The global floating offshore wind (FOSW) development pipeline has grown 228% since the last quarter of 2020, reaching 115.9 GW, according to The Renewables Consulting Group’s 2021 Global Offshore Wind Annual Market Report.
New FOSW capacity that is operational, secured or in development, including capacity that is scheduled for auction, has reached 116.2 GW, the report said. Of the new development capacity, 4.9 GW is attributed to the U.S., where the Bureau of Ocean Energy Management is planning lease auctions in California that would unlock at least 4.5 GW of FOSW capacity.
That planned capacity puts the U.S. eighth in the world in terms of national FOSW pipelines, with the U.K. and Sweden taking the No. 1 and 2 slots at 20.9 GW and 18 GW, respectively.
Industry studies of the global pipeline generally expect between 5 and 12 GW reaching commercial operation by 2030, with the remaining capacity coming online post-2030, Dan Kyle Spearman, director and global lead for floating wind at RCG, told NetZero Insider.
RCG analysis expects that West Coast FOSW projects could come online by 2030. Given the nascent status of the FOSW market, those projects looking to deploy by 2030 will be relying on a growing and risky supply chain.
A lot needs to happen by 2030 for the FOSW market to “pump out the big projects,” Spearman said, including identifying the most cost-effective and reliable floating platforms. “We have a database of over 100 different floating wind platform designs, which is madness.”
The market needs to winnow those designs down to a handful that can use the same supply chain and work in an industrialized, modularized process, he said.
Building a domestic FOSW supply chain for the early West Coast projects will bring a complex set of challenges.
“The West Coast is particularly difficult because you don’t have the history of either big ship building or oil and gas,” like on the south and east coasts, he said. That limits the ability of existing ports to service projects in the near term.
Developers will have to be clever about the construction process, according to Spearman. That might include finding alternatives to the current construction approach that favors erecting turbines on their platforms at port and towing them to the project site.
“It’s quite challenging actually to tow a platform long distances with a turbine fully erected because you get quite significant fatigue in areas such as your tower,” he said. If, for example, construction for Morrow Bay projects were to occur in Humboldt Bay, towing the platform approximately 500 miles to Morrow Bay would test the tower’s structural integrity.
The West Coast’s very deep waters of between 900 and 1,200 meters will also present challenges for the platforms’ mooring system design and required supply chain.
“It’s not insurmountable, but there will be a cost to installation,” Spearman said.
The process of sorting out which of the major platform designs the market will choose to invest in likely will come down to geography, cost and the capabilities of local suppliers.
Designs that are suitable for harsh, deep-water conditions on the U.S. West Coast also might be suitable for projects such as in Australia, Spearman said. Currently, semisubmersible technologies are the “most preferred choice,” but Spearman says he would not rule out a tension-leg-platform (TLP) design. TLP is a “very attractive technology because you can reduce your steel weight,” which is beneficial at scale.
If the U.S. is unable to build a robust domestic FOSW supply chain by 2030, developers will be forced to compete for components internationally against developers in more mature markets.
While there will be a strong opportunity for U.S. domestic component supply to develop, Spearman said, there will be uncertainty about the price point developers will be “willing or forced to pay.”
Ultimately, policy will influence supply chain development and the choice between low-cost energy and a thriving domestic economy.
“Developers can go either way, but if they are left with no policy framework, they’ll just go for the lowest [component] option, and local suppliers are just not going to be able to compete,” Spearman said.
The U.S., he said, will need a policy framework in place to build a joint business case for developers and the supply chain.
Maryland has identified 502 “optimal” locations where it might install electric vehicle charging stations over the next five years, using the $63 million it is slated to receive from the Infrastructure Investment and Jobs Act (IIJA).
Maine is proposing a staged approach to deployment of DC fast chargers, focusing first on the more populated Southern part of the state, and then building out to the central and Northern regions. | Maine Dept. of Transportation
But according to the plan the state recently filed with the Federal Highway Administration (FHWA), not all of the sites are within one mile of key highways, as the funding guidelines require.
Maryland is also one of several states raising concerns about whether its electric system will be able to interconnect and integrate multiple charging stations, each with four 150-kW DC fast charging ports, which are also required under the National Electric Vehicle Infrastructure (NEVI) program established by the IIJA.
“Upgrades needed to both the line and load side to meet this increased demand could be extremely costly, especially in areas where the infrastructure may be limited,” the plan said. But the plan also includes a basic assumption that installation costs to be covered with federal funds could include system upgrades as needed.
Maine’s proposed solution to the problem, laid out in its plan, is a staged approach. The initial stage would see the state install charging stations with four 150-kW ports at high-traffic sites, mostly in the southern part of the state. Medium- and lower-traffic sites in the middle and northern regions will only get two 150-kW chargers, at least to start.
Monday was the deadline for all 50 states, Puerto Rico and the District of Columbia to file their NEVI plans with the FHWA, and the agency reported on Tuesday that all had met the deadline. The FHWA now has until Sept. 30 to review and approve the plans.
North Carolina currently has 10 NEVI-compliant charging locations in the state. | North Carolina Dept. of Transpor
The program will provide a total of $5 billion in formula funding to the states over the next five years, with the goal of building out a national network of 500,000 chargers that will make EV charging safe, convenient and affordable. (See Biden Administration to Order EV Charging Standards.)
Still, like Maine and Maryland, many states have raised concerns about their ability to meet all the program guidelines and may be asking for “exceptions” to allow them to get their plans approved and start receiving funds. (See EV Charging Standards Leave Some Obstacles Untouched.)
The exception process is intended to provide states with flexibility on some of NEVI’s core requirements, said Steve Lommele, a senior project manager with the Joint Office of Energy and Transportation (JOET) launched by the Energy and Transportation departments earlier this year to help states with their plans. For example, under the NEVI guidelines, the IIJA-funded EV chargers must be installed every 50 miles along interstate highways, and no more than one mile off these routes.
