Duke Energy (NYSE:DUK) asked North Carolina regulators Tuesday for approval to spend $56 million to fund more than 1,000 electric vehicle charging ports and aid school systems to purchase 60 electric school buses (Dockets E-2, Sub 1197; E-7, Sub 1195).
Duke Energy Carolinas and Duke Energy Progress said they designed their “Phase II” pilot program based on stakeholder input, as directed by the North Carolina Utilities Commission in November when it approved Duke’s $25 million Phase I pilot.
The utility also proposed a pilot for an EV charging tariff that would allow residential and business customers to choose their brand of hardware and network. The company’s Phase II filing followed its April 30 request for approval of a “make-ready” tariff offering credits to reduce the upfront cost of upgrading electrical systems to install charging hardware.
Duke Energy says it will convert all of its nearly 4,000 light-duty vehicles to electric and half of its 6,000 combined fleet of medium-duty, heavy-duty and off-road vehicles to EVs, plug-in hybrids or other zero-carbon alternatives by 2030. | Duke Energy
Duke said the proposal would put DC fast chargers on state highways and at multifamily dwellings and encourage a competitive market for charging equipment by requiring multiple providers of the hardware and software. It promised a “transparent stakeholder informed process around vendor selection that allows for alternative pricing by site hosts.”
The proposal includes $14.5 million for the 60 school bus purchases, following Phase I funding to help purchase 30 buses.
Another $41.5 million would be sufficient to fill 25% of the additional DC fast chargers (DCFCs) expected to be needed to meet the 2025 target, Duke said. It would close only 10% of the charger “gap” if the program were reduced to $33 million, including the bus funding.
The companies said they would locate half the chargers in low- to moderate-income communities and half in the state’s 80 most economically distressed rural counties.
The state has more than 1,400 publicly accessible, open standard Level 2 charging outlets but only 127 publicly accessible, open standard fast charging outlets, Duke said. The companies cited a recent study that found that about 20% of EV owners in California replaced their cars with gas ones, mainly because they found charging inconvenient. (See Study Examines Drivers Who Unplug from EVs.)
| Duke Energy
The proposal includes an EV supply equipment (EVSE) program modeled after Duke’s outdoor lighting programs, in which the companies will install and maintain EV charging equipment for customers.
“The companies’ outdoor lighting programs allow for low up-front cost and an all-in rate, which makes lighting simple and affordable for customers,” they said. “Similarly, the EVSE tariff pilot allows for low up-front cost, which makes EVSE installation affordable for customers. New chargers can be added to the tariffs at any time with commission approval or as extra facilities for non-standard equipment. Additionally, like outdoor lighting, the EVSE tariff allows for multiple vendor options and a wide project selection.”
The $25 million Phase I pilot approved by the commission last year was less than one-third the $76 million proposed by Duke.
It included deployment of up to 160 public Level 2 charging stations; 40 DCFC stations at 20 locations; and 80 Level 2 charging stations at multifamily dwellings.
The commission said it supported the programs to test public response to wider availability of public charging infrastructure and to acquire data on alternative implementation approaches. “In approving these three components of the ET pilot the commission is not sanctioning an open-ended or broad, general participation by Duke in the EV charging infrastructure market,” it said.
Texas lawmakers last week passed a pair of utility reform bills in response to the ERCOT grid’s near collapse during February’s winter storm, giving them more influence over the grid operator but also creating doubt over the measures’ effectiveness.
Senate Bill 2 would overhaul the ERCOT Board of Directors’ makeup, shrinking its members from 16 to 11 and task a selection committee, appointed by the governor, lieutenant governor and the House speaker, with choosing the independent directors. Nine of the 11 board seats would be voting members, giving state politicians more influence than before over the grid operator.
The provision emerged from a conference committee late Saturday night and was approved by both chambers Sunday.
“I am pretty upset by this massive change,” tweeted Cyrus Reed, president of the Lone Star chapter of the Sierra Club. “This should be debated in public, not snuck in a bill in the dead of night!”
The bill would still require all board members be Texas residents. The chair and vice chair have normally come from outside Texas to maintain separation from market participants and lend outside expertise. The board’s five non-Texans all resigned in February in the face of political and public outrage over their status. (See ERCOT Chair, 4 Directors to Resign.)
SB2 would further order that new protocols or revisions may not take effect until the Public Utility Commission approves their market impact statements.
A separate bill also approved Sunday, SB3, would require weatherization of power plants and some critical gas infrastructure, improve oversight of the electric industry’s supply chain, and create a statewide emergency alert system to better alert Texans to potential power outages.
The 87th Texas Legislature expired at midnight Sunday. Special sessions devoted to more controversial political issues are expected later this year.
Rep. Chris Paddie defends SB3 during debate before the Texas House of Representatives. | Texas House
Rep. Chris Paddie (R), who carried SB3 in the House of Representatives, said the bill targets “the systematic failures from wellhead to light switch” in addressing legislators’ three main priorities: oversight and accountability, communication failures, and weatherization.
“I don’t think it is acceptable for us to leave this session not having passed this bill and these reforms,” Paddie said during the debate.
While SB3 would require weatherization of power plant facilities, it would only ask the same of gas facilities identified as critical infrastructure by a supply chain mapping process. The Texas Railroad Commission (RRC), which critics say does more to protect the oil and natural gas industry than provide oversight, would be responsible with determining what upgrades to make. The bill does add penalties that range from $5,000 to $1 million for violations of the standards.
Several energy experts criticized the legislation as it unfolded, saying it ignored the fact that gas generation accounted for the bulk of outages that plunged the ERCOT grid into four days of blackouts. (See “Updated Storm Outage Report Minimizes Wind Energy’s Contribution,” ERCOT Technical Advisory Committee Briefs: April 28, 2021.)
