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.
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%).
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.)
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.
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.”
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.
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.
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.”
Gov. Gavin Newsom (D) announced last week that California will team up with the Chinese province of Hainan to fight climate change, in the state’s latest international partnership focused on the climate crisis.
Speeding the deployment of zero-emission vehicles (ZEVs);
Reducing air pollution;
Developing and implementing climate adaptation and carbon neutrality plans; and
Exploring nature-based carbon solutions.
California and Hainan agencies will work together on an action plan for meeting the objectives. Specific activities might include organizing meetings on carbon neutrality planning or best practices for decarbonizing transportation, energy and industry.
The four-year agreement may be extended if the parties agree, or canceled at any time.
“We’re an ocean apart but share the same goals — leaving this planet better off for our kids and grandkids,” Newsom said in a statement.
Vice Governor Chen Huaiyu said Hainan is pleased to partner with California.
“We share the desire to raise the bar for climate solutions like cleaning our air, advancing zero-emission vehicles and embracing clean energy,” he said in a statement.
The memorandum points to some of California and Hainan’s shared climate goals. Hainan, which is China’s southernmost province, plans to ban the sale of fossil fuel vehicles by 2030 and reach carbon neutrality by 2060. California has committed to 100% light-duty ZEV sales by 2035 and carbon neutrality by 2045.
In addition, Newsom renewed a climate cooperation agreement with China last year. The governor said at the time that the agreement “deepens California’s strong climate and clean energy ties with China.”
An announcement on the agreement noted that China is the world’s largest emitter of greenhouse gases. The U.S. is the second-largest GHG emitter, with roughly half the annual emissions of China in 2020.
Newsom’s action last year renewed a climate agreement with China signed by Gov. Jerry Brown (D) in 2018.
Brown is now chair of the California-China Climate Institute at the University of California, Berkeley. The institute partners with the Institute of Climate Change and Sustainable Development at Tsinghua University in China.
In March, the institute released an 11-paper series aimed at accelerating U.S.-China climate action. Topics of the papers include decarbonizing the power sector, advancing the ZEV market, electrifying buildings, accelerating zero-emission shipping and reducing food waste.
The institute is named as one of the primary points of contact for communication and information exchange under the agreement signed last week with Hainan.
PJM detailed changes to the performance assessment structure and risk modeling in its critical issue fast path (CIFP) proposal Aug. 1, followed by presentations from Constellation Energy and Vistra.
While an additional meeting has been scheduled for Aug. 14, several stakeholders expressed concern there would not be enough time to get through the remaining stakeholder presentations and hold a dialogue about them before sponsors propose to the board and the Members Committee votes on the proposals Aug. 23. (See PJM Updates Proposal as CIFP Nears End.)
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if it would be possible to delay the Stage 4 presentation to the board and subsequent MC vote to allow more Stage 3 meetings to be held.
“We’re trying to do too much in too short a time, and I just don’t see how we’re going to get through this all,” he said.
PJM Director of Stakeholder Affairs Dave Anders said staff are investigating all the ways of ensuring stakeholders have the information they need to make an informed vote. He told RTO Insider that any delay of the meetings would need to be made at least seven days prior to their scheduled date but that PJM would intend to announce any such changes as early as possible to respect stakeholders’ travel arrangements.
PJM Modifies Performance Assessment Proposal
Presenting how PJM could measure performance during emergencies and how it would determine penalty charges and bonuses, Pat Bruno said the proposal would retain the current capacity performance framework, while making changes to the penalty structure and balancing ratio and creating a new bilateral trading system.
The proposal would use the same performance assessment interval (PAI) trigger as was included in a filing PJM made in May, which allows an emergency to be declared only when there is a primary reserve shortage, voltage reduction warning and at least one of several additional emergency actions, including a manual load dump warning or maximum emergency generation action. The commission approved the filing July 28.
The penalty rate and stop loss will remain status quo under PJM’s proposal. Both were components of a proposal endorsed by the Members Committee in May, but which the board decided not to include in its filing. (See PJM Board Rejects Lowering Capacity Performance Penalties.)
