The Bureau of Ocean Energy Management on Dec. 11 issued its final environmental impact statement for Sunrise Wind, endorsing an 11% reduction in the number of wind turbines for technical and environmental reasons.
The move sets the stage for Sunrise to be the seventh major offshore wind project approved in federal waters — BOEM typically follows its final EIS with a Record of Decision several weeks later, and all of the previous six were greenlit.
BOEM said Dec. 11 it plans to issue the Record of Decision in early 2024.
Securing a positive Record of Decision is the final major regulatory hurdle for Sunrise, but a different obstacle remains unresolved: paying for construction of the project, which would send 924 GW to the New York grid.
Ørsted has said it cannot proceed with the project under the financial terms negotiated with the state because the cost of construction has increased so much since the deal was struck. But the state refused to grant increased compensation. (See NY Rejects Inflation Adjustment for Renewable Projects.)
The most recent Record of Decision by BOEM was an approval for Empire Wind 1 and 2 in late November. (See BOEM Approves Empire Wind.) The two offshore wind farms would send 2 GW of electricity to New York, but they, too, are under significant financial pressure. The developers of Empire Wind have said they cannot start construction without more money.
Nonetheless, the announcement of the final EIS for Sunrise was welcomed as good news for a fledgling U.S. industry that has been struggling in 2023.
Oceantic Network, a trade association, said in a news release: “Advancement of the Sunrise Wind project further strengthens confidence in the U.S. permitting system as the administration is nearing its halfway point in reviewing 16 projects and conducting seven new lease auctions by the end of 2024, approving 8 GW of power generation for construction. Adhering to this commitment is critical to drawing new and securing old investments in U.S. supply chain, and the network applauds BOEM’s consistent efforts to reach this goal.”
The plan Sunrise Wind submitted to BOEM called for up to 94 wind turbine generators across 86,823 acres of OCS-A 0482, 27 nautical miles east of New York’s Long Island and 17 nautical miles south of Martha’s Vineyard in Massachusetts.
After reviewing comments and technical data, BOEM developed a preferred alternative — 84 wind turbines — for reasons of geotechnical feasibility and impact on the marine environment.
The actual potential effects of Sunrise are identified in the EIS as a range of positive and negative possibilities. These effects are similar to those predicted in the EIS documents BOEM prepared for other projects stretching between Cape Cod, Mass., and Cape May, N.J.: Sunrise could have major negative impacts on the endangered North Atlantic right whale, commercial and recreational fishing, search-and-rescue operations, scientific research and the view from land.
Federal regulators Dec. 11 announced a planned auction of wind energy leases off the Delaware and Virginia coasts in 2024.
The announcement excluded a wind energy area off the Maryland coast that is seen as problematic due to other activities in the area but included a pledge to help that state work toward its ambitious offshore wind goals.
On Dec. 11, BOEM said B-1 is not viable for wind energy development at this time, due to the expensive mitigation that would be needed. But BOEM is not giving up on B-1 — it might be offered in a second potential lease sale as soon as 2025, the Department of the Interior said.
And BOEM said another potential area off the Maryland Coast of similar size and energy generating capacity has been identified and will be further analyzed.
In its announcement Monday, BOEM emphasized a commitment to developing other potential wind energy areas that could feed clean energy to Maryland, which has an 8.5-GW offshore wind goal.
In statements quoted in a BOEM news release, Maryland’s governor and U.S. senators welcomed BOEM’s commitment to identify other options.
“I am pleased that we have reached an agreement on offshore wind leasing in the Central Atlantic that ensures Maryland can continue to make progress toward meeting our wind energy deployment goals, while protecting key national security and navigational safety priorities in these waters,” Sen. Chris Van Hollen (D) said.
The senator’s comment points to the crowded and strategic nature of the ocean east of the nation’s capital. The shoreline is dotted with multiple military bases, squadrons of supersonic jet fighters, a NASA launch site and a bombing/gunnery range, raising questions about the risks of a phalanx of towering wind turbines spinning nearby.