“SB3 does an OK job of requiring regulatory bodies to develop weatherization standards and have rules and penalties in place. Those are good things,” Beth Garza, a senior fellow with R Street Institute and former director of ERCOT’s Independent Market Monitor, said during a media briefing last month. “What hasn’t been addressed is any kind of energy efficiency or demand-side actions to improve the usage, the lower and controlled requirements for electricity.”
“If there’s a take-home message for legislators to consider, are we requiring the gas plants, which were the biggest part of the outages, to winterize?” asked Daniel Cohan, an energy researcher at Rice University. “There’s been more to winterize the power plant side than the gas side. We’ll just have more plants that don’t have fuel to burn. It’s hard to see how this provides the full coverage of winterization that we need.”
At the same time, the House removed Senate language that would have charged renewable resources to provide ancillary services, currently covered by the market. Similar language targeting renewables for their intermittency is also not in the House version of SB3.
Jeff Clark, Advanced Power Alliance | Advanced Power Alliance
That pleased Advanced Power Alliance President Jeff Clark, who said this has been the most difficult legislative session he has lobbied. He complimented the House and Senate for working together to address February’s failures.
“[Rep.] Paddie and the House have thoughtfully worked with [the Senate] to find common ground on many issues, balancing many competing interests,” Clark said in an email to RTO Insider. “We hope that they will continue to consider the consumers, investors, communities and power generators who raised their voices of collective concern and not move backward on the improvements made to the bill.”
During a debate May 23, Paddie said the February disaster “opened the eyes of a lot of folks” to the interdependency between the electric and gas industries. “I think everyone can admit there were failures, in communication most importantly,” he said.
Garza referred to the dependency between the two industries as a “dysfunctional relationship.”
“One of the ways [SB3] can address that is by forcing those two industries to work together on a couple or three things,” she said. “Any product that comes out of forcing those two industries to work together and produce something is a step in the right direction.”
The RRC and PUC, which oversees ERCOT, water utilities and telecommunications, will be responsible under SB3 to work together in mapping critical infrastructure and helping develop an alert system that would be coordinated by the Texas Department of Public Safety.
No Electricity Market Changes — Yet
Under questioning from fellow representatives, Paddie said his committee purposefully avoided addressing the electric market’s structural issues to focus on oversight and accountability, communication and weatherization. He pointed out that the bill includes a section that would create a hand-picked select committee to review the various improvements being recommended and to deliver a comprehensive report by September 2022.
Any major changes to the ERCOT energy-only market would be the first since the legislature deregulated the electric industry in 1999 in an effort to reduce prices.
“If we’re going to make a decision in this body, I want to make sure we have all the information that is accurate,” Paddie said. “I really wanted us to push any discussion of market tweaks to a market that’s served us pretty well for 20-plus years, but that probably deserves a little bit of a look. We probably need to pop the hood and take a look at some potential tweaks … [but] we should proceed very deliberately and fully understand the full impact of those types of changes.”
SB3 would allow for a State Energy Plan Advisory Committee composed of 12 members selected equally by the governor, lieutenant governor and House speaker. The committee members would be asked to evaluate the market’s structure and pricing mechanisms, including the ancillary services market and emergency response services, and provide recommendations to remove barriers that prevent “sound economic decisions” and improve the grid’s reliability, stability and affordability.
Charlie Hemmeline, the Texas Solar Power Association’s executive director, agreed that any changes to the market are “complicated” and should be done in a “thorough, consolidated” way.
“Let’s take some time to look at some new things we need to add,” Hemmeline said. “It’s been 20 years since deregulation. What else do we need to do to reform this market, to be inclusive and create new products for new needs? Those are all good things. Let’s just make sure we are doing that in a thoughtful manner.”
An amendment to study the feasibility of ensuring significant reserves are available to the grid for emergencies only failed. Berkshire Hathaway Energy and Starwood Energy Group Global have both proposed building about 10 GW of natural gas facilities to provide backup power, funded by decades of monthly charges to customers. (See Berkshire Hathaway Offers Texas Emergency Power Supply.)
ERCOT Overhaul
The Legislature also agreed to SB2154, which would increase the PUC from three commissioners to five. A previous requirement that commissioners be “well informed and qualified in the field of public utilities and utility regulation” would only apply to two of the five commissioners.
Rep. Drew Darby (R), whose district consists of nine West Texas counties, failed in his attempt to amend the bill so that at least one commissioner hails from a county with 150,000 or less residents.
“If we don’t want them to be competent, at least let one of them come from rural Texas,” Darby said during debate last month.
Another bill securitizes $2.5 billion worth of bonds to help the ERCOT market recover some of its losses from February. The market was still short nearly $3 billion as of May 21, with bankrupt Brazos Electric Power Cooperative owing $1.88 billion.
A special session is already being scheduled in the fall to handle redistricting and allocating $16 billion in federal COVID-19 response funds. Legislation that doesn’t pass this biennial session could be added to the fall agenda.
PUC Sets Weekly Schedule for June
In anticipation of the pending legislation, the PUC has set up weekly workshops in June to “get ahead” of the rulemakings and scheduling issues.
“It’s fair to say there’s a lot of homework coming our way,” Commissioner Will McAdams said during the agency’s May 21 open meeting.
McAdams proposed that the “informal” workshops begin this Thursday, giving himself and Chairman Peter Lake, the only other current commissioner, an opportunity to discuss the February blackouts with PUC and ERCOT staff. The workshops have yet to be set on the commission’s calendar.
Texas PUC Commissioners Will McAdams (left) and Peter Lake discuss their plans in response to forthcoming legislation. | PUCT
The commission has a number of standing agenda items related to the winter storm and the coronavirus pandemic, including a review of wholesale-indexed retail products, gas-electric coordination, and reviews of a weatherization standards rulemaking, scarcity-pricing mechanism and critical load standards and processes.
Resource adequacy and transmission planning are already challenging using historical weather data; planning for climate change is on a completely different level, panelists told FERC on the first day of a climate-focused virtual technical conference June 1.
