Search
`
August 12, 2024

Posted on

Interconnection Costs on the Rise, Berkeley Lab Study Finds

Interconnection costs are on the rise across the U.S., according to a Lawrence Berkeley National Laboratory analysis of thousands of projects in five organized electricity markets.

The team manually scraped cost estimates from 2,500 interconnection studies from ISO-NE, MISO, NYISO, PJM and SPP, LBNL policy researcher Joachim Seel said during a webinar Thursday. CAISO has stronger data privacy rules than others, while ERCOT uses a “connect and manage” system that limits the amount of upgrades developers must pay for. Non-RTO regions generally do not release such information.

“Collecting this cost data has been quite difficult as the cost estimates are often the only available interconnection study PDFs, [and] that required time-intensive manual scraping,” Seel said. “We’ve cleaned and sanitized the data and made much of the underlying project cost data available on our website. And to our knowledge, this is really the first time that this data can be easily accessed.”

The data collection was partially funded by the U.S. Department of Energy’s Interconnection Innovation e-Xchange (i2X) process, said DOE’s Cynthia Bothwell, who helps run the exchange created to enable simpler, faster and fairer interconnection of clean energy resources.

“The motivation for the cost analysis that you’re going to hear about more today was that we found it very hard to get information,” Bothwell said. “Developers said, ‘You know, we don’t know how much things cost, [or] where we can interconnect, and a lot of other issues.”

While the data was public, it was not easy to gather — taking hundreds of worker hours per market to compile. Now the industry will have a central place to look up interconnection cost information, she said.

The LBNL team plans to continue collecting data, including eventually from CAISO and traditionally regulated utilities, and performing additional analyses, Seel said. While costs have been trending up, they vary greatly by project type and other factors, meaning they are “not normally distributed,” he said.

“There are many projects with rather low interconnection costs, but also some projects with very high interconnection costs,” he said. “And although these high-cost projects may be fewer in number, their high project costs can influence the sample mean quite a bit and pull it upward.”

Out of the projects that have made it through PJM’s queue since 2017, nearly 120 had interconnection costs of $25/kW, but some were several times higher than that — with a few at $450/kW.

Costs have been on the rise over time, and LBNL broke down projects by complete, pending and withdrawn, with those pulling out of the process having the highest average costs and completed projects the lowest, Seel said.

Newer projects must generally pay for more broad transmission network upgrades triggered by reliability or stability violations found in the modeling of the proposed resource. That could involve reconstruction of high-voltage transmission lines as renewables are often in more rural areas where the grid is weaker.

Breaking Down by Project Type

The analysis also found differences among technologies, with solar costs remaining fairly consistent across regions, and completed projects spending between 5% and 10% of their total capital on interconnection upgrades, while withdrawn projects faced interconnection costs comprising 20% to 40% of their total capex.

Storage projects also face high costs, which Seel said could be due to their being built in congested parts of the grid to benefit from energy arbitrage opportunities.

Onshore wind has greater variation, with completed projects spending between 3% and 16% of their total budgets on interconnection and withdrawn projects 10% to 40%.

The onshore wind numbers were particularly skewed by ISO-NE, where nearly all proposals since 2018 have withdrawn after facing huge interconnection costs that run up to $800/KW, LBNL’s Julie Kemp said.

“For onshore wind, all of the recent projects are located in Maine, and many of them are in quite remote areas where the existing transmission system is pretty limited,” said Kemp. “And, so, these high costs that we see are the result of the significant buildup that would be required to connect substantial new generation in these areas that currently do not have much load or much generation.”

An LBNL graphic showed the highest interconnection costs for wind in Aroostook County in the state’s far north, where the limited transmission system is not even operated by ISO-NE, but rather the Northern Maine Independent System Administrator.

Posted on

NJ Lawmakers Back Ørsted’s Tax Credit Plea

New Jersey legislators this week backed a measure to allow the state’s first offshore wind project, Ocean Wind 1, to receive federal tax credits to help offset construction cost hikes, advancing the legislation forward in what state officials said was a “critical” element needed to get the project completed.

The Senate Budget and Appropriations Committee and Assembly Budget Committee on Tuesday each approved a version of the bill (S4019 and A5651) that will allow the credits to go to developer Ørsted instead of the state. The Assembly committee voted on the bill again Wednesday to reconcile differences between each house’s version after the Senate committee made amendments. To arrive at the desk of Gov. Phil Murphy, the bill now needs full Assembly and Senate votes, which likely will take place Friday before the Legislature recesses until November.

The Senate committee voted at the end of a six-hour meeting with lengthy breaks while lawmakers negotiated amendments they said were designed to strengthen the requirements on Ørsted. The changes included requiring a $200 million cash escrow fund put up by the developer that New Jersey can spend on other wind-related projects.

Unlike those in other states, New Jersey law prohibits developers from obtaining federal tax credits for offshore wind projects, and instead grants the benefits of the credits to the state to help ratepayers.

The hearing offered a snapshot of the vigorous debate over offshore wind, with opponents saying the turbines would blight the state’s much-prized shore; damage local beaches, historic landmarks, and the tourism and fishing industries; and hurt marine life. Proponents said the advance of Ocean Wind 1 is essential to the state’s plan, backed by more than $600 million, to create a homegrown industry that will create jobs and be a major economic driver.

