CHARLOTTE, N.C. — Renewable power advocates said last week they remain troubled by the concessions legislators made to utilities in return for the carbon-reduction goals of House Bill 951, saying the law fails to protect low-income residents, undermines competition and excludes renewable technologies other than solar.
The law, enacted in October, directs the North Carolina Utilities Commission to take the “least cost path” to cut electric-sector carbon emissions by 70% from 2005 levels by 2030 and reach carbon neutrality by 2050. The law also requires the state’s utilities — including Duke Energy Progress, Duke Energy Carolinas (NYSE:DUK) and Dominion North Carolina Power (NYSE:D) — to add 2,660 MW of new solar generation, 45% through power purchase agreements and the remainder utility-owned. Utilities will be limited to securitizing only 50% of the remaining book value of coal generators retired early. But it also ensures any other new generation will be utility-owned and subject to cost-of-service rates. (See New Era for Grid Planning in North Carolina?)
The 11-page bill that emerged from the North Carolina Senate was less prescriptive than the initial 50-page House bill, leaving much of the policy decisions to the NCUC.
“But from my perspective, what happened is it got much more prescriptive about the renewable resources that have the opportunity to compete in a marketplace,” Adam Will Foodman, CEO of Solar Operations Solutions and chair of the Carolinas Clean Energy Business Association (CCEBA), said during a panel discussion last week at Infocast’s Southeast Renewable Energy conference. Aside from the 2,660-MW carve out for solar and solar plus storage, “everything else is considered regulatory assets of the utility,” he said.
“Innovation, competition, is the lifeblood of an economy,” he said. “And absent those items, I think it’s difficult to see us charting the most efficient path to an energy transition. … We want a broader opportunity for technologies to compete in the transition that is going to take place with the retirement of coal. There are some opportunities there opened up in the bill. I think it remains to be seen how they will be implemented by the utility commission.”
Consultant Diane Cherry, whose clients include renewable energy developers, the Sierra Club and Carolina Utility Customers Association, a group of manufacturers and other large consumers, said she was disappointed that the law lacked a carve out for stand-alone storage. She also expressed concern that the design of customer programs will be subject to commission rules, making the upcoming dockets — as many as seven of them may be needed to implement the law — a “full employment” guarantee for regulatory attorneys.
Stephen Kalland, executive director of the North Carolina Clean Energy Technology Center at North Carolina State University, said he was disappointed that the final bill did not address distributed generation, community solar, net metering or rooftop solar. But he said the compromises could not obscure the historic nature of the bill’s carbon-reduction goals.
“To see legislated carbon goals … in a bill sponsored by Republicans in both chambers and signed by Democratic governor [is] pretty much unprecedented nationally. I think it was something that was somewhat breathtaking as an example of what states could actually do if they really wanted to drive the train forward in the clean energy space.”
Kalland said the current commission is knowledgeable about the technical issues the law presents. “And so if I had to pick between the legislature writing detailed rules for the energy market, and that utility commission writing those rules, I think it was actually a pretty good outcome,” he said.
“In the decade that I’ve been advocating for clean energy, mostly in front of conservative audiences, we have built the case that clean energy is an economically competitive technology. … And I think having [the perception that] the carbon standard be the driver … for these new clean energy technologies in North Carolina, it kind of takes us back a little bit on advocacy perspective. It’s, ‘Democrats got a carbon standard and, Republicans got things that were good for the vertically integrated monopoly.’ … I think you all know it’s not that simple. But as someone who has to constantly advocate in front of people who don’t look at energy every day of their lives, and they get a sound bite here and there, I’m a little bit concerned.”
“There’s gonna be a lot of work to do at the commission,” she said. “… No doors have truly been closed. We’re just kind of moving the venue.”
Ivan Urlaub, chief of strategy and innovation for the NCSEA, said the NCUC will need to be innovative to overcome the Achilles’ heel of the law: the utility ownership provision.
“The evidence has shown that the utility is not least-cost; it’s just not,” he told the audience. “Your businesses are. … And when your businesses and the customer work together, that’s where we most often see the least-cost options.
“The law is basically inviting the regulator to come up with one integrated solution and innovate in how they do planning,” he continued. “The ball’s in the commission’s court. Are they going to pick it up and play a good hard game with it, and, and really be aggressive [or] are we going to get some status quo?”
Urlaub urged those participating in the upcoming dockets to be suspicious of short-term wins in settlement discussions.
In short term deals, “the carrot … gets dangled to slam the door on the next 12 carrots,” he said.
The California Air Resources Board on Friday approved a $1.5 billion clean transportation funding plan that includes $515 million for the Clean Vehicle Rebate Project, the state’s popular electric car incentive program.
The plan also includes $10 million for a new electric bike incentive program and $75 million for Clean Cars 4 All, a program that offers lower-income residents incentives to scrap their old cars and replace them with zero- or near-zero emission vehicles. The program is available in five of the state’s 35 air districts, but an expansion is planned.
On the heavy-duty side, the funding package contains $570 million for the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP). Within that amount, $70 million is set aside for zero-emission transit buses; $130 million for zero-emission school buses; and $75 million for zero-emission drayage trucks.
The spending plan allocates $195 million to the Clean Off-Road Equipment Voucher Incentive Project (CORE), which provides incentives for equipment such as zero-emission tractors and forklifts.
CARB staff said funding for the CORE program had been increased and that the range of eligible equipment was expanded. The program sets aside $30 million in incentives for small business and sole-proprietor landscaping companies.
