within 30 days after a transitional open-season cluster’s window closes (ER22-253).

FERC said it expected SPP’s process changes “will help expedite the process and give SPP the opportunity to reduce its interconnection queue backlog.”

SPP's GI backlog in November (SPP) Content.jpgSPP’s GI backlog in November | SPP

The commission found that the RTO’s proposed deviations from FERC’s pro forma large generator interconnection procedures, permitted under the independent entity variation standard, met Order 2003’s intent to foster increased economic generation development by reducing interconnection costs and time “and encouraging needed investment in generator and transmission infrastructure.”

“We find that SPP’s proposals … will allow SPP to complete studies more efficiently than under the current process,” the commissioners wrote. “SPP’s proposed transition plan … allows SPP to manage the interconnection study queue while it addresses the backlog.”

The tariff revisions are the result of the Strategic and Creative Re-engineering of Integrated Planning Team’s work to resolve a five-year backlog of GI requests by 2024. SPP staff said the backlog dates back to 2017 and is comprised of 533 interconnection requests and almost 100 GW of capacity, most of it for wind and solar generation. (See “Renewable Developers Applaud SPP’s Plan to Reduce GI Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

SPP staff are currently working on the oldest two study clusters.

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Coalition Sues New Jersey DEP to Tighten GHG Emissions Goals

A coalition of about 120 environmental, community, faith and grassroots groups have filed suit against the New Jersey Department of Environmental Protection (DEP), seeking to force the agency to enact measures that the coalition argues would cut greenhouse gas emissions in the state 50% below 2005 levels by 2030.

Filed in the state Appellate Division of Superior Court on Thursday, the EmpowerNJ suit seeks to overturn the DEP’s Dec. 14 rejection of a petition the coalition filed in July. The petition demanded that the state accelerate its timeline for reducing greenhouse gas emissions and immediately stop issuing permits for fossil fuel projects, including pipelines and power plants that use natural gas. (See NJ Enviros Squeeze Governor on GHG Goals.)

EmpowerNJ’s submission to the court said that the denial should be overturned because the DEP failed to comply with the state’s Global Warming Response Act, legislation enacted in 2007 that required the state to achieve certain emissions reduction goals.

The setting of “interim greenhouse gas reduction benchmarks” under the law is “mandatory … not discretionary” the coalition’s suit says. It adds that the DEP’s failure to establish benchmarks was an “abuse of discretion” and the decision to deny the coalition’s petition was “arbitrary and capricious” and conflicted with state policy.

“Anything less than 50×30 would be too little and too late, so we’re taking DEP to court,” said John Reichman of BlueWaveNJ, a citizen lobbying group, in a statement, using the shorthand term for reaching a 50% cut in emissions by 2030.

Demanding Action

With Gov. Phil Murphy’s December executive order committing New Jersey to the 50×30 goal, the chances of success for EmpowerNJ’s suit are uncertain.

When the coalition originally filed its petition, Murphy had previously set a goal of cutting New Jersey’s GHG emissions 80% by 2050, as set in his administration’s updated climate change masterplan released in 2020. But four days before the DEP rejected the petition, Murphy announced the 2030 goal and backed his pledge with more than $33 million in state funds for purchasing medium- and heavy-duty electric vehicles (See Murphy Toughens NJ Emission-reduction Goals.)

While Murphy’s latest pledge puts him in line with the coalition demands, EmpowerNJ filed the suit, it says, because the DEP’s denial does not match the governor’s rhetoric.

“Either they’re a rogue agency, or the governor is in collusion,” said Jeff Tittel, former director of the New Jersey Sierra Club, who acts as spokesman for the coalition. “Basically, the DEP ignored the governor, ignored sound science, ignored the International Panel on Climate Change (IPCC), and ignored the law.” The IPCC, a United Nations panel, said in August that the world must urgently step up its GHG reductions to limit climate change.

EmpowerNJ wants to see the DEP set and move forward on specific dates and emissions reduction goals to ensure that it can reach the 2030 target, Tittel said.

Murphy’s office said the governor does not comment on litigation. The DEP referred a request for comment to the New Jersey Office of Attorney General, which said it had no comment.