Resources’ performance in the balancing ratio would be capped at their installed capacity (ICAP) rating, meaning a resource with a capacity obligation of 70 MW and 100 MW ICAP would receive a maximum overperformance bonus equal to 30 MW. The status quo rules do not include a cap.
PJM’s Pat Bruno said energy prices likely would be sufficiently high during an emergency to continue to incentivize resources to perform above their ICAP if they are able.
Energy-only and uncommitted capacity resources would be ineligible to receive bonus payments, but the latter would be eligible to take on committed capacity resources’ obligations through a new hourly financial capacity trading option. Capacity resources would be able to sell a portion of their obligation to another resource, so long as the buyer had accredited capacity that was not committed. The buyer would be eligible for capacity performance bonuses and penalties and the seller would be required to indemnify PJM if the buyer could not perform and could not pay the penalty.
David “Scarp” Scarpignato, of Calpine, said PJM’s analysis of the December 2022 winter storm showed that 70% of the overperformance was from capacity resources and generators. Around 30% was from uncommitted capacity and energy-only resources, which are not eligible for bonuses under PJM’s proposed new rules because they are categorically excluded.
Scarp said the “non-committed capacity” resources might find it uneconomical to provide desired emergency energy, especially after the timely gas nomination period has passed.
“I’m not sure you want the uncommitted capacity generator having to make a decision about losing money to help out. The energy market revenues are not enough in some instances, such as when competing for emergency energy imports,” he said. “I’m worried that in adhering to PJM’s strict ‘committed capacity’ theory, we’re ignoring the reality that the huge quantity of energy-only and uncommitted resources are absolutely needed by PJM for reliability.”
PJM also proposed to modify the fixed resource requirement (FRR) penalties by lowering the insufficiency charge from 2 times the cost of new entry (CONE) to 1.75 times net CONE. The daily deficiency charge would be changed from 1.2 times the Base Residual Auction (BRA) clearing price to 1.75 net CONE.
PJM Updates Risk Modeling Calculation
PJM’s Patricio Rocha Garrido presented updated risk modeling figures focused on where the RTO believes the balance between winter and summer risk lies. The new “base case” the proposal uses is based on weather data going back to 1993, does not include any adjustment for climate change, a proposed change in how demand response and storage are dispatched and updated planned outage data.
The latest modeling places 68% of the annual expected unserved energy (EUE) risk in the winter, with the remainder in the summer. The seasonal risk shifts 56% of the risk to the summer if PJM does not include data from the 1994 winter, which included a particularly severe storm in January.
Previous risk modeling proposals included a longer weather lookback to 1973 and adjusted past weather events with a climate change modifier to account for the expectation that temperatures would be warmer if similar weather occurred in the future. PJM’s Walter Graf said the amount of variability PJM saw in the modeling outcomes when implementing the adjustment led it to become less confident in the adjustment.
The new dispatching in the modeling would deploy demand response before storage, which would be ordered so long-duration storage is used before short-duration.
Presenting estimated 2026/27 class average accreditation values, Garrido said storage resources would have significantly higher values during the summer owing to the historical finding that winter outages are likely to be more prolonged. Four-hour storage would have a 90% accreditation during the summer, while 10-hour resources would have 100%; during the winter, however, those resources’ values would be 38% and 69%.
Demand response and solar also see large hits to their accreditation during the winter, which Garrido said is because the times at which their contribution is strongest tend to not align with the peak reliability risks for the season.
Showing a heatmap of the hours that tend to have the highest risk for each month, Garrido said the bulk of summer risk is concentrated on July days between 5 and 7 p.m. In the winter, risk is split between around 6 to 10 a.m. and 5 p.m. to midnight in January and a smaller share in February following a similar distribution.
James Wilson, a consultant to state consumer advocates, said he was disappointed PJM did not update the resource mix in the modeling, which he said assumed a large increase in solar, inconsistent with the relatively low summer risk and reliability value in the results.