Record-setting Funding
The CARB board on Friday approved a resolution adopting the fiscal year 2021/22 funding plan. The agency described the funding package as its largest for clean transportation, more than twice the amount of the previous largest investment.
“This unprecedented mix of incentives and funding will continue to support our equitable transition to zero-emission cars and accelerate the commercialization of zero-emission technologies for medium and heavy-duty trucks and buses,” CARB Chairwoman Liane Randolph said in a release.
The state general fund will contribute $838 million of the funding, and $595 million will come from the state’s cap-and-trade program. The Air Pollution Control Fund and the Air Quality Improvement Program account for the remainder.
Other pieces of the plan include $45 million for replacing diesel trucks with trucks that meet a low-nitrogen oxide standard through the state’s Carl Moyer program. There’s also $180 million in incentives for alternatives to agricultural burning in the San Joaquin Valley.
CVRP Changes
CARB announced in April that funding was rapidly running out for its Clean Vehicle Rebate Project (CVRP), as electric-vehicle purchases rebounded more quickly than expected during the COVID-19 pandemic. (See Shortfall Looms for Calif. EV Rebate Program.)
According to CARB, almost 65% of EV owners in the state have received a rebate through CVRP, a program that was launched in 2010 and had issued more than $926 million in rebates as of April.
The $515 million approved on Friday for CVRP is intended to last for three years, CARB staff said. During that time, CARB plans to “ramp down” the program and shift the focus to lower-income car buyers.
A first phase of changes will be implemented after 1 million EVs are sold in California, but not sooner than February 2022. At that point, CARB has proposed lowering the income cap for standard rebates and reducing the cap on manufacturer’s suggested retail price for smaller vehicles.
When EV sales in the state hit 1.25 million, but not sooner than February 2023, the income cap for standard rebates will be further lowered, rebate amounts will be reduced and plug-in hybrids will be dropped from the program.
Some members of the public who commented during Friday’s board meeting objected to the proposed changes to CVRP.
Anthony Bento, director of legal and regulatory affairs at the California New Car Dealers Association, said the incentive program is valuable but is “undermined by its complexity, particularly with respect to eligibility.”
Bento said the group is concerned that the proposed changes would make matters worse.
“In particular, that two-phase reduction in income caps and vehicle eligibility creates needless confusion,” he said.
Eileen Tutt, executive director of the California Electric Transportation Coalition, said in a letter to the CARB board that reducing the CVRP income cap “serves only to confuse and frustrate both middle-class consumers and auto dealers and reduce the market for EVs.”
Tutt described the proposed changes in income caps as arbitrary.
“The phases are proposed even though there is no data indicating these phases are related to consumer response or market viability of EVs,” she said.
CARB board member Daniel Sperling also urged the agency to be cautious in making changes to CVRP. He disagreed with the idea of dropping plug-in hybrids from the program as part of the second phase of changes.
While many people can switch to battery-electric vehicles without much trouble, especially if they own multiple cars, the change may be more difficult for others such as apartment dwellers, said Sperling, who is founding director of the Institute of Transportation Studies at the University of California, Davis.
In addition, Sperling called for using some of the money in the spending package to assess the effectiveness of programs being funded.
“Making sure we’re investing our money wisely and especially looking to the future,” Sperling said. “It can be built into every program, and I think we need to be thinking along those lines more.”
A panel of conservative electricity market experts on Tuesday argued that markets work better than public policy at encouraging and developing clean energy resources.
“Private capital is foaming at the mouth to get in these markets, and the obstacle is outmoded regulation,” Devin Hartman, director of energy and environmental policy at conservative think tank R Street Institute, said at a webinar hosted by ConservAmerica, a conservative environmental advocacy group. Formerly known as Republicans for Environmental Protection, the group argues that “the most efficient way” of developing clean energy resources “is through policies that encourage competitive markets, private investment and expanded trade.”
The private sector wants to invest in building the infrastructure needed for a clean energy future, said Hartman, former CEO of the Electricity Consumers Resource Council (ELCON). He called for re-evaluating the regulatory structure.
Hartman was joined by current ELCON CEO Travis Fisher.
“A different way to view it is the difference between a state-level mandate versus a corporate goal,” said Fisher, previously economic adviser to former FERC Commissioner Bernard McNamee. A corporate goal can be dropped if things go poorly, there are reliability issues or the cost is too high, he said.
“It doesn’t take an act of state or Congress to drop that,” Fisher said. “The more rigid and the more top-down mandated it is, that’s where you get into problems. [Policy questions] can be borne out through voluntary transactions … instead of saying, ‘We know the answer has to be X, and we have to do it by year Y.’ I don’t think that’s the correct way to go about it.”
The discussion was framed the around a new report by the Energy Choice Coalition (ECC) on the environmental benefits of competition in electricity markets, which found that RTO/ISO regions have reduced their power sector CO2 emissions by about 35% from 2005 levels, while non-RTO regions have reduced theirs by about 27%.
Furthermore, the report found that RTO regions with more competitively owned generation, such as ISO-NE, NYISO and PJM, posted even deeper reductions: 61%, 56% and 41%, respectively, said Joshua Rhodes, research associate at the University of Texas at Austin and a founding partner of energy consultancy IdeaSmiths, which conducted the study.
Clockwise from top left: Robert Dillon, Energy Choice Coalition; Landon Stevens, Conservative Energy Network; Joshua Rhodes, University of Texas Austin; Travis Fisher, ELCON; and Devin Hartman, R Street Institute | ConservAmerica
The study also found that RTO/ISO regions deployed almost 80% of all utility-scale renewable generation capacity, despite accounting for 67% of all existing power plant capacity. In addition, RTO/ISO regions have seen stronger growth in distributed solar PV, increasing by about 214% versus non-ISO regions at 199%.
