Six years ago, I explained how regulators across the country were allowing electric utilities about 50% more return on equity than their actual cost of capital — amounting to roughly $17 billion in annual excessive costs to consumers. No more EEI cocktail parties for me.
I won’t repeat here the basis for that $17 billion, but if you’re interested, the excruciating detail is in that 2016 piece.[1] By the way, with the big increase in electric utility common equity over the last six years, that $17 billion would now be more like $25 billion today.[2] A mere bagatelle.
This being a subject that is not just dry but bone dry, no one seemed to care one way or the other. The band has just played on.
It’s Even Worse
Now the Energy Institute at Haas has released a working paper by Karl Dunkle Werner and Stephen Jarvis showing that equity returns charged to consumers have remained the same while various measures of capital cost have declined.[3] Severin Borenstein’s excellent blog about the paper is here.[4] A killer chart from the paper is reprinted nearby.
In other words, as bad as the overcharging was when I wrote that piece six years ago, and as much as the overcharging has grown with more utility common equity, it’s even worse than that.
Wait, There’s More
Excess returns not only cause excess charges to consumers but have two other pernicious consequences. When utilities get a return on equity above their cost of equity, they have incentive to fight like cats and dogs to keep and expand their monopoly on rate base assets like transmission. Which they are doing at the state and federal levels — frustrating the competition that is an unalloyed good thing.[5]
And when utilities can get a return on equity above their cost of equity, they have incentive to construct the most expensive solution to address a given reliability violation (or other driver).[6] The Haas study actually found evidence of this: “The paper finds that every extra percentage point of allowed return on equity causes a utility’s capital rate base to expand by an extra 5% on average.”
If allowed equity return is set equal to the cost of equity capital then the utility should be indifferent to whether it or a competitor adds a given increment of transmission, and it would not have incentive to gold-plate the system. Don’t take my word for it; just ask your neighborhood economist.[7]
FERC, historically the most sophisticated utility regulator in the country, seems unaware of all this. Instead of reducing the cost of equity being charged to consumers and reducing pernicious incentives to frustrate competition and inflate rate base, FERC seems intent on increasing the future transmission infrastructure to be monopolized by incumbent transmission owners.[8] No competition from lower cost providers or incentive for lower cost solutions.
In my humble opinion, climate change won’t get fixed by throwing money at monopolies.
[7] Or the Haas authors: “To the extent a utility’s approved ROE is higher than their actual cost of equity, they will have a too-strong incentive to have capital on their books.” https://haas.berkeley.edu/wp-content/uploads/WP329.pdf, page 21.
WASHINGTON — New ways of paying for transmission could increase interregional transfer capacity and improve reliability, speakers told the Energy Bar Association’s Mid-Year Energy Forum last week.
Nicole Luckey, senior vice president of regulatory affairs for Invenergy, said her company hopes to make the case for how interregional merchant HVDC can aid reliability during system emergencies at a FERC staff-led workshop Dec. 5 to 6 on setting minimum requirements for interregional transfer capability (AD23-3).
“Merchant transmission can provide these benefits at a significant cost savings when compared to lines paid entirely on a traditional cost-of-service basis,” she said. “Of course, the majority of the time, a merchant line is going to be providing service to its customers. But if properly incorporated into commercial agreements, that service could be interrupted to provide emergency energy and capacity to keep the lights on.
“Transmission’s value during extreme weather events is being significantly undervalued, and … policy to encourage merchant transmission — which can deliver these benefits to the grid, and potentially avoid complicated cost allocation arguments that I think have really stymied the deployment of transmission in this country — has been completely overlooked,” she said. “Worse, because merchant transmission is treated inconsistently across the country, it creates a disincentive to deploying it interregionally.”
Michael Skelly, founder and CEO of Grid United, which is seeking to build long-distance, interregional transmission, also called for new models for funding transmission, during an EBA panel discussion Oct. 11.
“I think there’s this notion that we’re either going to build a line and it’s going to get cost allocated toward everybody, or it’s not going to get built at all. … But there are other models out there,” he said, citing batteries, which can collect revenue for providing grid services such as frequency regulation but also generate revenues through energy markets.
Skelly also pointed to the U.K.’s proposal to construct transmission to France, under which a developer would receive a “floor” return of 3 to 4% with the ability to earn up to 15% through markets. Profits above the 15% cap would be returned to ratepayers who help finance the project.
Under such a model, “transmission lines start to look a little bit like generators,” he said. “And we’ve actually had pretty good luck mobilizing capital around investment in generation.”
By reducing the guaranteed return to 3 to 4% from 7 to 8%, “your revenue requirements go down like 40%,” he said. “You could save a lot of money if other parties take some of these risks.”
David Kelley, director of seams and tariff services for SPP, noted that the U.S. currently has little more than 2,000 MW of transfer capability among its three interconnections: 1,270 MW from the Western to Eastern Interconnection, and 800 MW between SPP and ERCOT.
“Think about the scale of the demand in this country. And we really only have the ability to share a little over 2,000 MW from the East Coast to the West or vice versa,” Kelley said. “I really think interregional transmission can certainly play a role in helping us introduce more operational flexibility. And HVDC, in particular, I think plays a really key role as we’re talking about transferring between the interconnections.”
