Page 267 – RTO Insider

June 19, 2023July 11, 2023

Energy Bar Association Meeting Focuses on Financing Clean Power Transition

NEW YORK — With individual project budgets reaching into nine and 10 digits, financing often is front and center in discussions of the clean energy transition.

And it was the leadoff topic Wednesday, as the Northeast Chapter of the Energy Bar Association convened its annual meeting in Manhattan.

The confluence of headwinds and tailwinds in the early 2020s — war, contagion, inflation, policy support, the end of cheap capital, massive tax credits, massively complicated rules for those tax credits, delay upon delay — makes for interesting times.

Kurt Strunk, managing director of National Economic Research Associates, said the fundamentals are the same as always: “What’s really needed is strong economic governance and reliable institutional foundations … The good news is, the institutional structure is there.”

The traditional formula to finance a power plant — “an airtight offtake contract with a creditworthy counterparty” — is still a winning combination, in his opinion.

“It’s true that the amount of investment needed to affect the energy transition is daunting,” Strunk acknowledged.

The extensive tax credits of the Inflation Reduction Act were intended to accelerate the U.S. clean energy transition and help create a domestic manufacturing base to supply it. A secondary beneficiary has been the army of legal and financial experts putting together deals to leverage those credits.

Financing the Transition

“Tax equity bridge financing has been the flavor of the year so far,” said David Avila of Paul Hastings LLP. “Everyone, with the IRA coming into place, is trying to take advantage of the ITCs and PTCs. That has really increased demand for the tax equity, which is now completely outstripping the supply.”

He said he has spoken recently with banks that have traditionally worked only in debt but are now looking to move into tax equity. “I think that’s going to be something we see evolving over the next couple of years.”

Also, Avila said, banks are getting more comfortable closing on just a letter of intent with a credit-rated entity, rather than the signed tax equity contribution agreements traditionally required. That puts much more scrutiny on the sponsors themselves, he added.

“We’re spending a lot more time structuring these deals than we ever have before. It’s a lot more problem-solving and constructing the financing.”

One aspect of the IRA — the domestic content adder — is problematic at this stage, Avila said. With U.S. manufacturing still ramping up or even still on the drawing board in mid-2023, it’s entirely possible a project planned now will have less domestic content than originally expected once it’s completed, years in the future. If the domestic content adder was factored into the financing but the project is disqualified from receiving it, there’s suddenly a big hole in the financials.

Another problem Avila is seeing more than in the past is project attrition.

If interconnection upgrade costs are spread between several projects in the queue, and some of those other projects drop out of the queue, the entire cost falls on the surviving projects, blowing out their contingency budgets.

“We’re getting a lot of questions from lenders … asking us to go into the dockets to see which interconnection providers have had these issues,” Avila said.

Vikram Bakshi, managing director at Skyline Renewables, said he’s been working in renewable energy since 2006 and sees enormous opportunity in 2023.

“In terms of market trends, couldn’t be more optimistic,” he said. “We see trillions of dollars of opportunity — not just cleaning up the grid, but if you look at decarbonization of the rest of industry, the numbers are enormous.”

Renewables are the cheapest form of generation, there’s regulatory support for them, the IRA creates tailwinds and corporations want to boost their ESG profile with green energy, he said.

“I’m not sure what obstacles and headwinds you’re talking about, Kurt,” Bakshi added, drawing a laugh from the audience.

Supply chain, financing, interest rates and indexed pricing, Strunk replied.

Bakshi acknowledged short-term supply chain constraints, cost increases and delays and uncertainty about IRA guidance.

“But that’s going to be sorted out. We’re in no rush,” he said.

Bakshi added an important detail: Skyline is not in early stage renewable development. It typically steps in at the notice-to-proceed or the commercial-operations-date stage.

Alex Stein, senior counsel at the New York State Energy Research and Development Authority, added the perspective of a governmental entity leading a clean energy transition and awarding billions of dollars’ worth of contracts to carry it out.

NYSERDA has built some flexibility and adaptation into its clean energy solicitations. Earlier rounds allowed developers to bid a fixed price for renewable energy credits or a strike price indexed to the zonal energy and capacity price.

It is not a perfect hedge, Stein said, but it insulates against a lot of volatility.

The most recent solicitations have the option of an inflation adjuster, he said.

The period from proposal to start of construction is particularly long in New York. Developers of most of the pipeline of clean energy projects the state’s leaders boast about had locked in their compensation — but not their input costs — before the tumultuous events of the past three years.

Developers of much of the onshore portfolio and almost all the offshore portfolio this month petitioned for the same inflation index as NYSERDA is offering newer projects, saying they can’t obtain financing without it.

Stein did not touch on the petitions, which await review by the state Public Service Commission.

But he said NYSERDA took steps to recoup some of the windfall offshore wind developers might receive through IRA tax credits: “We see it as a way of sharing the potential upside of this and also reflecting the uncertainty that remains.”

Another provision in the latest offshore solicitation allowed developers to recoup higher-than-expected interconnection costs and required them to turn over most of the savings if those costs were lower than expected.

It is an evolving process, Stein said: “I think we can brainstorm on how to iterate this in the future.”

Role of Natural Gas

It was observed Wednesday that practitioners of energy law have tended to focus either on electrons or molecules — electricity or gas — but that those lines are blurring because natural gas has become an important fuel for generating electricity and electricity will be used to generate another gas: hydrogen.