Wilson questioned why PJM has settled on using 1993 as the date to start its weather lookback and suggested the decision may have been made to include 1994 in the dataset and weight the risk modeling toward winter.
Graf said the year was chosen because it’s the starting point for lookback periods PJM uses for other parameters.
Constellation Responds to PJM Proposal
Presenting for Constellation Energy, Adrien Ford said several changes to PJM’s proposal would improve the construct, including using a prompt capacity market with a shorter timeframe between the auction and the corresponding delivery year or season, a minimum number of PAIs per delivery year and a rolling 20-year historical weather lookback.
Ford said the company is planning to update its own proposal in the matrix, but Tuesday’s presentation was meant to add to the wider discourse around other proposals and design components being considered.
A prompt auction design six months to a year forward of the period the capacity is being procured for would improve the data available to market participants, Ford said. That would include the potential for a more accurate forecast of supply and demand, and reflect changes in the amount of time it takes to build generators.
Ford also said Constellation is considering an earlier capacity performance proposal from PJM where a minimum number of intervals each year would be examined for performance, with the 10 highest load hours each season used to meet the threshold at the end of the year. The changes to the PAI trigger likely will reduce the number of emergencies generators experience, which she said increases the need for regular evaluation of resources’ contribution.
Constellation supports PJM’s proposal to derive the reliability requirement from EUE analysis, rather than the status quo loss of load expectation and using marginal effective load carrying capability for accreditation.
Vistra Suggests Changes to PJM Proposal
Vistra’s Erik Heinle said the company supports much of PJM’s proposal but is concerned with several provisions, including limiting bonus payments to committed capacity resources, generators’ ability to reflect the risk of being assigned penalties in their market seller offer cap and the ability for the CIFP process to result in an adequately fleshed-out seasonal auction model.
Not allowing a wider range of resources to receive bonus payment for overperforming reduces the incentive for investments that can support reliability and increases the risk for those considering whether to make upgrades to allow them to qualify as capacity resources. If such a resource makes significant reliability upgrades but doesn’t clear, Heinle said it would be deprived of both capacity revenue and the opportunity for bonuses.
While he said the hourly capacity obligation trading proposal improves the ability to mitigate risk and improve transparency, he also said more work is needed to ensure that generators can represent all the risks that come with taking on a capacity obligation. The company also supports PJM’s decision to maintain the current capacity performance penalty rate and stop loss limit, as well as exempting intermittent and storage resources from offering into the capacity market.
Heinle suggested that PJM include the seasonal capacity model in its filing but delay its implementation to allow more time to allow stakeholders to make changes and understand how the changes would play out.
FERC has approved PJM’s request to revise its tariff to tighten the triggers for a performance assessment interval (PAI), requiring that a primary reserve shortage be in effect paired with a set of emergency actions (ER23-1996).
In its May 30 filing, PJM argued that adding the primary reserve shortage would better align the timing of PAIs with their intended generator performance when it would be most beneficial to reliability. For a PAI to be declared, a shortage would have to be in place as well as a voltage reduction warning paired with any of the following actions: reduction of critical plant load, manual load dump warning, maximum emergency generation action or the curtailment of non-essential building loads and voltage reduction. The July 28 order stated that the changes would provide dispatchers with more certainty during stressed conditions.
The emergency actions necessary for the declaration of a PAI also were reduced to no longer include pre-emergency demand response, which PJM argued should be available for dispatchers to utilize without initiating a full emergency declaration.
“We also find that it is appropriate to remove the deployment of pre-emergency load response and emergency load response from the trigger for a PAI because PJM cannot verify the amount of response these resources are providing until 60 days after an event, and therefore it may be prudent for PJM operators to maintain load response even after capacity shortage conditions pass,” the order says. “As PJM explains, its proposed revisions will enable PJM operators to efficiently and effectively operate the grid without second guessing their decision to keep emergency procedures in place during non-capacity shortage instances, such as the hours between morning and evening peaks during extreme winter conditions.”