“You’re never going to get a pure market in this area because there are a lot of different drivers,” said Robert Dillon, executive director of the ECC and a member of the leadership team at ConservAmerica.
The environmental and regulatory aspects of the wholesale level also apply to retail, whether for the large corporations like Google and Microsoft wanting a certain supply of clean energy, or private homeowners that want to install storage or solar, Dillon said.
“Their ability to choose is a market driver; [it’s] a great principle compared to government saying, ‘You’re going to build this traditional huge coal or gas or nuclear plant on the edge of town and running wires through the city,’” Dillon said.
The discussion of the clean energy transition tends to get stuck in a dichotomy of either the Texas model on one hand or vertically integrated markets on the other, said Landon Stevens, director of policy at Conservative Energy Network (CEN), a group of state-based clean energy advocacy organizations.
“There’s actually a lot of different policy decisions that can be made along the way,” said Stevens, who described himself as a “recovering regulator.” He previously served as policy adviser to former Arizona Corporation Commissioner Andy Tobin and his successor, current Commissioner Lea Marquez Peterson.
It’s a big opportunity when about half of the country is trying to consider what the next market designs look like, he said, referring to the West.
The West is considering “an RTO model that we designed in 1995, and I would say there’s probably a lot of changes you can make to that model that would be more tailored to today’s solutions,” Stevens said. “We need to look at those really long and hard, and that’s where we have a lot of research coming down the pipe. … What does an RTO 2.0 look like, or is there a whole new model paradigm that we need to consider to incorporate some of these new technologies and leave room for that innovation?”
California Gov. Gavin Newsom on Monday named his senior energy adviser, Alice Reynolds, as the next president of the California Public Utilities Commission, a body under intense pressure to ensure resource adequacy, prevent utilities from igniting wildfires and shepherd the state through its transition to 100% clean energy by 2045.
“As my lead energy policy expert, Alice has been indispensable in our work to move California toward a cleaner, affordable and reliable energy future, navigate the bankruptcy of the state’s largest investor-owned utility [Pacific Gas and Electric] and accelerate the state’s progress toward meeting our clean energy goals, among other critical issues,” Newsom said in a statement. “I look forward to her leadership as President of the California Public Utilities Commission.”
Reynolds will replace outgoing President Marybel Batjer on Dec. 31. Batjer announced in September that she planned to step down at the end of the year with five years left in her seven-year term. (See California PUC President to Step Down.)
“I have had the privilege of serving four California governors and have given my all to public service for many decades,” Batjer wrote in a letter to CPUC staff. “I am now ready for a new challenge and adventure.”
Newsom had named Batjer, then the state’s government operations secretary, to fill out the term of retiring President Michael Picker in July 2019. He reappointed her to a full term last year.
Under Batjer’s leadership, the CPUC oversaw PG&E’s Chapter 11 reorganization and obtained greater oversight of the troubled utility, which has been blamed for starting catastrophic wildfires since 2015. The commission worked to prevent more wildfires through vegetation management and grid-hardening and to rein in the overuse of public safety power shutoffs.
The CPUC came under fire for failing to anticipate the capacity shortfalls that have plagued the state in the past two years and are expected to continue next summer. Commissioners responded by ordering record amounts of procurement, including requiring the state’s three big investor-owned utilities — PG&E, Southern California Edison and San Diego Gas and Electric — to find 11.5 GW of new resources by mid-decade. (See CPUC Orders Additional 11.5 GW but No Gas.)
As adviser to Newsom since early 2019, Reynolds was instrumental in PG&E’s reorganization and in enacting a controversial measure, Assembly Bill 1054, that sought to shore up the IOUs against wildfire liability through a state insurance fund. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
Reynolds was former Gov. Jerry Brown’s senior adviser for climate, the environment and energy from 2017 to 2019 and served as deputy secretary for law enforcement and general counsel at the California Environmental Protection Agency (CalEPA) from 2011 to 2017.
A lawyer by training, she worked for two law firms from 1998 to 2001 and as a state prosecutor before taking the job with CalEPA.
Industry and environmental groups congratulated Reynolds or offered praise on her appointment after Newsom’s announcement.
“We have worked with Alice Reynolds during her years of service with Governors Brown and Newsom and believe that she is superbly qualified to lead the California PUC at a critical time,” Victoria Rome, director of California government affairs for the Natural Resources Defense Council said in a statement. “She has unmatched expertise on California energy issues. Over the next few years, the PUC will help ensure that California’s clean energy transition is built on a foundation of reliable electric service and equity.”
Others noted the difficult job ahead.
“California has a lot of work to do to make its energy more reliable, affordable, and cleaner, and we look forward to working with the CPUC to make that happen,” Advanced Energy Economy tweeted.
The state Senate must confirm Reynolds’ appointment as CPUC president, a position that pays $229,000 per year.
A special inspection team sent by the Nuclear Regulatory Commission to the Davis-Besse nuclear power plant in Ohio on July 27 has issued five safety findings that it discovered during an examination of the plant’s steam system following an automatic reactor shutdown July 8.
NRC on Friday issued a 69-page report in which inspectors called the shutdown “complicated” because of the failures of a steam system and electromechanical steam line controls.
The problems started when the plant’s main steam turbine tripped off, causing the reactor to shut down without incident. But engineers had to manually shut valves to fix steam system problems after the electromechanical controls failed to work, according to the report.