How to Cut Emissions

In explaining why it rejected the petition, the DEP said the Murphy administration had taken a variety of steps to reach the emissions reductions set out in the state’s response to climate change, known as the 80×50 report. They included reform of air quality regulations, targets for the number of electric vehicles in use, and strategies to promote the electrification of new buildings. But each of these steps requires the involvement of multiple agencies and departments, the DEP said.

“The department fully recognizes, and its work is motivated by, the urgency of the climate crisis,” the DEP said in its denial of the coalition petition. “No single state agency or any one regulatory reform or set of regulatory reforms by the department can itself bring about the structural, economic, and societal changes necessary to reduce the worsening effects of climate change.”

“The complexity of achieving emissions reductions on the scale necessary does not lend to simplistic regulatory formulations as proposed by petitioners,” the denial stated. It added that it “would be impractical” for the DEP to limit fossil fuel development, in part because it would require the involvement of other government agencies, and also because the state will need fossil fuel plants for a while “to ensure the reliability and resilience” of the state’s “existing energy system.”

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CAISO Extends Wheel-through Rules

The CAISO Board of Governors and the Western Energy Imbalance Market (WEIM) Governing Body on Thursday agreed to extend controversial wheel-through rules for two more years while naming new members to WEIM’s Governance Review Committee (GRC).

CAISO enacted the wheeling provisions prior to summer 2021 to help avoid capacity shortfalls like those that caused rolling blackouts in August 2020.

The new rules sought to ensure that transfers from the Pacific Northwest to the Desert Southwest through CAISO territory did not take precedence over capacity needed to serve CAISO native load. One provision required non-CAISO entities to designate high-priority wheel-throughs needed for reliability at least 45 days in advance. (See CAISO Approves Controversial Wheeling Limits.)

The Bonneville Power Administration, Arizona Public Service, NV Energy and others protested the changes, saying they were inequitable and ran contrary to FERC’s open-access rules. FERC, however, ultimately accepted the provisions. (See FERC OKs CAISO Wheel-through Restrictions.)

In Thursday’s meeting, the WEIM Governing Body voted in its advisory capacity to extend the wheeling provisions, which were set to expire June 1, to May 2024. Previously the Governing Body had declined to support the change in a rare split between it and CAISO management. (See EIM Governing Body Rejects Part of CAISO Summer Plan.)

Entities from across the Western Interconnection participate in WEIM, CAISO’s real-time interstate trading market, in a sometimes uneasy relationship between California and the rest of the West.  

Governing Body Chair Anita Decker had opposed the wheeling provisions in April as a threat to the WEIM and Western cooperation, but she decided to support the extension of the rules last week as a means to achieving a long-term solution.

“In reading through the comments and hearing from various stakeholders, it’s abundantly clear that the underlying interest is to move something forward that actually supports a West-wide effort, and I think this is a step in doing that,” Decker said. “I’ve been skeptical … but I am going to support this.”

CAISO board member Angelina Galiteva agreed the extension was a “stopgap” measure on the way to a more workable plan.

“This is not an ideal solution, but it’s kind of a situation [where] the perfect is the enemy of the good,” Galiteva said.

Reaching a “long-term durable solution that is … equitable to market participants” in two years is “actually a very compressed timeline … [but] I’m confident that with the stakeholder process and inclusivity that we generally see around these processes, we’re going to reach a solution that works.”

GRC Appointments 

In a separate decision, the board and Governing Body appointed three new members to fill vacancies on the WEIM Governance Review Committee.

Pam Sporborg, Portland General Electric’s market analytics and performance manager, was named to fill the vacant WEIM entity sector seat. Michele Beck, executive director of the Utah Office of Consumer Services, and Amanda Ormond, principal of energy consultancy Ormond Group, were appointed to fill two vacant public interest and consumer advocate sector seats on the committee.

In August, the CAISO board and WEIM Governing Body approved a new delegation of authority over EIM matters after a lengthy stakeholder process and reassessment required by the market’s founding charter in 2014. (CAISO Agrees to Share More Power with EIM.)