Romany Webb, Columbia University | FERC“Utilities and system operators have a long history of dealing with extreme weather and weather challenges, but climate change presents these cascading, compounding synergistic risks,” Romany Webb, associate research scholar and senior fellow at the Sabin Center for Climate Change Law at Columbia University Law School, said during the first panel of the day. “Because we have this new challenge, we need to rethink old planning approaches and adjust them and also develop new planning approaches.”
Stakeholders from across the electric industry uniformly derided the resource adequacy metrics currently used by grid planners and called for new approaches to safeguard the reliability of electric service. Speaking on the second panel, Richard Tabors, president of energy and economics consulting firm Tabors Caramanis Rudkevich, called planners’ analytic methodologies and models “woefully and grossly inadequate.”
FERC Chairman Richard Glick | FEThe discussion came on the first day of this year’s hurricane season, after the first named tropical storm of the year, Ana, already formed last month. It also comes amid warnings of another summer of severe wildfire conditions in the West, and on the heels of a rare winter storm in Texas in February that almost led to the collapse of ERCOT’s grid. These extreme weather events are expected to increase in frequency as climate change worsens.
“How do we better address the fact that utilities need to plan for these extreme weather conditions on a more frequent basis, and how they perform both from a planning perspective but also an operational perspective?” Chairman Richard Glick asked at the beginning of the conference.
Future Data, Historical Trends, Divergent Paths
FERC posed several questions to help guide the panels’ discussions. Among them was how can futures-based inputs — such as expected future load, weather and temperature — be projected more accurately, rather than simply extending historical trends forward.
During the first panel, Judy Chang, undersecretary of energy in the Massachusetts Executive Office of Energy and Environmental Affairs, noted the extra difficulty of predicting future load amid global efforts to electrify building infrastructure. “Heating and cooling loads will increase because we’re transforming our building sector and trying to use more electricity for heating and cooling,” Chang said. “Of course, we know heating and cooling are affected by weather events.”
Webb said the quality and availability of climate projections — “particularly downscaled climate projections that show impacts regionally and locally” — have improved significantly, but simply integrating some forward-looking projections into existing planning processes are unlikely to be sufficient. “Assuming a consistent average across every hour of the year doesn’t necessarily make sense when we know that extremes, particularly extremes in temperature, can affect those things.”
Jessica Hogle, PG&E | FERCJessica Hogle, federal affairs and chief sustainability officer for Pacific Gas and Electric, said her company and state regulators are working to identify a process that determines “what a good climate vulnerability assessment looks like; how do we incorporate and understand that data?” She said that assessment would detail exposure to extreme weather, assets’ susceptibility to climate-driven risks and adaptive capacity of infrastructure.
“A good way to think about that is a transformer sensitive to heat has relatively higher adaptive capacity because we can change that transformer relatively easily,” Hogle said. “However, a substation that is subject to sea-level rise has less adaptive capacity because we would either have to relocate it or raise it, and it would take more to be able to do that.”
FERC’s Role
The panelists advised FERC to incentivize interregional transmission planning, push for industry-wide adoption of best practices, and enhance the equitable sharing of data so that all utilities and RTOs can benefit from the latest technologies and expertise.
FERC should tell RTOs and utilities to “come up with a plan that incorporates the best climate data that you can get your hands on,” Chang said. “Maybe the first time around is not perfect, but having FERC say, ‘Come up with a plan that incorporates climate data,’ is a huge step forward that we haven’t had in this industry.”
FERC Commissioner Allison Clements | FERC
Commissioner Allison Clements asked about the relationship between local planning and system planning, and whether existing resource adequacy planning processes are appropriate to the challenges of managing a grid at increasing risk of weather-related disruption.
“In New York City we have a number of different climate change efforts that will be ongoing, but we benefit from having a consistent set of projections,” said Susanne DesRoches, deputy director of infrastructure and energy for the New York City Mayor’s Offices of Resiliency and Sustainability. “Those can be successfully embedded into the distribution network planning as well as at the NYISO level.”
DesRoches referred to a NYISO climate change study released last November, saying that such analysis “should be done consistently across the country.”
Telos Energy President Derek Stenclik also told Clements that planners should incorporate a climate trend in their projections but also go one step further with vulnerability assessments to evaluate “what-if scenarios.”
For example, “what if a four-day, low wind or solar event were to occur on the system? Does that impact system reliability?” Stenclik asked. “So, as opposed to the conventional approach of just doing the probabilistic inputs in the model and seeing what the expectation of reliability out of it is, go inverse and evaluate ‘what if’ scenarios and if they have a material impact on reliability. Then go back to climate folks and meteorological folks and ask if this is plausible in the future.”
If ERCOT had asked him to do a conventional resource adequacy analysis in Texas ahead of February’s blackout, “there is no way I would have caught the magnitude of that event,” he added.
Lisa Barton, AEP | FERC
American Electric Power Lisa Barton COO said that the more the regions lean on each other for assistance, the better positioned they will be.
“Your variable resources may be adversely impacted within your region or within that local utility, but go to the next RTO and all their wind resources are still spinning,” Barton said. “Having those strong interconnections and making sure you can lean on each other is part of the ‘no regrets’ solutions that, when we think about planning, we need to focus on. … We can use the RTO planning process, but absent FERC pushing on that, I think it won’t happen.”
FERC and state regulators can provide data and a blueprint of how utilities and RTOs/ISOs can do things, but “it is really important to recognize not everyone has the same resources that we have and that we are only as resilient as we are together; we are only as strong as our weakest link,” Hogle said.
Clements said that while she recognizes the “broad spectrum of overlapping resource adequacy authorities” at the state and federal levels, she asked what FERC should consider to encourage utilities to better assess vulnerabilities to extreme weather.
Stenclik said FERC has an opportunity to press regional coordination between different entities to make “consistent assumptions” on how to better count on each other for reliability and resource adequacy in extreme conditions.
“Some low-hanging fruit is to make sure that when resource adequacy results are shared, all the metrics are provided,” Stenclik said. “You don’t have to change the criteria, but you can at least report the data more holistically.”