However, offshore wind is a signature initiative for the Biden administration, which has set a goal of 30 GW installed by 2030, and the various agencies are looking for solutions.
In Monday’s news release, the Department of Defense presented the issue as one of national security — but one of energy security rather than planes, ships and missiles.
“The Department has been an active participant in the Bureau of Ocean Energy Management’s efforts to find the best locations for offshore development in the Central Atlantic and we look forward to the continued collaboration on this critical issue,” said Radha Iyengar Plumb, deputy undersecretary of defense for acquisition and sustainment.
NASA Administrator Bill Nelson added: “Developing new wind energy areas will provide clean energy for millions of homes and businesses while boosting American innovation. The time to address the climate crisis is now — and NASA will continue its work to improve life on Earth.”
Lease Area A-2 totals 101,443 acres east of Delaware Bay. Lease Area C-1 consists of 176,505 acres east of the mouth of Chesapeake Bay.
BOEM on Dec. 12 will publish a proposed sale notice in the Federal Register, kicking off a 60-day public comment period.
It’s the time of the season for some happy talk. Real happy talk.
Let me start with a rock concert almost 40 years ago. For you kids, this was Live Aid, a 16-hour concert split between London and Philadelphia.
Steve Huntoon | Steve Huntoon
It was the greatest assemblage of rock royalty in history. By far. Thank you, Bob Geldof, for this miracle.
In no particular order: Elton John, George Michael,[1] Queen, Dire Straits, Sting, David Bowie, and Bob Dylan with Keith Richards and Ron Wood (introduced by Jack Nicholson).[2]
Eric Clapton, Phil Collins, The Beach Boys, The Who (also introduced by Jack Nicholson),[3] Led Zeppelin and Mick Jagger.
Tina Turner, the Pretenders, Madonna, Tom Petty and the Heartbreakers, Hall & Oates, the Cars.
U2, Paul McCartney,[4] REO Speedwagon,[5] Crosby, Stills & Nash, Boomtown Rats[6] and Black Sabbath.
The Hooters (introduced by Chevy Chase and Joe Piscopo),[7] the Four Tops, Joan Baez, Elvis Costello, Rick Springfield and Neil Young.
Bryan Adams, George Thorogood & The Destroyers, Simple Minds, Santana, Ashford & Simpson with Teddy Pendergrass, Kenny Loggins and Run-D.M.C.
And the all-star Band Aid closing London with “Do They Know It’s Christmas?”[8] OMG. And the all-star U.S.A. For Africa closing Philly with “We Are the World.”[9] OMG 2.
Yeah, that’s what I’m talking about. Just plug Live Aid and your favorite rock star into YouTube and turn it up to 11.[10] Or get the 4-disc DVD set (which sadly came out 20 years late and left out 6 hours of performances).[11]
How much would tickets go for these days? Maybe even more than Taylor Swift’s!
Global Famine
The theme of Live Aid was “Feed the World.”
Here’s a graph showing global famine mortality over the decades.[12]
Annual deaths per 10,000 from famine | Our World in Data (CC-BY-SA)
Did Live Aid help, or more generally, did the human sentiment leading up to and highlighted by Live Aid help? I’d like to think so. Not to diminish in any way the importance of the Green Revolution and Norman Borlaug’s role in it.[13]
Here are three more charts we should toast this season.
Global Life Expectancy
Global average life expectancy has basically doubled over the last 100 years. A miracle.[14]
Average life expectancy | Our World in Data (CC-BY-SA)
Global Average Income
How about global average income from 1960 to date?[15]
Global average income | Macrotrends.net
In current U.S. dollars, global gross domestic product (GDP) per capita increased from $457 in 1960 to $12,647 in 2022. That is incredible.
