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July 7, 2024

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DOE Issues Transmission Interconnection Roadmap

The U.S. Department of Energy has released its roadmap to speed interconnection of new clean energy projects to the nation’s grid. 

The framework announced April 17 is also intended to clear the queue of backlogs that have developed in the past decade, during which renewable energy interconnection requests have grown by 300 to 500%. 

It is intended as a guide for stakeholders, including transmission providers, interconnection customers, regulators, manufacturers, consumer advocates and energy justice communities. It is a collection of potential strategies rather than a rigid list of prescriptive fixes.  

DOE said its Interconnection Innovation e-Xchange (i2X) began working on the first-of-its-kind “Transmission Interconnection Roadmap” in June 2022. Midway through the process, in July 2023, FERC issued its landmark Order 2023, seeking to accomplish many of the same interconnection streamlining goals. 

The DOE roadmap’s authors indicate the new document contains some solutions that relate to Order 2023 while other solutions support a longer-term evolution of the interconnection process.  

The roadmap is intended to complement and support implementation of Order 2023 by focusing on issues that Order 2023 may not resolve, such as balancing stricter requirements placed on interconnection customers with open access and equity considerations; incentivizing faster interconnection studies; and better coordinating affected system studies. 

The roadmap also seeks to address issues not raised in Order 2023, such as data transparency, automation, cost allocation and workforce development. 

The roadmap’s authors anticipate further overlap as FERC completes its rulemaking on transmission planning. The interconnection process and transmission planning are so closely linked that some of the roadmap’s solutions involve transmission planning, the authors write, but its focus is on interconnection reform. 

DOE later this year expects to issue a draft of a companion roadmap focusing on the distribution grid. 

“Clearing the backlog of nearly 12,000 solar, wind and storage projects waiting to connect to the grid is essential to deploying clean electricity to more Americans,” U.S. Secretary of Energy Jennifer M. Granholm said in a news release.  

Goals and Suggestions

The roadmap frames the problem as one of volume: The U.S. grid saw fewer than 1,000 interconnection requests per year in the 2000s and as many as 3,000 per year in the past decade. The generation capacity represented in these requests has jumped from 150-200 GW per year to 400-750 GW. 

The roadmap is framed around four primary goals, and it suggests solutions for each: 

    • Increase data access, transparency and security for interconnection by improving data on projects already in queues; enhancing interconnection study models and modeling assumptions; and developing tools to manage and analyze data. 
    • Improve the interconnection process and timeline through better queue management; improved affected system studies; a more inclusive and fair process; and workforce development focused on technical expertise needed in many industry professions. 
    • Promote economic efficiency in interconnection through better cost allocation; closer coordination between interconnection and transmission planning; and a revised model for interconnection studies. 
    • Maintain a reliable, resilient and secure grid by improving interconnection reliability assessment models and tools, and by developing comprehensive interconnection standards for things such as IBR capabilities and expected project performance. 

The roadmap also includes four target metrics by which to judge improvements: 

    • An average time of less than 12 months for completed projects to move from interconnection request to interconnection agreement. As of 2022, this is averaging 33 months; the best performance since 2003 was 18 months in 2005-2008. 
    • A standard deviation of interconnection costs of less than $150/kW for all projects. As of 2020-2021, it was $551/kW; the best since 2007 was $154/kW in 2010-2011. 
    • A completion rate of greater than 70% for projects that enter the facility study phase. As of 2016, it was 45%; the best since 2006 was 55% in 2007. 
    • Zero annual NERC disturbance events involving unexpected tripping of IBRs not identified in offline analysis due to inaccurate IBR models. In 2022 there were four such events; the last time there were zero was in 2019. 
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DOE Report Highlights Benefits of Advanced Grid Technologies

Advanced grid technologies can help expand the grid quickly and relatively cheaply, according to a new report from the U.S. Department of Energy. 