Chris Smith, regulatory counsel to the Interstate Natural Gas Association of America, said natural gas has a critical role to play in the power grid for many years to come.

“There’s this perception that for the time being we can just gut it out because eventually we’re going to be transitioning to more renewable resources … we can kind of just squeak by the next couple years and then this thing will work itself out,” he said.

“Admittedly biased view, but I think for a lot of these problems you are going to need additional natural gas pipeline infrastructure — we don’t have enough now and we’re going to need more in the future,” Smith said.

Brian Fitzpatrick, principal fuel supply strategist at PJM, agreed.

He said gas fuels almost half of the RTO’s installed generation, but not all the generators have a locked-in supply. “About half of that has some firm level of transportation associated with it,” he said. “In an ideal world we’d love that to be 100%, but it’s not available — most of the large pipelines in this system are fully subscribed.”

Fitzpatrick said PJM is looking at 40 GW of potential fossil fuel retirements by 2030, mostly coal, without a similar amount of replacement capacity coming online in the same period. There needs to be multiple gigawatts of new renewable energy for each gigawatt of coal retired, but that is not happening, he said. Only about 8 GW of natural gas is in the queue.

“That mismatch can’t continue — otherwise we’re facing a significant reliability concern going forward,” he said.

PJM is gathering stakeholder input and intends to address this with a FERC filing by the end of October.

June 19, 2023July 11, 2023

WECC Says Summer Looks Better with Caveats

The West’s summer reliability outlook is better than it has been the past few years, but shortfalls could arise if new resources fail to materialize or imported electricity does not flow as expected, WECC analysts said last week in a technical session that preceded the organization’s Board of Directors meeting.

“Yes, we are improving,” WECC principal analyst Matthew Elkins said. “We’ve delayed retirements. We’ve expedited new resources online. Things are getting better in the near term.”

However, with supply chain holdups, fuel constraints and other problems, “I think we’re just kicking that can down the road,” Elkins said.

With more than 4,000 MW of coal-fired generating resources expected to retire by 2025, the supply chain issues need to be resolved and large amounts of new clean energy and storage resources need to be built if the West is to avoid further shortfalls, he said.

“We need to keep track of this,” Elkins said.

In its 2023 Summer Reliability Assessment, NERC said resources in the Western Interconnection are sufficient to support normal peak demand, but warned that a wide-area heat event could create problems for multiple subregions that normally rely on regional transfers to meet peak demand when solar production falls off.

The assessment also noted the risk of wildfires to the transmission network, which can limit transfer capacity and lead to localized load shedding. (See NERC Warns of Summer Reliability Risks Across North America.)

Elkins discussed those potential pitfalls and others in the technical session.

WECC analysts developed a matrix that shows hours at risk of shortfalls without new resources or imports in its four planning regions: California-Mexico, the Northwest, the Southwest and Canada.

In California-Mexico, there should be minimal loss-of-load hours if imports are not limited and all new Tier 1 resources come online this summer. Without those resources or transfers, the loss-of-load hours increase substantially, WECC’s analysis shows.

The same is true to a lesser extent in the Northwest and Southwest, WECC predicts.

Up to 13 GW of new generation and storage resources are planned to come online in the Western Interconnection by the end of this summer, but supply chain disruptions could undermine those plans, WECC says. (See Western Plan to Add 13 GW by Summer Comes with Risks.)

Most of the new resource additions will be solar, battery storage and wind, with some natural gas and biogas generation.

Last year, new solar installations in the West fell nearly 3 GW short of expectations because of tariffs on solar panels from Southeast Asia and supply chain constraints.

Many battery components still come from China, which has experienced COVID-related supply chain disruptions, as well as increasing tensions with the U.S. that could affect trade.

Planned battery installations last year fell short in WECC’s Northwest and Southwest regions, but not in California-Mexico, where the new batteries added to the grid exceeded expectations.

Through the end of 2023, more than 25,000 MW of new resources are planned to be installed. Elkins called the figure “historical.”

“We’ve never been over 10,000 MW,” Elkins said. “We’ve never built that much. This is two and a half times what we’ve actually built in the past.”

Whether most of those planned resources get built remains to be seen.

June 19, 2023July 11, 2023

EBA Roundtable Examines New York’s Transmission Buildout

NEW YORK — The Northeast Chapter of the Energy Bar Association held its annual meeting last week in New York, a state that’s keeping attorneys practicing in the energy sector particularly busy.

The state’s leaders boast of a nation-leading climate protection plan. Other states make similar claims, but New York would surely land at or near the top of any objective ranking.

It’s a hugely complicated and expensive undertaking, with many people working to make it happen.

New York State Public Service Commission Chair Rory Christian | © RTO Insider LLC

New York State Public Service Commission Chair Rory Christian, keynote speaker at Wednesday’s meeting, compared law to electricity: Society relies on both, expects both to function perfectly, but gives little thought to how they actually work.

The PSC has as its core mission maintaining affordable, safe, reliable, secure utility service, he said. But the passage of New York’s landmark Climate Leadership and Community Protection Act in 2019 gave the PSC a central role in climate protection as well.

And it’s taking steps every day to reduce greenhouse gas emissions from one of the largest sources: power generation.

“The results of this work will be seen in the form of changes to how our society uses and relates to the energy it needs to thrive,” Christian said.