Electricity Access
And apropos of our industry, global access to electricity has gone from 73.4% in 1998 to 91.4% in 2021 — little more than 20 years — as the chart at the top of this story illustrates.[16]
Holiday Cheer
It’s understandable to be concerned with the state of the world these days, but let’s take some comfort in these points of light. We’ll get through this.
I wish you and yours the happiest of holidays.
Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.
SPP stakeholder satisfaction remained high this year, staff told the RTO’s Board of Directors and Members Committee last week during their annual review of organization metrics and feedback.
Mike Ross, senior vice president of external affairs and stakeholder relations, said during the board’s Dec. 5 meeting that all of SPP’s service ratings increased from 2022 by an average score of 0.33, with generator interconnection (GI) seeing the largest improvement (2.59 to 3.01 on a four-point scale, with three points for meeting expectations and four for exceeding them).
Stakeholders rated SPP’s services for GI, stakeholder process, Integrated Marketplace and settlements, operations and reliability, support services, training and transmission planning. Scores were up in all categories and averaged 3.49, with support services part of the survey for the first time.
Staff received a 3.70 score.
SPP distributed 3,220 surveys to its stakeholders, including those in the Western Interconnection. They returned 289 surveys, the most since 2016. However, the 9% response rate was the lowest in recent history.
Staff will distribute the survey results to departments and managers as part of the evaluation process. They will work with Consolidated Planning Process Task Force members to address GI and transmission planning, the two lowest-rated services, Ross said. SPP says it expects to complete a backlog of interconnection requests, dating back to the previous decade, by the end of 2024.
Stakeholder comments on the two services included “accelerated GI study times are also acknowledged and appreciated” and “quit holding GI customer concerns above all others.”
Staff also said audit, tax and advisory services firm KPMG awarded an unqualified audit opinion to SPP’s market operations and transmission service settlements for the 14th straight year. In 2022, the grid operator settled about $49 billion for the Integrated Marketplace and an additional $5.5 billion for transmission.
6 WG Chairs Approved
The board approved the Corporate Governance Committee’s (CGC) nominations for several stakeholder group chairs, who will begin two-year terms, effective Jan. 1.
Operating Reliability Working Group: Ron Gunderson, Nebraska Power Public District (NPPD).
Regional Tariff Working Group: Robert Pick, NPPD.
Seams Advisory Group: Jim Jacoby, American Electric Power.
Security Advisory Group: Phil Clark, Arkansas Electric Cooperative Corp.
Supply Adequacy Working Group: Colton Kennedy, Omaha Public Power District.
Transmission Working Group: Derek Brown, Evergy.
All six are incumbents.
Directors also approved the CGC’s recommendation to revise the Project Cost Working Group’s (PCWG) scope. The PCWG now will review transmission service projects where the cost is 100% directly assigned to one or more transmission customers that are not the transmission owner. The scope previously identified only regionally funded projects as being reviewed.
BOSTON — Order 2023 is just the first step in addressing the interconnection backlogs in New England and across the country, FERC Commissioner Allison Clements said at Raab Associates’ New England Electricity Restructuring Roundtable on Dec. 8.
“It would be silly and naive to think that we would fix the interconnection queue just by taking a first step,” Clements said. She outlined several next steps that were detailed in her concurrence on Order 2023.
The commissioner said addressing transmission planning issues will be key to reducing backlogs. FERC has been working on a final rule on transmission planning, which has generated significant interest from environmental, industry and labor groups. (See FERC Gets Growing Calls to Finish Transmission Rule in 2024.)
“Fundamentally, we’re not going to fix the interconnection queue process if the transmission system planning process doesn’t anticipate and doesn’t recognize what’s in the queue,” Clements said.
Clements highlighted the potential of a default cost-sharing mechanism for large transmission projects that would prevent disagreements between states from hindering progress.