The six-member inspection team concluded that Davis-Besse engineers had installed the wrong part in a switch controlling the steam valve system and that overall the plant had inadequate “procedural guidance” for control room operators in such a situation.
The commission is still determining the safety significance of two of the five findings, involving the failure of the plant’s emergency diesel generators (EDGs) five times over 24 months preceding the July shutdown. The failures occurred during routine testing to make sure the EDGs would instantly start and instantly generate electricity.
The inspection team reviewed the efforts by Davis-Besse’s engineers to find the cause of the failures of the large EDGs during routine testing. The inspectors determined that there had been inadequate maintenance in one case and the use of an updated but inappropriate electronic part in another case. The correct, updated parts have been installed since the failures.
NRC is now doing a complicated risk assessment of the failures of the EDGs to start as designed, as failure during an actual emergency involving the reactor could lead to catastrophic consequences.
EDGs must be able to automatically start and immediately generate power when a reactor shuts down and the plant is simultaneously cut off from grid power, making their operability critical during an emergency.
A nuclear power plant requires about 4 MW to run all its operating, safety and control systems. If the generators are inoperable during an emergency, a battery backup system powers certain emergency equipment for a limited number of hours.
Davis-Besse is owned by Energy Harbor, the successor to FirstEnergy Solutions. Davis-Besse is owned by Energy Harbor, the successor to FirstEnergy Solutions. Energy Harbor did not respond to a request for comment.
Municipal utility Seattle City Light wants the same legislative green light to manufacture hydrogen for fuel that Washington’s rural public utility districts (PUDs) have received.
In 2019, Washington’s legislature passed a law that allows the state’s PUDs to produce and distribute hydrogen. The state’s municipal utilities do not have that legal authorization.
“We would like municipal hydrogen authorization,” Mendy Droke, government and legislative affairs advisor for Seattle City Light, said Thursday at a briefing of the Washington House Environment and Energy Committee.
While committee members did not say whether they would tackle such a bill in their 2022 session, Droke’s statement addressed a question from Rep. Alex Ramel (D) about whether municipal utilities should have that authorization. Ramel is active in climate change legislation in Olympia.
Washington has no infrastructure to support fuel cell vehicles (FCEVs) powered by hydrogen.
But the Douglas County PUD plans to start operating a hydrogen manufacturing plant in the first quarter of 2022 along the eastern shore of the Columbia River in central Washington. The $25 million facility is expected to produce two tons of hydrogen per day with plans to expand when more output is needed. (See Wash. PUD Breaks Ground on Hydrogen Plant.)
“We want to make Douglas County a hotbed of hydrogen production,” PUD General Manager Gary Ivory said.
Two hydrogen refueling stations are on the drawing board in Douglas County and in Chehalis, which is south of Olympia. Both are slated to begin operating sometime in 2022. The first hydrogen-fueled vehicles in Washington will be a handful of buses to be operated by Twin Transit in Lewis County — which contains Chehalis — plus a few Douglas County PUD trucks.
By contrast, California has roughly 11,000 hydrogen-fueled vehicles and about 50 refueling stations, Jason Sekhon a senior consultant with Toyota North America, told the committee.
Sekhon said that Washington faces several challenges in bringing hydrogen-fueled vehicles to the state, including the current lack of local hydrogen production.
Sekhon said the state needs to build a hydrogen-refueling network prior to boosting the sales of the vehicles. Government agencies need to coordinate their refueling facilities so all agencies can use them. He added that tax exemptions should be set up for the earliest purchasers of hydrogen-fueled vehicles.
He said co-locating hydrogen refueling stations with gas stations is an easy path to take. A hydrogen-refueling station in California capable of handling 1,400 vehicles a day costs about $3 million to develop, roughly the same cost as an electric-vehicle charging center cable of handling the same volume of vehicles, he said. However, hydrogen refueling takes three to five minutes compared to up to 30 minutes for an electric recharging.
Seattle City Light and Tacoma Power plan to study getting into hydrogen vehicles and possibly production, said officials from those utilities.
CHARLOTTE, N.C. — About 300 representatives from independent power producers, utilities, law firms and regulatory agencies met at Infocast’s sixth annual Southeast Renewable Energy conference last week to discuss the region’s progress in integrating solar power.
Michael B. Woodard, a partner with McGuireWoods, introduced a panel of regulators by showing a chart of states’ growing solar capacity since 2016, with Florida now in the top spot, having supplanted North Carolina. The Sunshine State trails only California and Texas nationally as of the second quarter of 2021, according to the Solar Energy Industries Association.
Other states in the Southeast, however, are playing catch-up, speakers said. Here’s some of what we heard.
State Regulators Panel
Arkansas regulator Ted Thomas joined Georgia’s Lauren “Bubba” McDonald and Mississippi’s Brandon Presley (participating virtually) in a panel on issues facing their states.
Thomas, chairman of the Arkansas Public Service Commission, said state regulators must be flexible to respond to the pendulum swings of federal clean energy policy. “We don’t know what’s going to happen. What happens might, in fact, change in four years,” he said. “What we’re trying to do is be prepared regardless of which of the scenarios happen.”
Thomas said regulators look to entrepreneurs to help them judge emerging technologies. “We don’t know what the customer wants. We don’t know what the feds are going to tell [us we] have to have,” he said. “But entrepreneurs test demand.”
McDonald, re-elected to the Georgia Public Service Commission last year, defended his support of the delayed and overbudget Vogtle Units 3 and 4, which he proudly noted are the first new nuclear plants built in the U.S. in more than three decades. The cost of the project has nearly doubled from early estimates of $14 billion to about $27 billion.