“There is a looming and booming offshore wind energy industry coming to life in the North Atlantic,” Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), said at the hearing. “In the bill before you is an incredibly important milestone on that journey.”

He described the bill as “critical to getting the first project unlocked, and under construction and developed.”

“This is a bit of a gut-check moment: Does New Jersey want to lead?” he said. Or does the state want to “follow … to be left out of the jobs and economic opportunity and prosperity that offshore wind represents?”

Sen. Michael L. Testa Jr. (R) responded by suggesting that the state should consider the potential harm of the wind projects on the shore’s tourism and commercial and recreational fishing sectors, and whether the preliminary exploration for the OSW project was somehow linked to the deaths of whales that have washed up on the New Jersey shore.

“Certainly I always want New Jersey to be at the forefront of very positive changes and innovation,” he said. But he suggested the state should “take a pause” in the OSW projects. He noted that several federal and state lawmakers have called for a moratorium on the projects until the whale deaths are fully investigated.

“They’re not kooks; they’re people that are really concerned about preserving New Jersey,” Testa said.

State and federal officials say there is no evidence linking the whale deaths to the wind projects, for which construction has yet to start, and the investigations are ongoing.

Rising Costs

The legislation allows federal tax credits to flow only to offshore wind projects approved before July 1, 2019. That effectively limits the benefits to the 1.1-GW Ocean Wind 1 project, which the Board of Public Utilities (BPU) approved in its first solicitation in 2019.

The board approved two more projects in 2021 — the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores — in a second solicitation. In March, it launched a third solicitation, which could result in the award of capacity totaling 4 GW or more. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)

Ørsted has said since that the approval, materials, equipment and transportation costs have risen dramatically because of a variety of unanticipated events, including the COVID-19 pandemic and the Russo-Ukrainian War.

Maddy Urbish, the company’s head of government affairs and market strategy, said in a statement after the hearing that “these federal incentives present an opportunity for the state to further secure economic investments and create hundreds of family-sustaining jobs in New Jersey while addressing the unprecedented macroeconomic challenges of today, at no additional cost to ratepayers.”

“As the state’s first offshore wind project, Ocean Wind 1 is critical to helping New Jersey achieve its clean energy goals,” she said, adding that Ørsted is “focused on identifying opportunities to advance the American offshore wind industry locally.”

But Kristen O’Rourke, quality of life director at Point Pleasant Beach, questioned the fairness of the plan, saying nearby businesses, many of them small and family owned, face potential losses because of the impact on tourism and fishing.

“We’re the ones who are also facing fiscal instability over inflation [and] supply chain issues that Ørsted’s facing,” she said. “We’re all on the same page here, but we’re not receiving a tax credit for it.”

In a letter to both committees Monday, the New Jersey Division of Rate Counsel urged them not to advance the bill, saying, “Statements claiming that this bill will not cost ratepayers additional costs are inaccurate.”

Director Brian O. Lipman said that under the 2019 deal struck by Ørsted and the BPU, the cost to the state of the offshore wind renewable energy certificates (ORECs) awarded to the developer is offset by tax credits earned by the developer.

“To the extent that the developer keeps the tax credit, the reduction in the OREC is decreased — leading to higher OREC prices for ratepayers,” Lipman wrote. “There should be no doubt that this bill will increase the amount the developer earns on this project and will result in higher OREC prices being paid by ratepayers.”

Competitive Dynamic

The bill requires Ørsted to issue a report on the project’s anticipated environmental impacts, economic benefits and financial viability, and the feasibility of completing it by the commercial operation date approved by the board.

The bill’s escrow requirement replaces an earlier requirement that the $200 million be a letter of credit. The escrow can be used to help fund the New Jersey Wind Port, a manufacturing, marshaling and wind logistics hub in Salem County, and the port and wind manufacturing facility at the Paulsboro Marine Terminal.

The EDA’s Sullivan said the funds would likely be used for a second phase of the manufacturing operation at Paulsboro that German manufacturer EEW is building to make monopoles. Ørsted is sourcing monopoles for Ocean Wind 1 at the plant and has invested in it, according to a recent report by the Sweeney Center for Public Policy at Rowan University.

Sen. Paul Sarlo (D), chairman of the Senate committee, said the amendments made it a “much better piece of legislation.”

At Sarlo’s prompting, Sullivan confirmed that there had been no other state payments to the project and would be no more. “This will be the last push that they will need to get out of the ground,” he said.

Rumors that Ørsted was negotiating with Gov. Murphy and legislators on the bill had been circulating in Trenton for weeks. Sarlo had said at a May 23 hearing of the committee that he would resist additional subsidies to offshore wind developers, saying, “These are large players, international players, who knew what they were getting into when they built these facilities.” (See NJ OSW Projects Face Public Funding Scrutiny.)

Sullivan said the state’s investment in the wind port and Paulsboro terminal would make New Jersey a major player in the regional wind industry, enabling the state to supply offshore wind services, logistics and products to not only its own projects, but also others along the East Coast.

“The competitive dynamic here is real,” he said. “Other states want this just as badly or worse than we do.”