The importance of transfer capacity was tragically illustrated during Winter Storm Uri in February 2021, when ERCOT and SPP were forced to shed load, leading to more than 200 deaths in Texas.
“Without a doubt, this was the most challenging operational event in SPP’s history,” said Kelley, who noted it was the first time SPP had to direct load sheds in its history. “That was a very sobering moment for our organization. And I know we fared better than others did. But that was absolutely a wake-up call for us.”
During the height of the storm, SPP was importing as much as 6,000 MW. David Souder, PJM’s executive director of system planning, who also spoke on the panel, said the RTO exported as much as 19,000 MW to its West while importing 3,000 MW from the North.
HVDC’s Impact: Location, Location, Location
Moderator David Schwartz, of Latham & Watkins, asked Kelley how much of a difference HVDC transmission could have made to SPP during Uri.
Kelley said it would depend on the HVDC line’s sink location relative to SPP’s AC transmission.
During the storm “we ran into limitations within the SPP footprint … moving massive amounts of energy in ways that was never planned to be moved within the SPP region before,” he said.
“You may have a 3,000-MW HVDC line that’s perhaps dumping power at a specific location within the footprint. So can you receive it there? And then can you move it to where it needs to go within the region?
“At the time, we were shaking couch cushions trying to find every kilowatt we could find in order to keep the lights on. So would we have loved to have had another 3,000 to 4,000 MW? Absolutely. But it would have to be at the right spot, I think, in order to be effective.”
Dunkelflaute
Kelley said SPP recently increased its planning reserve margin to 15% from 12% because of concerns about the variability of its wind power. Although the RTO has more than 33 GW of nameplate wind capacity — and in March was serving 90% of its load with renewables at times — “we still have periods of time where we have less than a gigawatt of wind capacity generating within our footprint,” he said.
Skelly noted that the Germans have a phrase for the fear of having inadequate sun or wind energy: dunkelflaute, or “a dark lull.”
“This is a real challenge in this energy transition that so many of us are trying to try to figure out,” said Skelly. “One way to do that is to connect the grids, because we have a whole continent to work with here. We don’t have just, you know, a few hundred miles.
Skelly said it’s a bigger problem for SPP than MISO. “MISO is basically oriented East-West,” he said. “As Dale Osborn, a legendary MISO planner always points out, when you have wind fronts move across the country, if you have enough grid, you can integrate those along the way.”
The Easy Part
Kelley said the obstacle to increasing interregional capacity is not technical.
“The engineering part of this is pretty easy. Getting everybody to agree on what the problem is to be solved — and then to how do you pay for that — those are the hard parts,” he said. “You can get a group of engineers in a room to run a study [and] we could probably design a national grid for you in less than a year. And I’m not kidding about that. That’s how easy it is, if everybody agreed on what the national grid was supposed to do, and who was going to pay for it.”
Invenergy’s Luckey said one problem is that RTO voting structures “gives incumbent transmission owners a lot of power.”
Incumbents were unhappy that FERC Order 1000 called for interregional projects to be competitively bid. “I don’t want to sit here and say that’s the only reason these projects haven’t been planned. But it certainly doesn’t help that incumbent TOs know they’re going to have to compete,” she said. “They’d really rather build stuff they know they’re not going to have to compete to build.”
Another problem is how RTOs perceive merchant transmission, such as Invenergy’s proposed Grain Belt Express, an 800-mile, 5-GW HVDC line that would connect four balancing authorities: SPP, MISO, PJM and Associated Electric Cooperative Inc., which serves 51 distribution cooperatives in Missouri, Iowa and Oklahoma.
Invenergy envisions its proposed Grain Belt Express as “the reliability backbone of the Midwest” Designed to deliver wind and solar power from western Kansas to customers in Missouri, Illinois and beyond, it could reverse flows during system emergencies. | Invenergy
The project, which the company envisions as “the reliability backbone of the Midwest,” is designed to deliver wind and solar power from western Kansas to customers in Missouri, Illinois and beyond. “But during system emergencies, if we have contractual agreements in place with our customers, we could reverse flow on that line,” Luckey said.
In MISO, Luckey said, “we’re triggering hundreds of millions of dollars in network upgrades, simply to interconnect our merchant transmission project, which by the way, will provide benefits to that region. So not only are we paying to upgrade the system to move our energy around — to make sure that it’s deliverable. But now we’re providing a benefit to the system, potentially based on the multidirectional ability [of] an HVDC line. But there’s really no way for the grid operator to evaluate what the benefit is to their system right now. They see us as more of a problem that needs to be solved rather than as an asset that can benefit them.
“That’s not necessarily their fault, right? That’s just the way the system is sort of set up for merchant transmission today. And I think it’s something that needs to be changed, because you don’t have that one entity that’s looking at this project and saying, ‘How can this benefit these two regions?’”
WASHINGTON — To be a natural gas, or not to be a natural gas? That was the question at the Energy Bar Association’s debate Wednesday on how hydrogen — the “Swiss Army knife” of decarbonization — should be regulated.
Van Ness Feldman partner Michael Diamond told the EBA’s Mid-Year Energy Forum that hydrogen should be regulated under the Natural Gas Act, along with the fuel it will compete with. Venable counsel Joseph Hicks said it would be better for the nascent industry to be regulated under the “less onerous” Interstate Commerce Act (ICA).