This year, the GRC plans to weigh changes to support the proposed WEIM extended day-ahead market (EDAM), a top priority for CAISO. (See CAISO Takes on Transmission, EDAM in 2022.)

“In addition to the benefits an EDAM market offers our partners, an extended day-ahead market can serve as the next important step in the creation of a regional market that will result in meaningful efficiencies for utilities in the Western interconnection,” CAISO CEO Elliot Mainzer said in a statement on the decision.

The GRC’s next public meeting is scheduled for Feb. 17.

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FERC Rejects PJM 10% Capacity Market Adder

FERC ordered PJM last week to remove the 10% cost adder for the reference resource used to establish the variable resource requirement (VRR) curve in the RTO’s capacity market (ER19-105).

In a 4-1 decision at its monthly open meeting Thursday, the commission said it determined there was “insufficient record evidence to support PJM’s proposed inclusion of a 10% adder,” reversing its original decision in April 2019. Commissioner James Danly dissented.

The D.C. Circuit Court of Appeals in July rejected FERC’s logic for approving the adder, ruling that the commission “did not provide a satisfactory explanation for its approval, which reasoned decision-making requires” (20-1212). (See DC Circuit Rejects FERC Logic on PJM 10% Adder.)

PJM argued that the 10% adder was necessary “based on the uncertainty of natural gas costs” and the “differences between the key assumptions made for the reference resource relative to actual attributes of a similarly situated representative resource.”

“Based on a thorough review of the record, we find that PJM failed to meet its burden of demonstrating that inclusion of the 10% adder in modeling energy market offers for purposes of calculating the E&AS [energy and ancillary services] offset for its VRR curve is just and reasonable,” FERC said. “The record fails to support PJM’s central argument for including the adder: that a 10% adder should be included in the modeled energy market offers of the reference resource during all hours of the year because tariff provisions governing energy market sellers’ cost-based offers permit such adders to be included.”

PJM must remove the adder from the determination of the VRR curve beginning with the 2023/24 Base Residual Auction and submit a compliance filing within 30 days with tariff revisions reflecting the removal.

The commission said although it rejected the adder, it remained “mindful” that the VRR curve is partially based on calculation of the reference resource’s estimated cost of service, which is used to determine the resource’s net cost of new entry (CONE) and “necessarily require the use of assumptions.”

“PJM, however, has not demonstrated that adding 10% to the reference CT’s costs, which raises the net CONE used to develop the VRR curve, is a reasonable assumption that results in a more accurate representation of such costs compared to an estimate without a 10% adder (i.e., PJM’s prior method of calculating the E&AS offset),” FERC said in its order.

Glick Comments

FERC Chairman Richard Glick discussed the decision with reporters after the meeting, saying the adder has been an “ongoing discussion” in PJM for several years and that there was “no justification” for it. Glick dissented on the original order, with former Commissioners Neil Chatterjee, Cheryl LaFleur and Bernard McNamee making up the majority.

Glick said there have been “constant proposals” from PJM, stakeholders and the commission to make “pretty significant changes” to the RTO’s capacity markets.

“We all like to think that there are competitive markets out there, but they’re called market constructs for a reason,” Glick said. “They require a lot of administering, whether it be through the Independent Market Monitor, through PJM or FERC.”

Glick said there’s been an “obsession” by some stakeholders in trying to increase revenues for generators, with some believing they haven’t been able to recover enough revenue and making “constant” proposals that “blatantly increase prices” without any clear justification, citing the minimum offer price rule as the biggest example.

“In some cases, I felt like we were just making stuff up in order to increase prices,” Glick said. “I think it’s very important that we go back to basics and figure out what is truly just and reasonable and not focus extensively on bolstering uneconomic generation.”

Danly Dissents

In his dissent, Danly admonished the majority, arguing that the adder was being removed shortly before a scheduled auction “that had already been delayed to accommodate other recent commission intrusions into PJM’s market design.”

“The fact is, a new commission with different membership has decided to reverse itself, which it is entitled to do, but in so doing, it discounts the evidence submitted by PJM and the market participants in support of the 10% adder,” Danly said. “But since not all generators will include the adder every time, we jettison it. Forget that PJM easily met their burden for a [Federal Power Act] Section 205 rate filing.”