“If the states can agree on a cost-allocation approach, great. But what happens if they can’t?” Clements asked. “There’s a lot of support for a default mechanism so that the infrastructure that comes out of this robust planning process can then get cost-allocated and we don’t worry about a single-state veto or free-ridership concerns.”
Regarding state clean energy solicitations, Clements told attendees that “resource planning processes across states should be aligned with the interconnection queue … if you can’t get your state-solicited resources online, then we have an immense problem.”
New Technologies
Clements also spoke about the potential of grid-enhancing technologies (GETs), calling them the “cheapest, nearest term, shortest payback investments that we can make related to getting more efficiency out of our existing system.”
She added she’s considering which GETs should be included in a final rule on transmission planning.
Hudson Gilmer, CEO of the grid monitoring and analytics company LineVision, said the adoption of dynamic line ratings has accelerated across the country, in part because of the pressures of load growth and the availability of federal funding from the Department of Energy’s Grid Resilience and Innovation Partnerships Program.
However, Gilmer said the Northeast has lagged in its adoption of GETs.
“The U.S. is behind the rest of the world … and let’s be honest, New England is behind the rest of the country,” Gilmer said. He added that GET adoption “can be accelerated by incentives that level the playing field with more capital-intensive traditional grid upgrades.”
Jackson said the lack of recognition in ISO-NE’s capacity market of the reliability benefits of multiday battery storage is one of the factors holding back the technology in New England.
“This is a place where the markets have not caught up to the technology,” Jackson said. She added that state procurements of long-duration storage could help speed up its commercial development in New England.
“We don’t have the luxury of waiting for the technology to mature, we need this energy storage yesterday,” Jackson said.
Gas Decarbonization
Two days prior to the Roundtable, the Massachusetts Department of Public Utilities (DPU) released a major ruling following a multiyear investigation into the Future of Natural Gas in the state (DPU 20-80-B).
The release of the ruling came as a surprise to many stakeholders in the state and generally was applauded by environmental groups for its emphasis on weaning the state off gas. (See Massachusetts Moves to Limit New Gas Infrastructure.)
“The focus is on setting a regulatory framework that is flexible, protects consumers, promotes equity, and provides for fair consideration of current technologies and commercial applications,” DPU Chair Jamie Van Nostrand told the Roundtable.
Van Nostrand said the order is intended to bring the state’s gas industry and heating sector into compliance with the state’s statutory emissions targets, including the sector-specific sublimits established in the state’s Clean Energy and Climate Plan for 2025 and 2030.
“We’re either serious about addressing climate change in Massachusetts, or we’re not. We’re either serious about meeting the sector sub-limits for greenhouse gas emissions, or we’re not,” Van Nostrand said.
Despite the state’s climate goals, the gas utilities have continued to operate as if it is “business as usual,” Van Nostrand said. “We’re still seeing 1 to 1.5% annual growth in gas load.”
Nikki Bruno, vice president of clean technologies at Eversource Energy, one of the major gas and electric utilities in the state, said she is “really excited about the guidance in the order.”
The pilot project “positions Massachusetts as a state leader in this technology, and we’re looking forward to more,” Bruno said. “It doesn’t matter that it’s not gas, we want to do right by the customer.”
Zeyneb Magavi, co-executive director of HEET, a climate nonprofit that’s been working with Eversource on the project, said geothermal networks could be a significant tool in decarbonizing dense environmental justice neighborhoods.
“The hardest places for us to decarbonize today are often the ideal places for geothermal networks,” Magavi said.
Looking ahead, several speakers at the Roundtable spoke about the need to address state laws that require utilities to provide gas to existing customers who request it. Under these laws, individual gas customers could prevent the decommissioning of parts of the gas network.
“I do think we need to revisit that obligation to serve, to make it clear that customers are still going to be provided the essential utility service of heat, but it may be provided in some way other than gas,” Van Nostrand said.
CAISO staff and stakeholders on Dec. 6 again dove into the details of the ISO’s resource adequacy construct, including increasing visibility, creating year-ahead requirements and refining the existing capacity procurement mechanism (CPM).