Amanda Mertens Campbell, vice president of government affairs and community outreach for The Williams Companies (NYSE:WMB), said additional federal regulation would be counterproductive now. Campbell said that although hydrogen blended with natural gas is covered by the NGA, all-hydrogen “purity” pipelines are not currently federally regulated.
Williams, the largest operator of natural gas infrastructure in the U.S., has pledged to reduce its greenhouse gas emissions by 56% from 2005 levels by 2030 and reach net zero by 2050. The federal government is betting that hydrogen can decarbonize heavy industry, freight shipping and air travel. (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)
“Nobody’s [net-zero] vision for 2050 can exist without introducing and accommodating a hydrogen economy,” said Campbell.
The Case for the Natural Gas Act
The NGA governs gases that can be used for energy, while the ICA covers oil pipelines, which also transport gasoline, diesel and jet fuel.
Diamond said the NGA regulates natural gas and any blend of natural and artificial gas, which he said FERC has defined as gas “created by the agency of man or the product of some kind of engineering process.”
“Hydrogen fits pretty neatly into this definition,” said Diamond. Currently, most hydrogen is manufactured through steam methane reforming, in which high heat and high pressure is used to strip the hydrogen molecule (H2) from methane (CH4). “That fits very neatly into this idea that it’s artificial. The same really goes for hydrogen created from water through electrolysis: splitting the molecular structure of water and pulling the hydrogen from the oxygen.”
Diamond cited a letter that FERC Chairman Richard Glick wrote to U.S. Sen. Martin Heinrich (D-N.M.) in October saying the commission has the authority under the NGA over hydrogen blending with natural gas in interstate pipelines. Because FERC recently approved the abandonment of the natural gas storage facility to be used for hydrogen, Diamond said, the “only logical conclusion” is that the commission considers hydrogen as artificial gas.
He said FERC could assert jurisdiction over hydrogen as a natural gas under a more expansive reading of the word “natural,” as hydrogen is a naturally occurring element. Sen. Joe Manchin’s (D-W.Va.) legislation to ease permitting of pipelines and electric transmission would have amended the definition of natural gas in the NGA to include hydrogen. (See Manchin Permitting Package Cut from Spending Bill.)
Under either definition, Diamond said, the NGA is the right law for hydrogen. “Hydrogen … competes directly with natural gas. It is going to be a direct substitute for natural gas. … So there’s a lot of good reasons to regulate hydrogen under the same statute that natural gas is,” he said.
Diamond said the industry need not fear FERC’s oversight because the agency has flexibility under the NGA to apply light-handed regulation, as it has done with LNG terminals.
Hicks countered that hydrogen is not an artificial gas. “The courts have looked at this multiple times. They’ve never said that hydrogen is an artificial gas; there’s no precedent to support that. There the test appears to be about where the origin of the gas comes from, rather than its composition,” he said.
Hicks said the ICA is “far less onerous in its requirements” than the NGA, with no certifications of pipelines or affiliate standards of conduct. NGA jurisdiction could also require corporate reorganization or revision of existing long-term contracts, he said.
The ICA would aid in the financing of hydrogen pipelines. “But the ICA is hands-off other than rates and recordkeeping and making sure that it’s treating people equally; that there’s antidiscrimination provisions,” he said.
“If a developer seeks to construct a hydrogen pipeline between two points already served by a methane natural gas pipeline, [and] hydrogen is now natural gas, the FERC has to make some type of determination about whether it’s going to allow two pipelines transporting natural gas to the same destination and has to approve one or the other.”
Hicks acknowledged that the ICA doesn’t provide the eminent domain authority that comes with certification under the NGA. “But I think that’s really a double-edged sword, considering how long it takes for pipelines to be certified. And there are plenty of petroleum products pipelines that have been built and operate in this country without siting authority.”
Campbell agreed. “Eminent domain is not worth what it used to be. And so if we are trying to incent interstate construction of either purity or blended pipelines, we should think about the current situation, which is where you need state permits and there’s no federal regulator. Would that not allow more [pipelines] to be constructed?”
Manchin Permitting Bill
If hydrogen were regulated as natural gas, Hicks said, it should be accompanied by provisions exempting existing hydrogen transportation assets, such as hydrogen-only pipelines in the Gulf Coast and spur lines that deliver hydrogen to refineries.
“My understanding is that Sen. Manchin’s energy adviser wrote an article arguing that hydrogen should be regulated by the NGA,” said Hicks. “I don’t know honestly if it was fully thought out about what the implications of doing this were. My sense was that it wasn’t, because of the possible implications to industry.”
Williams also opposed the provision. “We thought it was premature to add that language to the permitting reform bill, because it did not fully flesh out all of the unintended consequences,” Campbell said.
Short-term Thinking?
Diamond cautioned against what he called “short-term thinking” focused on existing hydrogen pipelines. “Yeah, bringing them under the NGA would impose some uncertainty during the time that FERC works out how it’s going to regulate,” he said. “But we’re talking about the hydrogen industry for the next 50 years. So we’re trying to lay a sustainable groundwork for something that could be a major source of energy, not just an input into oil production in the Gulf.”
Responded Hicks: “I would say if you’re looking for a … statute that has been successfully administered for a long period of time, that would [point] you to the ICA, which has been around since the 1880s.
