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November 1, 2024

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EPA Power Plant Proposal Gets Mixed Reception in Comments

EPA was deluged with comments Tuesday on its proposal to limit greenhouse gas emissions from existing plants, with supporters and opponents urging changes to what the agency produced. (See EPA Proposes New Emissions Standards for Power Plants.)

Filing as the “Joint ISOs/RTOs,” four organized electricity markets — ERCOT, MISO, PJM and SPP — told EPA that the power plant rule could exacerbate the trend of retirements outpacing the commercialization of new resources needed to produce vital reliability attributes.

“The Joint ISOs/RTOs have long been at the forefront of renewable energy integration but have seen an increasing trend of retirements of dispatchable generation, which provides critical attributes that are needed to support the reliable operation of the grid,” the grid operators said. “Although each region is working to facilitate a substantial increase in renewable generation, the challenges and risks to grid reliability associated with a diminishing amount of dispatchable generating capacity could be severely exacerbated if the proposed rule is adopted.”

While EPA has created subcategories of dispatchable generation in an attempt to stagger retirements, its rule assumes that new, low-greenhouse gas substitutes will be available, and that existing plants will be able to retrofit with carbon capture and storage (CCS) or co-fire with clean hydrogen. The grid operators said the proposal overstates the commercial viability of CCS and clean hydrogen while ignoring the cost and practicalities of developing new supporting infrastructure.

EPA should do additional analysis and address the potential reliability impacts of its proposal before moving forward with a final rule, the Joint ISO/RTOs said. If EPA decides to go forward, the grid operators suggested that it allow for a new sub-category of existing units, which are needed for local or regional reliability until alternatives are running that address the reliability issues. ISOs and RTOs would identify such units, in a process similar to reliability-must-run agreements.

“To be clear, the reliability sub-category is not a panacea,” the Joint ISO/RTOs said. “It still would leave generation owners with considerable uncertainty as they assess the long-term future of market participation.”

But the reliability sub-category could keep some generation that would put reliability at risk if it retired too early running while viable alternatives are developed and can be deployed economically and practically, they said.

The agency should also build a regular technology review into the rule to determine whether CCS and hydrogen-fired generation are developing quickly enough to meet compliance timelines, the grid operators argued. That would help balance the pace of retirements with needed replacements, they said.

The rule suggests states could develop allowance trading systems, but the ISO/RTOs said it should provide specific recognition of allowance trading on a regional, if not national level to allow for greater flexibility and to allow units that can “over comply” early to do so (and sell any excess allowances that leads to).

The Joint ISO/RTOs also want a tweak to the proposal’s definition of a system emergency, which would apply under “any abnormal system conditions.” That “abnormal” is unnecessary because grid operators already have to determine that the generator in question was needed for reliability, they said.

ISO-NE filed its own comments, which noted that while it had lacked the time for a complete analysis of the rule, it believes some of EPA’s proposals could actually work against reducing emissions. When it comes to natural gas power plants, the proposal is focused on combined cycle plants above 300 MW that operate more than half the time.

“The resulting effect is a shift in generation from these large EGUs [electric generating units] to the smaller, less efficient EGUs,” ISO-NE said.

ISO-NE’s modeling assumes all coal generation will be retired by 2032 and the grid will have less generation from large gas plants, which means the grid will rely on active demand response (ADR) much more often than it does now.

“If ADR resources dispatch as often as they are in the results of the ISO’s analysis (a large increase from today), some resources may no longer choose to provide ADR,” ISO-NE said. “In the absence of ADR, other load in this model would go unserved.”

EPA has not released a related rule on how it plans to regulate smaller natural gas plants, and ISO-NE said it was difficult to determine how its system would be impacted without those details.

Broad Opposition to CCS

A diverse array of stakeholders challenged EPA’s designation of CCS as a best system of emissions reduction (BSER), arguing the technology has not been “adequately demonstrated,” as the proposed rule states.

Representing a consortium of environmental justice and conservation groups, the Clean Energy Group (CEG) argued that carbon capture could increase greenhouse gas emissions. “Because of the additional fuel needed to power CCS equipment itself, electricity generation paired with CCS requires up to 44% more fuel than standalone power generation,” it said. Emissions of nitrogen oxides (NOx) and particulate matter, generally not captured by CCS technology, would also increase.

Leading a group of five other unions, the International Brotherhood of Boilermakers pointed to the $2.5 billion in the Infrastructure Investment and Jobs Act (IIJA) for CCS demonstration projects as clear evidence that the technology is not at commercial scale, nor is likely to be within the time frames the rules suggest.

Power plants with a retirement date of 2040 “would need to begin preparations for a major CCS retrofit project — engineering, financing, permitting and related activities — as soon as possible following a final rulemaking,” the unions said.

EPA’s requirement that these plants capture and sequester 90% of their CO2 emissions “itself is objectionable because these units likely differ widely in age, size, capacity factor, access to suitable CO2 storage capacity, and the technical and economic feasibility of retrofitting CCS.”

Other commenters pointed to the lack of adequate pipelines and storage facilities and the lead time needed for buildout.

Mississippi’s Office of Pollution Control suggested that the agency’s promotion of both CCS and hydrogen were intended to build demand for the technologies as a means to justify the incentives they would receive from the IIJA and the Inflation Reduction Act.

“However, the cost and feasibility of constructing thousands of miles of pipeline to address the CO2 and hydrogen infrastructure requirements is not contemplated in the proposed rules or regulatory impacts analysis. EPA provides no substantive evaluation of the environmental impacts constructing thousands of miles of additional pipeline will have, including additional air emissions that may be generated from compressor stations required along these pipelines or associated with sequestration and storage facilities.”

Even the Carbon Capture Coalition, an industry advocacy group, said that while EPA’s time frame for getting CCS projects planned and online is possible, “there are several potential economic and practical delays due to project permitting and financing. EPA should clearly specify what happens when factors outside the owner’s control delay construction or operation of a carbon-capture system.”

The coalition called for “a cohesive national plan” for CCS buildout.

“We urge EPA to work with states to make available supportive infrastructure and a robust and timely permitting process to deploy carbon-capture technologies not only at individual facilities but in a coordinated regional manner.”