The ISO’s Resource Adequacy Modeling and Program Design Working Group is getting into the weeds of how to plan for RA in different time horizons, including the year-ahead, two- to four-year and five- to 10-year time frames. During its third meeting, the group focused on the year ahead.
Aditya Jayam Prabhakar, CAISO lead resource assessment and planning analyst, presented a proposed assessment of RA showings, designed to determine if load-serving entities have procured enough resources for the ISO to meet the one-in-10-year standard. Staff discussed potential modeling inputs for determining sufficiency, questioning what resources should be included in the assessment.
“As the world is changing and you have a lot more variable energy resources, probabilistic modeling of risks is necessary,” Prabhakar said. “Ensuring reliability is the responsibility of the ISO, and that’s what we’re trying to assess here.”
CAISO proposed a variety of inputs to be put into a stochastic production cost model that would run simulations and determine surplus and deficit megawatts, including information on when a shortfall is occurring and for how many megawatt-hours. They include the California Energy Commission’s one-in-two load forecast, 500 load profiles, 500 wind and solar profiles, hydro and imports modeling, and outage draws.
There was some disagreement surrounding the resources the ISO chose to include in the modeling. In particular, some stakeholders thought strategic reserves and other emergency resources should be included.
“I’m curious about the decision to exclude the strategic reliability reserve and the reliability demand response resources from this assessment,” said Doug Boccignone, principal with Flynn Resource Consultants. “We’re treating these as hidden resources that we are not acknowledging exist, but we know we will rely on them and have relied on them in the past, and that just seems like we’re now creating a standard that is much higher than a one-in-10.”
Prabhakar answered that the intent of the RA program is to ensure operation under normal conditions and to avoid emergency events.
“Accounting for resources that are only accessible for us under emergency conditions, I think in our opinion, defeats that purpose because that essentially means that we’re planning to get into emergency conditions,” Prabhakar said.
Still, Boccignone suggested including extreme load events and the resources they expect will be available to meet those loads in the stochastic modeling so they can ensure they’ve “got it covered” in the event of bad conditions. He was also concerned with how this modeling could affect the decision to backstop should the ISO choose not to include emergency resources in modeling.
“If you weren’t considering those resources when you’re deciding to CPM something, that would be a mistake. If you know you can count on them, they’re going to be there; there’s no point in CPMing,” he said.
However, Nuo Tang of Middle River Power pointed out that emergency reserve type resources are generally used only after the RA program exceeds a 0.1 loss-of-load expectation, and therefore shouldn’t be included for the purposes of reaching 0.1.
Kallie Wells, senior consulting with Gridwell Consulting, also questioned if energy-only resources that can be used to charge batteries should be included in modeling.
“I think it makes as a good question as to whether or not there is a way to maybe include them only so that they can charge the batteries,” Wells said. “Then the batteries are able to discharge up to the amount that they’ve been shown for, but not necessarily include those resources to also be discharged to the grid.” Not including them could impact storage resource availability, she added.
Closing the Gap Between 90-100% Showings
The year-ahead time frame considers both shown capacity and forecast eligible capacity. Currently, the framework requires LSEs to provide 90% showings from May to September for system RA requirements, with the remaining 10% not shown because of the wide range of varying local regulatory authority requirements, leaving room for assumptions. As a result, CAISO questioned how to close the gap between 90 and 100% showings, assuming the remaining 10% could be RA-eligible resources held back for substitution or non-RA resources.
Kyle Navis, senior analyst with the California Public Utilities Commission’s Public Advocates Office, questioned if CAISO could request a nonbinding showing of the 90% requirement in the year-ahead showing process.
“If LSEs at the time of the showing are contracted to a compliance position that is above 90%, would they be able to show those additional resources without that additional capacity being bound by rules to acknowledge that there may be some movement in the market until the month-ahead showing process?” Navis said. “It seems like it would maybe close the assumption gap a little bit so that it’s not just ISO staff trying to come up with your best guess.”