In directing the board to file the proposal, the PJM Board of Managers took one of three components of a package endorsed by stakeholders during the May 11 Members Committee meeting. The other two portions of the package would have based the penalty for resources that perform below their capacity obligation and the annual stop-loss limit on the Base Residual Auction (BRA) clearing price for the locational deliverability area (LDA) that the resource is located within. (See PJM Board Rejects Lowering Capacity Performance Penalties.)
Several organizations filed in support of the change to the trigger, but asked that the commission remain open to the possibility of changes to the penalty rate and stop loss in the future.
Though it supported the change to the trigger, the Independent Market Monitor argued that PJM did not make a satisfactory case for not including the full stakeholder-endorsed proposal and suggested that the commission should open a Federal Powers Act (FPA) 206 proceeding to evaluate if the charge rate is just and reasonable.
PJM filed a response stating that commission action is not needed as stakeholders are considering changes to capacity market design, including the penalty charge rate and stop loss limit, through the critical issue fast path (CIFP) process. American Municipal Power (AMP) argued in response that it’s unknown what the result of the CIFP process may look like, whether the commission will approve any resulting filing and whether changes will be effective for the next auction.
The latest version of PJM’s CIFP proposal, presented during the Aug. 1 stakeholder meeting, did not include changes to the penalty charge rate or stop loss limit.
The Public Service Commission of West Virginia protested the filing, arguing that the change to the trigger would create unbalanced obligations between load and generation. Under the proposed language, it said load will receive voltage reduction and load shedding warnings encouraging consumers to reduce their consumption, but capacity resources will not be notified that they need to be ready for dispatch.
Vitol argued that the tariff revisions would violate the filed rate doctrine and rule against retroactive ratemaking if it were to be applied to auctions that already have concluded. The company stated that market sellers include their expectations about the number of PAIs and how they will impact their generators when forming the capacity performance quantified risk (CPQR) component of their market offers, which goes on to influence their bids and the ultimate auction clearing price.
PJM responded that it is not aware of any unit with a CPQR component that did not clear in either auction which has been concluded for future delivery years that would be affected by the tariff language, nor did the marginal unit in either auction contain a CPQR component to its offer.
The commission stated in its order that insufficient evidence had been provided that the proposed language would have had any impact on capacity offers. In considering the balance of settled expectations for those auctions, the order states that the commission found that the benefits of more accurately aligning PAIs with stressed grid conditions where generator performance impacts reliability outweighed market participants’ expectations based on the emergency action definition.
“There is insufficient record evidence, and no evidence from parties that raise such arguments, that such risk had a material impact on final capacity offers, especially given the other major uncertainties that affect suppliers’ assessments of PAI penalty risk, such as weather, fuel availability or equipment failures,” the order says.
In supporting the filing, the PJM Power Providers Group (P3) argued that it would allow PAIs to be more reflective of when emergency conditions exist on the grid and avoid “false positives” that have been seen in PJM’s history.
The order directs PJM to submit a compliance filing within 30 days to correct clerical errors and capitalize the phrase “Primary Reserve requirement” to more explicitly refer to the parameter defined in the RTO’s manuals by the same name.
The Ohio Federal Energy Advocate and Earthrise argued there was ambiguity in PJM’s filing around whether the primary reserve requirement by which a shortage is measured against referred to the manual defined reserve requirement or to the broader reserve requirement for primary reserves, which includes the extended reserve requirement. The primary reserve requirement is set at 150% of the synchronized reserve reliability requirement, which itself is based on the single largest contingency on the grid.
Earthrise argued that the filing should be read to refer to the primary reserve requirement without extended reserves and that PJM should be required to make a compliance filing specifying its intent. PJM filed that it preferred to include extended reserves in its definition and included new proposed tariff language in its response.
The commission’s order stated that the language of PJM’s original filing referred to the primary reserve requirement without the inclusion of extended reserves and its intent or preference to include extended reserves was not reflected.