Speaking before he voted for the bill Tuesday, Sen. Steve Oroho (R) asked Sullivan what the impact would be if Ocean Wind 1 did not go ahead and Ørsted did not put the $200 million in escrow. Would that mean that “a revenue-generating project” would be at risk of “not being a revenue-generating project?” he asked.

After Sullivan affirmed that could be the case, Oroho said that though he had originally opposed the bill, he would back it in the committee. But he may not do so in the vote by the full Senate, he said, being “torn” between concerns about the bill and worries that the $600 million invested in the state’s offshore wind could be much less valuable if the projects do not go ahead.

Posted on

BLM Holds Record-breaking Solar Auction in Nevada

The Bureau of Land Management on Tuesday auctioned four parcels in the Amargosa Desert in southern Nevada for solar development, raising a record-breaking $105 million.

The four Amargosa Desert parcels, totaling 23,675 acres, could support nearly 3 GW of renewable energy, the Department of the Interior said in a release. The $105 million auction was the highest-yielding onshore renewable energy auction in BLM history.

“This record-breaking auction for solar energy development is further evidence that the demand for clean energy has never been greater,” Interior Secretary Deb Haaland said in a statement. “The technological advances, increased interest, cost effectiveness, and tremendous economic potential make these projects a reliable path for diversifying our nation’s energy portfolio.”

NV Energy was the provisional winner for leases of two parcels within the Amargosa Valley Solar Energy Zone. The company bid $35.25 million for the 3,775-acre Parcel A and $46.6 million for the 3,451-acre Parcel B.

BLM auctioned two other parcels outside of the solar energy zone.

Boulevard Associates LLC, a subsidiary of NextEra Energy Resources, placed the high bid of $21 million for 10,129 acres known as Parcel 1. Silver Star Solar I LLC, a subsidiary of Leeward Renewable Energy, had the high bid of $2.3 million for the 6,320-acre Parcel 2.

As the provisional preferred applicants for Parcel 1 and Parcel 2, Boulevard Associates and Silver Star Solar have secured rights to submit solar energy development proposals for the land. Right-of-way applications are due within 30 days, followed by development plans within 60 days. BLM will review the proposals before approving further project development.

Greenlink Influence

Solar energy zones are the BLM’s preferred areas for utility-scale solar energy development. Solar energy zone locations were chosen based on their low potential for conflict with natural and cultural resources and other land uses.

BLM said last year that interest had surged in the Amargosa Valley Solar Energy Zone due to NV Energy’s proposed Greenlink West, a roughly 350-mile transmission line that will be built nearby. (See FERC Approves Greenlink Nevada Incentives.)

In addition to interest in land within the Amargosa Valley Solar Energy Zone, BLM received 15 applications within a year for utility-scale solar developments in the Amargosa Desert outside of the solar energy zone. The BLM described the area as having “many resource constraints.”

At the same time, BLM weighed the administration’s priority of permitting 25 GW of solar, wind and geothermal production on public lands by 2025. Working with other agencies, BLM developed a strategy for leasing Amargosa Desert land.

According to the Interior Department, BLM is processing 74 proposals for utility-scale clean energy projects on public lands in the Western U.S. The projects, which include solar, wind and geothermal development as well as gen-tie lines, could potentially add more than 37,000 MW of renewable energy to the Western grid.

Another 150 applications for solar and wind projects are under preliminary BLM review.

Posted on

States Make Progress Toward Renewable Energy Goals

The Lawrence Berkeley National Laboratory on Wednesday issued the 2023 edition of “U.S. State Renewables Portfolio & Clean Energy Standards,” which finds that states are mostly meeting their renewable energy goals.

The report provides an update on legislative revisions and progress toward targets in the renewable portfolio standards (RPS) adopted by 29 states and the District of Columbia. Those 30 RPS policies apply to 58% of U.S. retail electricity sales.

New in this year’s edition is a look at clean energy standards (CES). Fifteen states have established a 100% CES, most of them in combination with an RPS.

Renewable portfolio standards (RPS) nationwide. | Lawrence Berkeley National Laboratory

The report and spreadsheets of supporting data are on Berkeley Lab’s website.

Among the highlights:

    • Roughly half of nationwide growth in renewable energy generation since 2000 is associated with state RPS requirements, but the annual percentage has been declining, with only 30% of renewable capacity added in 2022 being attributable to RPS mandates.
    • RPS and CES policies will require about 300 TWh of additional clean energy supply by 2030 and 800 TWh by 2050.
    • RPS compliance accounts for 3.5% of retail electricity bills on average, but actual impact varies significantly, ranging from below 1% of retail bills in Texas, which met its final RPS target 15 years ago, to 12% in Massachusetts, where solar renewable energy certificates are the most expensive.
    • On-site or behind-the-meter projects have been growing slowly as a percentage of renewable energy capacity but surged to 30% of new renewable power in 2022.

The report notes that RPS and CES standards continue to evolve. In 2022 and the first quarter of 2023, some 150 pieces of RPS- and CES-related legislation were introduced — 63 of which would strengthen the standards and 32 of which would weaken them.

However, only 17 of those bills had been passed when the authors gathered their data. And 13 of those were only peripheral to the standards or had a neutral effect on their strength.