Southeast solar capacity by state (MW) as of Q2 2021 | Solar Energy Industries Association
“It hasn’t been easy, [but] I’ve committed to it,” he said. “Nuclear is the best friend that solar energy has, because [it] runs 24/7 [at] 99.8% [capacity factor]. And it’s cheap, and it’s clean.”
McDonald acknowledged Vogtle’s cost overruns and delays. “My personal preference as a regulator is the least regulation is the best regulation. But we do have to intervene sometimes when a project gets out of hand. We’ll have to spank somebody a little bit and straighten it back up.”
Presley, a Mississippi Public Service Commissioner, acknowledged his state has trailed in renewable energy development but said the PSC will be issuing “forward-looking” rulemakings soon on net metering rules and community solar in a bid to attract new generation.
“Money, it completely votes with its feet. … The Fortune 100 [companies], the Fortune 50s — in any economic development project — one of the biggest questions on the map is whether or not you have a renewable source of power,” he said. “We know that [other] states are ahead of us on [that], and we’re working like the dickens to catch up.”
He said the PSC is to blame. “For a long time, they did pretty much what Mississippi Power and Entergy and others wanted done, and that has really led over time to things like the Kemper County power plant,” he said. Initially estimated at $2.4 billion, the cost of the carbon capture and sequestration plant more than tripled to $7.5 billion before the project was canceled.
“Imagine if we had invested those dollars at that time in renewable energy research, renewable energy projects, where we would be on the rankings today,” Presley said. “If the South is going … to pull forward out of the economic morass that we find ourselves in … we’ve got to attract this development.”
Presley said the state’s utilities should take full advantage of federal infrastructure funding for upgrading transmission and hardening assets. “There’s going to be some dollars in this infrastructure bill that can go to offset that. The utilities are going to have to be aggressive. I really don’t want to hear them come in before me and tell me about how laborsome and awful it is to go through and apply for this federal money,” he said. “We’ve got to get this work done. And God forbid that we look back 10 years from now, 15 years from now, and we sat on our hands and did not take advantage of what’s on the table today.”
Build Back Better Impact
Democrats’ Build Back Better act, approved by the U.S. House of Representatives and pending before the Senate, was also a subject of discussion.
Akin Gump partner Shariff Barakat said the law’s direct pay provisions won’t eliminate the need for tax equity investors because of the volume of extended and expanded tax credits and “timing issues,” including the inability to offset estimated tax payments. He also said depreciation may be more valuable with a tax equity investor and that projects beginning construction after 2023 will need to satisfy domestic content requirements to use direct pay without penalties.
Solar Panels Increase Resilience in Hurricanes?
PosiGen Solar, which develops rooftop solar for low- and moderate-income residents, has 12,000 systems in Louisiana, many of them along Interstate 55 — coincidentally the path that Hurricane Ida took in August. More than 3,000 houses suffered storm damage, but less than 50 systems had to be replaced, CEO Thomas Neyhart said.
“The solar systems reinforced the roof; the solar systems help harden it,” he said, displaying an aerial photo showing blue tarps over damaged roofs beside undamaged roofs with solar.
“We’re having a study done right now by [Louisiana State University] on how to harden roofs, not just by putting solar on but then also using the right types of shingles and the right types of construction to allow them to sustain direct winds of 130 to 150 mph. We think there’s a great future in our ability to help harden roofs in some of these hardest hit areas,” he added. “More importantly, though, as you think about the future, we start to think about batteries. … We’re working right now with the governor’s office and the incoming [City] Council members to try and put together a battery program for the hardest hit people in Louisiana, which is down in New Orleans.”
Hydrogen emerged as one possible solution to climate change during the recent 26th U.N. Climate Change Conference of the Parties, but details of the transition to the fuel were sketchy, leaving the door open to competing solutions.
What was clear even before the historic conference is that hydrogen research has been underway for some time and that moving away from energy-dense oil, coal and natural gas would be as consequential as the switch from burning wood to coal at the start of the industrial revolution.
The Center for Strategic and International Studies (CSIS), a non-partisan think tank founded to address national security issues, has been focusing on what that transition might look like, including the underlying economy necessary to support such a change.
CSIS has hosted a series of energy webinars on the topic, the most recent of which examined the “building blocks for a hydrogen economy.” The discussion was sponsored by Japan House of Los Angeles.
Moderated by Jane Nakano, a CSIS senior fellow heading the security and climate change program, the Nov. 16 discussion focused on:
efforts in California to expand the current fleet of 100 fuel cell buses and more than 10,000 fuel cell cars and light trucks already on the roads and expand the network of hydrogen fueling stations;
plans to begin switching a small number of the nearly 3,000 diesel and gasoline trucks and unloading equipment at two major California ports to either fuel cells using hydrogen or batteries charged on the local distribution grid;
efforts in Japan to burn anhydrous ammonia (NH3) with coal at power plants and ultimately modify gas turbine power plants to operate with hydrogen — and importing all that hydrogen or ammonia through a global supply chain still under development.
Fueling the FCEV Fleet
Bill Elrick, executive director of the California Fuel Cell Partnership, said fuel cell electric passenger cars and light trucks would provide the foundation for building a hydrogen refueling system for heavy trucking.
His organization launched a retail-oriented hydrogen market about six years ago, opening hydrogen refueling stations, typically at gas stations already in business. The point was to convince potential owners of fuel cell electric vehicles (FCEVs) that they would have a steady supply of hydrogen. Now they want to expand the system in order to increase the light-duty FCEV fleet.