EEI Offers to Work with EPA

The Edison Electric Institute said that while its members are committed to cleaning up the grid, with 41 having committed to getting to net-zero emissions by midcentury, some elements of EPA’s proposal need to change to get that job done while maintaining reliability.

“While there are challenges presented by the proposed [Clean Air Act Section] 111 rules, these challenges are technical in nature,” the investor-owned utility trade group said. “EEI and our member companies share EPA’s goals of continuing to reduce emissions from the power sector and of achieving an economy-wide clean energy transition.”

Current technologies can support a continued decline in emissions from generation over the foreseeable future, but getting to net zero is going to require the development of technologies that are not commercially feasible today, EEI said. CCS and hydrogen blending have yet to be adequately demonstrated and are not deployable, available or affordable across the entire industry, and they require significant infrastructure outside of the power plants to work, it said.

EEI supports the proposal’s use of subcategories, which in the case of coal units are based on their operating horizon or when they plan on retiring, and one of the categories caps plant’s capacity factors. Coal plants running past 2040 would need 90% CCS, with declining standards for those that retire earlier. While EEI has some quibbles with those specifics, it noted that EPA’s much less flexible approach to large natural gas units is not supported.

“EPA’s inflexible, rate-based approach to regulating existing natural gas-based turbines presents significant challenges and is likely to result in perverse outcomes that are inconsistent with EPA’s larger emissions-reductions goals,” EEI said. “EPA’s failure to offer similar compliance flexibilities to existing natural gas-based turbines as those offered to states for existing coal-based units is fundamentally arbitrary.”

Gas units provide some of the same key grid services that coal plants do, but they are also more flexible and thus help in balancing intermittent renewable power, EEI said. EPA should develop and provide a full range of flexibilities in compliance for natural gas units, it argued. By the 2030s, such plants will either have to make costly, long-term investments or agree to capacity factor limits that will make them unavailable to help meet growing demand from electrification, which the industry is already experiencing. The power industry would have to turn to less efficient power plants to meet demand, it said.

“Under several plausible scenarios, this could result in an aggregate increase in emissions during the 2030s, at the expense of reliability,” EEI said. “This is an outcome that should be avoided by the agency.”

EEI noted that it had a limited amount of time to file comments on the rule, and it would continue to update its analysis and keep EPA in the loop on those efforts. EPA should also pay attention to FERC’s annual reliability technical conference in November, which the commission announced would cover the impact of EPA’s proposal.

Other Power Sector Trade Groups More Skeptical

The Electric Power Supply Association (EPSA) told EPA that it should give weight to its comments as its members own and operate power plants and thus are going to be responsible for the costs of implementing any final rule. The trade group said that implementation of the proposal would degrade reliability at a time power demand is growing.

“This proposed rule is intended to reduce emissions,” EPSA said. “However, while indirectly boosting investment in renewable energy, the proposal may negatively impact emissions reductions by rewarding less efficient existing power plants and hampering the use of existing lower-emission resources. Further, retirements of existing fossil fuel resources may occur before adequate replacement resources of any/all types are constructed, raising genuine concerns about electric grid reliability in the near and midterm.”

While many might dismiss the reliability concerns as voiced by directly impacted generators, EPSA said, FERC, NERC and the ISO/RTOs have made the same kind of arguments. FERC Commissioner Mark Christie recently told the Senate that the industry is headed toward a reliability crisis. (See Senators Praise Philips, FERC’s Output at Oversight Hearing.)

The lynchpins of compliance in EPA’s proposal are co-firing hydrogen and CCS, but those are emerging technologies, the group said.

“As a practical matter, robust CCS/hydrogen co-firing industries will need to be built almost from scratch, and the proposed rule requires those technologies be counted on in an unworkable and unrealistic time frame,” EPSA said. “They are not ‘adequately demonstrated’ by any real-world definition, and it is critical that the fundamental impediments to the technologies given the timelines outlined in the proposal be addressed and mitigated.”

The National Rural Electric Cooperative Association (NRECA) told EPA that it should withdraw its proposal, arguing that it exceeds the agency’s authority and would jeopardize reliability by requiring the industry to shift too early to technologies that are not commercially viable.

“Under the Clean Air Act, EPA’s standards must be adequately demonstrated, achievable and cost effective,” NRECA said. “Its proposed best systems of emission reduction in the form of carbon capture and storage, co-firing clean hydrogen or co-firing natural gas all fail to meet these criteria.”

CCS has promise, and NRECA members have been involved in deploying it, but it is not ready to capture 90% of the emissions from the nation’s coal- and gas-fired power plants, the group argued.

The proposal “is also heavily reliant on outside-the-fence-line infrastructure that does not currently exist and will not exist by the proposed compliance dates,” NRECA said. “Clean hydrogen is even further behind CCS in its development. There is currently no supply of clean hydrogen to meet EPA’s standards.”

NRECA said that even without the proposal, the U.S. is seeing too many power plants retire too early, noting that NERC and ISO/RTOs have raised that concern in recent reports. Federal agencies, including EPA, should be considering how they can avoid exacerbating those risks.

The American Public Power Association made similar arguments, saying that the agency could not rely on hydrogen and CCS under the CAA because they are not commercially viable. EPA needs to analyze the impact of its proposal on electric reliability, as the grid has already started on its transition away from traditional power plants to a growing share of renewables, the group said.

APPA said the impact of retiring fossil-fuel plants can be seen in the number of requests that the Department of Energy has had to process under Section 202(c) of the Federal Power Act, which suspends compliance with environmental rules when a unit needs to do that to maintain reliability. In the first 20 years of the century, DOE issued eight orders under 202(c).

“This number of orders was nearly matched in 2022 alone, when seven such emergency orders were issued, highlighting the urgency of the situation,” APPA said. “Since 2020, DOE has issued a total of 11 emergency orders over reliability concerns. This surge in emergency orders underscores the need for EPA to re-evaluate the proposed rule to maintain the reliability of the electric system.”

Flexibility Needed

Other commenters said EPA should broaden its definition for BSERs to include renewable energy or other energy-efficient and clean technologies.

The Business Council for Sustainable Energy, an industry organization that includes natural gas companies, recommended a “flexible and technology-inclusive approach” to BSERs. EPA should “recognize and consider recent market trends that include the falling costs and increased deployment of clean energy and energy efficiency. Regulation should provide clear and sustained market signals that spur emissions reductions through investment in the full portfolio of clean energy technologies.”