But four major revisions were enacted:

    • Connecticut created a CES calling for 100% zero-carbon electricity by 2040;
    • Minnesota established a 100%-by-2040 CES and increased its RPS to 55% by 2035;
    • Rhode Island increased its RPS to 100% by 2033;
    • Hawaii effectively raised the target of its RPS by basing it on percentage of total generation rather than retail sales.

Excluding hydropower, U.S. renewable energy generation has grown by 630 TWh this century, significantly more than the 281 TWh mandated via RPS or CES policies.

Clean Energy Standards (CES) nationwide. | Lawrence Berkeley National Laboratory

The authors note that multiple factors are driving the growth of renewable energy, including other state policies, federal tax credits, green power markets, declining cost for renewables, utilities’ integrated resource planning, net-metered solar and voluntary green power markets.

Given the number of potential factors, and the potentially overlapping or synergistic relationships among them, assigning an incremental impact to an individual RPS or CES policy can be difficult, the report notes.

The authors say the future impact of RPS and CES programs will depend on factors such as whether states decide to expand their targets; what kind of implementation and enforcement mechanisms states establish; the impact of federal attempts to stimulate creation of new clean energy supplies and transmission; and cost trajectories for renewable energy and renewable energy certificates.

Posted on

FERC Authorizes Final Construction for Mountain Valley Pipeline

FERC on Wednesday approved Mountain Valley Pipeline’s request to move forward with all remaining construction activities, just two days after the pipeline made the request (CP21-57).

The commission first approved the Equitrans Midstream project, which runs around 300 miles from West Virginia to southern Virginia, in 2017. But the project was delayed by years of court challenges until Congress passed a provision in the recent debt deal requiring final approvals for the project. President Biden signed the legislation on June 3. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

Despite the legal issues, Equitrans says the pipeline, planned to bring shale natural gas to customers in the Southeast, is already 94% complete. A spokesperson said the first of several “forward construction” crews should start work on the right-of-way shortly, with completion expected by the end of the year.

“Mountain Valley looks forward to flowing domestic natural gas this winter,” the company said.

FERC said that the new law means that all federal authorizations have been ratified by Congress, which includes issues before it on remand from the D.C. Circuit Court of Appeals in a decision that came down a week before Biden signed the law. (See DC Circuit Partly Vacates FERC Gasline Approval.)

The commission specifically authorized the firm to resume construction in the Jefferson National Forest, and across all remaining waterbody crossings.

Sen. Joe Manchin (D-W.Va.) has long championed the project and welcomed FERC’s approval in a tweet, saying that “MVP is vital to America’s energy and national security and will benefit not only West Virginia, but the entire nation.”

The Sierra Club, which has long opposed the pipeline, released a statement urging regulators to uphold basic environmental safeguards when construction continues.

“Through their own failures alone, the Mountain Valley Pipeline should never be completed,” Sierra Club Executive Director Ben Jealous said in a statement. “The unnecessary project has repeatedly been unable to comply with bedrock environmental laws and should never have been used as a tool in must-pass legislation to hold our country hostage or capitulate to special interests willing to destroy the planet for their own profits.”

Equitrans stock, which had been trading below $6/share before the debt deal, closed Thursday at $9.55, up 1.8% on the day.

Posted on

Stakeholders Respond to ERO Budget Drafts

Industry stakeholders urged NERC to focus on keeping cost increases in check in their reactions to the ERO Enterprise draft 2024 business plan and budget.

NERC and the regional entities submitted their draft budgets in May, projecting an overall ERO Enterprise budget of $275.4 million, up $25.2 million from the 2023 budget. (See Personnel, Meeting Costs Drive 2024 ERO Budget Hikes.) Each RE’s budget, along with NERC’s is set to grow by at least 8%, while the ERO’s overall assessment is planned to rise from $214.1 million to $240.1 million. Most of the organizations cited growing personnel, investments in technology, and rising travel costs after the COVID-19 pandemic to explain the planned increases.

NERC’s projected spending of $110.6 million is, as usual, the largest share of the ERO’s overall budget. While this amount is only slightly higher than that predicted in the 2023 budget — and the organization’s planned $97 million assessment is actually slightly less than last year’s projection — multiple respondents worried about not only this year’s budget, but also those planned for 2025 and 2026, which are slated for increases of 11% and 7.2% respectively.

A commonly expressed concern was the belief that the rising assessments would have to be passed on to utilities’ customers in the form of higher electric rates. Bonneville Power Administration and others warned that “the noticeable budget increases proposed by NERC [will] directly translate to budget pressure on registered entities,” and wondered if such pressure is necessary given the economic climate.

“We recognize costs are on the rise across the board,” BPA said. “As we look to the future, we feel it is our responsibility to highlight [that] those increases are acceptable when they are both a direct path forward supporting each organization’s core mission and are applicable to the region(s) they impact.”

The National Rural Electric Cooperative Association similarly argued that the ERO should consider “more cost-efficient methods” to achieve its goals. Highlighting the intended headcount expansion across the ERO, with nearly 45 full-time equivalent positions to be added in 2024, NRECA pointed out that “many stakeholder organizations are maintaining or lowering headcount through 2024.”