“By achieving that light-duty market, we see it lowering the cost not just for that market, but [lowering] hydrogen infrastructure and fuel cell technology costs for other applications and even other regions,” he said.
Whether EVs are powered by batteries or fuel cells is not as important as what fuels them, he added. Both hydrogen and electricity stored in batteries are 100% carbon-free.
Toru Sugiura is a senior manager at Toyota Tsusho America, a Kentucky-based subsidiary of Toyota Tsusho, a global trading company dealing in metals, automotive parts, chemicals, food and fuels. He said his company has been working to develop the kind of hydrogen supply chain that Elrick described.
“We operate hydrogen stations in Japan,” Sogiura said. “That is currently a challenging business model for economic viability by simply waiting for customers to come.”
In California, the company is about to begin a demonstration project, supported by several federal grants to create hydrogen from methane produced from cow manure and then deliver that gas to the Port of Los Angeles, where efforts are underway to switch out diesel-powered equipment with that powered by fuel cells.
“By making the whole value chain together as one business model, we are trying to create a supply and demand [and] at the same time a self-sustainable supply chain from upstream to … [down]stream,” Sugiura explained.
He said the company has held extensive discussions with terminal operators at the Port of Los Angeles and at Long Beach, about 25 miles away.
The two ports are home to 13 shipping container terminals. The nearly 3,000 trucks, gantry cranes and other cargo handling equipment, powered by diesel or gasoline engines, operate around-the-clock at the terminals.
The company has developed a mobile fueling station that will deliver the renewable hydrogen to the terminal equipment powered with fuel cells, he said.
A related company, Toyota Motors, has partnered with truck maker Kenworth to build 10 fuel cell terminal trucks, now operating at the ports.
“Port terminals have determined a very clear goal of zero emission. The equipment must be 100% zero-emission by 2030 and … the trucks that must be-zero emission by 2035,” Sugiura said.
“There are many challenges to overcome for this technology transition from diesel to hydrogen in the port area. The first one is hardware commercialization by the [original equipment manufacturers]. So we work closely with the OEMs to promote the development and also the actual manufacture of the equipment.
“Another obstacle is that currently only the Port of Los Angeles will require the fuel cell-powered equipment.”
Finally, fuel cell trucks are more expensive than diesels. And hydrogen is more expensive at this point than diesel fuel, he said.
Even if the demonstration is successful, moving to mass production of hydrogen and full commercialization of fuel cell trucks will be a challenge, Sugiura said, including regulatory issues that must still be worked through.
Hydrogen fueling protocols and fire code permits will be critical, he said. “This is a slow process, so we are working closely with the government and related authorities.”
Room for Both
CSIS’s Nakano asked whether it would make more sense to rely on batteries rather than fuel cells.
“We need both of them because they both have strengths and weaknesses that actually match each other,” Elrick said. “Just like neither diesel nor gasoline dominated everything in either market, but they found where they worked best.”
“I think we’re going to find that generally and in transportation especially,” he continued. “And I don’t think it’s out of place to say the heavier applications will clearly play with the advantages of hydrogen more, where batteries, on weight alone, can be one of the disadvantages.
“But in the light duty, especially in the urban communities, we will see more battery vehicles because they don’t go as many miles and that’s a really nice niche for them. But I also think there will be a lot of overlap.”
Izumi Kai, president of Houston-based LNG company JERA Energy America, a subsidiary of Japan’s largest electric power producer, said LNG will remain important for the next two to three decades, especially in developing countries.
He said JERA wants to blend ammonia with coal at its most efficient coal-fired power plants with the goal of completely replacing coal. Similarly, the company hopes to begin to switch its gas turbine power plants to 100% hydrogen by co-firing hydrogen and natural gas. (Anhydrous ammonia is a gas but turns to liquid at -28 degrees Fahrenheit.)
“But it takes 20 years or so, to achieve a full replacement … to enable such co-firing. It is very difficult to be responsible for a stable energy supply and also a competitive energy supply,” Kai said.
Japan now imports its LNG but in the future hopes to import ammonia because it is easier to transport, he added, and it can be converted to hydrogen at its point of use if necessary.
Asked by Nakano whether carbon pricing or the creation of a carbon market might speed up the development of hydrogen as a fuel, all three panelists agreed it would.
Kai said Japan and other Asian nations, which will be importing low carbon fuels, would especially benefit.
“It’s important to have some kind of government support or some kind of commercially viable mechanism. A carbon credit system is one of the key options,” he said.
Sugiura, whose company wants to electrify the Port of Los Angeles, agreed. “In order to make hydrogen a common fuel, I think it’s very important that we start using hydrogen, whatever the color,” he said, adding that hydrogen would be become a “common fuel” if given a credit in a federal carbon market.
And Elrick, whose organization is poised to go national in its advocacy of hydrogen fuel cells, said decarbonizing the fuel is equally as important as switching to FCEVs.
“If we changed every car, or vehicle, if we changed every heat pump and every stove to zero emission, it doesn’t necessarily mean that fuel, whether hydrogen or electricity, was decarbonized,” he said.
CHARLOTTE, N.C. — Renewable developers said last week they don’t expect much from the controversial Southeast Energy Exchange Market (SEEM), saying it falls far short of the transparency and competition found in RTOs and ISOs.
The developers reacted coolly to representatives of Southern Co. (NYSE:SO) and Duke Energy (NYSE:DUK), who defended SEEM at the Infocast Southeast Renewable Energy Conference.