State officials, RTOs and public interest groups warned the Department of Energy last week not to let transmission developers dominate the development of National Interest Electric Transmission Corridors (NIETCs), saying the program should not overrun states’ interests and existing regional transmission planning processes.
DOE received 112 comments in response to its May Notice of Intent/Request for Information on the proposed designations, which DOE says would “unlock new financing and regulatory tools” as well as federal siting and eminent domain authorities. (See DOE Rolls out New Process for Designating Key Transmission Corridors.)
Public officials, RTOs and trade and environmental groups were generally supportive, although many asked DOE to ensure it chooses only projects that improve resilience, enable connection of renewable generators or produce cost savings. There was wide agreement that DOE should prioritize interregional projects, and some commenters said the department should also encourage use of grid-enhancing technologies (GETs).
But some commenters challenged the legality of DOE’s proposed “applicant-driven, route-specific” approach. Individual landowners were almost universally opposed, criticizing the potential use of eminent domain by “greedy developers.”
Below, based on a review of the comments, is a summary of concerns and questions raised.
Eligibility Questions, States’ Role
The Infrastructure Investment and Jobs Act (IIJA) created the Transmission Facilitation Program, giving DOE $2.5 billion for public-private partnerships to co-develop transmission projects located within NIETCs. The Inflation Reduction Act (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.
DOE said it expects that most proposed routes will be “associated with specific transmission projects under active development, meaning that a potential applicant has progressed beyond the preliminary concept and has begun actively routing the project and engaging in community and landowner outreach, land surveys or initiation of environmental compliance work.”
Public interest groups including the Natural Resources Defense Council, Earthjustice, the Southern Environmental Law Center and Environmental Defense Fund said DOE “must exercise independent judgment” in evaluating developers’ proposed corridors, warning that DOE’s proposed approach “risks conflating developers’ commercial interests with the national interest.”
“Although developers’ NIETC proposals may reveal where there is the greatest commercial interest in transmission development, there is no guarantee that developers will propose corridors that are truly in the ‘national interest,’” they wrote. “For example, they may hope that a NIETC designation will unlock financing that makes a transmission project easier to build or more profitable.”
State regulators submitted comments ranging from supportive to highly skeptical, with many expressing concern that DOE’s proposal would make private companies the only entities capable of applying to have NIETCs recognized. DOE said it may also allow tribal authorities, states, transmission-dependent utilities, local governments, generation developers and others to submit proposals.
The Mississippi and Louisiana public service commissions expressed strong opposition, saying the Federal Power Act grants the designation authority to the Secretary of Energy only, and contains “no language that authorizes the DOE to allow independent developers to make the NIETC designations based upon those developers’ own economic self-interests.”
They said the NOI could harm ratepayers. “Construction of transmission … can have enormous cost consequences on affected transmission facilities. Those consequences … must be remedied and financed by the entities causing those impacts.”
The Pennsylvania Public Utilities Commission also questioned allowing “private transmission developers to be the driving force” in designating NIETCs, adding that the NOI’s route-specific approach could create a presumption that transmission lines are the best solution to congestion and discourage investigation of other alternatives.
California’s Public Utilities Commission and its Energy Commission supported the plan overall, but urged DOE to open the application process to states, tribes and transmission operators. They also suggested creating an “applicant-driven ministerial certification process” for projects that address the purpose and needs of a given NIETC, which would encourage developers to participate in such projects while leaving state authorities and FERC in charge of the permitting process.
‘Clear and Prominent Role’
The New England States Committee on Electricity said DOE’s designation process “should provide a clear and prominent role for states,” allowing them to file applications for potential routes “where one or more potential transmission projects have clear state support” as well as providing input on others’ proposals. “Such an approach would recognize the primacy of the states’ role in siting transmission infrastructure and their authority over investments made to satisfy their own mandates and legal requirements,” NESCOE said.