1-in-10 Standard ‘Completely Outmoded’
A particular focus of speakers on the second panel was NERC’s so-called “one-in-10” standard, which requires the grid to have sufficient capacity “such that system peak load is not likely to exceed available supply more than once in a 10-year period.”
Given the multiplication of threats in recent years, particularly from shifting weather patterns because of climate change, Tabors said grid planning urgently needs to catch up to the current state of the science.
“There is a lot going on, and the fact that the industry still references an engineering-driven reliability standard of one day in 10 years is close to unbelievable,” Tabors said, explaining that the currently used models don’t consider factors such as the economic consequences of service interruptions while also relying on outdated assumptions of “unit outage independence” and weather trends.
Alison Silverstein, Alison Silverstein Consulting | FERC“We have to understand that there are probability distributions out there that we are simply not paying attention to … [and] we have to get [industry] not to ignore the fact we know more and are able to do more analysis now than has been the case in the past,” Tabors added.
Alison Silverstein, who was an adviser to former FERC Chair Pat Wood III and now has her own eponymous consulting firm, echoed Tabors, calling the one-in-10 standard “completely outmoded.”
“It’s generation-centric and ignores all of the other capabilities out there, including demand response and … the fact that we can actually enlist customers to control their demand and manage it in better ways,” she said. “It [also] ignores … the fact that the grid is much more energy-dominant and stochastic than it used to be, instead of just turning a dial and controlling a power plant.”
Mark Lauby, NERC | FERC
NERC Chief Engineer Mark Lauby also emphasized the expansion of technical capabilities on the modern grid, explaining that the one-in-10 standard was never considered the optimal way to approach system reliability. Rather, it was the product of technological limitations that no longer apply.
At “that time, in that computer space, [we] only had one event in 10 because that’s all you can model in a 1960s IBM [System/]360,” Lauby said. “Obviously now we can do hours and hours and hours of calculations. … We can model all the response we want.”
He added that new planning models must incorporate not only the impacts of climate change, but also the ongoing electrification of transportation, heating and other areas of modern life, as well as the growing diversity of the generation mix. All of these factors must be considered by planners trying to “figure out what the one in whatever is.”
Addressing Transmission Planning Shortfalls
Silverstein proposed a national transmission authority that would ensure consistent transmission planning processes and cost allocation across the nation.
“Our current processes and system are not working. … Making incremental changes means you’re saying the current process isn’t working,” she said. “Transmission planning and its inadequacies matter because our nation cannot achieve our decarbonization goals, period. We can make transmission more effective, and we can open up renewable resources with greater transmission, but more transmission is non-negotiable for the sake of achieving decarbonization.”
Clements jumped into the discussion to ask Silverstein for more specificity on her proposal and how FERC would work with a national entity. Silverstein replied that she has been thinking about the concept and is working on it, giving the impression that she is not ready to roll it out.
“Clearly it needs to be empowered by FERC and supported by the intellectual muscle and funds of the Department of Energy,” Silverstein said. “It’s FERC’s job to get transmission built, or to at least find effective ways to build transmission, and to also find the appropriate participation, definition of benefits and the cost allocation that comes out of that.”
She suggested FERC might want to determine whether it is just and reasonable to use outdated cost-benefit analyses or cost-allocation methods that don’t reflect transmission’s full scope of benefits.
“I think you have an obligation to pull people together and work on it,” Silverstein said.
But what about jurisdictional issues? Clements asked.
Richard Tabors, Tabors Caramanis Rudkevich | FERC
“Almost everything reliability-related is FERC jurisdictional,” Silverstein responded, “and that includes things like whether Texas has an interconnection to the rest of the nation and could have gotten a black start [during February’s winter storm] if it needed it. The answer is, ‘No.’”
Tabors said that until there’s an economic incentive for transmission owners to be creative and operate efficiently, the ability to plan transmission will be “stuck in a hole.”
“What we all agree to is wrong, [that] we have to build more wires and bigger wires to hook things up,” he said. “In reality, we have a ton of wires. Let’s learn to use them more efficiently. Let’s go back to the drawing board and say, ‘What do we expect transmission to do, and how do we want it to?’”
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:05-9:10)
Members will be asked to endorse the following manual changes and tariff revisions:
B. Manual 03: Transmission Operations, with revisions resulting from a periodic cover-to-cover review. Stakeholders endorsed the changes at the May Operating Committee meeting after complaints that PJM didn’t have the updated language available for the first read. (See “Manual 03 Changes Endorsed,” PJM Operating Committee Briefs: May 14, 2021.)
1. New Service Requests Deficiency Review Requirements (9:10-9:30)
Stakeholders will be asked to approve the proposed solution and tariff revisions to address deficiency review requirements for new service requests. PJM is proposing to change new service application deadlines to better manage the large number of requests. (See “New Service Requests,” PJM MRC/MC Briefs: April 21, 2021.)
State officials pursuing offshore wind projects said last week they are happy with support from the Biden administration but need additional federal help on transmission planning and designing clean energy markets to support the infrastructure.
Commissioner David Lehman, Connecticut Department of Economic and Community Development | Connecticut DECD
Officials from Connecticut, Massachusetts, New Jersey, New York and Virginia spoke on a panel at the Reuters U.S. Offshore Wind 2021 conference, two weeks after the Bureau of Ocean Energy Management gave final approval for the Vineyard Wind project, which had been delayed by the Trump administration. The approval made the 800-MW Vineyard Wind I the first commercial-scale offshore wind project to win approval in the U.S.
“It’s a whole different ball game at the federal level now than it was two or three years ago,” said David Lehman, commissioner of the Connecticut Department of Economic and Community Development.
“There’s a ton of momentum here,” agreed Tim Sullivan, CEO of the New Jersey Economic Development Authority. “There’s going to be a North American, North Atlantic offshore wind energy patch that creates a regional industry of great consequence, in a way that fossil fuels have done for the Gulf [of Mexico]. The [potential] from a job creation perspective is extraordinary.”