Additionally, NRECA questioned why only about 31% of NERC’s budget was slated to go to standards development and compliance monitoring and enforcement, with the rest earmarked for “areas that were initially supplemental to the intent of the ERO” such as the Electricity Information Sharing and Analysis Center, the Cybersecurity Risk Information Sharing Program, and NERC’s event analysis and situational awareness programs. NRECA requested that future drafts explain why such a large amount would go to these areas.

The Ontario Independent Electricity System Operator joined NRECA in urging NERC to consider using some of its reserves to reduce the assessment, claiming that “assessments for Canadian entities are likely to increase” more than those for U.S. entities due to the way assessments are calculated in Canada. IESO also supported Electricity Canada’s call for NERC to ensure Canadian regulators are briefed on its projected spending.

Pushing for greater savings, NRECA even suggested that NERC reconsider whether it needs its Atlanta office at all since transitioning “to a predominately remote work organization” during the pandemic. NRECA argued that keeping the office for meetings is unnecessary because “there are many other alternatives available for these types of engagements.”

The only other stakeholder to touch on the Atlanta office issue was the ISO RTO Council Standards Review Committee, which did not commit to a position on the matter but acknowledged that “a space where meetings can be scheduled on short notice … is important to have.” Referring to NERC’s recent stakeholder survey about the office, the IRC SRC encouraged the ERO to “find the most cost-effective solution to retain this capability.”

NERC and the REs’ final business plans and budgets are expected to be presented at the August meeting of NERC’s Board of Trustees in Ottawa, Ontario.

Posted on

PacifiCorp Says It Can Meet Oregon GHG Targets

PacifiCorp will be able to meet Oregon’s ambitious greenhouse gas emissions-reduction targets for electric utilities, but “it will not be without challenges,” a company official told state regulators Tuesday.

Among those challenges is the sheer growth in PacifiCorp’s projected demand in Oregon, according to Zepure Shahumyan, the utility’s director of energy and environmental policy. The six-state utility expects its Oregon load to increase by 60% by 2030 and 80% by 2040, meaning that growth in absolute emissions will counter progress in reducing per-megawatt-hour emissions.

Shahumyan was among the team of executives on Tuesday presenting PacifiCorp’s integrated resource plan (IRP) and inaugural clean energy plan (CEP) to members of Oregon’s Public Utility Commission, launching the utility’s 2023 IRP process.

PUC Chair Megan Decker noted that it will be the first time the commission will be considering a CEP within an IRP proceeding. CEPs are a new requirement for Oregon utilities, the product of House Bill 2021, which state lawmakers passed two years ago to require electricity providers to reduce their GHG emissions to 80% below a 2010-2012 baseline by 2030, on the path to zero emissions by 2040.

For PacifiCorp, that will mean cutting emissions to 1.8 million metric tons (MMT) of CO2 equivalent by 2030 from a baseline of 8.9 MMT — and from actual current levels of about 11 MMT. HB 2021 also requires the utility to achieve another reduction to 0.9 MMT in 2035 ahead of the 2040 zero-emissions mandate.

Randy Baker, PacifiCorp’s director of resource planning, told the PUC that the 2023 IRP positions the utility to hit those targets. Over the next 20 years, Baker said, PacifiCorp seeks to add 9,111 MW of new wind generation, 8,095 MW of storage resources and 7,855 MW of new solar.

To support that growth in renewables and tap resources located farther inland, the utility also seeks to add more than 1,000 miles of new transmission, including the proposed Boardman-to-Hemingway (B2H) project, to be built in partnership with Idaho Power. Part of the PacifiCorp’s Energy Gateway project designed to increase flows between the company’s eastern and western systems, the 500-kV B2H line would run for 290 miles from the Boardman substation in Eastern Oregon to the Hemingway substation in Idaho, with additional links expected to grow out from both ends, Baker said.

PacifiCorp’s IRP additionally calls for 4,953 MW in capacity savings through energy-efficiency programs and 929 MW saved through demand response.

The PacifiCorp officials presenting Tuesday also acknowledged that meeting the 2040 zero-emission requirement will require adoption of technologies still under development, including 1,500 MW of advanced nuclear generation and 1,240 MW of non-emitting peaking resources. The utility in 2021 agreed to partner with Washington-based TerraPower to build a demonstration Natrium small reactor at the site of a retiring coal plant in Wyoming and last year said it would explore deploying five such plants in its service territory by 2035.

Baker also pointed out that HB 2021 requires that small-scale renewables make up 10% of PacifiCorp’s resource portfolio by 2030. Those resources currently comprise 4.6%, leaving PacifiCorp to procure an additional 490 MW by the target year. He told the commission that PacifiCorp has not received as many bids for small-scale projects as it would have liked, and he encouraged developers “to begin the process to identify interconnection costs for projects” ahead of the opening of a request for proposals in April 2024.

‘Massive Load Increase’

But the prospect of sharp load growth in Oregon will complicate the way PacifiCorp complies with state emissions targets.

Commissioner Mark Thompson noted that the projected 60% jump in demand by 2030 represents “just a massive load increase in a very short time” and asked what the utility could publicly divulge about the nature of the new load.

“I can’t speak much about the load, but I can say it’s a large new commercial load that we are forecasting and as part of the planning horizon and planning assumptions for load on our system and in Oregon specifically,” Shahumyan said.