The National Association of State Energy Officials (NASEO) said that, in light of the role of state energy offices in facilitating transmission upgrades and expansion, DOE should allow them to apply for NIETC designation as well. NASEO said state energy offices “have the tools, resources and knowledge to identify potential corridors that would benefit their states, regions and the nation.”
In a joint comment, the utility commissions of Michigan, New Jersey, North Carolina and Virginia pointed out that because “a NIETC designation has the potential to boost a project’s chance of being constructed considerably,” there is a danger that transmission developers could use the designation “strategically” to gain an advantage over projects “that may be better or more cost-effective.” The commissions also feared that the designation might help “shovel-ready” projects lose ground to less prepared developers.
The Edison Electric Institute said DOE’s process is “reactive” and would “unnecessarily limit DOE’s evaluation of corridors to only the areas, or indeed projects, submitted by applicants.”
Rather, it said DOE should, “proactively identify the geographic areas exhibiting the most significant or persistent need for immediate transmission development.”
The American Public Power Association said DOE should also allow transmission-dependent utilities to apply for NIETC designation and participate in joint ownership of projects, which it said could save ratepayers money and help win local support.
“The diversity gained by including public power in joint ownership arrangements can help with the acquisition of rights-of-way and permits, by having a broader and more diverse set of utilities advocating for projects at the state level. Engaging more rural communities and helping to bridge urban-rural division, as well as being more inclusive of rural communities, are additional public policy benefits of joint ownership arrangements that include public power,” APPA said.
Respect Existing Planning Processes
CAISO, PJM and the MISO Transmission Owners were among those insisting that any procedures the DOE settles on should complement existing transmission planning efforts.
WIRES, a trade association representing transmission providers, developers, customers and regional grid managers, cautioned DOE against allowing the NIETC designation process to “inject unhelpful uncertainty into regulated transmission planning processes.” It said ongoing planning initiatives like MISO’s long-range transmission planning shouldn’t be undermined by DOE “potentially elevating” inefficiently planned projects over those contemplated in FERC-approved planning processes.
“That situation could slow progress and erode stakeholder support for these plans and/or make it more difficult to move ahead with regionally planned portfolios that have been in the works for years,” WIRES said.
WIRES, state regulators and PJM said DOE should require projects be included in a regional transmission plan before they can receive a NIETC designation.
“The NIETC process should not be used to circumvent [RTOs’] transmission planning processes. If a project is proposed as part of the RTO planning process and does not meet RTO planning or benefit criteria, then [its] proponent should not have recourse to the NIETC process to push that project into construction,” regulators from Michigan, New Jersey, North Carolina and Virginia said in a joint comment. “Both are federal processes — one subject to a FERC-accepted tariff, the other this application process. Having two conflicting federally approved processes would deter, rather than promote, responsible transmission planning.”
APPA agreed. “Failure of a proposed project to participate in a regional, interregional or even local planning process should weigh heavily against NIETC designation, particularly since a NIETC designation (and the prospect of FERC backstop approval) might otherwise encourage transmission developers to circumvent regional transmission planning and/or interregional coordination,” APPA said.
PJM said that without an “orderly, sequential NIETC process” that recognizes the authority of RTOs and ISOs, “DOE could find itself having to referee among developers/applicants who are seeking to end-run the detailed RTO/ISO analyses and competitive planning processes … Absent such a clearly-defined and sequential process, the roles of an RTO/ISO as a Planning Authority could be blurred with DOE potentially granting a NIETC designation that is at odds with the reliability, market efficiency and state public policy analyses undertaken by the RTO/ISO in choosing among competing projects.”
Invenergy said DOE should solicit interregional merchant transmission projects, “which have the potential to solve critical interregional needs while largely avoiding contentious discussions on cost allocation, but which face unique barriers and hurdles.”
“DOE must ensure that the process is equally accessible to transmission developers and transmission projects regardless of their business model and inclusion (or not) in a FERC-approved regional transmission planning process. Since many of the FERC-approved regional transmission planning processes exclude from consideration merchant transmission projects, as well as any other transmission projects not seeking cost allocation, inclusion in such a plan must not be a criteria in the NIETC process. … FERC-approved regional planning processes tend to be narrowly focused, considering only benefits that accrue to that particular region and specific needs identified by the region.”