Proposed by more than a dozen utilities and cooperatives including Southern, Duke and the Tennessee Valley Authority, SEEM would automate bilateral trades, allowing 15-minute energy transactions, and use free transmission to reduce rate pancaking. The SEEM agreement took effect Oct. 12, after FERC deadlocked 2-2 on the proposal. (See SEEM to Move Ahead, Minus FERC Approval.)
Critics of the proposal say it would only perpetuate the utility monopolies of the Southeast and produce a fraction of the savings that could come from an RTO.
Utilities’ Control
“I think there’s a lot of concern that participation — controlling who participates — is in the hands of the people developing SEEM. And so whether or not we get the chance to actually participate, we’ve got a lot of questions about that,” Blan Holman, vice president of regulatory affairs for solar developer Pine Gate Renewables, said during a panel discussion at the conference.
Noel Black, vice president of federal regulatory affairs for Southern, responded that SEEM’s sponsors are seeking wide participation.
“Participation and liquidity [are] really important for SEEM and how much benefit it brings to customers, so we are eager and excited to have more participants. I want to be clear on that,” he said. “The opportunities I believe are fantastic. If you get a giant footprint … 160,000 MW, 50 million customers, 1,000 miles between Savannah and Springfield, Mo., with zero transmission [cost] … the more participants, the more liquidity, the more opportunity we have to bring value … to our customers. So if we buy something, in SEEM, it’s cheaper than something we would have run … that goes straight to our energy costs, to our customers. If we [make] short-term opportunity sales, the margin we make flows back through to our customers, either through lower rate base or energy clauses.”
Cost, Speed
Black said the cost of establishing SEEM — $5 million to $6 million — is “extraordinarily inexpensive” compared to alternatives such as an RTO.
Molly Suda, associate general counsel for Duke, also touted the speed at which SEEM will be launched, with hopes to begin operations by the end of 2022. “For other market designs, there are substantially longer lead times,” she said.
In response to questions, Black and Suda acknowledged SEEM will not offer LMP or provide a clearinghouse for environmental attributes.
SEEM’s sponsors said an independent third-party consultant estimated the market will provide members a total of $40 million to $50 million in annual savings in the near term, potentially growing to $100 million to $150 million annually “as more solar and other variable energy resources are added.”
“By the utilities’ own admission, [comparing SEEM to an RTO is] sort of like comparing a flea to a basketball,” Chris Carmody, executive director of the Carolinas Clean Energy Business Association (CCEBA), said in a separate session at the conference. “The projected savings that the entire SEEM project would do across these many, many utilities is $40 million a year [and] I think $10 million for North Carolina. … Ten million is less than half of the salary of a significant CEO.”
In September, the American Council on Renewable Energy released a report that found an energy imbalance market (EIM) would reduce total resource costs from $64.7 billion in 2020 to $42.1 billion in 2040, a 35% savings, versus a more modest reduction to $53.1 billion (18%) under SEEM. (See Report: SEEM’s Benefits Beaten by Other Models.)
Black said SEEM’s sponsors considered an EIM but rejected it because of its “command-and-control nature” and the cost and time to stand it up. “So the question becomes can you get the same benefits at a much lower cost without the bureaucracy and burdens of some of the other structures? And right now, the answer, in our minds and in our hearts and on paper seems to be ‘yes.’ [We] can effectuate scope and scale without the bureaucracy and burdens of more complex structures.”
Transparency
Transparency is another concern of renewable developers, said Pine Gate’s Holman. “If you have a full-blown RTO, you get visibility in the pricing. And here, I think there’s concerns about whether or not you can be able to … see the transactions in a way that helps send signals to the market for further investment,” he said.
Black said there is a “fine line between transparency and … exposing commercially sensitive information.”
“We were trying to thread that needle so that we give enough exposure … to build that trust [and ensure SEEM is] executing the tariff as designed, but also not expose information that participants might find too sensitive. I think we struck the right balance. We’ll see. I think time will tell.”
Black said the cost-benefit study done for SEEM found that 2% of the energy in the region will flow through the market, which he said, “feels defensible, and maybe a little conservative.”
Although only 5% of the Western Energy Imbalance Market’s regional energy flows through the market, BIack said “you get a sort of cost transparency on 100% [of transactions] off that 5% at the top of the stack.”
“I believe that [SEEM] has the potential to bring those sorts of benefits to customers as it grows. And the more participation we have and the transparency and comfort grows, I think we’ll see those sorts of benefits. So I feel comfortable coming out of the gate and looking anyone and everyone in the eye and saying, ‘Here’s what we believe this will do,’ … and then having hopes and dreams that it will be much bigger and amazing as we move down the road.”
In a statement Oct. 20, FERC Chairman Richard Glick expressed concern that because the commission did not issue an order approving SEEM, its sponsors might not honor the promise they made to provide transparency. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.)
In response to a FERC deficiency letter, the sponsors promised in June to provide confidential weekly submissions of market data to the commission and SEEM’s Market Auditor, “comparable” to the data provided by RTOs under Order 760, including participants, bid/offer prices, quantities and locations. They also agreed to make the “just-and-reasonable standard” the default for most SEEM rules rather than the lower Mobile-Sierra public interest standard. (See SEEM Members Offer Rule Changes.) In Mobile-Sierra, the Supreme Court ruled that when sophisticated parties negotiate at arm’s length, their agreement should be presumed just and reasonable unless it can be shown to harm the public interest.
Black said Glick has no reason to worry. “I would say the SEEM members are all comfortable with those commitments, and highly likely — within the next week or two — to file those commitments with FERC in some form or fashion,” Black said. The transparency provisions “are there to build trust in the system, for not just participants, but members as well. The more trust in the system, the more likely the system will work and [there will be] liquidity. … So we will be filing something to put those commitments in … place, regardless of whether we were ordered to do that.”