Prabhakar answered that, if the process is effective, no one will have to make guesses on what resources will be available.
“If we have an approach where we can get 100% shown capacity for each month, and we don’t have to make any assumptions — that’s the idea of this entire process: We want to limit the number of assumptions that are made.”
The group will discuss the two– to four-year time frame during its next meeting, tentatively scheduled for Jan. 16.
ORLANDO, Fla. — MISO board members last week greenlit the $9 billion, 572-project 2023 Transmission Expansion Plan (MTEP 23), which contained the most expedited project reviews the RTO has ever conducted.
MISO directors unanimously approved the 2023 collection of transmission projects at a Dec. 7 board meeting. MTEP 23 more than doubles the spending of last year’s package and triples that of MTEP 21.
Executive Director of Transmission Planning Laura Rauch has said MISO expects bigger MTEP projects to continue in future cycles. She said MISO will perform economic screens on projects that may have regional potential on a case-by-case basis and will conduct alternatives analysis on large, complex projects.
Regarding MTEP 23, Rauch said the RTO is “confident” it landed on an appropriate alternative for the largest MISO South project to help relieve the strained Amite South load pocket in southeast Louisiana.
“Facilities that propose new lines or are larger in cost and potential impact on the system are prioritized for analysis. Roughly 75% of MTEP 23 projects didn’t meet criteria for alternative solution analysis, as they address needs with no cost-effective alternatives,” Rauch said during a November System Planning Committee meeting of the MISO Board of Directors that was held in preparation for last week’s vote.
Since MTEP 03, $35 billion in transmission investment has gone into service in MISO, with $23 billion planned or under construction. The $23 billion includes the $10 billon first portfolio of long-range transmission plan projects approved last year.
MISO members, meanwhile, mused about how the process behind expedited project reviews under the MTEP cycle might change.
The RTO has said the growing number of expedited project review requests it studied under its MTEP 23 planning cycle means it should rethink its expedited review process for transmission projects that can’t wait until the usual December MTEP approval to begin construction. (See “MISO: Expedited Review Process Needs Revamp,” MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)
MTEP 23 Investment breakdown | MISO
MISO said it fielded more than 30 expedited project review requests — double the number it received in 2022 — predominantly because of new load interconnections.
Some members said the increasing number and growing sizes of projects requested for expedited treatment cause concern.
“The size, the magnitude of the projects are becoming a bigger deal,” Clean Grid Alliance’s Beth Soholt said. She said MISO might consider increased transparency around project requests and its review.
ITC’s Brian Drumm said MISO could raise its minimum $1 million threshold for projects to be vetted when they’re built out of the usual MTEP cycle. He said the dollar limit has been in place for years and hasn’t been adjusted for inflation. A higher threshold would scale back the projects that require expedited review and mean the RTO isn’t spending time reviewing insignificant projects, Drumm said.
LS Power’s Brenda Prokop said MISO might consider more proactively planning transmission for new load so fewer expedited reviews are needed.
MISO will hold more discussions on how it might overhaul its expedited review process in public stakeholder meetings next year.
A growing chorus of stakeholders is hoping to see a final transmission planning rule from FERC sometime in the New Year, with a set of letters sent to the commission last week.
A group of nongovernmental organizations including Advanced Energy United, American Clean Power Association, Earthjustice, Environmental Defense Fund and Sierra Club said finalizing the transmission planning rule was important to ensuring the incentives from the Inflation Reduction Act actually get used and increasing the resilience of the grid to extreme weather.
“The electric industry is undergoing a major transformation driven by consumer, utility and corporate preferences, state public policies and the cost-competitiveness of renewable energy,” said the letter sent to FERC Dec. 8. “The commission’s transmission planning and cost allocation standards must be up to the challenge of enabling this transition while ensuring the continued provision of reliable and affordable electricity at just and reasonable rates.”