ERCOT meanwhile made clear it wants no part of NIETC, saying DOE should ensure that “a proposed NIETC does not include any portion of the ERCOT region.”
Metrics and Priorities
EEI criticized the NOI/RFI for lacking information on how DOE will compare and prioritize NIETC applications. “Section 216 of the Federal Power Act does not limit the number of national interest corridors that DOE may designate, but reason demands that DOE cannot designate every submitted application (or even many applications) as a NIETC,” EEI said. “… An explanation with respect to how DOE will evaluate the magnitude and effects of the transmission needs in proposed corridors would ensure that DOE designates the corridors of greatest need. This would further ensure prudent management of the financing tools created by the Infrastructure Investment and Jobs Act and Inflation Reduction Act.”
Idaho Power said DOE should use available transmission capacity as an indicator of areas with constraints. “The amount of transmission service requests that entities receive for a given corridor and the cost of required transmission upgrades identified in transmission service request studies is also a potential metric,” the company said. LMP data from the Western Energy Imbalance Market could be used to identify areas with large reoccurring price spreads in the Western Interconnection, it added.
The New York Transmission Owners said DOE’s pending Transmission Needs Study should incorporate existing transmission planning processes rather than relying solely on National Renewable Energy Laboratory modeling for projecting future transmission expansion. DOE issued a draft Needs Study in February and expects to issue the final study later this summer.
“It is important that the study’s findings are reconciled with existing transmission planning, including existing planned project solutions, in DOE’s consideration of NIETC designations,” the TOs said.
NRDC and the other public interest groups said DOE should favor proposals that “provide the greatest and most immediate benefits in terms of increasing interregional transfer capacity and diversification of regional resources to speed the development of wind, solar and storage resources …” and “highly prioritize GHG reductions.”
The groups said interregional transmission has shown strong benefit-to-cost ratios and cited calculations by MIT researchers who found that “interstate coordination and transmission expansion [including across regions and interconnections] reduces the system cost of electricity in a 100%-renewable U.S. power system by 46% compared with a state-by-state approach, from $135/MWh to $73/MWh.”
“Because [interregional] projects provide great benefits but face great obstacles, they provide the best opportunity for DOE to maximize the positive impacts from NIETC designations,” the groups added.
Broad or Specific Designations?
The Rail Electrification Council and NextGen Highways, which suggested NIETC designations for existing railroad or highway rights of way, praised DOE for focusing on narrower areas and specific projects than in the first NIETC effort, “an ambitious approach in 2006 that set itself up for rejection by the courts.”
In 2011, the Ninth Circuit Court of Appeals vacated the first National Electric Transmission Congestion Study and its designation of the Mid-Atlantic Area national corridor and the Southwest Area corridor.
“The regional breadth of prior designations … made adequate identification and consultation with stakeholders extraordinarily difficult because of the volume and variety of landowner, environmental, economic and other issues involved,” the groups said.
Largest congestion value of new transmission is across the interconnects and during extreme weather events. | Lawrence Berkeley National Lab
However, Power From the Prairie, a proposed, 4,000-MW interregional HVDC line from southern Wyoming to northwestern Iowa, asked DOE to define NIETC corridors “broadly,” not tying them to any established routes. It also said DOE could consider establishing a separate “promising NIETC candidate project in-waiting” category for lines in the early stages of development.
NRDC and its allies supported DOE making NIETC designations not associated with a project under development. “DOE is well-situated to identify corridors that are in the national interest but where private development alone may be too challenging,” they said.
EEI said DOE should reconcile an apparent conflict in the NOI/RFI between the department’s assurance that it “does not intend to identify preference for specific projects within the corridors” and its assumption that proposed NIETCs will likely be “route-specific.”
PJM said if DOE opens NIETC applications to generation and merchant transmission developers it should limit it to those with executed interconnection agreements.