Dany said he also disagreed with the process leading to the dismissal of the adder, noting PJM detailed “numerous reasons” why it should not be eliminated for the 2023/24 delivery year, including that it would have to recalculate the E&AS offset, net CONE and net avoidable-cost rate.

“These are not minor details, but fundamental changes we now require after critical auction deadlines have already passed,” Danly said. “I am not certain it is possible for the commission to make any more of a muddle of the PJM capacity market. I suppose if we really wanted to cause trouble, we could delay the auctions again but, wait … we already have.”

MSOC Decisions

The commission also ruled on two issues regarding PJM’s market seller offer cap (MSOC).

In the first, FERC rejected 10 individual filings each requesting commission approval of letter agreements between capacity market sellers and the Monitor (ER22-474). The agreements concerned alternative MSOCs for each seller’s offer into the 2023/24 BRA.

The commission determined that the agreements did not identify offer cap values, failing to comply with PJM’s tariff requirement that any alternative offer cap must be filed with FERC for approval.

“We find that, when filing these letter agreements, it is insufficient to merely reference the existence of a nonpublic offer cap posted by the IMM,” the commission said. “We cannot evaluate an offer cap value that is not before us.”

The order also instituted a show-cause proceeding in a separate docket on the justness and reasonableness of the tariff provision that allows sellers and the Monitor to agree on and file an alternative offer cap that is inconsistent with the PJM tariff (EL22-22).

FERC also ruled on the Monitor’s request for waiver or clarification to update the net E&AS offsets used in the calculation of default and unit-specific MSOCs for the 2023/24 BRA, dismissing the issue as moot (EL19-47).

The Monitor had requested waiver of four of the revised pre-auction deadlines pertaining to the offer caps in November. But last month, the commission partially reversed its May 2020 decision, impacting several of PJM’s energy price formation revisions. (See FERC Reverses Itself on PJM Reserve Market Changes.) The ruling led to a delay of the BRA for the 2023/24 delivery year originally scheduled for Jan. 25, nullifying the IMM’s request for the waivers. PJM earlier this month filed with FERC proposing to move the upcoming BRA to the end of June to comply with the commission’s order. (See PJM Reveals Preliminary Capacity Auction Timeline.)

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Smooth Passage Expected for Wash. Green Hydrogen Bill

A bill to expand the provision of green hydrogen by municipal and rural utilities appears headed for easy sailing through the Washington House.

On Friday, Democrats and Republicans on the House Environment and Energy Committee unanimously recommended that the full House pass House Bill 1792, which provides tax credits for “green electrolytic hydrogen” produced, sold or distributed by municipalities and public utility districts.

Green electrolytic hydrogen is hydrogen produced through electrolysis and does not include hydrogen manufactured by steam reforming or by any technologies using fossil fuels.

Rep. Alex Ramel (D) introduced the bill. “I’m really excited about the future in Washington of green hydrogen,” he said at the committee vote.

This is the latest baby step as Washington tries to set up a renewable hydrogen industry to power fuel cell electric vehicles.

In 2019, the legislature passed a law to allow Washington public utility districts to manufacture and distribute hydrogen. This spring, the Douglas County PUD in central Washington hopes to open the state’s first hydrogen production plant, which will use electrolysis to separate hydrogen and oxygen from water pumped from the PUD’s Wells Dam on the Columbia River.

Douglas PUD and the Twin Transit Authority in the Lewis County city of Chehalis are building hydrogen fuel stations for their agency’s vehicles. These would be the first such fueling stations in Washington. 

The bill has a still-undefined 25-year tax exemption that would be created for the electricity that a utility sells to a green electrolytic hydrogen production business, a renewable hydrogen production business, or a business compressing, liquifying, or dispensing green hydrogen or renewable hydrogen. Existing exemptions from the retail sales tax, use tax, and leasehold excise tax that apply to certain aspects of the production of renewable hydrogen would be also expanded to include the production of green hydrogen.

“We are very grateful to Rep. Ramel for the tax incentives,” said Rep. Mary Dye, the committee’s ranking Republican member.