The Pathways to Commercial Liftoff: Innovative Grid Deployment report, released April 16, focuses on identifying ways to accelerate deployment of commercially available, but underused, advanced technologies over the next five years on existing transmission and distribution infrastructure. The technologies can quickly respond to accelerating grid pressures such as the need to expand capacity in the face of rising demand, enhancing reliability and supporting integration of clean energy. 

“The majority of the nation’s transmission and distribution lines are drastically overdue for an upgrade, which is why President Biden’s Investing in America agenda is so critical to bring the grid up to date,” Energy Secretary Jennifer Granholm said in a statement. “DOE’s new Innovative Grid Deployment Liftoff report outlines the existing tools that can be deployed in less than five years to modernize the nation’s power sector, making it more secure and reliable to deliver cheaper, cleaner power to American consumers.”   

The technologies covered include advanced conductors, high-voltage direct current lines, advanced distribution management systems, dynamic line ratings (DLRs), topology optimization, storage as transmission and distribution, data management systems and others. Deploying the advanced grid solutions could cost-effectively increase the capacity of the grid by 20 to 100 GW of incremental peak demand when installed individually, the report said. 

Making sure the grid has enough capacity is important to many of the projects DOE has funded recently, Jigar Shah, director of the agency’s Loan Program Office, told reporters. 

“Our other manufacturing and energy generation applicants and grantees need to be able to connect to the grid,” Shah said. “If our applicants can’t connect to the grid quickly, that’s going to meaningfully impact our ability to underwrite their debt.” 

The report was developed by staffers from around DOE with deep engagement from the private sector, said Vanessa Chan, director of the Office of Technology Transitions. 

“The liftoff report breaks down the value chain of various portions of the economy and sketches a road map for the private sector to deploy the solutions that we need,” Chan said. “So, in basic terms, [the report covers] things like: What cost do we have to hit in order for these technologies to take off? What are the technological and market-driven barriers that we have to overcome? What’s the amount of investment that we need where and by when?” 

While the grid needs to be expanded with new transmission and distribution investment, major new lines can take a long time to build and the GETs identified in the report can be deployed much more quickly, said Grid Deployment Office Director Maria Robinson. 

“We’re talking about three to five years deployment of key commercially available — but what we believe to be underutilized — advanced grid technologies and applications, and specifically how we can leverage existing transmission and distribution systems,” Robinson told reporters. 

Most of the solutions cost less than a quarter of traditional alternatives and can be deployed quickly, since they use existing infrastructure. 

DOE thinks the technologies can become a self-sustaining industry within three to five years, with “liftoff” happening when utilities and regulators comprehensively value and integrate advanced solutions as part of grid planning and operations. Pursuing between six and 12 operational deployments across a diverse set of utilities can cut risks enough to scale up the GETs industry, DOE said. 

Besides building evidence for how the technologies work and getting utilities and grid operators comfortable with using new technologies, the industry’s economic models and incentives must be updated for GETs to take off. 

“For regulated utilities, this will require regulators to lead in aligning utility compensation models with the value generated from, and costs of, advanced grid solutions to deliver ratepayer benefits — e.g., implementing performance-based regulation, allowing some operational expenditures to be capitalized,” the report said. “New mechanisms are needed that allocate costs in ways that better align with beneficiaries and equitably share benefits.” 

Grid operators also need to know how to include GETs in system planning and prioritize them for investments, the report said. That requires a comprehensive understanding and method for evaluating the costs and benefits of the technologies. 

The grid will benefit if the industry institutes the right reforms to use advanced transmission and distribution technologies to their full potential, it said. 

“Using just one-fifth of the current investment in conventional transmission and distribution asset replacement to instead upgrade assets with advanced grid solutions could nearly double industry investment in advanced grid solutions, driving greater grid impacts without increasing costs to ratepayers,” the report said. 

Maintaining reliability and keeping the grid’s frequency at 60 Hz are vitally important, and one way of showing utilities and grid operators the technologies can do those things while enhancing capacity is through demonstrations, including one DOE has funded at Philadelphia-area utility PECO, Robinson said. 