But Con Edison said DOE should not reject projects in the early stages of development that lack details on routing and environmental impact. “Projects in the conceptual or preliminary stages of development may have significant value and stakeholder support to address emerging clean energy needs, and therefore should be accommodated and not overlooked or delayed through the DOE process due to their nascent status,” the company said.
Balancing Climate and Conservation
The Arizona Game and Fish Department said while DOE is on the right track to include state, tribal and local authorities in NIETCs planning, it should also explicitly state that applicants consult with state wildlife agencies and other natural resource agencies to select routes that minimize habitat damage.
“State wildlife agencies can provide specific recommendations and information from subject matter experts on sensitive resources, species occurrence and distributions, areas of concern, wildlife connectivity, and more, as well as advise on potential conservation measures to avoid, minimize or offset potential impacts,” the Arizona agency said.
Conservation organization the Land Trust Alliance urged the DOE to write in explicit protections for conserved lands; incentivize proposals that utilize existing rights of way and minimize the land use footprint of transmission corridors; and only accept route-specific applications for consideration to avoid “orphaned NIETCs that are never built out due to conservation needs being identified too late in the process.”
“We must not undermine our nation’s investments in and future needs for conservation by siting energy transmission infrastructure in such sensitive environmental areas as conserved lands or lands with high conservation or agricultural values. For our nation to achieve its climate goals, there must be a balance of planning for clean energy through smart siting that recognizes conservation goals.”
A group of cities and communities across PJM and MISO called on DOE to develop a replicable and transparent designation process with community workshops and roundtables. They also asked DOE to require applicants to submit community benefits plans and address equitable siting issues.
“The process should seek to balance the need for timely transmission and infrastructure development with community priorities,” the PJM and MISO communities said.
Legal Questions
Several commenters raised legal questions over DOE’s proposed approach.
The sponsors of the Southeastern Regional Transmission Planning Process (SERTP) — including Southern Company, Duke Energy and Louisville Gas and Electric Co./Kentucky Utilities Co. — said the applicant-driven, route-specific NIETC designation is “inconsistent” with the Federal Power Act and could override state resource plans or regional transmission planning.
EEI challenged DOE’s contention that the NIETC process is only guidance, saying the department must adhere to the notice-and-comment rulemaking requirements of the Administrative Procedure Act.
“DOE has taken the position that the designation of NIETCs constitute informal adjudications under the APA, not informal rulemakings. While that may be a defensible interpretation as to any given designation of a specific NIETC, that is not what DOE intends to accomplish in the planned ‘guidance’ that the NOI lays the groundwork for,” EEI said. “Rather, the planned ‘guidance’ would establish a prospective, broadly applicable framework for the designation of all route-specific NIETCs. DOE must do so through a rulemaking.”
Farm bureaus from multiple states — aware that their members may have lands seized through eminent domain — argued that the DOE doesn’t have the authority under the FPA to prescribe applicant-driven, route-specific framework for corridors, which would “put the cart before the horse,” they said. Rather, they said the DOE should “solicit input regarding specific geographic areas that should be designated as NIETCs, but not specific projects needed to alleviate congestion or constraints in those areas.”
DOE cannot solicit projects that are already under development and draw a corridor around them, the farm bureaus said. Instead, they said the department must defer to states and regional planning authorities.
Some commenters questioned DOE’s proposal to limit applicants’ “Affected Environmental Resources and Impacts Summary” to 20 single-spaced pages, not including maps. The filing is required to detail engagements with “Communities of Interest,” the status of regulatory approvals and whether the project has been included in any local or regional transmission plans. DOE also asks applicants to explain if they are using transmission technologies such as advanced conductors that allow more capacity in smaller corridors.
The Arizona Game and Fish Department said the limit should be removed.
Next Steps
DOE’s NOI/RFI doesn’t say how soon it will finalize its guidance on the NIETC program after reviewing comments. It has said it expects to post the final Needs Report in late summer 2023.