As a result, she said, PacifiCorp will likely need to bring on even more small-scale renewables — beyond the HB 2021 requirement — to prevent serving that load with other emitting resources in the utility’s six-state system, which also includes portions of California, Idaho, Utah, Washington and Wyoming.

PacifiCorp’s efforts will be further complicated by ongoing changes to its resource mix, part of its push to reduce companywide GHG emissions and reach net zero by 2050. While the utility’s IRP calls for retiring much of its coal fleet in the coming years, it plans to convert a handful of coal-fired units to natural gas and operate them until the middle of the next decade. It also plans to upgrade NOx emissions-reduction equipment at its Hunter and Huntington coal plants in Utah and keep those facilities running until 2042.

All those plants will have to play a diminishing role in providing energy to Oregon because, as Shahumyan pointed out, they will continue to contribute to emissions. But those units will still be part of a PacifiCorp system designed to allocate the costs and benefits of all resources across participating states in a process administered by utility regulators.

To overcome the challenges of meeting Oregon’s mandate, PacifiCorp has identified two “pathways,” which Shahumyan said are not mutually exclusive.

The first pathway entails managing how gas-fired resources are dispatched until they are replaced by non-emitting peaking technologies.

“Since adding renewables doesn’t inherently reduce your emissions, you have to back off thermal emission drivers in order for them to impact our goals under HB 2021,” Shahumyan said. “So just flooding the system with renewables by itself won’t do it.”

The second pathway will require PacifiCorp to engage in multistate negotiations with regulators on how to allocate the costs and benefits of its systemwide resources.

“Under this pathway, we’re still allocating our system to Oregon, but we’re limiting thermal resource allocation to Oregon,” Shahumyan said. By doing that, she noted, the utility reaches its 90% emissions reduction target by 2033, seven years ahead of deadline.

During a public comment period after the PacifiCorp presentation, Mike Goetz, general counsel with the Oregon Citizens’ Utility Board, urged the utility to revise its IRP to replace coal with renewables — not new natural gas units.

“Has PacifiCorp truly put forward a least-cost, least-risk plan to benefit Oregon customers while complying with applicable mandates? Or is it simply planning as a system and then layering on HB 2021 requirements?” Goetz said. “On top of that, if PacifiCorp continues to operate thermal units across its system by converting a number of coal plants to gas, how will the cost of these resources be allocated in future years?”

The Oregon PUC is now taking comment on PacifiCorp’s IRP and CEP and will hold another public meeting on the plans Aug. 10.

Posted on

ERCOT Briefs: Week of June 26, 2023

Former EIA Administrator Appointed to Board of Directors

ERCOT said Wednesday that former U.S. Energy Information Administrator Linda Capuano has been appointed to its Board of Directors. Her appointment is effective Saturday.

Capuano fills the independent director’s position left vacant by Zin Smati, who resigned in December over a conflict of interest. (See ERCOT Board Member Resigns over Business Conflict.) She has been a faculty member of Rice University’s Jones Graduate School of Business since 2015, interrupted by her three-year stint at EIA from 2018 to 2021. Capuano also serves as an adviser to the school’s dean on energy initiatives.

She has also previously served on the boards of CAISO (2007-2010) and Peak Reliability (2013-2018). She has a doctorate in materials science and engineering from Stanford University and was a fellow in energy technology at Rice’s James A. Baker III Institute for Public Policy from 2014 to 2018.

“Linda’s deep energy expertise will be of great value as we continue to strive towards industry-leading reliability and efficient markets,” ERCOT CEO Pablo Vegas said in a press release.

Linda Capuano, Rice University | Rice University

Capuano will be joining a board under a new compensation structure approved Thursday by the Texas Public Utility Commission. The action increases the independent directors’ annual compensation from $87,000 to $160,000, an 83.9% increase. It is the first increase since 2011.

The ISO’s eight independent directors are appointed by the state’s three-person ERCOT Board Selection Committee, which comprises appointees from the governor, lieutenant governor and the speaker of the House of Representatives. The directors are required by law to not have fiduciary duty or assets in the ERCOT market and must be Texas residents.

Record Renewables Fill Gap

The Texas grid operator did not see a new high for peak demand Wednesday, but it did set a record for renewable energy production when wind and solar resources produced a combined 31.47 GW of power at 1:20 p.m. CT, according to Grid Status.

“[E]very megawatt helps,” Stoic Energy’s Doug Lewin tweeted, noting that 9.6 GW of thermal plants were offline at the time. ERCOT defines 8.3 GW as “high outages.”

ERCOT set an unofficial peak demand record Tuesday when it averaged 80.83 GW during the hour ending at 6 p.m. That would break the old mark of 80.15 GW set last July, the first time its demand was over 80 GW. (See related story, Under the Dome: ERCOT Sets Peak Demand Marks.)

The grid operator has averaged more than 80 GW during seven interval hours this week.

Gas Plant to Suspend Operations

Talen Energy notified ERCOT on Tuesday that it plans to indefinitely suspend operations at a gas-fired unit near Corpus Christi, Texas.

The company said Barney Davis Unit 1 will stop operating Nov. 24. The 49-year-old unit has a summer seasonal rating of 292 MW.