But Kathleen Theoharides, secretary of the Massachusetts Office of Energy and Environmental Affairs, said long-term transmission planning will be necessary for offshore wind to succeed and states to meet their clean energy targets. “That need is arguably the most significant barrier to offshore wind buildout in the region and has been a real focus for Gov. [Charlie] Baker and our energy team,” she said. “Guidance from FERC to the regional ISOs around the country around the design of clean energy markets and transmission planning is a key piece where the feds could step in and be very helpful.”
Awarded offshore wind capacity and long-term targets | BloombergNEF
John Warren, director of the Virginia Department of Mines, Minerals and Energy, said inadequate transmission could increase financing costs. “I see a scenario where our ability to make generation infrastructure far outpaces our ability to distribute the generation,” he said. “It’s almost like we’ve gotten really good at building cars, but we don’t have enough roads to drive them on. When it reaches that tipping point, it could impede the further growth and the momentum.”
NYSERDA CEO Doreen Harris | Reuters
Doreen Harris, CEO of the New York State Energy Research and Development Authority, said states pursuing OSW are “grappling with [the] need to walk and chew gum at the same time. … We cannot pause our generation projects and the infrastructure and the investments that we’re all making to wait for coordinated transmission to emerge and be available. But there are smart ways to do both in parallel. … I see them as two lanes that will travel in parallel and eventually merge. That’s really what we are doing when we look at transmission planning.
“These are …. incredibly complex projects to advance, but they are indeed necessary for the ultimate buildout on the scale that we are looking at,” she continued. “It’s one of the reasons that New York is looking at emulating some of the mesh transmission solutions utilized in Europe, because it allows us to move our projects forward and ultimately build the grid … as the projects are built themselves.”
Lessons Learned
Theoharides also shared the lessons learned in Massachusetts, which has conducted three OSW procurements since 2018.
“One strategy we’ve used … is giving us enough time between procurements so that our Department of Energy Resources can continue to refine our procurement process. And we’ve done that since the first project was selected.”
Secretary Kathleen Theoharides, Massachusetts Office of Energy and Environmental Affairs | Reuters
After the Trump administration delayed approval of Vineyard Wind’s permit in 2019, Theoharides said, “developers put in much [longer] timelines for going through the federal permitting process.”
She said the state had benefited from feedback from a wide range of stakeholders, including fisheries, wind developers and environmental justice communities.
“For example, the [request for proposals] issued earlier this month for the third solicitation now allows [proposals of] 200 to 1,600 MW — doubling the [size] of the previous solicitation — consistent with findings … that by allowing larger-size bids, we could capture some potential efficiencies related to cabling [and] the use of [on-land] connection points.
“For our latest RFP … we’ve made significant revisions to strengthen criteria regarding impacts and benefits to environmental justice communities,” she added.
Connecticut’s Lehman asked whether the states might obtain lower prices from developers by conducting joint procurements. “I think that’s a possibility and something we’d be eager to discuss in Connecticut,” he said.
“We are very interested in regional procurements in Massachusetts,” Theoharides responded. “And we have been talking to our legislature about including that in future” procurements.
30 GW by 2035?
Before the state officials’ panel discussion, the conference heard a presentation from Imogen Brown, the head of BloombergNEF’s offshore wind research, who predicted fast growth in the U.S. — but not fast enough to reach Biden’s target of 30 GW by 2030.
BloombergNEF expects global offshore wind to grow from 36 GW in 2020 to 206 GW in 2030, led by China, the U.K., Germany and the U.S. | BloombergNEF
Global OSW is likely to grow from 36 GW in 2020 to 206 GW in 2030, a 19% compound annual growth rate, she said. The surge will be led by China, the U.K., Germany and the U.S., the last of which will have 24 GW by 2030, she said.
“This is significant growth from where we are — almost at nothing — today. And we expect the U.S. by 2030 to account for about 11% of the offshore wind market.”
Bloomberg expects the market to “get kickstarted around 2024” with Vineyard, the 1,100-MW Ocean Wind project off New Jersey and 704-MW Revolution Wind off Rhode Island.
“If you compare it to a market like the U.K., which is very well established — it has been commissioning offshore wind projects for decades … essentially the U.S. is skipping this ramp-up period. It’s going big and going big quickly. If you compare it to Germany, it looks about double Germany’s installations across the second half of the decade.”
Bloomberg predicts the U.S. will add about 3 GW of OSW annually from 2025 to 2030, short of the 5-GW average needed to reach the 30-by-2030 goal.
Imogen Brown, BloombergNEF | BloombergNEF
“We view the U.S. offshore wind market as a very state-led game; they’re the ones that are procuring offshore wind capacity. And they’re the ones that are setting targets,” Brown said.
The states driving currently driving OSW are New York, with a target of 9 GW; New Jersey (7.5 GW); Massachusetts (5.6 GW); Virginia (5.2 GW); Connecticut (2 GW); Maryland (1.2 GW); and Rhode Island (400 MW).
Bloomberg conducted an assessment to predict which states might be next to join the OSW trend, evaluating factors including resource potential, power prices, onshore wind saturation and renewable energy policies. Based on all the criteria, it ranked California top in the “next phase markets,” followed by New Hampshire, Maine, Oregon and Hawaii.
Delaware, Ohio, Michigan, Pennsylvania, Washington, Illinois, Texas, Louisiana and South Carolina were ranked lower as “potential markets.”
CPS Energy is celebrating a pair of victories in its battle with ERCOT over the nearly $50 billion in market transactions during the February winter storm.
A Bexar County district court on May 21 agreed with the San Antonio municipal utility that it has the legal right to sue ERCOT over the grid operator’s alleged “serious violations of Texas law, Texas statutes, contractual obligations and the Texas State Constitution.” ERCOT claimed sovereign immunity in asking the court to dismiss the case and allow the proceedings to take place before the Texas Public Utility Commission.