With the electricity sector already moving toward decarbonization, narrow and prescriptive regulations could draw resources away from planned projects and investments, BCSE said. EPA’s regulations “should not inhibit compliance with local, state and regional policies or divert investment and/or human capital that has been dedicated to decarbonization goals.”

CPS Energy, the municipal utility serving San Antonio, Texas, and its suburbs, also argued that both CCS and hydrogen “might not be easily applied to every fossil generating plant depending on design and location. The rule should allow for flexibility and not lean on specific technology solutions but rather allow each state broad discretion while working with utilities to evaluate measured proposed responses that protect system reliability and resiliency.”

Advanced Energy United wrote in support of the proposed rule but presented renewables, demand response and virtual power plants as technologies that also can provide grid reliability and resilience, undercutting traditional arguments on the need for dispatchable fossil-fueled generation.

“During Winter Storm Uri in 2021, coal and gas plants made up 73% of generation capacity in Texas that experienced ‘outages or de-rates,’” AEU said.

“Fossil-fueled power plants will need to employ costly best systems of emission-reduction technologies in order to meet [EPA] standards. However, renewable energy provides a price-competitive and reliable opportunity to maintain access to affordable power and mitigate grid outages.”

Similarly, CEG argued for renewables and energy storage as BSERs, noting that the proposed rule acknowledges that renewables and battery storage would eventually outcompete natural gas, leading to an expected decline in gas-fired generation.

Given that renewables and storage are “readily available, more than adequately demonstrated and reasonable in cost,” why is EPA trying to incentivize CCS and hydrogen, technologies that are not mature and “not non-emitting”? CEG asked. “Why isn’t the focus instead on developing rules that help accelerate the pace of renewable energy and energy storage displacement of fossil generation?”

Finding themselves potentially on the same side as utilities and fossil fuel companies opposing the rule, environmental groups have been quick to differentiate their concerns and goals from the industry’s.

“Utilities oppose regulation; we oppose bad regulation,” Monique Harden, of the Deep South Center for Environmental Justice in New Orleans, said during a Tuesday press call. “We want the EPA to do better, and it can do better.”

“Our problem with the rule is that it’s not bold enough; the rule doesn’t go through that rapid-change transition … to renewable energy and energy efficiency,” said Nicky Sheats, director of the Center for the Urban Environment at Kean University in New Jersey. “We want massive change not only in technology, but systemic change also.”

‘Penalty-free Emissions’

Another subset of commenters supported the rule as a way to cut emissions from coal and natural gas plants but called for accelerated timelines for compliance for more power plants, with a specific focus on the health impacts for disadvantaged and low-income communities.

The nonprofit Wisconsin Environmental Health Network encouraged “the EPA to strengthen and fast-track the improved standards placed on new and existing fossil fuel-fired power plants.”

“To maximize the efficacy of these regulations … the EPA [should] apply pollution safeguards to a wider number of power plants across the nation. A [broader] distribution of this action will ensure that fewer communities are subjected to unhealthy levels of pollution and dangerous air quality. This is especially important for socially vulnerable populations, since they are impacted more severely from climate change.”

Mass General Brigham, a network of hospitals in Boston, also urged that the rules be applied to more power plants “by lowering the threshold for unit size and capacity factor. … As written, the rule only regulates larger power plants [more than 300 MW], which could incentivize plant operators to shift power generation to smaller facilities that emit more pollution and are more likely to be proximal to environmental justice communities.”

The group also called for EPA to require new plants to immediately comply with the proposed 90% emission reduction and to move up compliance dates for existing coal and natural gas plants. If opting to “co-fire” with natural gas and hydrogen, existing plants would have until 2032 to comply, while those using CCS would have till 2035.

“The health harms of fossil fuel combustion have long been known,” Mass General said. “These delays represent 10 additional years of penalty-free emissions and lost opportunities to accrue additional health benefits.”

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Green Mountain Power to Expand Mobile Battery Fleet

Vermont’s largest electrical provider and a home-grown battery system manufacturer are expanding their fleet of portable utility-scale energy storage in the state.

Green Mountain Power and NOMAD Transportable Power Systems have been designated for a $9.5 million U.S. Department of Energy grant to create new resiliency zones in five Vermont communities with a history of power outages during extreme events.

GMP bought one of NOMAD’s 2-MWh trailer-mounted systems last year and the DOE grant will help pay for five more.

That first unit has been used for grid resilience since it arrived. It got its first field test last month during a planned outage near a manufacturer with round-the-clock operations.

“This was the first time we deployed it to benefit a customer,” GMP spokesperson Kristin Carlson told RTO Insider. “We had already been using it for load management. The NOMAD units are really a game-changer because they’re mobile.”

The utility already had trucks large enough to haul the NOMAD. So when it was time to upgrade the power lines near Twincraft Skincare in Colchester, GMP calculated Twincraft’s electrical load, moved the battery to the site and back-fed a transformer.

GMP then re-energized just enough of the area to power the manufacturing operations while the utility crew worked safely for six hours on the de-energized lines.

Images of Vermont were in the national eye just a few days later, as a slow-moving rainstorm inflicted epic flooding on many small towns.

But while such emergencies are one of the crises the NOMAD system is designed to meet, it was not needed this time.

“We were actually able to get people back online pretty quickly,” Carlson said.

That has not always been the case.

Vermont is the 43rd-smallest and 49th-most-populous state, and the residents are widely dispersed. Its hills and mountains can make for slow travel in severe weather.

Also, its grid is chopped into a patchwork of service areas. GMP, the state’s only investor-owned electric utility, serves more than 270,000 customers; two cooperatives and 14 municipal utilities power everyone else.

The federal grant is designed to demonstrate long-duration energy storage in military housing and in remote communities such as those in rural corners of Vermont.

Carlson said the NOMAD will be an important tool in building resilience in the face of climate change, but it’s just one of the tools GMP is using.

The utility is continually expanding its virtual power plant and energy storage network. It now stands at about 50 MW of utility-scale batteries, controllable EV chargers and 4,500 residential battery systems.