“A lot of this is just increasing awareness and making sure that the regulators also feel comfortable with taking these approaches as well,” she added. 

AES and LineVision Case Study on Dynamic Line Ratings

Segments of the industry have been working on rolling out the technologies, with LineVision and AES releasing a case study April 15 on the use of DLRs on five high-voltage lines across AES’ utility territories in Ohio and Indiana. DLRs can increase reliability by giving operators a better sense of how their lines are operating, LineVision CEO Hudson Gilmer said in an interview. 

“It’s providing utilities better data with which to do their jobs,” Gilmer said. “In the absence of monitoring of these lines that are really the backbone of the grid, utilities are guessing; they’re making conservative static assumptions about how much power they can put through the lines. And what this technology does is for the first time, it really allows them to see actual conditions and know precisely how much power they can put through those lines.” 

While the case study found that, on average, DLRs can increase a line’s capacity by 9 to 27% in the summer and up to 81% in the winter, Gilmer said they could sometimes help grid operators recognize when their assumptions are too generous and prompt them to dial back a line’s capacity, such as on a hot summer day with no wind. 

The case study involved installing LineVision’s monitoring technology on major backbone lines, but results indicated it could benefit lower-voltage transmission as well, although the biggest savings were on the 345-KV lines. 

The project involved installing 42 sensors in just eight weeks, with individual installation times of just a half-hour without considering travel time to the location. The quick installation time means they can easily be moved around as the grid changes, but Gilmer believes they might become standard across the entire system in the long term. 

“There’s one approach, which is deploying it almost like Band-Aids on that small number of problem lines,” Gilmer said. “But another philosophy is to say, ‘Why wouldn’t I want this data on my entire transmission system?’ So, these are the high-voltage lines that form the backbone of the grid. Wouldn’t your operators want to know exactly how much power they can put through, and if there are any anomalies that they need to be concerned about?” 

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Stakeholders Spar over PJM Request to Recalculate Capacity Auction Results

Stakeholders filed comments April 11 debating PJM’s request that FERC direct it to recalculate the results of the 2024/25 Base Residual Auction and rerun the third Incremental Auction (IA) based on those results, with general support from generators and opposition from state regulators and consumer advocates (ER23-729). 

The 3rd U.S. Circuit Court of Appeals in March vacated FERC’s order allowing PJM to revise the locational deliverability area reliability requirement for the DPL South zone after the BRA had been conducted but before the publication of its results, finding that it constituted a violation of the filed-rate doctrine. 

PJM on March 29 petitioned FERC to order it to use the results that would have been the outcome in December 2022 had it not revised the reliability requirement. It also requested to rerun the capacity period’s third IA, completed March 11, arguing that matching the “new” BRA results with those of the IA would be too complicated. (See PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters.) 

The issue stems from PJM identifying a substantial increase in capacity prices because of the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool based on the reliability requirement. The RTO asked FERC to allow it to revise the calculation of the requirement after bids had been received to exclude generators expected to offer that ultimately did not. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.) 

PJM requested FERC to act by May 6. It argued that rerunning the third IA would prevent generators that did not clear under the original auction from being assigned a capacity commitment with less than a month to make any preparations necessary to meet their obligations before the start of the delivery year (June 1). Some generators that did not originally clear may also have sold their uncommitted capacity through bilateral transactions, raising the risk that capacity may be double-counted if those resources are picked up should the BRA be rerun with different parameters. 

Should the commission decline to rerun the auction or not reach an order by then, PJM presented a “less optimal” alternative of allowing it to relieve market sellers of capacity commitments that both increased through rerunning the BRA and exceed what they reasonably believe they could provide. Market sellers would have seven days to request that PJM relieve them of their capacity obligations, which the RTO expects to be such a small amount that finding replacement capacity would not be necessary. PJM said that option would remain viable until May 22. 