“Each of you in this room today, in some way, will be called upon to address these concerns. Though you may not be climate lawyers by name, every lawyer in this room, in one way or another, will be working on climate change. Your clients’ needs will be increasingly driven by impacts of climate change, and it will be up to you to help support them through those efforts.”

Christian set the stage for a roundtable discussion later in the meeting about transmission infrastructure in New York, noting that PSC’s effort to reduce emissions from generation is only part of decarbonizing the power sector.

“Transmission is incredibly important because it’s integral to be successful in what we’re doing. The system we built — one based on large, central power plants — requires a different kind of transmission infrastructure than the one we envision in the future, one that’s largely decentralized, distributed, relying on smaller, more intermittent resources,” he said.

“Building out this transmission infrastructure is going to be a critical component in our efforts to meet our goals. Accomplishing this is going to require a multipronged effort above and beyond the vehicles available to us.”

Roundtable Discussion

Moderator William Hollaway, of Gibson Dunn & Crutcher, opened the roundtable on a positive note: Why have there been so many success stories with transmission infrastructure development in New York?

Asha Gandhi, a senior vice president at energyRe, offered four reasons: a policy that sets a very ambitious target for renewable energy generation and recognizes transmission’s role in that; frameworks for public-private partnerships; a structure for revenue sourcing; and a streamlined permitting process.

EnergyRe is part of one of the largest clean energy projects in the nation, partnering with the New York Power Authority and Invenergy on Clean Path NY, which entails 3.8 GW of wind and solar power and a 175-mile HVDC line to bring that electricity to the New York City region at an estimated $11 billion cost.

Part of the Solution

Hollaway closed the session with the thought that the processes discussed Wednesday need to extend beyond policymakers, energy developers and attorneys to the millions of people who ultimately will reap the benefits of the decisions being made — as well as foot the bill.

The need, in other words, is for people to realize they are part of the solution.

“That might mean land use, but it also means contributing into the pot to help defray the cost of these things,” he said.

The increasing visibility of electric cars and other tangible signs of change may help this happen, he said.

“As people see that, maybe they’ll start to say, ‘You know, I AM part of this transition, and I do have a responsibility to pay, I am a beneficiary,’” Hollaway said.

“Maybe the whole beneficiary-pays thing will become less abstract once people are actually seeing how this stuff hits home with them.”

June 19, 2023April 11, 2024

JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B

MADISON, Wis. — The cost estimate for MISO’s and SPP’s package of 345-kV lines meant to facilitate the interconnection of generation at the seams has nearly doubled, the RTOs have said in the past week.

The portfolio’s costs have climbed from $1.1 billion to $1.9 billion because of the mounting cost of materials and labor and the transmission owners providing more precise routing options.

Aubrey Johnson, MISO’s vice president of system planning, updated the joint targeted interconnection queue’s (JTIQ) cost estimate during the grid operator’s Board Week in Madison, Wis., last week.

The increased amount was included in an application led by the Minnesota Department of Commerce and The Great Plains Institute for Department of Energy funds from the agency’s Grid Resilience and Innovation Partnerships program. If successful, the JTIQ portfolio could receive up to 50% funding match from the federal government. (See DOE Clears JTIQ Projects to Proceed with Funding App.)

MISO said the first cost estimate was theoretical and two years old.

“The 2023 JTIQ application to DOE reflects a higher end, broader scope, cost estimate for matching federal funds, and it is not directly comparable to the 2021 planning-level cost estimates,” MISO spokesperson Brandon Morris said in an emailed statement to RTO Insider. “Since 2021, we have also seen inflationary pressures and supply chain uncertainty.”

“Developers are having heartburn about the cost increases and would like to have some understanding and parameters around the increases,” Clean Grid Alliance’s Beth Soholt said during an Advisory Committee meeting Wednesday.

She urged MISO and its transmission owners to institute “checks and balances,” given the JTIQ’s proposed cost allocation that has generation developers responsible for 90% of costs and load picking up the remaining 10%.

MISO said it will further update stakeholders on the JTIQ’s application for DOE funding at a June 27 combined Planning Advisory Committee and Regional Expansion Criteria Benefits Working Group meeting.

During an SPP Seams Advisory Group meeting June 9, the RTO’s Aaron Shipley said staff is reviewing the cost increases and developing a more detailed breakdown of the rising prices.

“Whereas originally we were working on a conceptual cost estimate basis, as we get closer to it, we find those cost estimates from the TOs themselves,” he said. “Some of that [is] inflation impacts … but also more accurate routing of assessments, materials’ costs, the construction timeline [and] supply chain concerns. Those type of items really drove some of that cost [increase].”

Shipley said had the applicants’ DOE application used the $1 billion estimate, they would have been limited to up to half that amount should the agency award any funds.

June 15, 2023July 9, 2023

Historic Solar Growth Seen in Southeast

The Southeast’s solar capacity will more than double by 2026, according to the Southern Alliance for Clean Energy’s (SACE) sixth report on solar energy development.

The report released Wednesday forecasts growth to 40 GW of capacity by 2026, more than double the 18.8 GW claimed last year. Available watts/customer (W/C) are expected to increase as well, from 580 last year to 1,217 in 2026. SACE Executive Director Steve Smith described this rise as a “generational transition” in more than one sense.