GMP has carried out pilot projects with vehicle-to-grid charging but is waiting for technology to evolve before integrating it on a wider scale.

NOMAD Transportable Power Systems is going to market with three models that it will fabricate in Waterbury, Vt. — the 1-MW/2-MWh Traveler that GMP has been using and two smaller models.

It recently sold its second unit, a spokesperson told RTO Insider, and is getting attention both for its adaptability and as an alternative to emergency diesel generators.

In carrying out the DOE grant, GMP and NOMAD will be joined by KORE Power, the lithium-ion battery cell and module manufacturer that launched NOMAD in 2020.

Electric reliability research organization EPRI will study the cost and reliability benefits of the project.

And in the process, GMP will create more of its Resiliency Zones, in which it combines backup batteries and local renewable power generation to limit outages in communities.

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Newsom Orders up Hydrogen Strategy for California

Gov. Gavin Newsom (D) has issued instructions to develop a state hydrogen strategy, “employing an all-of-government approach to building up California’s clean, renewable hydrogen market,” his office said Tuesday.

“California is all in on clean, renewable hydrogen — an essential aspect of how we’ll power our future and cut pollution,” Newsom said in a statement. “This strategy will lay out the pathway for building a robust hydrogen market to help us fully embrace this source of clean energy.”

The state is competing for a share of $7 billion from the Infrastructure Investment and Jobs Act for the Department of Energy to establish six to 10 hydrogen hubs across the U.S. and $1 billion from the law to underwrite demand for the clean hydrogen produced by the hubs. (See DOE to Invest $1 Billion to Build Demand for Clean Hydrogen.)

A private-public partnership called the Alliance for Renewable Clean Hydrogen Energy Systems (ARCHES) filed California’s application to create a statewide hydrogen hub.

“ARCHES was structured to enable and deliver a clean renewable hydrogen energy system in California and beyond,” said the partnership’s CEO, Angelina Galiteva, a member of the CAISO Board of Governors. “Gov. Newsom’s all-of-government approach to accelerating the hydrogen market is exactly what we need to deliver for California and the nation.”

On Aug. 3, Newsom wrote to Dee Dee Myers, director of the Governor’s Office of Business and Economic Development (GO-Biz), saying the state needs to scale up its hydrogen market “1,700 times by 2045 to meet our carbon-neutrality goal.”

Last year’s Assembly Bill 1279 established the state’s policy to achieve net-zero greenhouse gas emissions by 2045.

The ARCHES initiative is “another example of California’s continued role as a pioneer, developing new markets for hydrogen that have to date been primarily focused on the transportation sector,” Newsom wrote to Myers. “Thanks to innovative policies and robust investments, California has the world’s largest retail hydrogen fueling station network, deploys the most hydrogen fuel cell electric buses in the country and continues to lead the nation towards the commercial operation of Class 6-8 fuel cell trucks. …

“To further position California’s leading role in this emerging market … I am directing GO-Biz to develop an all-of-government hydrogen market development strategy … organized around our north star: leverage hydrogen to accelerate clean energy deployment and decarbonize our transportation and industrial sectors,” the governor wrote.

The strategy should be developed in consultation with the Air Resources Board, Energy Commission and Public Utilities Commission, while clearly defining the agencies’ roles and responsibilities. In addition, it should “identify shared strategies to deliver projects, which may include new financing models, permitting modifications and procurement initiatives,” he said.

Stakeholders should be engaged, and partnerships with ARCHES and others leveraged, to produce and use hydrogen “at scale to meet our policy objectives.”

“Hydrogen has tremendous potential to not only grow our economy but also clean our air, create family-supporting jobs and lead the nation’s clean energy transition,” Myers said in a statement. “The ARCHES model provides an incredible opportunity to accelerate this market and drive down cost for everyone while unlocking critical community benefits.”

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Duke Energy Quarterly Call Focuses on Long-term ‘Organic’ Growth Plans

Duke Energy on Tuesday reported a second quarter loss of 32 cents/share in the second quarter, attributed to mild weather and an impairment of $1 billion from the sale of its commercial renewable business.

The firm’s core market of the Carolinas saw the mildest January and February in the past 30 years, while May and June were mild enough to make the top five, CEO Lynn Good told investors on a conference call. The mild weather was enough to cut earnings by 30 cents/share, she said.

“We’ve had an early look at July, and as you would expect July weather, it’s positive, consistent with the trend across the U.S., and August and September are in front of us,” Good said. “With our largest quarter ahead, we are reaffirming our guidance range for 2023.”

The firm sold off its commercial renewables business earlier this year, with deals expected to close by the end of the year. (See Duke Energy Sells Distributed Renewable Business to Arclight.)

“We’re a wholly regulated company operating in constructive and growing jurisdictions with a wealth of clean energy investments driving growth for years to come,” Good said. “The regulatory constructs in our states have also meaningfully improved over this time, including landmark bipartisan energy legislation passed in North Carolina in 2021.”

Now the firm’s sole focus is on its regulated businesses and its ongoing work on the clean energy transition, she added.

“Our energy transition in the Carolinas remains a top strategic priority, and we’re working diligently on updated resource plans to be filed with the Public Service Commission of South Carolina and the North Carolina Utilities Commission in mid-August,” Good said. “Similar to previous filings, the plans are based on significant stakeholder engagement and will outline multiple portfolios, each of which preserve affordability and reliability while transitioning to cleaner energy resources.”

The plans will include benefits from the Inflation Reduction Act and will reflect healthy load growth in the Carolinas as they continue to see population growth because of migration, she added.

Duke has been adding solar to its generation mix with a procurement in North Carolina finalized recently that will see 1,000 MW added to the grid by 2027 and another approved recently by the NCUC that will add 1,400 MW in the coming years. In Florida, the firm added 300 MW of solar this year and now operates 1,200 MW in the state, with plans to add 300 MW per year there going forward.

“In Kentucky, we’ve partnered with Amazon to install a 2-MW solar plant on top of their fulfillment center in Northern Kentucky, the largest rooftop solar site in the state,” Good said. “This partnership supports the carbon-reduction goals of both Duke Energy and Amazon.”

The firm has a clear strategy focused on “organic” growth of its regulated businesses, said Good.