“It’s a weighing of priorities,” he added. “Do we want this industry to get off the ground very quickly, such that we mitigate climate change issues quickly? Or do you want a situation where it takes time to integrate this industry into the existing regulations?”
Hicks said he could also support a new law for hydrogen “that kind of takes the best of both [ICA and NGA] worlds.”
“But right now, I think that — if the goal is to take the money that has been laid on the table by the government in this recent legislation and run with it as quickly as possible to decarbonize our economy — I think light regulation is better.”
‘View from the Ground’
Campbell offered Williams’ “view from the ground,” saying the company is investing in hubs where it can mostly use existing infrastructure.
“It’s really hard to build pipelines … and so a hydrogen strategy does not exist without repurposing existing infrastructure, because those are critical pathways into population centers,” she said. “The real opportunity in 2022 and the foreseeable future is decarbonizing the gas stream through blending. And that’s clearly under Natural Gas Act regulation and jurisdiction.”
Because hydrogen has one-third of the energy content of methane, “in order to [replace] our methane with hydrogen, we will need three times as much infrastructure,” Campbell said. “So that should be part of the consideration when determining who should regulate.
“We think we have time as this purity economy develops to be thoughtful; to weigh the pros and cons; to think through all of the potential unintended consequences of adding a federal regulator on top of an industry that [now] only needs state permits,” she said. “To add this layer of regulation without first thinking through all the pros and cons … is premature.”
Pennsylvania-based Coaltrain Energy has agreed to pay $4 million in disgorged profits to resolve a FERC investigation into accusations that the company engaged in market manipulation in the course of its up-to-congestion transaction (UTC) trading in 2010.
In its order approving the stipulation and consent agreement issued Oct. 11, FERC said the company “had engaged in market manipulation by placing UTC trades for the sole or primary purpose of collecting marginal loss surplus allocation (MLSA) payments, rather than to profit from price changes.” Under the agreement, Coaltrain neither admits nor denies the alleged violations (IN16-4).
In a 2016 Order to Show Cause, FERC alleged that in 2010, the company shifted from legitimate UTC trading — in which companies aim to predict the changes in spreads between PJM’s real-time and day-ahead markets — to profiting off PJM’s MLSA alone by minimizing the UTC price spreads and collecting refunds of a portion of the transmission loss charges from PJM. (See FERC: Spy Software Provides Evidence of UTC Scam.)
MLSA is designed to account for the loss of electricity as it is transmitted between its source and sink; traders receive rebates proportionate to megawatts delivered. FERC alleged that Coaltrain made trades between nodes in both directions to simply collect the rebates.
The agreement marks the last of three investigations FERC launched over allegedly manipulative UTC trading in PJM. In each case the commission said traders used risk-free strategies designed to maximize line-loss rebates from MLSA, instead of trying to predict price spreads between the RTO’s day-ahead and real-time markets. (See Trader Agrees to Pay $2.7M in Win for FERC and Powhatan Energy to Declare Bankruptcy.)
FERC also accused Coaltrain of providing “false and misleading statements to [FERC Office of] Enforcement staff about the existence of records created by employee monitoring software.”
That charge stems from investigators learning of employee-monitoring software that captured evidence of trading and messaging, which was provided by a former Coaltrain employee. FERC claims that the company concealed information about the software and did not make access readily available; the company had said in its March 2016 response to the show-cause order that it hadn’t occurred to staff that the software contained information relevant to the investigation. (See Traders Deny FERC Charges; Seek Independent Review.)
In addition to Coaltrain itself, the agreement also lists co-owners Peter Jones and Shawn Sheehan and traders Robert Jones, Jeff Miller and Jack Wells as defendants in the case. In the show-cause order, FERC had previously sought more than $42 million in civil penalties from the company and individual defendants.
The fine is to be split into five disgorgement payments to PJM over the same number of years, which the RTO will distribute to its members in a manner to be approved by the commission. Should the provisions be abided by, the agreement will end a 2016 lawsuit FERC filed against Coaltrain in the U.S. District Court for Southern Ohio.
The agreement notes that while FERC’s investigation into Coaltrain will cease, there could be additional sanctions still to come.
“Coaltrain acknowledges and agrees that this may subject it to additional action under the enforcement provisions of the FPA, which in turn may result in additional sanctions separate and apart from the $4,000,000 restitution payment required to be made by Coaltrain pursuant to this agreement.”
Virginia Gov. Glenn Youngkin (R) is doubling down on his efforts to bring the nation’s first commercial small modular nuclear reactor (SMR) to abandoned coalfields of Southwest Virginia, announcing plans on Friday to provide up to $7 million in state funds to help kickstart the project.
Speaking at an abandoned mine site in the southwest corner of the state, Youngkin announced he would be proposing a $10 million Virginia Power Innovation Fund in his next budget, with half the money dedicated to “our moonshot mission to establish the very first small modular reactor right here in Southwest Virginia within the next 10 years.”
Earlier in the day, the governor and U.S. Rep. Morgan Griffith (R-Va.) announced another $10.6 million in grants from the state’s federally funded Abandoned Mine Land Economic Revitalization (AMLER) program, including another $2 million for the Energy DELTA Lab, an innovation testbed, launched Oct. 4.