“You have to be part of the clean energy generation, both in a generational sense where each and every one of us are part of the generation to actually seize this moment and create change,” Smith said. “But then also we’ve got to get more literally physical clean energy generation on the ground.”

This growth, the report says, is due largely to two federal moves: The implementation of the Inflation Reduction Act (IRA); and a two-year moratorium on import duties from Vietnam, Cambodia, Thailand and Malaysia that “helped the U.S. solar industry regain its footing after an extended supply chain disruption.”

Southeast Solar Forecast by State | Southern Alliance for Clean Energy

Within the IRA, production and investment tax credits were returned to their full valuation of 30% and extended out to 2032, which “provided certainty into the market that the market really needs,” said Bryan Jacob, SACE’s solar program director.

The IRA also contains a $9.7 billion grant for rural electric co-ops, which Jacob said may be “the most transformational program for rural America since the Rural Electrification Act itself, back in 1936.”

The steep increase in available solar capacity in the next four years will not be evenly borne by the states in the Southeast, the report showed. Driven by policies such as solar base rate adjustment, said Jacob, Florida will increase its capacity to more than 17 GW by 2026, “almost as much as the entire Southeast region had last year.”

North Carolina, Georgia and South Carolina are also projected to increase their capacity dramatically, with Georgia slated to overtake North Carolina in both total capacity and watts/customer by 2026. Alabama, Tennessee and Mississippi “continue to fall far short of other Southeast states in both installed capacity MW as well as watts per customer (W/C) solar ratio,” the report said.

When asked to elaborate on the latter projection, Smith said he has not seen these states’ utilities “look at solar as a workhorse resource yet,” adding that many utilities are “inappropriately planning for what the future is unfolding to be,” and “making the wrong bets” on fossil fuels.

Sunblockers and Sunrisers

SACE’s report highlights several of these lagging utilities as “Sunblockers” — utilities with more than 500,000 customers with a four-year projected W/C ratio less than the Southeast’s average for last year (580).

Alabama Power and the North Carolina Electric Cooperative remain on this list from last year, at 331 and 197 W/C respectively, with PowerSouth joining them at 169 W/C. While Tennessee Valley Authority and Seminole Electric “remain considerably below the region averages,” at 658 and 600 W/C, the report said, they are not quite Sunblockers technically.

The opposite category also exists: “Sunrisers,” or the seven utilities with the largest projected increase in W/C solar ratio. Walton EMC, projected to increase its ratio by more than 4,000 W/C, retained its large lead. The second-largest increase was 1,564 W/C by the Knoxville Utilities Board. New to the Sunrisers list is Santee Cooper, due both to the utility’s own plan and commissioned solar development. The Sunrisers list is not constrained by customer base size as is the Sunblockers list.

However, these projections are not set in stone, Jacob said, as “the most important contributor to the forecast is integ resource plans (IRPs) that we have access to.” Because of the IRA’s recency, some utilities “haven’t had a resource planning process since August of last year, when the Inflation Reduction Act was signed.”

Georgia Power, for example, will not have a new resource planning process until 2025, while Duke will file its first IRPs aligned with its new Carbon Plan on Aug. 1and Sept. 1 for South Carolina and North Carolina.

So, while some growth is reflected in the forecast, Jacob said, “We’re gonna see a lot more for kind of the back half of the decade. That being said, the current forecast out to 2026 is already super bullish.”

June 15, 2023January 3, 2024

MISO Modeling Line Options for 2nd LRTP Portfolio

MADISON, Wis. — MISO says it’s on track this year to map the new transmission lines required for its second long-range transmission plan (LRTP) portfolio.

“We’re facing unprecedented circumstances, new conditions coming at us faster,” Aubrey Johnson, vice president of system planning, said Tuesday during the Board of Directors’ System Planning Committee meeting.

Johnson said resource churn is driving MISO’s need to pull together a second Midwestern LRTP portfolio. He said staff are planning to regularly update 20-year transmission planning futures after a refresh this year revealed dramatic changes since the previous update in 2020 (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)

“The system we’re operating, and the plans our members have are dynamic, and they’re changing day by day,” Johnson said.

The grid operator has finalized the second of the portfolio’s three futures, a mostly decarbonized scenario that anticipates a 2042 energy mix comprised of 51% wind, 22% solar, 8% battery, 8% other resources and 7% nuclear. It also includes a 2% hybrid with renewables paired with storage and a 1% contribution each from coal and natural gas.

MISO hopes that the last 0.3% of the energy mix will come from 29 GW of “flex” resources, yet undefined resources that are expected to be a dependable, on-call source of firm capacity.

The second future projects MISO will operate with 466 GW of nameplate capacity. That is broken down into 160 GW of wind generation, 112 GW of solar, 65 GW of natural gas, 41 GW of other generation, 31 GW of battery storage, 29 GW of “flex” resources, 12 GW of nuclear, 10 GW of storage and 6 GW of coal.

Johnson said though the RTO still expects to operate several gigawatts of gas and coal facilities, their energy contributions will be on a strictly as-needed basis.

“We need to have these resources, but they’re going to be used very infrequently. But when they’re needed, they’re needed,” Johnson stressed.

MISO foresees risks during calm, hot summer days when the wind doesn’t pick up after sunset and during winter daytime load peaks, where there’s a risk of unserved energy before sunrise and after sunset. Johnson referred to those risky periods as the grid operator’s “twilight problem.”