Some of the analysts on the call asked about “inorganic” growth, with one asking if Duke was interested in buying Dominion Energy’s Public Service Company of North Carolina subsidiary. Dominion has sold off some of its other non-core assets recently.

Good declined to comment on “another company’s process,” but earlier in the call she explained her thoughts on mergers and acquisitions generally.

“Our sole focus is on this organic plan that’s in front of us,” Good said. “And, so, any idea about M&A has to beat what we have in front of us, and it is an increasingly high hurdle because of the confidence we have in our plan.”

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EIA Reports Rising Solar Installation, Oil Production

Competing pictures of the U.S. energy transition were drawn Tuesday, as federal reports showed soaring solar power output and domestic crude oil production poised to set a record.

In its latest inventory of electric generation capacity, the Energy Information Administration said that 5.9 GW of solar came online in the first half of 2023 and that the figure would have been much higher but for supply chain constraints.

EIA also reported that it expects sustained global demand for petroleum to drive U.S. crude oil production above 12.9 million barrels a day for the first time this year and above 13 million in early 2024.

The solar data were drawn from EIA’s preliminary Monthly Electrical Generator Inventory for June. The report inventories utility-scale generating facilities, defined as those with a nameplate capacity of 1 MW or greater.

It showed that 5.9 GW of new solar came online in the first six months of 2023, along with 5.7 GW of natural gas-fired generation, 3.2 GW of wind power and 1.8 GW of battery storage.

At the start of 2023, developers and planners reported that they expected to build 10.5 GW of solar in the first half of the year but fell far short of that projection, largely because of shortages or delays in obtaining materials.

Two large gas-burning plants — the 1,836-MW Guernsey Power Station in Ohio and the 1,214-MW CPV Three Rivers Energy Center in Illinois — accounted for more than half the new natural gas nameplate capacity in the first half.

Most of the new battery capacity was in Texas and California; the Moss Landing battery energy storage facility in California became the nation’s largest as expansion nearly doubled its capacity to 750 MW.

Delays in construction of battery facilities in the first half were even greater than in solar: 3.1 GW of planned storage construction was pushed back to the second half of the year.

The total 16.8 GW of new capacity in the first half of the year was countered by the retirement of 8.2 GW of existing generation capacity, almost all of it coal and gas. The second half of 2023 is expected to see 35.2 GW added, bringing the totals for the year to 25.2 GW of solar, 9.6 GW of storage, 8.1 GW of wind and 7.8 GW of natural gas.

The second half is also expected to see the continued exit of coal from the U.S. fuel mix. Total coal retirements in 2023 are expected to reach 9.8 GW, or 5% of the existing coal-fired fleet at the start of the year.

Crude Output

Even as emissions-free generation capacity is being built, lakes of petroleum are still being pumped out of the ground, refined and burned.

The EIA on Tuesday also released its August Short-Term Energy Outlook, which bumped the prediction for average daily crude oil production 200,000 barrels a day higher than the July outlook. That puts it in record territory for the U.S.

EIA solar

U.S. crude oil production. | U.S. Energy Information Administration (EIA)

The “why” is simple: because there’s money to be made on the global market, as demand persists amid Saudi Arabia’s production cutbacks.

The global benchmark Brent Crude started July at $74.52/barrel and ended the month at $85.22, EIA reported. The agency expects it to reach $90 this year.

“We forecast continued growth in domestic oil production, which is bolstered by higher oil prices and higher well productivity in the near term,” EIA Administrator Joseph DeCarolis said in a news release Tuesday announcing the outlook.

The U.S. likely approached a single-month record for electricity consumption in July, according to the report, as temperatures soared and air conditioners hummed. EIA estimated Americans used 388 billion kWh last month.

Coal use is expected to drop sharply from 513 million short tons in 2022 to 410 million this year, while natural gas is expected to generate 42% of the U.S.’ electricity this year. Other large sources are projected to be nuclear (19%), coal (16%), wind (11%), hydro (6%) and solar (4%).

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FERC Rejects MISO South Waiver Requests from MISO Accreditation Standard

FERC last week shut down the possibility of Entergy and other smaller MISO South capacity providers bypassing a provision within MISO’s availability-based capacity accreditation rules.

In a series of orders, FERC turned down Entergy Arkansas and Mississippi, East Texas Electric Co-op and Arkansas Electric Cooperative Corp. and municipal utilities Conway Corp. of Arkansas, Jonesboro’s City Water and Light, and West Memphis Utilities’ requests for exemptions of MISO’s rule to consider thermal resources that take longer than 24 hours to start up as unavailable, assigning them a zero capacity credit (ER23-1140; ER23-1199; ER23-1154; ER23-1186).

In each case, FERC said the parties “failed to demonstrate that the waiver would not result in undesirable consequences, including harm to third parties.”

The commission said that while granting the exemptions would raise the resources’ accreditation values, it would also reduce MISO’s systemwide unforced capacity to seasonal accredited capacity ratio. A reduction in the ratio would decrease the final accreditation values of MISO’s other capacity resources, it said. MISO uses the ratio to determine supply ahead of its capacity auction. The RTO calculated it incorrectly last year, holding up its first-ever seasonal capacity auction.

This year, FERC similarly denied the Southern Minnesota Municipal Power Agency’s and Cleco’s requests for waivers of the 24-hour lead time threshold under the new accreditation. (See FERC Denies Exemption Requests from MISO Accreditation Rule.)

Entergy requested exemptions for its gas-fired Gerald Andrus Power Plant in Mississippi, its partial ownership interests in Units 1 and 2 of the coal-fired Independence Steam Electric Station in Arkansas and its majority interest in Units 1 and 2 of the coal-fired White Bluff Steam Electric Generating Station in Arkansas. Before the capacity auction, the utility said without the waivers, it risked a supply shortfall in Mississippi. (See Entergy Seeks Exemptions from MISO Accreditation Rules.)

MISO’s first seasonal capacity auction using the new availability-based accreditation came and went in spring without any capacity shortages. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

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NJ’s 3rd OSW Solicitation Attracts 4 Bidders

New Jersey’s third offshore wind solicitation drew proposals from four developers, including two that would put turbines much farther out to sea than earlier projects that have triggered opposition over their visual impact.

The state’s Board of Public Utilities (BPU) did not identify the bidders that hit Friday’s deadline, saying details would not be released until early in 2024, when the winners are announced.