California, which did not identify specific exceptions in its plan, asked that the FHWA allow for exceptions to be requested at any time throughout the NEVI program. “Flexibility in requesting exceptions will be especially important in the rural areas of the state,” the plan said.
Washington will initially prioritize EV charger buildout on it heavily traveled I-5 and I-90 corridors, while making areas in the east secondary priorities. | Washington State Dept. of Transportation
“There are certainly sections of rural highway, particularly in the Western United States, where there might not be much at all along a 50-mile stretch of highway, Lommele said during a recent webinar on state planning for NEVI, sponsored by the nonprofit Advanced Energy Economy (AEE). “So, it might be worth considering expanding that to 55, 60 or 70 miles.
“There might be a town with amenities that’s a bit further than one mile from the highway, and so states are, in some cases, requesting exceptions because we want these to be convenient locations that have amenities,” he said.
Renee Samson, director of regulatory affairs at FreeWire Technologies, an EV charger manufacturer, raised yet another concern during the AEE webinar that “sites that may not be able to support four charging [ports] or have no economic need or do not have enough EV drivers.” Echoing Maine’s approach, she said, such locations “might be better suited to have one to begin with and then work towards that goal” of having four ports.
Lommele said the JOET and most states have been working closely with utilities to develop strategies for deploying increasing numbers of DC fast chargers in the coming years. “It really starts with close collaboration and working together to understand where the infrastructure is going to go, where maybe some stations will be more difficult,” he said.
“By and large, states are probably going to be focusing on the lower hanging fruit to start, the areas where there may be less significant challenges, and then, as we kind of develop best practices and learn from deployments, using that information to inform investment in the later years,” he said.
An FHWA spokesperson also stressed that “these plans will be updated annually, and the build-out of a national network will continue to evolve over the coming several years. But we are confident that we will have a truly national and publicly available EV charging network that builds consumer confidence in the growing number of EVs that automakers are offering.”
Changing NEVI Requirements
Installing the fast chargers every 50 miles on major interstate routes is the top priority for the first round of NEVI funds, creating a national network of Alternative Fueling Corridors, or AFCs. But previous guidelines for AFCs, set before passage of the IIJA, allowed for fast chargers of less than 150 kW and as far as five miles off a corridor, rather than one mile. The current guidelines were issued in February and further updated in June.
California already has an extensive network of public EV chargers in populated areas. | Caltrans
In addition to the 50-mile and 150-kW requirements, the June updates also require fast chargers to be available 24/7, operating 97% of the time and able to accept any debit or credit card. The program also requires states to contribute 20% of the cost of building out the charging stations on their AFCs.
These updates have meant some states needed to quickly rethink their plans. Slated to receive $21.1 million in NEVI funds, Vermont already had a plan for putting fast chargers along its highways based on the previous federal guidelines. As a result, the state currently has no locations with more than two 150-kW ports, and fast charging stations that the state has funded and built along its AFCs mostly have two 50-kW plugs.
Further, of the 15 sites for NEVI charging stations identified in Vermont’s plan, four will fall outside the one-mile zone and may need to apply for exceptions.
With 565,000 EVs on the road, California is the country’s leading EV market and will get $384 million in NEVI funds over the next five years. The state has already installed 28,877 public Level 2 chargers and 6,764 public fast chargers, but only 592 fast chargers within one mile of a key highway exit are 150 kW, according to figures in the state’s draft NEVI plan.
Fast charging stations installed on the state’s highways “before the NEVI requirements were introduced … may serve as prime locations and critical sites to be upgraded,” the plan says. In addition, fast charging sites that were developed with funds from the California Energy Commission must be wired to accommodate 150-kW chargers, the plan says.
California is planning a competitive bidding process in which developers will be asked to identify potential sites for NEVI-compliant charging stations “based on an analysis of gaps in the current network, future charger needs and geography,” as well as the minimum NEVI requirements, the plan says.
‘Fail Early and Often’
With nearly $408 million in federal funds, Texas took a different approach to NEVI planning, starting without an existing EV policy blueprint, said Ryan Granger, a strategic planning manager at the state’s DOT, also speaking at the AEE webinar.
Ohio only has 10 charging stations that are NEVI-compliant but is analyzing highway interchanges across the state to identify additional sites. | Ohio Dept. of Transportation
“We didn’t have any state goals. We were able to focus on the [federal] requirements in the plan and getting that done,” he said. “We wanted to fail early and often and learn from people telling us what we were doing wrong.”
Like Maine, Texas is planning for a phased rollout of EV charging infrastructure, with an initial focus on AFCs, adding 55 new sites to 27 preexisting charging stations installed by private companies, Granger said. In subsequent years, the state will target installing charging stations in rural counties, small urban areas and county seats, which, Granger said, “are pretty centrally located.”
In states with smaller, still-developing EV markets, such as Ohio, the process for identifying charging sites begins with an analysis of highway interchanges with existing electric infrastructure that could support four 150-kW chargers, the state’s plan says. With only 10 NEVI-compliant DC fast charging stations at present, Ohio is looking for interchanges with one or more truck stops, one or more retail centers or big box stores, or three or more gas stations or convenience stores.
Potential sites meeting those criteria are then analyzed by the local utility to “confirm the sites are viable or [have] capacity constraints that would add costs,” the plan says.
In Ohio, which is eligible for $140 million in NEVI funding, the state’s DOT had “an initial conversation” with the state’s utilities, said Luke Stedke, managing director of communications and policy, “overlaying our sites with their grids.”
How the utilities will meet the future demand from DC fast chargers is something each utility will have to develop with the Public Utilities Commission, he added.