The test bed is being developed with $975,000 in previously announced AMLER funds and has been in the works for four years, according to the project’s website, which makes no mention of nuclear as part of its plan for future energy development.
Rather, the website outlines two potential projects. One would seek to draw in data centers, which would be cooled with geothermal technology using “the billions of gallons in water collected in underground mines.” The second, called Project Energizer, would develop modular pumped hydro storage that could be paired with solar or wind projects to provide dispatchable baseload power.
Nuclear power currently provides about 29% of Virginia’s electricity. | EIA
But Youngkin has been keenly focused on the idea of bringing nuclear development to the southwestern part of the state since the release of what he called Friday his “all American, all-of-the-above“ energy plan on Oct. 3. The plan sees Virginia as particularly well positioned to lead SMR development, pointing to nuclear engineering programs at Virginia Commonwealth University and Virginia Tech, and companies such as Huntington Ingalls, which maintains nuclear submarines and aircraft carriers at Norfolk Naval Base. (See Gov. Youngkin Releases 2022 Energy Plan.)
“By marshaling the state and federal resources, we will establish a Virginia nuclear innovation hub that will bring together Virginia’s nuclear stakeholders … universities, corporate interests [and] research dollars to develop new and emerging nuclear technologies for deployment right here in the commonwealth,” Youngkin said Friday. “And we will work with our regional allies to go after more than our fair share.”
He envisioned the hub performing “research on advanced material manufacturing and design; methods to improve reactor lifespans and ensure safe operations; on advanced computation and machine learning; on workforce training; and strategies to improve the nuclear fuel cycle and supply chain, including recycling spent nuclear fuel.”
Alireza Haghighat, director of the Nuclear Science and Engineering Laboratory at Virginia Tech, stressed the integral role of nuclear as clean, baseload power. “Nuclear is a must to continue not only affordable, reliable energy [but] also to achieve what we all look for: zero carbon emissions. … You have to be realistic and just follow the science.”
According to figures from the U.S. Energy Information Administration, Virginia’s two nuclear plants, owned by Dominion Energy (NYSE:D), currently provide 29% of the state’s electric power. Hydropower and non-hydro renewables account for 11%, with fossil fuels — predominantly natural gas — providing the other 60%.
One of the Dominion plants, the Surry nuclear plant, won a 20-year license extension from the Nuclear Regulatory Commission in 2021. The commission is reviewing the utility’s application for a similar extension for its North Anna plant.
Surry nuclear power plant | NRC
Under the 2020 Virginia Clean Economy Act (VCEA), Dominion is required to decarbonize its electricity supplies by 2045, increasing clean power 3% per year through 2030 and 4% per year through 2045. Youngkin’s Energy Plan criticizes the VCEA as mandating the retirement of baseload resources and recommends that it be reauthorized every five years.
Local Criticism
While the small audience at Friday’s event responded enthusiastically, Youngkin’s announcement drew quick criticism from local environmental and community groups.
“The announcement comes as a surprise to many key stakeholders in the region,” according to a press release from Appalachian Voices, a community group that has supported the growth of solar in Southwest Virginia. “No local citizen groups were informed about the governor’s visit — nor have any been invited to participate in the planning of the location and development of the new energy infrastructure.”
“Project development processes that leave out community voices [are] the wrong way to build support for a proposal,” said Rebecca Shelton, director of policy and organizing at the Appalachian Citizens’ Law Center, who was quoted in the release. “Time and again, the way residents learn about a new project is through a press announcement. There is every reason to be skeptical about the benefits of a project when it’s planned behind closed doors.”
While Appalachian Voices supports clean energy and the development of new technologies, Adam Wells, the group’s regional director of community and economic development, called for “a new model of energy production that centers equity, justice and communities. So far, it appears that this [nuclear] effort misses that opportunity — all the more alarming given the well documented social and environmental problems associated with nuclear energy.”
Groups like Appalachian Voices and The Nature Conservancy have been pushing forward on bringing solar development to Southwest Virginia and its abandoned mining sites.
Earlier in the week, Appalachian Voices and other members of the region’s Solar Workgroup cut the ribbon on a new rooftop solar installation at Wise Elementary School, one of 12 schools in Wise and Lee counties the workgroup is helping to go solar. Apprentices from a local community college training program worked on the project, according to a press release.
The Nature Conservancy is also developing 120 MW of utility-scale solar on abandoned mine sites in its Cumberland Forest Project, 253,000 acres of preserved forest land in Southwest Virginia and along the Tennessee-Kentucky border.
The Western Power Pool’s future independent board of directors will include the previous CEO of PJM, a former member of the Western Energy Imbalance Market’s Governing Body and the WPP’s present board chair, among others.
The WPP’s current board of directors last week approved the slate of nominees who will serve on the new independent board once the group’s Western Resource Adequacy Program (WRAP) is approved by FERC. The federal regulator requires organizations under its jurisdiction to maintain independent boards.
“This is an important step in the path toward WRAP implementation,” WPP Treasurer Mary Ann Pease said in a press release Friday. “I look forward to the continued development of a sustainable resource adequacy program, with the incredible benefits it will bring to participants, while ensuring we continue to deliver the benefits and cost savings the Western Power Pool has long provided our members and our region.”