However, three developers disclosed that they submitted bids, including Leading Light Wind, a partnership between New York-based energyRe and Chicago-based Invenergy, which proposed a 2.4-GW project for a site 40 miles off the coast, which would power up to 1 million homes.

Community Offshore Wind, a joint venture between RWE and National Grid Ventures, said it submitted a 1.3-GW proposal, enough to power 500,000 homes. The project would be 37 miles from the shore, Doug Perkins, the venture’s president, said.

A third bidder, Atlantic Shores Offshore Wind, a joint venture between Shell New Energies US and EDF-RE Offshore Development, did not disclose the size or location of its project.

The bids come as OSW developers off the Atlantic coast have expressed concerns about the impact of rising costs on the viability of projects.

Gov. Phil Murphy (D) on July 10 signed a bill that allowed Ørsted to reap the benefit from federal OSW tax credits, instead of the state, after the developer said it needed the credits to complete its Ocean Wind 1 project approved in 2019. After Murphy backed the change, Atlantic Shores said the state should enact an “industry-wide solution, one that stabilizes all current projects,” including Atlantic Shores. (See Murphy Signs OSW Tax Credit Bill.)

New Jobs, Sourcing Options

The state awarded its first OSW contracts to the 1,100-MW Ocean Wind 1 project in 2019, followed by the selection of the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores projects in 2021. All three projects are located about 10 to 15 miles from the shore, prompting opposition from residents and businesses who fear the visible turbines will ruin the ocean view and deter tourists.

New Jersey is seeking to build 11 GW of offshore wind by 2040. With 3,758 MW already approved in the first two solicitations, the third solicitation could significantly expand that capacity. The solicitation guidance document sought projects totaling 1.2 GW to 4 GW, adding that the BPU may award projects above or below the target. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

Opposition to OSW has grown in recent months, in part fueled by a series of whale deaths along the shore that project opponents suggest could be tied to preliminary undersea mapping work, although state and federal investigators have found no connection. But commercial fishing and tourism interests also oppose the projects, as do some local governments. (See Lawsuits Mount over NJ OSW Projects as Opposition Digs in.)

Bidding developers generally did not address those issues, but focused on the benefits, including job creation, their intent to source materials and services in New Jersey and greenhouse gas reduction benefits.

Community Offshore Wind said its project would leverage “RWE’s experience as the second-largest offshore wind developer in the world and National Grid’s expertise as a global leader in transmission infrastructure.”

The company also is developing a 3-GW project in the New York Bight that will power more than one million homes, which it obtained in a February 2022 auction for a lease area of 126,000 acres.

Leading Light Wind’s proposal includes a 253-MW advanced energy storage facility. The partnership is developing a 2,100-MW project on 84,000 acres in the New York Bight that will serve 800,000 homes. energyRe is an energy company with onshore and offshore wind, as well as solar and storage interests and offices in New York, Houston and Charleston. Invenergy is a global energy company, with a portfolio that includes clean energy.

The two developers are working with New York Power Authority on the Clean Path NY project, a 175-mile, 1,300-MW underground HVDC transmission line. Leading Light Wind in January submitted a bid to New York State Energy Research and Development Authority (NYSERDA) in the state’s third solicitation for a 2,100-MW offshore wind project. (See NYSERDA: 3rd OSW Solicitation Breaks Record.)

Atlantic Shores, whose New Jersey project is presently the largest planned in the state, said in a release that its latest bid was the “culmination of over four years of dedicated planning and research.” That experience would enable the developer to “deliver the most economically, environmentally and socially responsible renewable energy solution for New Jersey,” Atlantic Shores CEO Joris Veldhoven said.

Atlantic Shores also is developing a project in the New York Bight, having won a bid to build a 924-MW project. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

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What are National Interest Electric Transmission Corridors and Why Do We Need Them?

On May 15, the Department of Energy’s Grid Deployment Office issued a Notice of Intent to create a process for designating “route-specific” National Interest Electric Transmission Corridors (NIETCs), an initiative to support transmission projects that address congestion, connect renewables or advance other policy goals. The accompanying Request for Information sought comments on DOE’s proposed design for the program and suggestions for other elements that should be included.

Application Requirements

Applicants must provide sufficient information about the potential route to allow DOE’s review under the National Environmental Policy Act.

DOE said it may also allow tribal authorities, states, transmission-dependent utilities, local governments, generation developers and others to submit proposals.

Applicants will be required to show that their proposed route is defined “with sufficient specificity to allow for meaningful evaluation of the potential energy and environmental impacts,” including the geographic boundaries of potential corridors, and the rationale for those boundaries.

Benefits of NIETC Designation

Under the Infrastructure Investment and Jobs Act (IIJA) and Inflation Reduction Act (IRA), DOE said the NIETC program “can assist in focusing commercial facilitation, signal opportunities for beneficial development to transmission planning entities, and unlock siting and permitting tools for transmission projects.”

The IIJA created the Transmission Facilitation Program, giving DOE $2.5 billion for public-private partnerships to co-develop transmission projects located within NIETCs. (See DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs.)

The IRA created the $2 billion Transmission Facility Financing program, allowing DOE to offer loan support to transmission facilities designated by the Energy Secretary as being in the national interest.

The IIJA also amended Section 216(b) of the Federal Power Act to give FERC the authority to overrule states when they deny a certificate for a line within a NIETC.

DOE’s notice included a caveat that designation of a NIETC “does not constitute selection of or a preference for a specific transmission project for financial, siting or industry planning purposes; selection for these other purposes will continue to occur through established planning and regulatory processes.”

However, some commenters expressed concern that NIETC could usurp existing transmission planning processes. (See related story, States, RTOs Caution DOE on Transmission Corridors.)

Reason for NIETC Program

DOE’s notice cites the importance of electric transmission to national “economic, energy and national security” and says more transmission capacity is needed to survive more frequent extreme weather, provide access to renewable energy and serve rising demand from electrification of transportation and industry.

The Biden administration’s goal of a 100% clean electric power sector by 2035 would require increasing transmission system capacity. DOE cites a Princeton University analysis projecting that transmission systems may need to expand by 60% by 2030 and triple by 2050.