“In other words, only a capacity resource that is committed in the recalculated Base Residual Auction to provide more megawatts than it is now capable of providing (due to either bilateral transactions or commitments from the February 2024 third Incremental Auction of capacity not committed under the prior Base Residual Auction results) would be eligible to be relieved of such excess megawatts,” PJM explained. 

Consumer Interests Urge Rejection

In a joint protest, several state commissions, consumer advocates and industrial groups urged the commission to reject PJM’s petition, arguing that rerunning the BRA with the original reliability requirement would increase DPL South consumers’ capacity bill by $178 million with little reliability benefit.  

They cited informational auction results PJM posted April 4, which showed what the December auction results would have been if the requirement had not been modified. Those figures, which PJM’s petition proposed using as the new auction results, show an increase in the DPL South clearing price from $90.64/MW-day to $426.17/MW-day, for a regional capacity cost of $288.4 million. 

Rerunning the IA would exacerbate the issues that have made commission reluctant to order auctions be reconducted by substantially increasing load-serving entities’ and consumers’ capacity costs with little time to find ways to lower them, argued the organizations, which included American Municipal Power, the Delaware Division of the Public Advocate, Delaware Energy Users Group, Delaware Municipal Electric Corp., Delaware Public Service Commission, Maryland Office of People’s Counsel and Old Dominion Electric Cooperative. 

“Rather than proposing to maintain the posted BRA results in light of these problems, PJM doubles down and proposes to rerun the third Incremental Auction. But that will not solve problems; it will instead create even greater disruption,” they told FERC. “PJM … ignores that doing so could adversely impact market participants who have relied in one way or another on the already completed third Incremental Auction.” 

Instead, they argued FERC should reaffirm that the BRA results PJM posted in February will stand because the commission’s obligation to protect consumers outweighs the general presumption that resolving a legal error should revert parties to their standing prior to the error. 

“The equities especially disfavor rerunning the auctions in this case, where PJM and one commissioner have acknowledged — and no one has meaningfully disputed — that the new prices reflect an unjust and unreasonable result of using an inflated reliability requirement, at odds with actual reliability needs, that increases capacity charges by more than $177 million, or 160%, with no consumer benefit,” the organizations said, referencing Commissioner Mark Christie’s concurrence with the commission’s order accepting PJM’s changes to the auction parameters.  

“Indeed, the commission here already balanced the equities when it weighed customers’ interest in paying only a just-and-reasonable rate against the generators’ allegedly settled expectation of exorbitant rates driven by use of an inflated reliability requirement, and concluded that the former outweighed the latter.” 

“PJM’s proposal would have profound adverse impacts on consumers in the Delmarva peninsula. Granting PJM’s proposal would serve only to provide power plant owners an unjustified windfall through massive price increases. It should be rejected,” Maryland People’s Counsel David Lapp said in a statement. 

In a statement regarding the Maryland Public Service Commission’s own protest, Chair Frederick Hoover said PJM’s proposal would result in “excessive capacity costs” for consumers and replace auction parameters the commission found just and reasonable last year with a flawed market design. 

“Allowing PJM to apply the same flawed market design that it has once correctly characterized as being unjust and unreasonable would be unconscionable,” Hoover said. “With FERC’s acknowledgement of the consequences of a flawed market, PJM already set the fair price for electric capacity well over a year ago. We are asking FERC to require PJM to retain those rates in order to ensure that customers on the Delmarva Peninsula will not be harmed by having to pay for reliability at inflated prices with no economic or reliability justification.” 

Generators Supportive of New BRA Results, Divided on IA

The Electric Power Supply Association and PJM Power Providers, which appealed FERC’s order to the 3rd Circuit, jointly supported PJM’s petition, saying that resolving the case before the delivery year begins is imperative. 