A CPS Energy crew works to restore power following the February winter storm. | CPS Energy
The same court on May 21 also rejected ERCOT’s request to change the proceeding’s venue to Travis County, where the grid operator is headquartered. Instead, the case will continue to be litigated in Bexar County, where San Antonio is located (2021CI04574).
Judge Solomon Casseb issued his decisions in two single-page orders after hearing oral arguments from both parties.
“Tuesday’s ruling underscores the strength of CPS Energy’s case against ERCOT, and I look forward to the people of San Antonio having an opportunity to hold ERCOT accountable for its errors during and after the storm,” San Antonio Mayor Ron Nirenberg said in a statement issued by CPS.
“What ERCOT did was wrong, and it continues to refuse to correct its own acknowledged errors, including roughly $16 billion in illegitimate charges,” CPS CEO Paula Gold-Williams said. “CPS Energy looks forward to continuing to fight for our Greater San Antonio customers and Texans across the state.”
ERCOT has claimed sovereign immunity as the lawsuits have piled up following the storm, noting it is funded by generators’ transaction fees. The Texas Supreme Court in March declined to rule on an appellate ruling granting ERCOT immunity from lawsuits. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)
The grid operator said the appeals court “clearly demonstrated” its sovereign immunity and said it expects the Texas high court to “ultimately … confirm this.”
“ERCOT is neither concerned nor surprised by the recent Bexar County ruling,” spokesperson Leslie Sopko said. “Lawsuits like this only increase costs, which are ultimately passed on to all Texas end-use customers, including CPS Energy’s own customers.”
“A city-owned utility cannot be asked to unlawfully extend its credit to help settle the debts of other entities, especially in cases where there is no chance of being repaid,” CPS said.
CPS is the nation’s largest public utility, providing service to more than 884,000 electric and 366,000 natural gas customers.
It is also involved in 17 lawsuits with gas suppliers over $700 million in bills. The utility on Wednesday issued another statement from Gold-Williams accusing Enterprise Products Partners of “predatory price gouging” by inflating its natural gas prices by as much as 12,000% during the storm. She said CPS has already paid Enterprise $36.5 million, but the gas supplier is suing to collect nearly $100 million more.
“Enterprise held these exorbitant prices in place knowing full well that public utilities, such as CPS Energy, had no choice but to continue to buy,” Gold-Williams said. “CPS Energy’s legal positions are based on longstanding legal doctrines, deeply rooted in Texas law: Price gouging during a declared disaster is a violation of public policy, and the exorbitant prices charged by Enterprise are unenforceable because they are unconscionable.
“We at CPS Energy will not pass the higher, unlawful part of the charges to our customers only to further fatten Enterprise Products’ bottom line.”
A Midwest wind energy developer has filed a complaint with FERC over SPP’s practice of allocating network upgrade costs, alleging that an unexpected $66 million increase slapped onto its wind farm is unjust and reasonable (EL21-77).
Tenaska Clear Creek, an affiliate of Nebraska-based Tenaska, filed the Section 206 complaint May 21. It is asking the commission to halt a multiyear affected system study process that it said “has been characterized by systematic errors, irregularities and delays.” The company said an SPP restudy report assigning the project about $99 million in upgrades — including $66 million to address reliability issues that predate the facility’s interconnection — is “untenable.”
Tenaska’s Clear Creek Project in northern Missouri is the subject of a complaint over SPP transmission planning practices. | Tenaska
Tenaska said it filed the complaint after failing to resolve the matter with SPP and that it hoped the proceeding at FERC would help parties develop a “mutually acceptable solution.”
“Tenaska believes FERC will agree that allocating to Tenaska Clear Creek 100% of the financial consequence of SPP’s actions and the passage of time is unjust and unreasonable and should not be allowed,” Tenaska spokesperson Timberly Ross said in an email.
The 242-MW Clear Creek Project went into commercial operation in May 2020. It is interconnected with the Associated Electric Cooperative, Inc. system in northern Missouri.
According to Tenaska’s complaint, SPP’s initial studies identified about $16 million in network upgrades associated with the Clear Creek project, but the grid operator later more than doubled the cost to $34 million. When a higher-queued project withdrew, SPP’s preliminary restudy assigned $763 million in upgrade costs, a figure that was revised several times down to about $99 million.
Tenaska alleged the withdrawn projected did not affect Clear Creek’s network upgrade cost responsibility. It said the “dramatic” cost increase was a result of SPP’s decision to restart the study process with a new set of models and assumptions. They included adding in 4.5 GW of generation resources that SPP said was omitted from the project’s initial studies, according to the complaint.
Nick Borman, Tenaska’s senior vice president of engineering and construction, said in a statement that the complaint was filed with “reluctance” to raise the broader question of the “appropriate method of allocating interconnection upgrade costs” to FERC’s attention.
“If renewable, or for that matter any, generation projects are to be added to the country’s generation base, certainty around interconnection costs is critical,” Borman said. “We hope FERC will realize that other, more equitable solutions are readily available that will provide the certainty needed for such investments to continue to be made.”
Tenaska warned that inaction by the commission “will certainly impact decision-making by developers of renewable projects on the SPP system and elsewhere.”
An SPP spokesperson said the grid operator is reviewing Tenaska’s complaint and is not yet ready to comment on it.
Rob Gramlich, Grid Strategies | ACORE
“I know FERC is asking a lot of questions about this, and I am hopeful that we will see some proposed reforms soon,” Grid Strategies President Rob Gramlich told RTO Insider.
The report says current planning processes are not designed to identify the best methods for getting renewable energy to load. It emphasized the need for a “centrally coordinated and integrated” planning process.
“There is a basic structural problem across most ISO/RTOs because of the reactive project-by-project or cluster-by-cluster approach,” Gramlich said. “RTO planners need to turn on the headlights and plan for future needs, like planners of any public utility do.”