According to the release, the board members were selected after a monthslong “continent-wide” search led by WPP’s 14-member Nominating Committee and assisted by an executive search firm.
“The committee’s stated criteria for candidates included electric industry, regulatory, general management, Western electric system or organized market experience; geographic diversity, so no region was overrepresented; diversity of perspectives, including professional background, gender, ethnicity and life experience; and strong collaboration skills,” WPP said.
Among those chosen to sit on the new board is current WPP board Chair Bill Drummond, who has held that position since 2018. Drummond formerly led the Mid-West Electric Consumers Association and previously served as administrator and deputy administrator of the Bonneville Power Administration.
But perhaps the most well known industry figure on the new board is Andy Ott, former CEO of PJM, the largest RTO in the country. Ott was at the helm of PJM when it kicked off an effort to partner with now-defunct reliability coordinator Peak Reliability to create an organized market that would compete with CAISO’s own efforts to expand into other parts of the West. (See Q&A: PJM’s Ott Still Looking West.)
The PJM-Peak Reliability effort dissolved after CAISO moved to undercut Peak’s core business by offering RC services to Western utilities at lower costs. Peak closed its doors at the end of 2019 after nearly losing nearly all of its customers to competing RCs.
Ott retired from PJM in 2019 amid the fallout from a massive default by a trader in the RTO’s financial transmission rights market. (See PJM CEO Andy Ott to Retire.) He is currently director of technical operations at Tapestry, X Development’s “moonshot” for the electric grid.
WPP’s other independent board members include:
Doug Howe, former chair of the WEIM’s Governing Body and past member of New Mexico’s Public Regulation Commission. Howe is currently a consultant for the West Coast Public Utility Commissions’ Joint Action Framework on Climate Change. He previously led the Global Power consulting group for international consultancy IHS CERA and worked for various utilities.
Michelle Bertolino, who served as director of Roseville Electric Utility in California for 12 years before retiring this year. Bertolino previously worked for the Sacramento Municipal Utility District, San Francisco Public Utilities Commission and KPMG Peat Marwick. She has served as president of the Northwest Public Power Association and the California Municipal Utilities Association, and as chair and commissioner of the Balancing Authority of Northern California and the Transmission Agency of Northern California.
Susan Ackerman, who last year retired as chief energy officer of the Eugene Water & Electric Board in Oregon. Before that Ackerman served as an attorney for BPA, an attorney and regulatory manager for NW Natural, and as a commissioner and chair of the Oregon Public Utilities Commission from 2010 to 2016.
Current board members Pease and Secretary Scott Waples will hold non-voting advisory seats on the new board, which will take effect after FERC approves the WRAP tariff and the program receives commitments from a “requisite” number of participants, WPP said.
“The varied backgrounds and expertise the new board members bring are first class,” Waples said. “The Western region, and the customers who rely on a reliable source of electricity, are in very good hands.”
ISO-NE is narrowing down its options as it moves forward with revamping its process for resource capacity accreditation (RCA).
In a presentation to the NEPOOL Markets Committee last week, ISO-NE officials gave an update on their thinking, which included a firmer decision to work on a marginal reliability measure rather than other options, including an average approach.
The marginal approach, which ISO-NE has been leaning toward from the beginning, sets a resource’s accredited capacity based on the “marginal reliability impact [MRI] of an incremental change in size.” (See ISO-NE Starts its Capacity Accreditation Journey.)
In its latest update, the grid operator said that marginal approaches are the only ones that are truly cost-effective.
Because the average approach, which accredits resources based on their share of their class’s total reliability contribution, does not “yield substitutable accredited capacity, there is always a better way to set FCA [Forward Capacity Auction] awards that result in the same level of reliability at lower cost,” the RTO said in its presentation to the committee.
The marginal approach does put forward substitutable accredited capacity, so “there is not a better way to set FCA awards that result in the same level of reliability at lower costs.”
“As a result, the ISO cannot support a non-marginal approach to accreditation and will pursue an MRI approach as part of the RCA reforms,” said RTO economist Steven Otto.
At the MC meeting last week, the group backed that up with new numbers from an analysis that it commissioned from GE Energy Consulting.
“At high penetrations, average and marginal accreditation have vastly different results for clean energy resources,” the analysis says. In its model, renewables plus batteries under marginal accreditation would get capacity awards of about 2,200 MW less in 2028 and 6,400 less in 2040 compared to average accreditation.
“Socializing over half of the total reliability contributions of clean resources could result in a reduced market signal for reliability in clean resource selection and development,” the group said. It urged ISO-NE to thoroughly examine the tradeoffs between the two approaches and not dismiss the possibility of a hybrid between them.
NRDC also called on the grid operator to look at whether a seasonal capacity auction and capacity accreditation might be worth considering in light of the changes in seasonal peak load in New England.
Also at the MC meeting last week, RENEW Northeast gave a presentation laying out its own set of design principles for capacity accreditation and promising to use them to assess ISO-NE’s proposals down the line.
The California Energy Commission updated its load management standards Wednesday in anticipation of residents owning millions of grid-connected electric vehicles and “smart” appliances that can respond to hourly or sub-hourly price signals from utilities and CAISO.
The regulatory update was the latest move by energy authorities in California to shape load to respond to times of abundant solar power or shortfalls during summer peak demand as the state advances toward its 100% clean energy goal by 2045 while struggling to maintain grid reliability.