He said staff are anticipating escalating thermal generation retirement requests and are preparing to study them. MISO plans to complete the second LRTP portfolio’s modeling by early fall. That modeling will inform which projects MISO ultimately recommends.

“We’re getting ready for the sprint, if you will,” Johnson said.

Johnson said it’s getting more challenging to feasibly model a future system that can reliably serve load with the resource mixes on the horizon.

“In reality, we’re probably behind in the way we’ve done some of our economic analysis,” he told board members.

Senior Director of Transmission Planning Laura Rauch said MISO’s resource expansion tool currently used for transmission planning was intended to account for large baseload power sources, not siting a host of scattered wind and solar facilities.

Johnson said the RTO’s forthcoming proposal to tighten rules around when developers can enter and exit the interconnection queue should make clear to planners the future mix they’re planning for. (See MISO Wants Tougher Obligations on Queue Entry and Exit.)

He said MISO is hoping to encourage generation plans that are “targeted toward completion rather than targeting holding a place in the queue.”

The grid operator’s current generator interconnection queue contains 1,379 active projects totaling a little more than 237 GW. Almost all of that is renewable energy or battery storage.

“Future generations are depending on this to get this done and get it done right,” director Mark Johnson said of the expansion planning.

Ciaran Gallagher, with nonprofit Clean Wisconsin, said MISO is neglecting storage resources in its annual transmission and LRTP planning. She said there’s “insufficient” representation of battery storage in modeling and the RTO’s assumptions don’t represent the projects in the queue.

Gallagher said storage and hybrid resources can “bolster the grid with attributes” that MISO is losing through thermal generation retirements. She said more battery storage incorporation must be considered “to plan the optimal grid.”

ROFR Developments May Complicate LRTP Planning

Johnson also addressed right-of-first refusal (ROFR) legislation activity in the MISO footprint.

He said staff are monitoring developments in Illinois and Iowa. A bill in the former that would specifically give Ameren Illinois exclusive rights to build regional MISO lines has passed both houses and is awaiting the governor’s signature (HB 3445). Iowa’s ROFR law has been temporarily overturned, pending a final ruling from a district court. (See Iowa Regulators Ponder MISO Tx Projects After ROFR Ruling.)

Both developments could determine which utilities are allowed to construct some projects in the LRTP portfolios.

“There’s a lot of activity we’re following and working with our legal team to understand the implications,” Johnson told board members.

June 15, 2023November 9, 2023

California EV Grid Fixes Could Cost $35B Less than Estimated

Upgrading California’s distribution grid to serve millions of electric vehicles could cost far less than the $50 billion that a study published last month indicated, the California Public Utilities Commission’s Public Advocates Office said in a paper announcing its own study.

“The Public Advocates Office is finalizing a study of the costs of upgrading the distribution grids of the three largest investor-owned utilities to meet California’s transportation electrification goals,” the paper said. “Our preliminary results indicate that the total cost of upgrading the distribution grid by 2035 will be approximately $15 billion to $20 billion.”

California law requires that all new vehicles sold in-state be zero-emitting by 2035, but the potential effects on the grid are only now being weighed.

A separate study commissioned by the CPUC and published May 9 found that it could cost as much as $50 billion to upgrade the distribution grids of Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric to accommodate high levels of EV charging. (See Study: Calif. Needs $50B in Distribution Work for EVs.)

Energy analytics firm Kevala conducted the study. It emphasized that the findings assumed existing time-of-use rates would remain in place throughout the study period, from 2025 to 2035.

“It did not consider alternatives or future potential mitigation strategies such as alternative time-variant rates or dynamic rates and flexible load management strategies,” the firm said.

Kevala’s study predicted that distribution systems’ peak load would increase by an average of 56% from 2025 to 2035, requiring the utilities to nearly double their current spending on feeder lines, transformer banks and substations.

The Public Advocates Office, also known as Cal Advocates, is an independent consumer watchdog that often disagrees with CPUC staff and commissioners. It said it used assumptions different from Kevala in preparing its preliminary findings.

“The difference between our preliminary cost estimate and Kevala’s higher cost estimate stems from Kevala’s forecast of a larger growth in peak load,” it said. “Our peak load forecast is drawn from, and aligned with, the California Energy Commission’s Integrated Energy Policy Report (IEPR).”

Kevala’s peak load estimate may have resulted from its assumption that many EVs will be charged at 9 p.m., when time-of-use rates fall on weekdays.

In contrast, “the IEPR, which Cal Advocates uses, forecasts that EV charging occurs much more evenly across the day,” the paper said. “As peak load is a key driver of the need to upgrade the distribution grid, Kevala’s higher peak load growth forecast drives Kevala’s higher costs.”

The paper also says that that Kevala forecast the “total energy consumed in charging EVs will be 40% higher on the peak day than in the IEPR or in Cal Advocates’ study. Higher charging energy contributes to the difference in the peak loads and results in higher cost estimates.”

The advocates office said it intends to refine its analysis, engage with stakeholders and complete its study by August.

A second part of Kevala’s Electrification Impacts Study will build on the first part’s findings, including by developing scenarios that reflect state policy goals, state agency targets and the Energy Commission’s demand forecast. The advocates’ finding will be available to Kevala as it performs the second part, the office said.

Cal Advocates said additional studies would be useful for state planners.