Like other grid operators, SPP has added staff as it struggles to work through an interconnection queue with projects dating back to 2017. As of April, the backlog included 451 interconnection requests totaling 79.9 GW of capacity.
Stakeholders have complained about restudies following a project’s withdrawal, which often happens when projects are assigned high network upgrade costs. Stakeholders and staff are working together on long-term planning recommendations to re-engineer the transmission planning processes. (See “GI Backlog a Pressing Issue,” SPP MOPC Briefs: April 12-13, 2021.)
“Interconnection costs are wildly variable and hard to predict, so it is no wonder developers put in multiple requests. At the same time, the RTO planners are pulling their hair out over multiple requests and projects dropping out of the queue all the time.” Gramlich said, calling the situation an indication of a “dysfunctional and inefficient process.”
The Biden administration is taking a whole-of-government approach to meeting its goal to deploy 30 GW of offshore wind by 2030, a top federal energy official said Wednesday.
Speaking at the Reuters’ U.S. Offshore Wind 2021 conference, Acting Assistant Secretary of Energy Kelly Speakes-Backman said the road to 30 GW by 2030 could pave the way for the U.S. to become a net-zero economy by 2050, given that the fastest — and most cost-effective — way to get there is the decarbonization of the electric grid.
The effort could also trigger billions in capital investment, create tens of thousands of jobs, generate enough renewable energy to power millions of American homes and significantly reduce carbon emissions. Reaching the target will require the federal government’s close coordination with states, private-sector partnerships, unions and other key stakeholders to scale up efforts from concept to construction.
Speakes-Backman said that much of the near-term carbon-free energy is going to be onshore wind and solar PV, though “that’s not going to be enough.”
“We need every clean energy resource we can get to address this climate emergency,” she said.
On Tuesday, the Biden administration announced plans to offer leases for California’s first OSW areas, a 399-square-mile block off Morro Bay that could support 3 GW of resources; the Humboldt Call Area off Northern California is big enough for an additional 1.6 GW. (See BOEM to Offer Leases for Calif. Offshore Wind.)
“[Tuesday’s] announcement is so significant because this wasn’t the Department of Interior in California saying, ‘We are going to advance offshore wind in the Pacific,’” said Amanda Lefton, director of the Bureau of Ocean Energy Management. “This was the Department of Interior with the Department of Defense, coming together with us and California to say that ‘We are aligned, and we have a path.’”
Lefton called it “a sea change for all of us.” Expanding to new lease areas is vital because the East Coast has been the primary OSW focus, including the recently approved Vineyard Wind I project off the coast of Massachusetts. She said BOEM is looking at future OSW opportunities in the Gulf of Maine, Gulf of Mexico, the Carolinas and Hawaii.
Lefton also anticipates BOEM issuing a proposed sale notice for New York Bight, an area between Long Island and New Jersey, followed by a public comment period and an auction late this year or in early 2022. BOEM plans to advance new leases and complete a review of at least 16 construction and operations plans by 2025, representing more than 19 GW of OSW.
Nicole LeBoeuf, acting assistant administrator for the National Oceanic and Atmospheric Administration, said there is “real momentum” to put resources toward whole-of-government collaborations. NOAA helped BOEM with data to advance the work on the California leases. NOAA signed a memorandum of agreement with Ørsted to share data in its leased waters subject to U.S. jurisdiction. This first-of-its-kind agreement between an OSW developer and NOAA clears the way for future data-sharing agreements with other developers. NOAA anticipates the data will fill gaps in areas such as ocean mapping and observation to advance climate adaptation and mitigation, weather-readiness, healthy oceans, and resilient coastal communities and economies.
“We know that these collaborations have been ongoing, but to have those marching orders from the top to [encourage] ‘whole-of-government’ [efforts] is super liberating,” LeBoeuf said. “If you’re sensing enthusiasm, it is because it’s real, and we’re just really ready to get started.”
Ruth Perry, business environment adviser at Shell, said the Biden administration’s 30-by-30 goal has “got everybody energized.” She added that federal and state coordination, interagency collaboration and private-sector partnerships could help the U.S. become a leader in a renewable energy, in addition to setting “national objectives of how we’re going to get there.”
Meeting 2050 emissions goals in the U.S. will require a “swift, maximum certain transition out of all fossil fuels, including natural gas,” in the building sector, former New York Public Service Commission Chair John Rhodes said Thursday.
Buildings account for about 30% of U.S. emissions directly, but that number is even higher with the indirect emissions of electricity from the current generation mix.
“As we clean up buildings … it’s really an appreciating asset, because the more electricity becomes the fuel for buildings, and the more electricity decarbonizes, you get a double reinforcing effect,” Rhodes said during a Columbia University webinar, “Getting the Gas Sector’s Energy Transition Underway.”
Transitioning buildings fully to electricity, according to Rhodes, must be an immediate-term priority that focuses on practical alternatives to fossil fuel use for cooking and space and water heating.
“For many building types — especially for new construction but also for some retrofits — a lot of electrification is practical now,” he said. “There’s clearly a justified call for marching in the direction of going strong now.”
There is also a need for solution development that goes beyond energy efficiency, he said.
John Rhodes, former Chair of the New York Public Service Commission. | Columbia University
“Efficiency for natural gas typically means another, albeit more efficient, natural gas appliance to take the place of an expiring current one,” he said. Demand response for gas service, he added, is “practically nonexistent” and “heat pumps need further development.”
Rhodes also said that renewable natural gas and hydrogen are “not ready for prime time.”
As potential resources, they deserve meaningful R&D investment he said, but they cannot be the justification for building new infrastructure.
The best ways to bridge gaps in the fossil fuel transition will be policy support and targeted investments, he said.
“Policy support should be our best, most pragmatic assessment of the portfolio, whether it’s rebates, subsidized financing, organizing the markets to boost uptake, addressing regulations that impede electrification [or] developing the workforce,” he said.
At the same time, regulations and standards should minimize natural gas infrastructure development.