FreeWire’s Samson also cautioned that states and utilities will need to provide developers with appropriate pre-application information to ensure that a site will be able to connect to the grid and not get caught in a long interconnection queue.
“Handling the utility connection upfront and showing that a site will indeed be able to be built out is going to be important for ensuring that there’s a smoother process than what it potentially could be,” she said.
Facing Workforce Shortages
Beyond geography and the grid, another common theme across many state plans is the need for workforce development. California has estimated that its existing statewide goals for light-, medium- and heavy-duty EVs and associated infrastructure will require a charging installation workforce of 47,300 to 71,500 job-years ― the equivalent of one person working a full-time job for one year ― over 2021-2031.
The state is tapping into a range of partnerships, including an apprenticeship program “for new and innovative sectors,” run by the Foundation for California Community Colleges. The state has also developed on-the-job training programs focused on EV supply equipment installations and service, including basic safety training.
Oregon, slated for $52 million in funding, also sees the NEVI program as a “significant opportunity” for workforce development, but the state’s plan acknowledges “there is insufficient qualified labor to complete these deployments, especially when considering certification requirements.”
The plan says the state’s DOT is in discussions with utilities and unions regarding the status of the local certified workforce and workforce development needs.
Samson pointed to the Electric Vehicle Infrastructure Training Program (EVITP), a national program to certify electricians to work on installing EV chargers. Some states are requiring that charging stations be installed by EVITP-certified electricians when “there simply aren’t enough electricians that are certified in certain areas of the country. … Making [it] a requirement is going to add complexity and expense to a project when you have to have electricians travel quite some distance to do installations,” she said.
California’s plan noted that, as of May, large areas of the state served by AFC-designated highways had no local contractors appearing on the state’s EVITP published list. To reduce the risk of a shortage of needed electricians, the California Energy Commission will contract with community colleges to expand the locations of in-person EVITP examinations outside the San Francisco and Los Angeles areas.
Workforce training may also be critical for state plans to meet federal “Justice 40” requirements that 40% of the benefits of federally funded projects go to disadvantaged communities. As noted in California’s plan, AFCs don’t, in general, run through or close to disadvantaged or low-income areas, either in dense urban areas or more remote rural regions.
Lommele of JOET said that “one aspect of [NEVI] benefits could be creating workforce opportunities for disadvantaged communities.
“States are engaging with disadvantaged communities to understand what benefits are important, what needs those communities have and how the program can support that,” he said.
The IIJA also provides $2.5 billion for competitive, discretionary grants to fill the gaps in EV charger infrastructure not covered by the NEVI formula funds. Guidelines for those funds are expected later this year, the FHWA said, and will further build out the national network by making investments in community charging.
“The NEVI formula program is really intended to be a backbone of a national network,” Lommele said. “It’s going to continue to require additional public and private investment to meet the needs five years from now, but we’re really working toward a future where everyone can ride and drive electric.”
[EDITOR’S NOTE: A previous version of this story incorrectly called Jonathan Booe the CEO of NAESB. He is COO.]
FERC Chairman Richard Glick and NERC CEO Jim Robb last week asked North American Energy Standards Board (NAESB) leaders to convene a forum to discuss plans to improve natural gas reliability in support of the electric sector and address challenges from gas-electric interdependency.
The request came Friday in a joint letter to NAESB COO Jonathan Booe and Chairman Michael Desselle. It was inspired by the FERC-NERC joint report on the winter storms that hit Texas and the Midwest in February 2021, leading to widespread generation outages, derates or failures to start that caused more than 23 GW of manual firm load shed. (See FERC, NERC Release Final Texas Storm Report.)
The report, released in November, found that natural gas facilities accounted for more than 50% of generation failures, both in terms of the number of units and their total nameplate capacity.
Among the report’s recommendations was that FERC establish “a forum in which representatives of state legislatures and/or regulators with jurisdiction over natural gas infrastructure, in cooperation with [other stakeholders], identify concrete actions … to improve the reliability of the natural gas infrastructure system necessary to support the Bulk Electric System.” Glick and Robb’s letter said that NAESB “is uniquely positioned” to organize such a forum, having “representation from all segments of the supply chain” in the gas and electric markets.
Speaking to ERO Insider on Monday, Booe said the organization was “excited to see the request” and had been “working through the weekend” to develop a response to the letter. While NAESB is not ready to schedule the forum yet, Booe observed that it has many years of experience working to address gas and electric market coordination issues, several times at the request of FERC and often with support from NERC and other stakeholders.
“We know it’s going to be a challenge, but we have faced similar challenges in the past,” Booe said. “So, I think that’s why the commission and NERC, with the support of NARUC [National Association of Regulatory Utility Commissioners], have put their confidence in us to help establish this forum and try and address some of those findings that were in the report … We have this long history of convening these kinds of diverse groups of interested parties and trying to find consensus positions.”
NAESB has pursued its own response to the February storms, including initiating a standards project aimed at improving gas and electric coordination last December. (See NAESB Starts Gas-electric Coordination Project.) Asked about the progress of this effort on Monday, Booe acknowledged that action had stalled after NAESB was unable to “find consensus from our groups” about the appropriate direction of the project. However, he said the request from Glick and Robb might inspire fresh movement toward new standards from the organization.
NAESB President Rae McQuade told ERO Insider she expected members from across both industries, as well as the regulatory community, would be happy to contribute to the forum, whatever form it takes.
“We have always worked very closely with NARUC, and we’ll certainly do so on this as well,” McQuade said. “And we’ve also got every segment of the wholesale and retail natural gas and electric market representatives as NAESB members. So, I’m sure that a number of our members will be very interested in participating, as well as others.”
Texas’ record-breaking heat through June boosted CenterPoint Energy’s (NYSE:CNP) second-quarter earnings and led its management to again raise its earning guidance.