Another letter largely signed by power companies and labor including Ameren Transmission, Consolidated Edison, Exelon, the Blue-Green Alliance and the IBEW International also urged FERC to act.
“We support the commission’s proposal for regional, long-term, scenario-based transmission planning and urge the commission to issue, as soon as practicable, a final rule that will facilitate needed transmission investment,” the letter said. “The commission should ensure that the final rule is sufficiently robust to achieve the commission’s goal of ensuring just and reasonable rates and ‘remedy[ing] deficiencies in the commission’s existing regional transmission planning and cost allocation requirements.’”
FERC still has one more meeting this year, but it is unlikely to move the final transmission rule, as it has yet to issue a substantive order on rehearing for Order 2023, in addition all the other work before its staff, said consultant Rob Gramlich at a press event Dec. 8 hosted by Americans for a Clean Energy Grid.
“The chairman and his staff have been saying, ‘we want this to be durable, legally, you know, we’ve got to dot every I and cross every T and make sure,’” Gramlich said. “You know, most rules like this do get challenged and, so, they’re planning for that. And … that’s all competing against time. We don’t have time. It feels to me like 18 months is enough. It’s time to get the order out.”
The last time FERC issued major transmission reforms was Order 1000 in 2011, and that was meant to be an iterative process, said ACEG Executive Director Christina Hayes. A major issue driving the change then was state policies, especially renewable portfolio standards.
“I think it’s a matter of kind of evolving the process and evolving the analysis, where things right now are very focused on the silos — economic reliability, and policy silos — and kind of breaking free of those and recognizing that renewable requirements are being driven by customers, by utilities, who are getting out ahead of their states,” she added.
Gramlich said Congress also could move forward on transmission proposals, including a bipartisan permitting reform effort led by Sens. Joe Manchin (D-W.Va.) and John Barrasso (R-Wyo.).
While transmission largely is a priority for Democrats in this Congress, it was not always that way. The Energy Policy Act of 2005, with its reforms on transmission, came out of a Republican Congress and was signed by a Republican president. There’s reason to believe the party might get on board with transmission reforms this time.
“Everybody cares about reliability,” Gramlich said. “Everybody will soon be aware of massive load growth that’s happening for the first time in over two decades. And that’s a reason to build transmission. So, there’s a lot of nonclimate reasons if climate isn’t your priority.”
Even once all the policies are put in place, the industry and regulators will have a massive job working to expand the grid. Princeton University has said the grid needs to expand by 60% by 2030 and triple by 2050, but that does not even take into account the amount of industrial reshoring and other sources of demand growth, Hayes said.
“I think we can do it,” Gramlich said. “And we know that because we did do it 10 years ago. If you look at, like, 2013: the MISO MVPs come online, the SPP Priority Projects, ERCOT CREZ (Competitive Renewable Energy Zones), the Tehachapi buildout — all in one year. That happened to be in the same year when there was another period of time when everybody was talking about big transmission … and we got a lot done. And then … we kind of like just lost our momentum for a variety of reasons.”
ORLANDO, Fla. — MISO’s base operating budget will increase 15% in 2024, mostly because of the grid operator adding about 70 staff positions so it can keep up with the pace of change and emerging issues in the footprint.
MISO’s Board of Directors approved the nearly $400 million budget for 2024 at a Dec. 7 meeting, continuing a trend of budget increases year-over-year.
MISO is proposing a $370 million 2024 operating budget, which contains a nearly 15% increase in base operating spending over 2023. It also is eyeing approximately $27.3 million in capital spending.
MISO has said it struggles to keep up with its current workload under existing staff levels and the hires will help it accomplish projects under intended timelines.
MISO will up its $0.44/MWh tariff rate for members to $0.47/MWh next year.