No Boon for Solar Developers
Meredith Chambers, general counsel and regulatory compliance officer for EDP Renewables (OTCMKTS:EDPR), said SEEM is unlikely to affect the plans of the Madrid-based company, which is new to the Southeast market, with 60 MW of generation operational and 350 MW under construction.
“We would like to work with other stakeholders to see a more a more regional approach that includes conversations with all the stakeholders,” she said. “I don’t know that [SEEM] changes what we do at this at this moment. But I think that there are opportunities over time to have broader conversations about ways to integrate.”
Carson Harkrader, CEO of Carolina Solar Energy, which develops utility-scale solar projects in North Carolina, Virginia and Kentucky, said large energy consumers share the frustration of renewable developers that the regulatory and market structure of the Southeast doesn’t allow them the options they have in RTO territories, such as the ability to sign long-term power purchase agreements. Financing solar projects requires a minimum 10-year PPA, she said.
In RTOs, “we’re able to sell for long-term, fixed-price contracts with energy users. … Obviously, SEEM would not enable that kind of transaction. … I think any solar developer would tell you that’s what we’re hoping for,” she said.
“So for new solar, playing in an open market with fluctuating prices, it would be hard, I think, to finance a new solar project,” she added. “Potentially for projects that are coming off an initial PPA, that might be an opportunity.”
Fight not Over?
Moderator Weston Adams, of Nelson Mullins Riley & Scarborough, noted that rehearing requests have been filed over SEEM’s proposal, and that Democrat Willie Phillips has been confirmed as the commission’s fifth commissioner, with the potential to break the 2-2 deadlock. “Certainly there are parties that think this fight is not over — that this is going to be litigated into the D.C. Circuit” Court of Appeals, he said.
Duke’s Suda said she doesn’t see legal obstacles to SEEM.
“In our view, given the recent order earlier this month on the transmission tariff changes … really the only issue holding back a three-vote majority on this is [a dispute over the application of] Mobile-Sierra.”
Suda was referring to FERC’s Nov. 8 order accepting revisions to four SEEM utilities’ tariffs that implement the special transmission service used to deliver the market’s energy transactions. Chairman Glick, who had opposed the market’s creation, sided with Commissioners James Danly and Mark Christie, saying the parties’ filings, unlike the SEEM agreement, do not apply Mobile-Sierra provisions that would limit FERC’s authority to require changes.
Integration, Transmission Costs
Hamilton Davis, vice president of markets and regulatory affairs for Southern Current, a developer of large-scale solar and energy storage projects, said SEEM does not address independent power producers’ concerns over increasing curtailments and rising integration costs in the Carolinas.
“What Duke and Dominion [Energy] [NYSE:D] both said in their recent [integrated resource plans] is that SEEM is not actually going to help with integration costs. There are big opportunities to improve the design of this market so that it actually does at scale; some of what Noel has pointed out is nothing more than aspirational right now.
“I don’t think from an IPP standpoint [that] we’re anticipating participating in that market; the business model is not structured in a way where you would go finance a project based on the ability to sell. … From an IPP standpoint, it looks pretty limited.”
CCEBA’s Carmody also said SEEM will do nothing to address the “black box” of transmission costs in the Carolinas.
“It is becoming harder to understand. The information is becoming less accessible rather than more accessible,” he said. “We’ve spent a lot of time talking about generation in both states over several years … but if we don’t have a transparent and objective process for determining investments in transmission, then we are really in big trouble in a lot of ways, economically and environmentally.”
Washington Gov. Jay Inslee is mostly happy with how state agencies are dealing internally with reducing their carbon emissions, but he still believes they must speed up their efforts.
Agency officials agreed last week during a virtual briefing with the governor.
“Whatever we’re doing, we have to have higher ambitions because we’re not meeting our goals,” Inslee said.
Hanna Waterstrat, director of the Office of State Efficiency and Environmental Performance in the Washington Department of Commerce said, “The science indicates our targets need to be accelerated.”
The biggest shortfall of those related to charging infrastructure for electric vehicles, the briefing revealed. Currently, 81% of the roughly 5,000 state-owned vehicles are hybrid gas-and-electric. Three percent of all the vehicles, including trucks and vans, are totally electric, while 7% are totally electric. The inadequate number of charging stations require electric cars to rotate through them rather than all being able to recharge overnight simultaneously.
The state needs to analyze its electric charging systems to come up with numbers, budgets, installation plans and policies, including allowing agencies to use each other’s chargers, said Kelly Lerner, chief of leased facilities and maintenance for the state’s Department of Social and Health Services.
“We need to have standard charging systems and policies rather than agency-by-agency systems. … I want to accelerate transitioning to electric vehicles,” Inslee said.
“We need the money for the infrastructure first,” Lerner said.
Building for Net Zero
In Spokane, the state government recently completed its first net-zero building. The 6,200 square-foot structure is a garage and storage building for the Department of Ecology’s emergency response team for the state’s 20 easternmost counties. The team covers hazardous spills, methamphetamine labs and illegal marijuana operations.
The building includes rooftop solar panels. However, the team’s vehicles are still gasoline-powered because potential hazardous sites could be beyond the round-trip range of an EV, said Sam Hunn, the department’s spills response supervisor for Eastern Washington.
Meanwhile, the state government is looking at constructing the first zero-emissions building on the Capitol Campus in Olympia — a daycare center for the children of state employees.