Also Tuesday, JX Nippon said that its Petra Nova carbon-capture facility near Houston will return to service July 15. It had been scheduled to return to operations Wednesday. The plant has been shut down since 2020, during the height of the COVID-19 pandemic and in the face of slumping oil prices. (See Carbon-capture Plant Coming Back into Service.)

Posted on

MISO IMM Zeroes in on Tx Congestion in State of the Market Report

MISO’s Independent Market Monitor debuted five new recommendations this week as part of his annual State of the Market Report, with multiple suggestions aimed at maximizing transmission utilization by clamping down on wind-related congestion.

“This is going to be one of the most central topics. Congestion is the single most significant operating factor we have to manage,” IMM David Patton told the Markets Committee of MISO’s Board of Directors Wednesday in a meeting to detail the 2022 report.

Patton said the footprint experienced a record $3.7 billion in real-time congestion over 2022, with most of that occurring in the Midwest.

He has said wind generation accounts for almost half of MISO’s transmission congestion and that wind resources often aren’t motivated to follow MISO’s dispatch instructions to reel in output to manage transmission constraints.

He suggested MISO ratchet up its excess and deficient energy deployment penalty charges, which he said are currently not high enough to dissuade generators from deviating from MISO’s dispatch instructions.

He said the recommendation stands to address reliability and economic concerns, considering that MISO’s unit dispatch system assumes that generators follow instructions and that flows will match dispatch instructions. He said penalties should be based on generators’ congestion component of their locational marginal pricing.

“Currently, generators do not accrue excess or deficient energy penalties until they exhibit such deviations for four consecutive intervals. Even after this time, the current penalties do not ensure that generators will benefit by following MISO’s dispatch instructions. This is particularly concerning when resources load binding transmission constraints,” Patton wrote, adding that if generators are not inclined to follow dispatch instructions, flows over constraints can “substantially exceed” transmission limits.

“We need our markets to motivate people to follow their dispatch instructions,” Patton previously said at a June 13 Markets Committee meeting. “If this improves dispatch, it would remove a lot of headaches in the control room.”

Patton said MISO has increasingly relied on manual redispatch of resources to manage transmission constraints.

Patton also recommended that MISO expand its transmission constraint demand curves so that its market dispatch system has better control over network flows.

Patton said MISO required “extraordinary operator actions” to manage network flows during storms in 2021 and 2022. He said the current transmission constraint demand curves restrict MISO’s market dispatch from managing transmission congestion because the RTO’s operating reserve demand curve can prevent the dispatch model from reducing output to manage network flows when transmission and capacity emergencies strike MISO simultaneously. Patton said the value the constraint curve places on managing transmission limitations isn’t high enough.

He said MISO operators having to manually dispatch generation to reduce flows on overloaded constraints is “costly and distorts market outcomes.”

Patton also said MISO could improve its near-term wind forecasting to recognize inherent principles of wind generation output. He said currently, MISO uses a “persistence” forecast that assumes wind resources will produce the same amount of output as it most recently observed.

“The downside of this approach is that the forecasted output will be predictably lower when output has been increasing and will be predictably higher when wind output is dropping,” Patton wrote. He said MISO would cut down on forecast errors if its forecasting recognized recent movement in wind output.

LRTP Doubts

Patton’s State of the Market report took an unprecedented foray into transmission planning. He recommended MISO re-examine its future energy mix assumptions behind its ongoing long-range transmission plan (LRTP). Patton said he’s concerned that the second of MISO’s three, 20-year transmission planning futures includes “unrealistically high levels of intermittent resources and unrealistically low levels of dispatchable, hybrid and battery storage resources.”

“The reality is you can’t separate transmission planning and markets. … There’s an interplay between the decisions resource owners are making on the generation side and the decisions MISO is making on the transmission side,” he told MISO board members, who expressed confusion and concern that the IMM would advise MISO on system planning.

Patton said “inefficient investment in transmission” will cause MISO to overlook other solutions to address transmission congestion, including more efficient siting of clean energy resources and investment in new generation, energy storage and grid-enhancing technologies.

MISO is anticipating its members will add 369 GW of mostly wind and solar generation over the next two decades, resulting in a 466-GW system total of nameplate capacity. MISO today operates with about 194 GW. (See MISO Modeling Line Options for 2nd LRTP Portfolio.)

Patton said MISO should reconsider its anticipated fleet evolution in its second future, use the most informed capacity expansion and generation retirement assumptions it can, evaluate energy storage alternatives to new lines, and ensure that “any estimated benefits include all of the costs incurred to realize the benefits.”

He told board members that if MISO assumes members add overwhelmingly intermittent resources, it will conclude reliability will suffer unless it adds dramatically more transmission. Patton said MISO should recognize that members will likely add energy storage components to renewable energy additions and continue to build natural gas facilities.

“I think we need to take a hard look at Future 2 as the basis before we begin this planning,” he said.

Markets Committee members said they must discuss whether it’s appropriate for them to consider MISO transmission planning decisions. The System Planning Committee of the MISO Board of Directors typically oversees MISO’s transmission planning choices.

Annual Offers in the Seasonal Capacity Market

Finally, Patton turned his attention to MISO’s first seasonal capacity auction and said MISO should establish a way for suppliers to submit annual offers and rework some of its 31-day outage limit.