The grid operator is poised to end the year with base expenses about 1.8% over budget, or $4.3 million. MISO said the cost overruns are mostly due to a $5 million cost overrun in salaries and benefits this year, due to hiring more staff, market pressures, and more overtime and on-call work.
MISO CFO Melissa Brown said MISO has returned to a more normal 3% employee vacancy rate after experiencing a 6% vacancy rate at the beginning of the year. She said the COVID pandemic was a “very strong lesson in how labor market dynamics can substantially impact [MISO].”
Brown said MISO is trying its best to get expenses down before year’s end, but the salary component is somewhat out of MISO’s control.
“Quite honestly, we’re talking about $50,000 line items right now, asking, ‘Do we really need to do that?’” Brown asked during a Nov. 30 meeting of the Audit and Finance Committee leading up to Board Week.
Brown said anticipating future budgets, especially on the five-year horizon into 2028, is becoming more challenging as the resource transition ensues and stubbornly high inflation sticks around.
ORLANDO, Fla. — MISO leadership predicted adequate supply paired with a temperate winter at the final Board Week of the year.
“Under normal conditions, we should be flush this year. If everything goes as planned, you won’t hear much from me come March,” Executive Director of Market Operations J.T. Smith told the Markets Committee of the MISO Board of Directors Dec. 5. “We have El Niño out there, keeping the Pacific Ocean waters warm. While we’re expecting this winter is going to be mild, we’re preparing for a significant drop in temperatures. … Winter Storms Uri and Elliott are great examples of how cold can blast into the footprint.”
MISO has said its winter demand could top 106 GW, with about 121 GW of supply available under normal grid and generation outage conditions. However, the RTO hasn’t ruled out the possibility of an emergency sometime in January. (See MISO: Possibility of Winter Emergency in January.) MISO’s record winter power demand, 109 GW, occurred Jan. 6, 2017.
Smith said it isn’t surprising NERC’s 2023-24 Winter Reliability Assessment highlighted fuel supply issues throughout the footprint and MISO South’s risk of high outages from inadequate weatherization if a deep freeze strikes southern states. Smith said MISO South generators rarely experience sub-zero temperatures, so they don’t prepare as if they’re an everyday occurrence.
“There is a risk that cold extends into the South, and that could be an issue,” he acknowledged.
Smith also said MISO members have access to healthy stores of natural gas and coal stockpiles heading into winter.
MISO’s 2023/24 generator winterization survey showed that 97% of MISO units responding to the survey have undergone winter preparations, 97% have recently reviewed NERC’s winter readiness guidelines and 96% have a severe cold weather checklist. The response rate of the survey was 92% of MISO generators. MISO said the reported level of preparedness generally is better than last year’s. The RTO uses its winter preparedness survey to inform its real-time market operations.
MISO also is preparing draft emergency trading rules for neighbors Louisville Gas & Electric/Kentucky Utilities and East Kentucky Power Cooperative, Smith said.
MISO’s Independent Market Monitor recommended MISO draw up emergency supply agreements with its non-RTO neighbors after MISO flowed a few gigawatts of power exports to utilities in the Southeast during winter storms last Christmas.
Monitor David Patton said he concurred with MISO’s take on the upcoming winter. However, he said an extreme winter event could drive forced generation outages to 29 GW and have MISO nearly draining its reserves. He qualified that MISO’s wind fleet usually performs well during winter weather events, so MISO experiencing a near-zero margin is unlikely, even if utilities’ gas scheduling becomes a problem.
“We should be OK this winter,” Patton concluded, though he added, “Thinking through fuel security is going to become a lot more important in the future.”
Smith also said MISO thankfully experienced a “wholly unremarkable” fall, with normal load, coal and fuel prices remaining inexpensive at about $2/MMBtu and no hurricane activity affecting the southern footprint.
MISO’s fall peak arrived early in the season on Sept. 5 when late summer heat drove 115 GW in load.