“This update is a huge leap into the 21st century, using digital approaches to unlock benefits for consumers by enabling them to automate their electricity use around cheaper rates and changing grid conditions,” CEC lead Commissioner Andrew McAllister said in a statement following the unanimous vote. “Automated load management reduces energy bills, makes better use of abundant renewable energy resources available during the day, and strengthens grid reliability.”
CAISO and the California Governor’s Office have increasingly relied on demand response to head off shortfalls during the past three summers following the rolling blackouts of August 2020. Those efforts have targeted large industrial users and asked ships in port, including Navy vessels, to disconnect from shore power during strained grid conditions.
CAISO barely avoided ordering utilities to shed load in September after the governor’s Office of Emergency Services sent out a text alert to 27 million cell phones warning of imminent blackouts. Within five minutes, the unprecedented alert resulted in a 2,100 MW drop in demand compared to CAISO’s hour-ahead forecast.
Like the CEC, the California Public Utilities Commission (CPUC) is also seeking to use dynamic pricing and demand-side management as a way to manage load. In July, it opened a proceeding aimed at shoring up grid reliability and soaking up more solar electricity by using real-time rates to influence customer demand. (See CPUC Opens ‘Critical’ Demand Flexibility Proceeding.)
The state’s current patchwork of demand response programs, which pay customers to reduce consumption, is insufficient, the CPUC said in a June white paper. The report identified strategies for broadening demand-side efforts, including by introducing dynamic energy prices based on real-time wholesale energy costs and localized marginal costs.
The Energy Commission’s decision instructs the state’s largest investor- and publicly owned utilities to develop retail electricity rates that change at least hourly to reflect wholesale electricity costs and other factors, and to regularly update those rates in a CEC database called the Market Informed Demand Automation Server.
The updated standards take effect April 1, 2023, for IOUs Pacific Gas and Electric, Southern California Edison, San Diego Gas & Electric; publicly owned utilities Los Angeles Department of Water and Power and the Sacramento Municipal Utility District; and large community choice aggregators (CCAs) that deliver more than 700 GWh of electricity annually.
The utilities and CCAs must also “educate customers about time-dependent rates and automation technologies to encourage their use,” the CEC said in the statement, which focused on the potential cost-savings to consumers. Affected devices would include smart thermostats, heat pumps, water heaters and EVs connected to the grid.
“Today’s action is expected to produce $243 million in net benefits over 15 years and could reduce annual peak hour electricity use by 120 GWh, equivalent to powering 20,000 average California homes for a year,” it said.
Combined, the IOUs and POUs affected by the new regulations have about 12.75 million electric customer accounts. Adding in the large CCAs, the CEC’s projected $243 million in net benefits amount to less than $1 per year per customer account over the next 15 years.
ATLANTA — Facility ratings, and the challenge of keeping them up to date, were a recurring theme on the second day of the North American Generator Forum’s Annual Compliance Conference, held at NERC’s headquarters, with multiple presentations on the subject from industry stakeholders.
NERC’s FAC-008-5 reliability standard, which governs facility ratings, was a frequent reference during the day’s discussions. Mike Gabriel, a co-founder of consulting firm Greybeard Compliance Services and NAGF board member who focuses on NERC compliance, walked attendees through the preparation process for an audit of the standard, reminding them that being upfront with any potential instances of noncompliance would be a major plus in the eyes of their regional entities.
“You’re trying to find what the auditors are going to find before they do it. You’ve got to beat them to the punch — give them nothing to mess with you about,” Gabriel said.
Acknowledging that performing a full walkdown of existing equipment can be daunting for even a moderately sized utility, much less a large one, Gabriel said that registered entities must nevertheless be prepared to take a critical look at their facilities and challenge all their assumptions.
“Your existing FAC-008 equipment list — you want to have that, and assume it’s not 100% accurate. If you follow what you already have, you’re not bringing any value to the table,” he said. “Do you have these nameplates already photographed or not? Do you have some other proof? Do you have design documents? Or is it just a reading on a one-line diagram somewhere?”
The reason for this level of detail is not because auditors are obtuse or rulebound, but because experience has taught industry participants — not just NERC — that design documents, no matter how detailed, quickly become irrelevant as parts are replaced through regular maintenance and repairs, Gabriel said. Improper facility ratings have become a frequent source of compliance issues across the ERO Enterprise, with penalties of over $200,000 levied against utilities in multiple regions over the last two years. (See SERC Urges Industry Effort on Facility Ratings.)
Gabriel added that entities should also be prepared to bring in outsiders to get a fresh perspective, warning that even the most conscientious internal review is vulnerable to overlooking crucial details of facilities with which they have spent years.
“Think about how the human mind works. When you drove to the airport to get here … how observant were you [of] all the details along the way, or were you on the phone listening to some music?” he said. “When you walk past your plant, it takes a lot of concentration to … really scrutinize [everything]. [If you have] that second set of eyes that you trust and you gave them free will to say anything … now you’re getting something.”
Along with Gabriel’s audit presentation, Tim Ponseti, SERC Reliability’s vice president of operations, updated attendees on the Facility Ratings Themes and Lessons Learned report that the RE released earlier this year. SERC used data from hundreds of FAC-008 violations since 2017 to identify three major themes associated with facility ratings problems, along with potential mitigation strategies for each issue.