The Houston-based utility reported quarterly earnings of $179 million ($0.28/diluted share) as compared to $221 million ($0.37/diluted share) in the same quarter last year, driven primarily by favorable weather and continued customer growth in its Houston Electric footprint.
CEO David Lesar said the performance of its transmission and distribution company gave CenterPoint the confidence to raise its 2022 earnings guidance from $1.37/share to $1.39, a 9% increase and the fifth time in two years his team has done so.
“We are setting a new and higher baseline for future earnings growth,” he said in a statement.
Lesar told financial analysts that Houston Electric accounts for only about 2.5% of ERCOT’s service territory but about 20% of its delivered energy. CenterPoint continues to see about 2% organic customer growth in Houston, which will be important as electric vehicle ownership and electrification increase.
“Consistently hot” temperatures that have reached as high as 105 degrees Fahrenheit in the nation’s fourth largest city have stressed the grid, but it has “held up well,” Lesar said.
CFO Jason Wells said CenterPoint will recover about 80% of its $1.1 billion in incremental gas costs from the February 2021 winter storm when the state’s securitization process begins to distribute funds.
The company’s non-GAAP earnings came in at 31 cents/share, up 11% from the comparable quarter in 2021. That beat Zacks’ consensus estimate of 31 cents/share.
CenterPoint shares were trading at $31.70 in the after-hours market, up 7 cents for the day.
SPP’s Western Energy Imbalance Service (WEIS) market saw “very limited growth” in its first 13 months, SPP’s Market Monitoring Unit said in its first annual report on the market.
Unlocking renewable resources in the market’s region — which spans six states in the West, from Montana south to Arizona — has been cited as one of the market’s key benefits. But the footprint’s nameplate capacity increased by only 207 MW, all of it wind. Coal generation produced more than 62% of the market’s total generation. Hydro was second at 22% and wind third at 9%.
SPP’s generation by technology types | SPP
The market continues to struggle with limited capacity and ramp constraints and is often unable to procure sufficient power in real time to balance, the MMU said. It has urged the market to address ramping issues, through either a minimum requirement per participant or a fully developed ramp capability product, and supply adequacy.
WEIS has been a net exporter of energy since its inception, with an hourly average of 800 MWh of net exports. The addition of Colorado Springs Utility this month and three more participants next April will essentially double the amount of generation and load within the market.
The market began service Feb. 1, 2021, just prior to the historic winter storm that month. Prices that month averaged $90/MWh, but the storm’s impact was limited because of the generation mix and a limited ability to export to the east. The MMU found that market prices averaged around $36/MWh for the first 13 months, but that drops to just over $31/MWh when February 2021 is removed.
The MMU also recently released its spring Quarterly State of the Market report, which found that day-ahead prices were $31.66/MWh during the quarter (March through May), double last year’s average of $15.97/MWh. Average real-time prices also more than doubled, up 112% to $29.37/MWh.
Wind generation accounted for 48% of total generation, up from 45% for the same period a year ago. Coal generation remained flat at 28%, and combined cycle and simple cycle gas generation fell from 18% to 14%.
Average gas prices at the Panhandle Eastern hub were more than double from where they were last spring, up 146% to $6.02/MMBtu this year from $2.45/MMBtu. Gas prices peaked at $7.59/MMBtu in May, an all-time high if not for the winter storm in February 2021.
The MMU is hosting a webinar Wednesday at 2 p.m. to discuss both reports.
SPP Releases VRL Analyses
SPP last week released its annual analysis of violation relaxation limits (VRLs) for the Integrated Marketplace and the WEIS.
The grid operator is recommending changes to the operating constraint VRL blocks and increasing the spinning reserve constraint VRL to $250 from $200. Its analysis showed the slight increase reduces the number of scarcity intervals and product shortage with only a slight increase to cost.
SPP did not recommend any changes to the WEIS VRL block, penalties or VRL related to resource capacity.
The RTO says that its market clearing engine (MCE) attempts to enforce all constraints when generating a solution. When this results in solutions that are not feasible, SPP will apply VRLs in the MCE solution. The VRLs and their associated values attempt to achieve a reasonable balance between honoring operating requirements and constraints while mitigating large price excursions or other extreme prices.
The security-constrained economic dispatch (SCED) for day-ahead and real-time balancing markets optimizes constraints to determine the most efficient and reliable solution, SPP said. When system limitations cause a constraint’s shadow price to exceed a defined VRL, the constraint’s limit is relaxed and the shadow price is replaced with the VRL penalty, allowing SCED to solve more economically.
Public Service Enterprise Group’s (NYSE:PEG) departing CEO Ralph Izzo said Tuesday he is optimistic that the Democrats’ proposed climate bill will pass Congress and provide stable, long-term support for the utility’s three nuclear plants, now subsidized by New Jersey ratepayers to the tune of $300 million a year.
As proposed, the federal subsidy, which would run for six years from 2024, includes the Nuclear Production Tax Credit that “we have advocated for over the last two years,” Izzo said during the company’s second quarter earnings call.
He also cited several other recent green energy developments that will put the company in a strong position for the future. They include the New Jersey Board of Public Utilities’ (BPU) June 29 approval of the company’s $511 million Infrastructure Advancement Program, spending largely intended to upgrade the “last mile” of the company’s distribution system, he said. The company, through its environmental, social and governance strategy, is also finalizing company-wide emissions reduction goals to be submitted to the United Nations by September 2023 for validation that they meet the requirements of the Paris climate agreement, he said.
Izzo, who steps down as CEO Sept. 1 after 30 years at the company, will be succeeded by current Chief Operating Officer Ralph LaRossa. Izzo will continue as executive chair of the board until his retirement on Dec. 31.
He told the conference call that the company sees a growing recognition that nuclear plants are necessary to cut carbon emissions.