He said an auction that uses only seasonal offer parameters “raises substantial challenges for participants that have annual going forward costs they must cover.”

“Suppliers with a resource that requires a capital investment to remain in operation would find it difficult to offer such costs since it will not know how many seasons in which the resource will clear,” he explained.

Patton also said MISO’s 31-day limit on non-exempt generation outages is causing some distortion in the capacity market because “a number of suppliers” this year deliberately adjusted their longer unit outages, so they straddled seasons, thereby dodging penalties.

“This can be problematic for outages that are shifted from shoulder seasons into higher-demand winter and summer seasons,” Patton said. He said MISO should figure out how it can motivate better outage scheduling.

MISO leadership will respond to Patton’s State of the Market report in December.

Posted on

MISO Stakeholders Request JTIQ Cost Containment Measures

Stakeholders pressed MISO to include some form of cost containment measures for it and SPP’s Joint Targeted Interconnection Queue portfolio, weeks after the RTOs revealed that the cost estimate for the projects nearly doubled to about $2 billion.

The requests came at a June 27 special meeting to firm up the tariff additions MISO will need to incorporate in the JTIQ study and cost recovery details so it can become a repeatable process.

Stakeholders asked MISO to include some oversight or protections against cost overruns on the transmission projects in its tariff edits. MISO staff said while they’ve discussed the possibility, at this point they will likely only consider cost protections for future JTIQ portfolios. However, their position became more fluid as the meeting wore on.

MISO and SPP this month announced the costs estimate for the first, five-project JTIQ portfolio of 345 kV lines rose from a little more than $1 billion to nearly $1.9 billion. The larger figure was sent to the Department of Energy under a funding application for the agency’s Grid Resilience and Innovation Partnerships program. (See JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B.)

MISO staff said for the DOE application, transmission owners included recent inflation and supply chain trends and tried to predict sharper routing and regulatory issues for their projects, raising costs. MISO and SPP have also included administration costs not included in the original JTIQ estimate, including FERC filing costs and costs related to the DOE funding application and federal environmental reviews.

Invenergy’s Sophia Dossin said a cap on project costs is important, considering JTIQ cost estimates have almost doubled in two years.

“Even just having a percentage somewhere, even a very high cap that we’re sure we’re never going to hit at least gives generators some sort of certainty,” Dossin said.

Clean Grid Alliance’s Rhonda Peters said some type of oversight on costs is “critical.” She warned that some generation developers might not go through with projects based on the risks of escalating line costs.

“If that dollar-per-megawatt charge is high right off the bat, this is not going to work. If those costs are in the mid-range and then double, then projects that invested significant capital will not be able to go forward,” she said, asking for “some sort of accountability mechanism.”

Some stakeholders said the grid operators and transmission owners might be underestimating the effect that stubbornly high inflation will have on the cost of projects.

MISO staff said the JTIQ portfolio can enable an estimated 28 GW of new installed capacity and should give large groups of interconnection customers lowered transmission upgrade costs and more cost certainty than under its previous affected system studies process.

MISO so far has not shared an estimated range of dollar-per-megawatt charges that individual generation projects might face.

“All the buzz around cost caps, is that going to be considered in the tariff language development? … What’s the upper limit where generation developers will not subscribe to these lines?” Southern Renewable Energy Association’s Andy Kowalczyk said.

“I wouldn’t say anything is off the table. We’re listening very carefully to your concerns, and we’re going to discuss them internally,” MISO counsel Chris Supino said. “If there’s a way to include these without disturbing what we’re working towards in the tariff, we’re going to consider them.”

Kowalczyk said contemplating “an upper limit where people are going to bail on lines” is important because load will temporarily pick up the tab on the first JTIQ portfolio if the first batch of lines don’t have enough subscribers to be fully funded.

The JTIQ study is designed to focus on backbone projects rather than point-of-interconnection network upgrades. Whereas MISO’s and SPP’s previous process used actual generation sites in interconnection queues in affected system studies, the JTIQ leans on the likely interconnection spots of future generation representing multiple queue study clusters from both RTOs.

Until now, MISO and SPP have used affected system studies to identify additional, across-the-seam network upgrades the other might need as a result of new generation connecting close to the seam. And while MISO and SPP until now have identified only network upgrades for a particular SPP or MISO study cycle, the JTIQ study is designed to identify larger and longer-term system needs across seams and across groups of generation projects under study.

At this point, MISO considers its proposal to split JTIQ costs 90% to interconnecting generators with the remaining 10% assigned to load final. It will include that cost allocation in tariff edits.

“There is some disagreement, but we believe this course is settled: JTIQ projects meet the definition of generator interconnection projects,” Supino said.

Supino said MISO and SPP are discussing whether the projects should be a subcategory of interconnection upgrades, but he said it’s undisputed that the JTIQ projects are replacing MISO and SPP’s affected system study process and should be allocated 90% to interconnecting generation and 10% to load. As such, he said JTIQ projects won’t be open to competitive bidding.

Supino said MISO will include a pledge in its transmittal letter to FERC to evaluate cost allocation changes in future JTIQ portfolios. MISO didn’t elaborate on which additional benefits it might consider allocating in the future.