Ponseti said that after the report’s publication in April, SERC offered it to NERC to serve as the basis for an ERO-wide analysis of facility ratings issues, to which the organization readily agreed. That broader report — which Ponseti said had “found a fourth theme that we missed” — is scheduled to be published next week.
The hydrogen revolution energizing green hydrogen advocates and producers in the wake of the Biden administration’s renewables push won’t happen until key players from the fossil fuel and financial sectors buy into the transition, according to a key government official charged with helping to make it happen.
Jigar Shah, a former green entrepreneur and now director of U.S. Department of Energy’s loan program office, offered the prediction Tuesday during a focused conversation at the two-day Hydrogen Americas Summit in Washington, hosted by the DOE and the Sustainable Energy Council, a global business organization. More than 600 attended.
Shah said U.S. heavy industry, including oil refineries, now uses about 10 million tons of hydrogen annually. Nearly all of it is made from methane, a process that produces carbon dioxide. Convincing the refineries to switch to buying green hydrogen would be a promising first step for the cleaner fuel, Shah said.
“The president has been very clear that we need to decarbonize the electricity sector by 2035. And the economy by 2050,” Shah said. “I don’t see a single refinery actually signing a long-term offtake agreement — not one. No one is suggesting that the refineries are going to go out of business next week. I mean, you’re talking about a hybrid system we’re going to live in for a very long time.”
Shah said he hoped the event — and others like it — will spur recognition of the need for long-term “anchor” customers for green hydrogen.
“And they’re not concerned about the volatility of the price of natural gas and hydrogen … because they’ve already picked hydrogen. Hydrogen is already being used [at the rate of] 10 million tons a year in the United States,” he said.
But he said refineries are not signing long-term offtake agreements with upstart green hydrogen producers, in part because the oil industry has been unprofitable in recent years and the long-term financial future of oil refining looks uncertain. Moreover, green hydrogen companies could look risky.
That is a real problem for green hydrogen producers that need solidly committed customers to finance expansion, he explained. They have trouble attracting both private equity investment as well as traditional formal financing because established industries are not ready to buy from them.
Shannon Angielski, a principal with Van Ness Feldman LLP, moderated the panel discussion. She suggested that the difficulty in jumpstarting U.S. green hydrogen production may also be the result of a supply chain problem.
“We’re talking about a big market here, and starting either small or going big, even with the regional hubs, there is a lot of equipment, components and other things that are really needed for that market. There are not a lot of manufacturers today, or they’re very limited and that could limit some of these supplies,” Angielski said.
“How do you look at that from a financing perspective, equity [financing] or otherwise? How do we accelerate that or send that . . . market signal?” she asked panel members.
Shah suggested that building a recognized parts supply system is not as big a problem as the green hydrogen industry itself.
He said the burgeoning industry keeps creating new business models for the use of hydrogen.
“That confuses the crap out of the finance sector because the [models] are all different. The use cases are completely different. They are not actually related to each other,” Shah said.
“Finance people think in terms of risk,” he explained. Their questions will include: “What do the standardized contracts look like? What [responsibility] does each party take on? Do I get protected if the electrolyzer manufacturer gives me a 10-year warranty? …
“Do I get protected … if the leak rates are much higher than expected, and the project is worse than what it was replacing? Is there moral harm? And if the project gets shut down and I don’t get paid back? …
“The last piece of it [investor concerns] are residual value and recovery rates,” he said. “What if the team ends up being completely incompetent, and the project itself is good, but the team can’t operate it. Is there a way to bring in a new team to actually realize that vision?”
New Finance Models Needed
The DOE’s efforts to bring more certainty to the situation include $9.5 billion in funding for governments and industries that can create the concentrated production of hydrogen and its use in a relatively small region. The agency is accepting concept proposals for these hydrogen “hubs” until Nov. 7 and is seeking full applications by April 7, 2023.
Early conversations have been disturbing, Shah revealed. “We do think that [green hydrogen producers] should strive to get offtake agreements, but I do also think that some of what we’re seeing seems slightly fanciful. There are a lot of people getting European offtake agreements with almost nothing happening in the United States,” he said.
Nicole Faucher, CEO of BEAM Group, a large private equity fund focusing on carbon-negative investments, said the problems that green hydrogen companies face “boils down” to outdated financing models.
“We can’t reinvent the future energy of how we’re going to power a better planet using yesterday’s financing models,” she said.
Faucher said current financing models will not work because the expansion of green hydrogen production requires a 20- to 40-year outlook.
“The current market is really set up in terms of venture capital hedge funds for a much shorter timeframe. We need long-term, patient, strategic capital to really move the needle on the clean hydrogen economy,” she said.
Private equity is set up to typically offer 10 years of financing, with possibly two one-year extensions on top of that. “So, you’ve got 12 years of runway there, not really enough time,” Faucher said.
Some private equity groups are now using another investment tool called “continuation funds,” an arrangement in which a second fund buys the debt from the original investor after the first 10 or 12 years.
“One of our anchors is very excited about doing a continuation fund. At that point, you’ve got 20 years. That’s what you need to move the needle on the clean hydrogen economy,” she said.
Steve Huntoon | Steve Huntoon