“We continue to observe a positive shift in public sentiment in support of preserving these nuclear plants,” he said. “This pricing floor for nuclear generation squarely addresses our need for a longer-term framework within which we can continue to own and operate our fleet with extended revenue visibility beyond the current three-year zero-emission certificate cycle.”
Solid Cash Flow
The enactment of the Democrats’ Inflation Reduction Act (HR 5376), is far from certain, with a possible Senate vote planned for this week. (See What’s in the Inflation Reduction Act, Part 2.) But its passage and the delivery of a federal nuclear subsidy would relieve PSEG of the pressure to secure state nuclear subsidies, at least for a while. The BPU in 2019 and 2021 awarded the company three-year subsidy packages of $300 million a year under the zero-emission certificate program. The state created ZECs to support nuclear plants that otherwise could be forced to close because they are financially unviable, undermining the state’s effort to meet its clean energy goals. The PSEG subsidies stoked criticism, however, that the company did not need a $10/MWh rate, the maximum allowed under New Jersey’s law creating the subsidies, to remain open.
According to an analysis by Taxpayers for Common Sense, the maximum subsidy awarded under the IRA would be $15/MWh, which the nuclear operator could only receive if it paid prevailing wage levels and met apprenticeship requirements.
Izzo said he is “very encouraged” by the bill, adding that based on his talks with legislators the “odds are looking quite good” that it could be passed. If that happens, and all goes to plan, he said, the nuclear plant will provide a “very predictable earnings stream with a very solid cash flow generation that I think serves the state of New Jersey very well, serves the company very well, serves the planet very well.”
PSEG officials said the company would no longer receive the state subsidy if it was getting the federal tax credit. Izzo said that talks continue with New Jersey legislators over future nuclear subsidies, should they be needed.
Those “policy level” talks with legislators include discussions with state legislators about “a longer duration alternative to the current zero-emission certificate framework for nuclear should the price levels contained in the [federal] reconciliation bill prove elusive,” he said.
OSW Investment or Sale
Izzo’s departure comes as the company faces a rapidly changing environment, which includes the sale earlier this year of the last of its 6,750-MW portfolio of 13 fossil generating units. The company owns 25% of 1,100-MW Ocean Wind 1, the first New Jersey offshore wind project to be developed, which is co-owned with Danish developer Ørsted.
And the company is awaiting the BPU’s decision on whether to adopt any of the 80 proposals for grid upgrades that would tie future offshore wind projects to the grid, among them several submitted by PSEG. Izzo has said in the past that the company’s proposals could be worth $1 billion to $3 billion.
Izzo said its part-ownership of the offshore project will have no bearing on whether the BPU adopts any of the utility’s projects to upgrade the grid. He added that “as related to the opportunity to co-invest with Ørsted, we continue to have conversations on a variety of fronts.”
Under questioning from an analyst, he elaborated, saying the company would evaluate whether it should sell its share of the offshore project.
“It should be obvious to everyone, New Jersey is going to build seven and a half gigawatts of offshore wind. I think half a dozen states are going to build 30 gigawatts of offshore wind,” he said. “That’s going to have a significant impact on power markets,” he said, adding that it would present “opportunities to grow earnings per share for companies. So it’s something that we want to make sure we are taking the long view in terms of the role we should or shouldn’t play in that.”
PSEG reported net income of $131 million ($0.26/share) in the second quarter, compared with a net loss of $177 million ($0.35/share) a year earlier. Non-GAAP operating earnings for the second quarter of 2022 were $320 million ($0.64/share) compared to non-GAAP operating earnings of $356 million ($0.70/share) in 2021.
FERC acted reasonably in rejecting a Wabash Valley Power Association power contract and denying it a Mobile-Sierra presumption, the D.C. Circuit Court of Appeals ruled Tuesday (20-1286).
The court upheld FERC’s April 2020 ruling over how to determine the reasonableness of rates for the sale of electricity from an energy cooperative to its individual member utilities (ER20-1101).
Indiana-based Wabash Valley generates and transmits electricity to 25 members in Indiana, Illinois and Missouri. Wabash’s bylaws give each member one seat on its board of directors, which acts by majority vote.
In 2020, Wabash executed new contracts with all but two of its 23 retail-serving members. The new contracts continued the prior practice of requiring members to pay the formulary rate tariff and empowering Wabash’s board to raise the rate to produce sufficient revenue to meet the co-op’s costs. But it also added a new provision asserting that any changes to the formulary rate tariff were entitled to the Mobile-Sierra presumption of justness and reasonableness, which can only be overcome only if FERC concludes that the contract seriously harms the public interest.
Tipmont Rural Electric Membership Cooperative, one of the two member utilities that did not sign the new contracts, protested to FERC that the Mobile-Sierra presumption should not apply to changes to the formulary rate tariff. The commission agreed, ruling that the tariff is a “generally applicable rate” rather than a contract rate, making the new language “an unlawful attempt to apply the public interest presumption to proposed changes to Wabash’s tariffs.”
In denying rehearing, FERC said the rate “is generally applicable to all Wabash members and is not negotiated between Wabash and its executing members on an individualized basis. Rather, the Wabash board of directors determines the rates.” In determining whether a unilaterally set tariff rate is just and reasonable, FERC must balance the interest of the investor and the consumer.
In its appeal, Wabash challenged FERC’s refusal to apply the Mobile-Sierra doctrine.
The D.C. Circuit agreed with FERC, saying a “contract requiring the purchaser to pay a utility’s ‘going rate’ on file with FERC, without more, does not eliminate review under the ordinary just-and-reasonable standard.”
The court noted that Wabash’s contracts with individual members are virtually identical, suggesting that “individual members face a ‘binary,’ take-it-or-leave-it choice” — not the “presumptively equal bargaining power” required under Mobile-Sierra.