The IIJA and IRA investments “will not be realized fully unless the United States can quickly expand enabling electric transmission infrastructure,” DOE said.

Identifying Corridors

A “key input” into the designation of NIETCs will be DOE’s triennial study of electric transmission constraints and congestion. Although previous studies were limited to considering only historic congestion, the IIJA expanded the scope to also consider anticipated future capacity constraints that could affect consumers.

DOE issued a draft Needs Study in February and expects to issue the final study this summer. The draft found that nearly all regions in the U.S. would see improved reliability and resilience from additional transmission and that those with high electricity costs — the Plains, Midwest, Mid-Atlantic, New York and California — also would benefit from access to cheaper generation.

The study said interregional transmission would produce the largest benefits, particularly new lines across interconnection seams — between the Mountain and Plains regions and between Texas and its neighbors.

It predicted that needs will shift over time to reflect impacts from the clean energy transition, evolving regional demand and increasingly extreme weather. “Significant transmission deployment is needed as soon as 2030 in the Plains, Midwest and Texas regions. By 2040, large deployments will also be needed in the Mountain, Mid-Atlantic and Southeast regions. The same is true for interregional transmission deployment; by 2040, there is a significant need for new interregional transmission between nearly all regions,” it said.

The IIJA added several outcomes, in addition to reducing congestion, that could justify transmission corridors, including impacts on a region’s “economic vitality” and growth; diversifying electric supplies; helping generators connect to the grid; and aiding the nation’s “energy independence or energy security” or “national defense and homeland security.”

The IIJA also directed DOE to maximize existing rights-of-way, avoid “sensitive environmental areas and cultural heritage sites” and consult with “affected states, Indian tribes and regional grid entities.”

The RFI sought comment on how DOE should evaluate the impact of a potential NIETC on generating host community benefits, “encouraging strong labor standards,” improving energy equity and achieving environmental justice goals, and maximizing the use of products and materials made in the U.S.

Related Authorities of FERC And Other Federal Agencies

DOE pledged to coordinate with FERC to avoid redundancy and promote efficiency in environmental reviews.

In December, FERC issued a Notice of Proposed Rulemaking to explore how it implement its “backstop” siting authority (RM22-7). (See FERC Moves to Implement New Backstop Transmission Siting Authority.)

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AECI To Pay $42K in NERC Penalties

Associated Electric Cooperative Inc. (AECI) will have to pay $42,000 to SERC Reliability for violations of NERC’s reliability standards that lasted more than 15 years, according to a settlement between the utility and the regional entity, approved by FERC at the end of July (NP23-18).

NERC submitted the settlement to FERC in June as the only publicly visible entry in its monthly spreadsheet Notice of Penalty. The ERO also submitted a separate spreadsheet NOP detailing violations of the Critical Infrastructure Protection (CIP) standards, which was not publicly accessible in keeping with NERC’s policy on CIP violations. FERC said in a July 28 filing that it would not further review the settlements, leaving the penalty intact.

AECI provides electricity generation and transmission services through six transmission cooperatives to 51 local electric co-ops in Missouri, Iowa and Oklahoma, serving about 935,000 end customers. Its settlement with SERC stems from six separate instances of noncompliance with reliability standard FAC-009-1 (Establish and communicate facility ratings) and its successor standard FAC-008-5 (Facility ratings), though the NOP did not disclose the precise location of the violations.

The first FAC-009-1 noncompliance came to light in May 2021, when one of AECI’s generation and transmission (G&T) co-ops was reviewing engineering drawings related to a 161 kV network transmission circuit that AECI had recently put back into service after a rebuild project. For this phase of the project, the G&T had told AECI that it would reuse existing bus work and jumpers.

However, the co-op staff later realized that its contractor had replaced a jumper without informing the co-op. The replacement jumper had a larger physical diameter and lower temperature rating than the original, which made it the most limiting element of the transmission circuit and reduced the facility’s capacity by 4%, although the error never caused AECI to exceed the correct rating during the duration of the violation.

After discovering the violation, AECI and the G&T conducted an extent of condition assessment and verified all facility ratings associated with equipment involved in the rebuild project. They did not find the issue in any other location on the AECI transmission system.

AECI later submitted updates to SERC notifying it of five additional noncompliance instances. The utility submitted four of these reports on Feb. 14, 2022, with the last provided that July.

The first of these instances involved the same facility as the original report. A contractor hired by the G&T identified a discrepancy between the substation’s engineering drawings and AECI’s asset management system that incorrectly reported the size of the facility’s bus work, which meant that once again, the wrong piece of equipment was identified as the most limiting factor.

After another extent of condition review, AECI and the G&T determined that no other substations had a similar problem with their bus work.

In the next instance, a G&T identified a switch at a substation with an inaccurate rating in the G&T’s asset management system during a review of spare equipment at certain transmission facilities in August 2021. Another G&T identified five inaccurate ratings in the process of its own spare equipment review that October.

AECI also reported an instance of noncompliance involving its Modeling and Network Transmission Information System (MANTIS) database of transmission equipment. After a G&T reported the equipment it owned at a neighboring utility’s substation in November 2020, AECI discovered that it had not modeled this equipment in MANTIS. However, the team maintaining the database did not update the facility’s ratings until an update nearly a year later.

Finally, AECI and the G&Ts discovered in May 2022 that some G&T personnel were providing relay loadability settings in their asset management systems that differed from those in AECI’s facility ratings methodology. This meant that the ratings for applicable relays were too low.

AECI’s mitigating activities included providing facility ratings awareness material to its associate G&Ts and implementing a process to perform field verifications of relevant substations every five years. As of the filing of the settlement it was in the process of performing the first of these field verifications; it promised to provide quarterly updates to SERC until the process is complete.

SERC assessed the violations as a moderate risk to grid reliability, noting that failing to establish accurate facility ratings creates the risk of operating facilities in excess of their operating limits, although the RE acknowledged that AECI never actually operated its facilities above the correct ratings. SERC awarded the utility credit for self-reporting the violations, for cooperating in the investigation and enforcement process and for agreeing to settle the issue.

However, it also referenced AECI’s compliance history with FAC-008 as an aggravating factor in several of the violations.