“No single study or pair of studies, particularly this early in the electrification process, can definitively answer such a complex question as what the costs of distribution grid upgrades will be,” the office said. “Cal Advocates’ study aids the continuous discourse on electrification costs and benefits rather than establishing a final cost projection.”

June 15, 2023June 26, 2023

Future of Grid Planning Debated at Infocast Transmission Summit

ARLINGTON, Va. — The electric industry must improve its long-term planning to account for a changing generation mix and new load patterns, experts at Infocast’s Transmission & Interconnection Summit said Tuesday.

While MISO’s long-range transmission planning and California ISO’s 20-year transmission outlook both stand out as exceptions, the industry generally does not think far ahead when it comes to grid planning, Grid Strategies President Rob Gramlich said at the summit. (See MISO Board Approves $10B in Long-range Tx Projects.)

But FERC’s Notice of Proposed Rulemaking requiring the industry to adopt long-range, scenario-based planning has started to change that. (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“I think the push has been helpful in the establishment of a sort of a vision that you should be proactively looking at the anticipated future resource mix and … the load forecast. And both of those things are, of course, uncertain, but the industry has had to deal with that for its entire history,” Gramlich said.

The uncertainty can be addressed by using scenarios to determine the best transmission options to link future supply and demand. While that would be the ideal, most of the country is not doing that even at the regional level, Gramlich said.

“What happens then is all the pressure for the limited capacity goes into the interconnection process,” Gramlich said. “And it’s a self-reinforcing downward spiral of studies and re-studies and queue churn — and all of those things that can be greatly alleviated if we had the infrastructure.”

In SPP’s 2021 interconnection process, most interconnecting resources were saddled with more than $1 million in transmission upgrade costs — often for lines rated at 345 kV and above, said ICF Vice President Himali Parmar.

“That clearly tells you that the system — the planning process — is broken somewhere in SPP,” she added.

Stuart Nachmias, CEO of Con Edison Transmission, agreed that the transmission planning process needs to start looking ahead to a grid dominated by renewables and responsible for the electrification of both transportation, which has already started, and heating, which he said is not far behind.

“There is much more robust planning process that we need. We need to identify the transmission … and distribution that needs to be expanded to meet the future needs,” Nachmias said. “Because the one thing I know for sure is that the day reliability is not what customers expect is the day that everything comes to a standstill. And none of us want that to happen.”

The industry has a spotty record when it comes to planning lines required to meet public policy mandates, but FERC could be doing more under existing rules to make that more common, said Sharon Segner, senior vice president of transmission policy at LS Power.

“There’s whole sections of the PJM operating agreement that are not being enforced right now relating to public policy planning and requirements,” Segner said. “And there’s more than this FERC could be doing under existing law.”

PJM’s Order 1000 compliance rules call for the RTO to perform an annual sensitivity analysis on public policy transmission requirements, which are not being used, she added.

Transmission planning processes were all designed around slow and deliberate change to the power system, but bigger changes are coming now, said Kris Zadlo, chief commercial and technology officer at Grid United.

The “institutional framework” was “set up for something that was relatively static,” Zadlo said. “And now we don’t have a very static system, the system is changing in front of our eyes, and the whole planning process must adapt accordingly.”

An increase in computing power has made planning much quicker. Where it once took hours for a mainframe to process one power flow, modern machines can now go through thousands of scenarios across an interconnection in just hours, Zadlo said. That extra analysis has led to paralysis: Instead of focusing on so many options, transmission planners should pick the best plan and move forward with it, he added.

At the request of New England states, ISO-NE started to plan further into the future with its 2050 study, in which the states helped identify what resources would be developed and how load would grow in response to their policies, said Maine PUC Chair Philip Bartlett II. (See ISO-NE Planners Outline Potential Solutions for 2050 Tx Overloads.)

Bartlett said state officials hope the change will ensure the region can “right-size” investments in larger projects that improve efficiencies. “Because the only way we’re going to get through this transition cost-effectively is if we think thoughtfully, we don’t miss opportunities for lower-cost upgrades, and we avoid some of the expensive costs down the road by making smarter decisions through our planning today.”

While New England has spent plenty on transmission in recent years, the spending has been directed at curing reliability issues, and not nearly enough has gone to help states meet long-term policy goals, he added.

PJM is also spending on transmission now, but its process often favors local projects that lack outside scrutiny, said Greg Poulos, executive director of the Consumer Advocates of the PJM States.

“We pay a lot of money for local transmission, and the local transmission process doesn’t typically allow for any oversight,” Poulos said.

Coordinating policies can be challenging in both RTOs. PJM states have a wide range of policy goals, while in ISO-NE, one state has no climate goals, while many others call for net-zero emissions by midcentury.

But transmission provides other benefits for all states, from improving reliability and resiliency to reducing emissions covered by existing federal laws, Bartlett said. The key to getting needed transmission built regardless of state policy differences is to define those benefits and allocate associated costs in a way that achieves agreement, he said.

By using separate planning processes to meet different goals, RTOs dilute the value of the kind of multipurpose transmission lines that are often praised as most effective, said Matthew Crosby, senior director of policy and strategy at Cypress Creek Renewables.

“There’s a clear need to look at the sequencing of these tests,” Crosby said. “And right now, without someone that’s independent of the transmission owner, or the regional transmission operators, enforcing that and guiding that process — I’m not sure how we disrupt the status quo.”