Wabash contended its rate changes are not unilateral because member utilities control the board. But the court noted that each individual member controls only 4% of the board’s votes.
While individual members collectively own the cooperative and benefit from higher prices charged by Wabash and passed on to retail customers, the individual utilities “lack the same incentive as a buyer negotiating with an unrelated seller for the lowest possible prices,” the court said. “In other words, the utilities are effectively on both sides of the transaction. And the Mobile-Sierra presumption applies only to rates that are ‘the product of adversarial negotiations between sophisticated parties pursuing independent interests.’”
The court declined to rule on FERC’s assertion on rehearing that a contract must contain individualized terms to enjoy the Mobile-Sierra presumption.
“We do not read FERC’s decision as resting on a per se rule that the presumption can never apply to form contracts, and we do not opine on such a sweeping rule. We simply conclude that, in this case, the small bargaining power of any individual member relative to the cooperative plus the highly standardized nature of the governing contracts supports FERC’s conclusion that the contracts impose a unilateral tariff rate as opposed to a freely negotiated bilateral contract rate,” it said.
Small fleets of electric school buses near San Diego will be part of the first vehicle-to-grid (V2G) project to participate in a program intended to boost reliability during electric emergencies, such as the rolling blackouts that hit California in August 2020.
The Lion Electric buses in the Cajon Valley Union School District will be aggregated with others in the nearby Ramona Unified School District to form a participating resource under the Emergency Load Reduction Program (ELRP), started last year by the California Public Utilities Commission.
The state’s three large investor-owned utilities — Pacific Gas and Electric (NYSE:PCG), Southern California Edison (NYSE:EIX) and San Diego Gas & Electric (NYSE:SRE) — manage the five-year ELRP pilot, which CAISO can call on as a last resort when shortfalls are imminent, as they were during electric emergencies the past two summers.
In the Cajon Valley school bus yard, SDG&E installed six 60-kW, bidirectional DC fast chargers able to participate in the ELRP, which pays business customers $2/kWh to export energy or reduce demand in grid emergencies. The first set of bidirectional chargers went live on SDG&E’s grid last month.
A V2G project participating in the ELRP is a first, said Jacqueline Piero, vice president of policy for Nuvve (NASDAQ:NVVE), a V2G technology developer that is partnering with the school districts and SDG&E in the effort.
“It’s a great demonstration of how electric vehicles don’t need to just be providing emergency backup,” Piero said. “They can actually be substantively contributing to the reliability of the grid in an aggregated manner.”
Nuvve previously worked with the Torrance Unified School District near Los Angeles on a demonstration V2G bus project, but it was connected to school district buildings and not to SCE’s grid. A similar project at the University of California, San Diego, supplied electricity to the university’s microgrid but did not connect to SDG&E’s system.
Bidirectional EV charging, allowing vehicle fleets to connect to the grid, was not permitted prior to September 2020, when the CPUC changed its interconnection rules, letting fully integrated V2G projects move forward.
“We’re really just now being able to take advantage of the updates in the interconnection rules,” Piero said. “So even though we did a project in Torrance where we were doing real work with their demand charges, we were not interconnected, and we were not allowed to export.”
The company was part of a V2G project in Denmark that showed connected vehicles could provide frequency response and other grid support services. It was one of dozens of V2G demonstration and pilot projects started in Europe, the U.S. and Asia over the past 10 years.
California is home to more than 1 million EVs and is under a mandate to sell only emissions-free passenger vehicles, primarily EVs, starting in 2035.
Earlier this year the CPUC signed onto the U.S. Department of Energy’s Vehicle to Everything (V2X) agreement, a “collaboration for accelerating development and commercialization of vehicle-to-everything technologies, which include vehicle-to-grid, vehicle-to-building and vehicle-to-load capabilities, by validating the technologies and demonstrating the commercial viability of such technologies.”
The effort is intended to bring together cutting-edge resources from the department’s National Laboratories, state and local governments and utilities to “evaluate technical and economic feasibility as we integrate bidirectional charging into energy infrastructure,” DOE said in a news release.
SDG&E was a signatory to the V2X agreement, along with PG&E, SCE and the California Energy Commission.
“Electric fleets represent a vast untapped energy storage resource and hold immense potential to benefit our customers and community, not just environmentally but also financially and economically,” SDG&E Vice President of Energy Innovation Miguel Romero said in a joint news release with the Cajon Valley school district and Nuvve.
PG&E and Ford said in March they would test the V2G potential of the automaker’s F-150 Lightning electric pickup trucks. Bus and commercial truck fleets with predictable schedules and more capacity are optimal V2G candidates.
“School buses are an excellent use case for V2G,” Nuvve CEO Gregory Poilasne said in the news release. “They hold larger batteries than standard vehicles and can spend peak solar hours parked and plugged into bidirectional chargers. Nuvve’s technology enables the grid to draw energy from a bus when it is needed most, yet still ensuring the bus has enough stored power to operate when needed.”
California regulators are waiting for a green light from the EPA for a rule that would require an increasing percentage of medium- and heavy-duty trucks sold in the state each year to be zero emission.
The California Air Resources Board (CARB) adopted the regulation in June 2020. Known as Advanced Clean Trucks (ACT), the rule will require vehicle manufacturers to sell a certain percentage of zero-emission trucks starting in 2024.
The rule will help California meet its climate goals and clean up the air in the state’s most disadvantaged and polluted communities, CARB said upon adopting ACT.
The regulation is also a key component of a multi-state action plan released last week aimed at speeding the adoption of zero-emission trucks. States including Massachusetts, New Jersey, New York, Oregon and Washington have adopted the ACT regulation, according to the report from the Multi-State ZEV Task Force. The group was facilitated by the Northeast States for Coordinated Air Use Management.