“We need to get to the point where, not only are we doing things through the energy regulatory utility instruments, but also through building codes and building permits,” he said.
Regional Studies
Regulators in California, New York and Massachusetts opened investigations on the transition from gas last year, and Washington State is working on a study plan.
“This year, Gov. [Jay] Inslee signed legislation that directs the [Washington Utilities and Transportation Commission] to initiate a study looking at how we can reduce emissions in the natural gas sector consistent with [the state’s] carbon reduction targets,” Commission Chair David Danner said during the webinar. The study is due in mid-2023.
Decarbonizing a carbon-based industry like natural gas is a unique challenge, he said.
While the commission’s study is far from ready to provide insights into that challenge, Danner sees two immediate priorities.
First, states need to review the policies that promote the use of natural gas or give an advantage to natural gas over other fuels, he said.
Many states have codified affordable natural gas service for their citizens, and that has created conflict with new climate policies. Washington, however, changed its policy to say that its citizens are entitled to “affordable energy,” Danner said.
Subsidies that come from existing natural gas customers to pay for connecting new customers also need reconsideration. Developers, Danner said, should pay the full cost of gas connections.
“Let’s see how natural gas fares in the market and give alternatives like electric appliances and heat pumps a shot,” he said.
Second, states need to reduce emissions in the existing gas system.
“We have to be better at plugging leaks in the gas system,” he said, adding that Washington’s utilities are pursuing a pipeline replacement plan that has proven effective.
Tension is inevitable when states have a dual responsibility of reducing investments in fossil fuel infrastructure and safeguarding existing infrastructure, he said. “We are not going to interrupt pipeline replacement plans because safety is too important for us to really slow down on, but that is a conundrum that we have to face going forward.”
Massachusetts has been trying to deal with the conundrum since a 2018 gas explosion killed one man and injured two dozen people in Merrimack Valley.
About a year after the accident, Brookline, Mass., passed an ordinance that prohibited new or restored buildings from having natural gas service.
Attorney General Maura Healey, however, concluded that the ordinance was not consistent with Massachusetts law. Healey decided that the state needed a comprehensive plan for natural gas use as the state transitions to net zero emissions.
Having towns address gas service “piecemeal” concerned the AG’s office, Rebecca Tepper, energy and environment bureau chief at the AG’s office, told the webinar. “We urged the [Department of Public Utilities] to implement a plan to ensure that the natural gas transition happens in a way that is safe, reliable and fair for all customers.”
Last October, the DPU issued an order to open an investigation into the future of natural gas. The order directs the state’s local gas distribution companies to submit a proposal by March 2022 with recommendations and plans for “helping the commonwealth achieve its 2050 climate goals.”
While that investigation is going on, the AG’s office is thinking about regulatory changes that Tepper said “might be necessary” for natural gas planning. To support its thinking on those changes, the AG’s office is holding a virtual think tank on June 10 and June 17. Participants will discuss forecasting; continued investment in gas pipeline repair, replacement and new infrastructure; and whether gas and electric planning should be integrated.
The city of Beverly, Mass., is advancing its fleet-wide electric school bus changeover for the district in July with the addition of its second of 48 buses.
Beverly tested its first electric school bus starting last October after entering into a lease agreement with Highland Electric Transportation. The company helps school districts afford electric school buses by leasing them out annually and using vehicle-to-grid (V2G) incentives.
Highland purchases all the power for the buses and uses V2G technology to sell power back to the grid when demand is high. Payments from utilities go back to the school district to offset the upfront cost of electric buses.
Dana Cruikshank, director of transportation for Beverly Public Schools, told NetZero Insider he could “smell the difference” between the district’s electric bus and its traditional diesel buses. Battery powered electric buses reduce the amount of emissions school kids are exposed to, and they are quieter than traditional combustion engines.
“The elementary school kids call it the ‘magic bus,’” Cruikshank said, because the bus driver and students can have conversations without yelling over the sound of a traditional combustion bus engine.
The Beverly School District in Massachusetts is adding an additional electric school bus to its fleet in July after a successful six-month start with its first electric bus. | Beverly Public Schools
The school bus charges overnight on a smart charging system in Beverly’s bus yard that powers on when the buses are below 100%. It takes the bus three hours to charge completely, and it will run for 125 miles before it needs to charge again.
The lease payment includes the cost of electricity and repairs, which “makes the buses affordable to us,” Cruikshank said. “We’re not a huge district.”
While electric buses are more expensive to purchase than diesel buses, lower maintenance and operations costs make the transition more affordable in the long term for school districts, Cruikshank said.
“Anything new we purchase will be electric,” he added.
The Beverly School District’s electric bus project was Highland’s first as a company. And because it has been successful, the project “put us in a position to do much larger projects,” said Matt Stanberry, managing director of market development at Highland.
Montgomery County’s public schools in Maryland struck a deal with Highland in February to lease 326 buses over four years and eventually replace its entire 1,422 bus fleet, making it largest purchase of electric school buses in the U.S.
“We’re really happy about how the project has unfolded in Beverly,” Stanberry told NetZero Insider. “They are in a good place for electrification for the school district going forward.”
The V2G capability adds a “new, interesting and important value stream for schools,” he added, because it lowers the cost for the electric bus service.
Highland is also installing a 360-kW fast charging station in Beverly that will go live next month. The station will be the first of its kind at that power rating, according to Stanberry.
FERC Order 2222 opened value streams by enabling distributed energy resource (DER) aggregators to participate in wholesale electric markets.
“That’s what we need to see from ISO-NE,” Stanberry said. “But we need a continuous participation model that gives resources credit for their value in reducing load and generating power.”
Highland is working to maximize all the resources school buses can provide to lower the cost of electrification for schools.
There are more than 480,000 school buses in the U.S., which adds up to a lot of battery storage capability.
FERC Order 2222 should allow DER resources to adjust their energy offers closer to real time, so they don’t face penalties, Stanberry said. “Getting those details right is really important to us.”