That role could be filled by an “independent transmission monitor,” an idea FERC floated in its advanced NOPR on transmission but that did not make the cut in its planning NOPR. Reliability often takes precedence because the issues need to be fixed quickly and a multivalue planning process takes longer, but Crosby suggested some of those issues could be dealt with using grid-enhancing technologies while giving planners enough time to come up with more efficient, long-term transmission fixes.

State Perspectives

In states participating in organized markets, grid planning is typically led by the RTO, but that seems to be changing, as FERC and ISO-NE have started to recognize that states should lead when it comes to planning lines for policies, said Vermont Public Utility Commissioner Riley Allen. States in his region are represented by the New England States Committee on Electricity (NESCOE), which gives them a cohesive voice on RTO issues.

NESCOE should be able to come up with a plan to build out the grid regionally to meet its members’ policies, both through the ISO-NE’s 2050 outlook and nearer-term planning, Allen said.

“Something that is relatively robust and amounts to a more postage stamp-type framework is probably preferable over time to kind of a state-by-state approach and addressing some of the challenges associated with that,” Allen said.

Allen sits on the Joint Federal-State Task Force on Electric Transmission with North Carolina Utilities Commissioner Kimberly Duffley, who said the Order 1000 process is working in the Southeast without resulting in capital flight to local projects with less oversight, which she attributed to her agency’s robust IRP process. (See Federal and State Regulators Look into How to Improve Grid Security.)

“If you do this type of top-down approach of transmission planning in non-RTO regions, you really are infringing upon the state’s resource planning that they’re doing where the state is looking at transmission, as well as generation, for solutions to meet the goals in a least-cost manner,” Duffley said.

Her state also has a robust transmission siting process, issuing certificates of public convenience and necessity in a process where the commission’s “public staff,” which represents state residents, can intervene to oppose unneeded projects. Another major difference is that North Carolina utilities can recover 70% of their transmission costs in retail rates, so FERC does not even control most of the funding.

Colorado is considering joining an RTO, but in 2021 it created the Colorado Electric Transmission Authority (CETA) to facilitate development of new transmission, said the agency’s Kathleen Staks.

CETA was established by the same bill directing the state’s utilities to join an RTO by 2030, so it was conceived to consider the broader regional perspective of better connecting the state with the rest of the West, Staks said.

Colorado modeled CETA on New Mexico’s Renewable Energy Transmission Authority, which helped clear the way for approval of Pattern Energy’s Sunzia line, which was designed to bring New Mexican wind output to markets further west, Staks said. (See Sunzia Project Wins Final Approval, Signs Offtakers.)

DOE Sees State Collaboration as Key

While the U.S. Department of Energy has limited authority to designate National Interest Electric Transmission Corridors, it will be increasingly important for it to collaborate with states as it studies the issue of transmission buildout, according to Jeff Dennis, deputy director for transmission at the agency’s Grid Deployment Office.

The nascent offshore wind industry could benefit from such a collaboration. The sector is currently driven by state contracts and dominated by an inefficient radial approach to transmission, where each project runs its own connection to the onshore grid. But that approach won’t scale as more projects get built, Dennis said.

DOE has been working on recommendations to help expand the industry, including getting Atlantic states to collaborate on a networked transmission system and share the costs.

“The obvious example is landing points, right?” Dennis said. “If we continue this radial approach, we’re going to impact lots of communities. We’re going to impact lots of offshore industries outside of energy, like fisheries.”

Offshore wind’s most obvious impacts are along the coast, but the resource will require an expansion of the onshore grid that will impact even inland states such as Vermont, he added.

“We’re not the regulator, of course, so that gives us some opportunities, I think, to provide support to collaboration [and] to try and provide good information that will help the states in those collaborations make decisions collectively,” Dennis said.

June 15, 2023June 26, 2023

FERC Approves More Extreme Weather Rules

FERC on Thursday approved two new rules intended to strengthen the grid against extreme weather events.

The commission ordered NERC to either update reliability standard TPL-001-5.1 (transmission system planning performance requirements) or create a new rule that would require responsible entities to plan specifically for both extreme heat and cold weather events (RM22-10). Either way, entities will be required to create a corrective action plan to mitigate any occasions where performance requirements for extreme weather have not been met.

FERC also directed transmission providers to submit a one-time report detailing their policies and processes for conducting extreme weather vulnerability assessments and mitigating identified risks (RM22-16, AD21-13).

Based on the staff’s presentation at FERC’s monthly open meeting in Washington, D.C., the commission made only minor alterations from when the rules were first proposed about a year ago. (See FERC Approves Extreme Weather Assessment NOPRs.)

Both rules will take effect 90 days after their publication in the Federal Register, and transmission providers will be required to submit their reports within 120 days of publication. FERC had originally proposed that the reports be due in 90 days. The commission also approved extending the public comment period on the reports to 60 days, from the 30 originally proposed. In doing so, FERC agreed with the Edison Electric Institute and other commenters that the time periods were too short. (See ERO Supports FERC Weather Assessment Proposal.)

According to Alyssa Meyer, an energy industry analyst in FERC’s Office of Energy Policy and Innovation, the final rule also requires transmission providers to include in their reports how they define extreme weather and how RTOs and ISOs account for differences between transmission owner members’ assumptions and results.