“Regulatory requirements mandating [medium- and heavy-duty] ZEV sales establish a regulatory floor that provides market certainty needed to drive investments in zero-emission technologies and charging and fueling infrastructure,” the plan said.
Wavering on Waivers?
But EPA approval of the California regulation might not be a slam dunk. A recent report from E&E News said the EPA is considering partially denying a waiver to California for Advanced Clean Trucks and another regulation related to heavy-duty truck emissions. The denial would reportedly impact the regulations in their first years, according to the news story, which quoted an unnamed source.
The story noted that denial of a California waiver request would be a first under a Democratic administration.
The EPA Office of Transportation and Air Quality told NetZero Insider in an email that the agency is at the beginning of its process for considering CARB’s waiver requests.
“As such, no decisions have been made by EPA at this point,” the agency said.
A CARB spokesperson did not respond to a request for comment.
The EPA held a virtual public hearing on the regulations on June 29. The deadline for the public to submit comments is Aug. 2.
Three Waiver Requests
Under the federal Clean Air Act, California may set its own vehicle emission standards if they are at least as stringent as federal standards. The EPA issues a waiver to the state if the rules meet certain criteria. The state must receive the EPA waiver before it may enforce the rule.
Other states may decide to adopt California emissions regulations.
The EPA is currently evaluating three California waiver requests.
Advanced Clean Trucks requires manufacturers to sell a certain percentage of zero-emission trucks each year based on the vehicle classification. For Class 2b and 3 trucks, which typically include step vans and city delivery trucks, the rule requires 5% ZEV sales in 2024, increasing annually to 55% in 2035.
Truck classes 4 to 8, which might include bucket trucks, beverage trucks and buses, start with a 9% ZEV sales requirement in 2024, growing to 75% in 2035. The ZEV sales requirement for Class 7 and 8 tractors ranges from 5% in 2024 to 40% in 2035.
CARB is also seeking an EPA waiver for the Heavy-Duty Low NOx Omnibus Regulation, which aims to reduce emissions of nitrogen oxides from trucks. The rule sets new standards starting with the 2024 model year and tightens the standards further in 2027. The CARB board approved the regulation in August 2020.
The Multi-State ZEV Task Force report recommends that other states adopt California’s low NOx omnibus regulation to reduce emissions from heavy-duty trucks while the market transitions to ZEVs.
The third regulation awaiting an EPA waiver is an amended emission warranty regulation that extends emissions warranty periods for heavy-duty diesel trucks in model years 2022 and later.
In comments submitted to the EPA, CARB Chair Liane Randolph urged the agency to quickly approve waivers for the regulations. California needs to address the climate crisis and improve air quality as soon as possible, she said, and a delay would hurt other states that are adopting the California regulations.
“A partial or full denial of the waiver at this point would also have negative impacts on ZEV and diesel engine manufacturers who have been investing significant resources to comply with California’s standards,” Randolph said.
ERCOT stakeholders endorsed two transmission projects with a combined capital cost of more than $760 million during last week’s Technical Advisory Committee meeting.
The Regional Planning Group classified both the Bearkat-North McCamey-Sand Lake project in West Texas and the Roanoke upgrade project north of the Dallas-Fort Worth area as Tier I projects because their costs exceed a $100 million threshold. Their status requires they receive TAC endorsement and the Board of Directors’ approval.
ERCOT staff said during the Wednesday meeting that it chose one of the first project’s three options to address reliability needs driven by rapid load growth in the Permian Basin’s Delaware Basin and to improve the region’s ability to import power. The recommended option will result in building two double-circuit, 345-kV transmission lines totaling about 165 miles, with the two segments meeting in McCamey, a former oil boomtown since labeled “the Wind Energy Capital of Texas” by the state legislature.
Bearkat-North McCamey-Sand Lake has a projected cost of $477.6 million in 2021 dollars, up from $371 million in 2019 dollars, and an estimated completion date of June 2026.
The Roanoke upgrade project involves 7 miles of 138-kV lines, 26 miles of 345-kV lines, four 345/138-kV transformers and five 138-kV low-voltage buses. Staff analyzed four options, choosing the one they say provides better operational flexibility and long-term load-serving capability for future load growth.
Oncor, the incumbent transmission service provider, expects to complete the upgrades by May 2025 at an estimated capital cost of $285.9 million.
The company has a hand in both projects. It paired with Lower Colorado River Authority Transmission Services and Wind Energy Transmission Texas to submit the first project to the RPG. It was alone in suggesting the upgrade project.
TAC approved the projects as part of its combination ballot, where they were included with unopposed revision requests and other measures. The board will consider both projects during its Aug. 16 meeting.
Staff Defer Comment on CSAPR
Staff told TAC they were unsure as to whether the Supreme Court’s recent decision voiding the Obama-era Clean Power Plan would affect a federal rule’s implementation that limits nitrogen oxide emissions. (See Supreme Court Rejects EPA Generation Shifting.)
Texas is one of more than 20 states that, under EPA’s Cross-State Air Pollution Rule (CSAPR) plan, must establish NOx emissions budgets beginning with the 2023 ozone season (May 1-Sept. 30). The agency says the reductions are necessary to address upwind states’ interstate transport obligations.
Staff were non-committal when asked whether the high court’s 6-3 decision in West Virginia vs. EPA would scuttle the CSAPR. The court rejected EPA’s assertion that “generation-shifting” was the “best system of emissions reductions” available and invoked the “major questions doctrine” that agency decisions involving “economic and political significance” require them to show “clear congressional authorization.”
Senior Corporate Counsel Katherine Gross noted that CSAPR was proposed under a different section of the Clean Air Act than was the CPP.