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EPRI Launches Cross-industry Initiative to Advance EV Adoption

The problem the Electric Power Research Institute’s (EPRI) initiative has been launched to solve, said Britta Gross, the organization’s director of transportation, is that a massive rollout of electric vehicles and EV chargers is underway, but “there’s not yet a plan or road map that lays out what do we have to be doing to prepare.

“There’s no plan year over year about what we should be doing and what we should be investing in on the grid side to prepare for all those loads coming onto the grid — and [they are] a very different load than building loads, housing loads and so on,” Gross said. “Cars move, trucks move, buses move, and you’ve got to accommodate them where they are, whether it’s in a driveway at home, an apartment or condo, on a highway or at a fleet depot.”

Coming up with that plan will take huge amounts of data and a lot of collaboration from a broad range of industry stakeholders, with electric utilities and their distribution systems playing a central role, Gross said, which is where EPRI and EVs2Scale2030TM come in. The three-year initiative announced Monday is aimed at drawing in as many as 500 industry players — from carmakers to utilities to federal and state agencies — to help scale EVs to 50% of new car sales by 2030.

The starting bench for the initiative includes Amazon, billed as a key “logistics provider,” along with more than a dozen electric utilities, as well as industry trade groups, the Department of Energy’s national laboratories and electric truck manufacturers such as Daimler and Volvo.

Many of those participants will be or, Gross said, already have been providing EPRI with data ― made secure and anonymous ― that is being used to create a range of online planning tools, including:

    • A 50-state, interactive map that will allow anyone to look at potential impacts of transportation electrification over the next three, five or more years, drilling down from the national level to what’s happening on individual transformers and feeder lines.
    • An online platform aimed at clarifying and streamlining the processes, such as interconnection and supply chain procurement, needed to support the pace of activity and investment that will accelerate large-scale vehicle electrification.
    • An approved and vetted list of charging equipment that meets industry and federal standards.

Gross is beyond excited when she talks about the map and other tools on the way, and the critical role data sharing will play for electric car and truck owners, utilities and regulators.

Data is the foundation of planning and confidence building, which is what the market needs to expand at speed, she said, with the map coming first, possibly within a month or two. “The data has to be granular enough … that utilities can actually take action on feeder-level information, and regulators behind many of the utilities can actually see why proactive investment is the smart thing to do, [making] no-regrets investments on the grid because this is where utilities are stacking up, loads are stacking up,” Gross said.

Gross sees the map and other tools as an interface for connecting utilities and the EV industry. “We’re trying to simplify the landscape for those fleet operators, the charging providers, the manufacturers of vehicles so that they know how to reach the utility industry, so the utility industry is prepared with better tools … so they know how to invest, when to invest,” she said.

Fleet Electrification

On the utility side, Xcel Energy has taken a leading role in the initiative, with Brett Carter, executive vice president and group president of utilities at the company, chairing the Advisory Board. The utility has committed to deliver its customers 100% carbon-free energy by 2050 and already has managed charging and other EV programs, he said.

But it is still in learning mode on fleet electrification as it prepares to electrify all the sedans in its own fleet by the end of the year, Carter said.

“What we’re really looking at is how does the logistics model or mapping look … for the jurisdictions that are really gearing up for some of these larger charging platforms that are being requested by our customers,” Carter said. “It’s one thing solving for the individual customer, the residential customer … where 80% of the charging is going to take place either at home or near home.”

“It’s another thing when you have large rental car companies saying, ‘Hey, we need to turn cars around in 20 to 30 minutes, and so we’re going to be charging several cars at a time at all times of the day,’” he said. “You’ve got to be really smart in how you’re building this infrastructure out to accommodate these large fleets.”

He sees transportation electrification and the EPRI initiative as a way for the transportation industry and utilities to move beyond their traditional adversarial relationship. “There’s a little bit of a misperception about the role utilities should play in this space,” he said. “Our partners are starting to really invite us in to help them as opposed to being adversarial to our participation.”

The Collaborative Imperative

Transportation electrification is driving unprecedented levels of cross-industry collaboration as automakers, utilities, regulators and policymakers look ahead to how they will reach a growing list of ambitious goals. EVs2Scale is based on President Joe Biden’s target for 50% of new vehicle sales in the U.S. to be electric by 2030.

California and at least five other states are pushing ahead with clean car rules that set a 2035 deadline for all new passenger vehicles sold in their jurisdictions to be electric. General Motors has committed to a zero-emission fleet by 2035, while Volvo is shooting for 2030.

Building off these goals, EPRI’s announcement is the third collaborative initiative rolled out in as many weeks. On July 26, seven automakers announced they would form a joint venture to install 30,000 EV fast chargers on U.S. highways and in urban areas. The seven ― BMW Group, General Motors, Honda, Hyundai, Kia, Mercedes-Benz Group and Stellantis NV ― have said the charging stations will be accessible to EVs from all automakers, regardless of the type of charging plug they use. (See Automakers Pledge to Put 30K EV Chargers on US Highways.)

On Aug. 3, the federal Joint Office of Energy and Transportation announced the 23 members of its own EV Working Group (EVWG), which will make recommendations to the Joint Office, other federal agencies and congressional committees.

While Gross stressed that EVs2Scale will focus on data-driven tools and solutions, some overlap between groups seems likely. Like EVs2Scale, the federal working group will look at how to overcome barriers to EV adoption, including charging infrastructure needs, regulation and planning, and equipment standardization ― issues that also could be obstacles for the automakers’ joint venture.

Daimler North America, Xcel Energy and the National Association of Regulatory Utility Commissioners have representatives in both EVs2Scale and the EVWG, and an official from the Joint Office is on the Advisory Board of EVs2Scale.

Collaboration also is a key theme in industry statements in EPRI’s announcement.

EPRI CEO Arshad Mansoor said “collaboration, coordination and standardization will be critical for the U.S. to meet its 2030 EV targets.” The new initiative “will bring together all of the key industry stakeholders to identify and address the challenges and opportunities needed to drive toward an affordable, equitable and reliable clean energy future.”

“No one company can solve the climate challenge alone, and stakeholders across the industry need to come together to transform fleets at an unprecedented scale and speed to meaningfully impact emissions,” said Udit Madan, vice president of Amazon Transportation. The company “will continue to work to give utilities the tools and information they need to successfully electrify the transportation sector.”