“For the first time, reliability standards will require planning for extreme heat and cold weather,” acting FERC Chair Willie Phillips said in a statement. “NERC will develop the standards, and once we approve them, transmission owners and operators will identify the elements of their systems that are vulnerable to extreme heat and cold and develop solutions to address those vulnerabilities.”

Elliott: Different Storm, Same Outages

Before the commission approved the orders, FERC staff presented some preliminary findings of the commission’s joint inquiry with NERC into the December 2022 winter storm, also known as Winter Storm Elliott.

Unplanned generator outages exceeded 70 GW of capacity. The three main causes of the outages, staff said, were mechanical problems, equipment freezing and lack of fuel availability. Natural gas production, processing and shipping was hindered by compressor facility and well outages.

The observations are familiar: They are essentially the same as those in a 2021 technical conference held in the aftermath of a February winter storm (Uri) that nearly led to the collapse of the Texas Interconnection. Thursday’s orders stemmed from that conference.

“We’re seeing the same three causes, so therefore we think that it makes all the sense in the world to continue full steam ahead on implementing prior recommendations” from Uri and other previous severe winter storms, said Heather Polzin, an attorney adviser in FERC’s Office of Enforcement. Those include weatherizing equipment, inspecting facilities before winter and reviewing emergency operations plans.

Phillips said after the presentation, “Let me be clear: I want to join [staff] in encouraging, urging, cajoling all the utilities — every covered entity — to not wait. Implement these recommendations now. Right now. We know, to borrow a phrase, ‘Winter is coming.’”

June 15, 2023December 26, 2023

NERC, Trade Groups Oppose Call for Quick Fix on CIP Standards

NERC and several electric industry trade groups asked FERC this week to reject a petition to change how assets are classified under the Critical Infrastructure Protection (CIP) standard, saying it duplicates an ongoing initiative (EL23-69).

The Secure-the-Grid Coalition last month asked FERC to order NERC to propose an “enhanced standard” for identifying critical infrastructure using the “most recently updated engineering models used in operations.” The group, which describes itself as “policy, energy and national security experts, legislators and industry insiders who are dedicated to strengthening the resilience” of the grid, said NERC should be required to submit the proposed standard within 90 days.

In its response, NERC noted that it already plans to review reliability standard CIP-014-3 (physical security) in a joint technical conference with FERC on Aug. 10 (RD23-2) and through a separate reliability standards development project. CIP-014 requires transmission owners to identify which of their transmission stations and substations are critical to bulk power system reliability and implement a physical security plan for protecting them. The standard requires similar protection for primary control centers controlling critical assets.

“The petition does not allege any significant new circumstances, nor does it raise factual issues that are not ripe for consideration through the current NERC initiatives addressing the physical security of the BPS. Since appropriate forums for considering the petitioner’s ideas have already been or are in the process of being established, development of a new rulemaking to address similar physical security issues is not necessary at this time,” NERC said.

In a separate filing, the American Public Power Association, Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group protested the petition, calling it duplicative, unsupported and procedurally deficient.

The groups said the Secure-the-Grid Coalition failed to make its case that CIP-014 requirements for conducting threat assessments are deficient.

“The petition’s support for this request is the bare assertion that ‘[b]ased on the increasing frequency and sophistication of attacks against electric grid infrastructure, and the growing evidence that there is a persistent intent to conduct such attacks from domestic anarchist and extremist groups and foreign adversaries, a more prudent new metric is now required for these “Risk Assessments.”’”

Citing their comments in docket RD23-2-001, the trade groups said their members “are acutely aware of the physical threats posed to the grid, and of the importance of effective protective measures. Notwithstanding an uptick in physical security events in recent years, however, simply pointing to a number of recent events does not establish the need for the commission to direct changes to the threat assessment requirements of CIP-014.”

The trade associations also said FERC should reject Secure-the-Grid’s petition for failing to follow commission rules requiring petitioners to first ask NERC to initiate a new reliability standard. The groups also said the petition should have been filed as a complaint.

Responding to an increase in reports of physical attacks on substations, FERC in December ordered NERC to evaluate the effectiveness of CIP-014. NERC responded with a report in April concluding that the existing criteria are still appropriate to “focus limited industry resources” on the most critical grid facilities and that expanding the criteria would not identify additional critical substations. (See NERC Says Changes Coming to Physical Security Standards.)

However, NERC agreed to conduct a technical conference with FERC to identify the type of substation configurations that should be studied to determine whether any additional substations should be included in the applicability criteria and to establish data needs for conducting those studies.

NERC also said Requirement R1 of CIP-014 should be refined, acknowledging inconsistencies in how entities perform the risk assessment, with some failing to provide sufficient technical studies or justification for study decisions.

NERC’s report recommended a reliability standards development project to clarify the risk assessment methods for studying instability, uncontrolled separation and cascading.

NERC told FERC this week that the project “will be commencing in the near future.”

“Petitioner has not demonstrated a significant change in circumstances or that there is a sufficient problem to merit a generic solution that would necessitate a rulemaking prior to and without the benefit of the public stakeholder processes,” it said.

In a second FERC filing June 13, Secure-the-Grid said it was acting on behalf of the “American public … whose security interests are grossly underrepresented by NERC.”

The group rejected the position that “the costs are too high to invest in widespread and mandatory physical protection of the electric grid.”

“We think the costs are far too high NOT to invest in this protection, and we believe that the public will be willing to pay more for their electricity to see this protection realized,” it said.