“At this point, we’re not sure of the significance of this case, and we don’t want to speculate too much about what it will mean for the ozone transport rule,” Gross said. “If the EPA rule here does have a significant economic impact, the EPA is going to need to be able to point to very clear congressional authorization, which they were not able to do in the Clean Power Plan rule, according to the court. And if they’re not able to do that, then that rule is going to be susceptible to being overturned.”
Gross said ERCOT would defer to the state’s Office of the Attorney General and the Public Utility Commission, both of which filed comments with EPA asking for the CSAPR rule’s withdrawal as it pertains to Texas (EPA-HQ-OAR-2021-0668-0007.)
The AG’s Office alleged the agency “acted arbitrarily and capriciously in several distinct ways, abused its discretion and failed to observe procedures required by law.”
“Regional actors are in the best position to determine how to meet the 2015 ozone transport obligations, but EPA failed to consult the necessary experts and denied states, specifically Texas, the opportunity to regulate where appropriate,” the office said.
The PUC said the transport implementation plan will have “significant, detrimental impacts on reliability” in the ERCOT region, as well as those portions of the state served by SPP and MISO.
ERCOT staff in June told the board that its preliminary analysis of the CSAPR rule assumed that over 10 GW of installed thermal generation would leave the market by 2026, requiring up to $1.5 billion to resolve local reliability issues. (See “10 GW Thermals Could Retire with EPA Rule,” ERCOT Board of Directors Briefs: June 21, 2022.)
Woody Rickerson, vice president of system planning and weatherization, told TAC that the thermal units staff “retired” in its analysis do not have the necessary emissions-reduction equipment and “seemed likely candidates” to be retired or retrofitted.
TAC Liaisons with R&M Trimmed
TAC Chair Clif Lange, with South Texas Electric Cooperative, told members that the committee’s leadership continues to work with several board members to iron out its reporting relationship under ERCOT’s new structure. (See ERCOT Technical Advisory Committee Briefs: June 27, 2022.)
He said TAC’s proposal to have as many as 11 liaisons with the board’s newly created Reliability and Markets Committee was found to be “cumbersome” and “unwieldy.” Lange said that in meeting with Directors Bob Flexon, the committee’s chair, and Peggy Heeg, they agreed that TAC’s chair and vice chair would act as liaisons. Segment representatives would be present should the R&M Committee want to hear from them.
Lange said the directors have additional changes they would like to see and they will continue to work with stakeholders on the details.
ERS Budget Increase Endorsed
The committee endorsed a Nodal Protocol revision request (NPRR1142) and its accompanying Other Binding Document revision request (OBDRR042) that had been granted urgent status by the Protocol Revision Subcommittee. The measure increases the annual budget for emergency response services (ERS) from $50 million to $75 million and gives ERCOT the ability to contract ERS for up to 24 hours in a standard contract term.
The NPRR is a result of a July PUC order that also allows the grid operator to broach the budget by up to $25 million for contract term renewals (53493).
Morgan Stanley’s Clayton Greer cast the lone opposing ballot in the 28-1 vote, saying he had requested information from ERCOT, still outstanding, on how many loads were already offline before ERCOT deployed them.
“We have waivers that allow loads to go offline when prices are high. We’re paying people to do what they would already do on their own,” he said. “There’s no additional value to this. I would rather see a capacity market where we pay all capacity that’s online.”
Staff said they wouldn’t have the data available until the end of August.
“We’re more than happy to bring this analysis to whatever stakeholder meeting would like to see it,” ERCOT’s Mark Patterson said.
RUC Scaling Factor to 100%
TAC members agreed with staff’s recommendation to change the reliability unit commitment’s (RUC) scaling factor from 20% to 100%, adding the measure to the combo ballot that passed unanimously.
ERCOT instituted a 20% scaling factor in 2018 with NPRR864, which modified the start-up and minimum energy costs for resources with a cold start time of one hour or less. This allowed the grid operator to defer commitment decisions and provide market participants additional time to self-commit their resources.
However, that has changed with ERCOT’s new conservative operations posture that makes greater use of the RUC process. Staff said the scaling has led to operators needing to make many of their RUC decisions outside of the process’s economic-based recommendations, leading to inefficient commitments.
Changing the cost-scaling factors to 100% will help ensure the commitment decisions better reflect the economically optimal commitment decision, ERCOT said.
“We’ve just seen more manual commitments occurring this year because of a desire to commit resources further in advance of the peak hours,” ERCOT’s Dave Maggio said.
The combination ballot also included six NPRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and a system change request (SCR):
NPRR1085: improves the physical responsive capability calculation and dispatch’s validity by requiring quicker updates from qualified scheduling entities (QSEs) on telemetered resource status, high sustained limit and other relevant information.
NPRR1133: clarifies the responsibilities of DC tie facility owners and operators for reporting DC tie model data.
NPRR1134: removes references to first available switch date (FASD) after recent mass transition/provider of last resort events indicated ERCOT’s use of FASD when processing switch transactions created an unintended negative experience for customers being transitioned from a bankrupt retailer.
NPRR1135: modifies the definition of real-time generation resources with an offline non-spin (OFFNS) schedule to allow non-zero values for the billing determinant only if the resource is offline when it telemetered OFFNS. This ensures an accurate settlement when an online resource erroneously telemeters OFFNS.
NPRR1136: adds clarifying language to the logic in place as fast frequency response is developed to ensure a QSE does not replace a regulation service with fast-responding regulation service.
NPRR1137: replaces the annual requirement to review the OBD list with a four-year review cycle.
PGRR101: clarifies that a DC tie’s owner will provide the appropriate dynamic model data to its tie operator, which will then provide the data to ERCOT.
RMGRR168: synchronizes ERCOT’s role and responsibilities with current market transactional solutions upon the removal of the “out-of-cycle” switch term and market process.
SCR822: creates a new daily integration report and dashboard for energy storage resources similar to the current wind and solar integration reports and dashboards.