While they said both routes PJM proposed were acceptable, they preferred leaving the third IA results in place and instead allowing market sellers to ask the RTO to relieve any increased capacity obligations they could not serve. Rerunning the IA could result in unintended consequences by allowing all market participants to adjust their positions after the results of the original IA had been posted, which they said is unnecessary because a smaller number of participants are expected to be affected by the issues PJM is seeking to resolve. 

Constellation Energy supported PJM’s entire proposal, stating that the IA was based on the same parameters the court found invalid and that rerunning it would allow market sellers to adjust their offers to account for changes in the BRA parameters. 

“If the BRA results are recalculated but the third Incremental Auction is not rerun, there will be a disconnect between the quantity of capacity procured in the BRA and the quantity needed in the third Incremental Auction” Constellation said. “Additionally, market participants should have a meaningful opportunity to adjust their participation in the third Incremental Auction in light of the recalculated BRA outcome.” 

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Granholm Defends DOE’s 2025 Budget at Senate Hearing

U.S. Energy Secretary Jennifer Granholm on April 16 defended her department’s $51 billion budget proposal for fiscal 2025 before hostile Republicans on the Senate Energy and Natural Resources Committee. 

Granholm said companies have announced 600 new or expanded clean energy manufacturing sites in the country and nearly $200 billion in investment in the sector since the Infrastructure Investment and Jobs Act passed. 

“Our commercialization tools are giving American businesses the confidence that they need to capitalize on this moment while deepening our energy security,” Granholm said. “But deepening our energy security is an ongoing project, and we need to fund it year over year, and that’s why the budget calls for significant appropriations for our demonstration and deployment programs.” 

While Granholm said DOE’s efforts were leading to reindustrialization and new jobs, Republicans — led by Ranking Member John Barrasso (R-Wyo.) — tried to hang their worries about the cost of living on the Biden administration’s energy policies. 

Energy Secretary Jennifer Granholm testifies before the Senate Energy and Natural Resources Committee. | Senate ENR Committee

“Prices are not only worse under Biden, they are significantly worse: gasoline up 48%, natural gas up 27%, home heating oil up 44%, electricity up 29%, total energy costs of 39%,” Barrasso said as a staffer held up a chart with those numbers. “Since Joe Biden has come into office, this is a record failure.” 

Sen. Bill Cassidy (R-La.) said later in the hearing that the same numbers show how the administration has not been successful in cutting costs for consumers. 

Granholm noted that the chart was comparing current prices to those at the height of the COVID-19 pandemic, when prices were depressed because of its impact on the economy. 

“Natural gas is at very low prices,” Granholm said. “Right now, the price of solar is very low. What’s causing the increase in energy prices? One contributing factor is the investments in the grid that are necessary, this old grid that gets ratebased among ratepayers. And it’s one of the reasons why it’s so important for us all in leadership to take a look at how we invest in the national electric grid, so that we are not forcing ratepayers to bear that burden.” 

Cassidy also argued that the lack of pipeline development had been hindered by Biden administration policies. 

DOE does not oversee pipeline siting, but Granholm noted that the budget request includes funding for the Low Income Home Energy Assistance Program for weatherization and other efficiency investments to help lower bills for customers. 

Sen. Steve Daines (R-N.D.) asked when DOE expected to complete the study for which the administration has paused all new LNG export facility approvals. 

“I look no further than the White House website where the first quote in their press release lauds — and let me quote — ‘this administration’s historic efforts to meet the global commitment to phase out fossil fuels,’” Daines said. 

Granholm said she had not seen the White House’s press release but noted that the industry has grown since the last time the impacts of LNG exports were studied. 

“We were only exporting 4 BCF of LNG at that time, and now we are exporting 14 with another 12 BCF under construction, and 48 total authorized,” Granholm said. “This pause doesn’t affect any of that.” 

DOE expects to finish the study around the end of the year, and Granholm said staff working on it have been focused on how exports will impact domestic prices and what the future demand will be for LNG, especially given that many of the countries buying it today have their own commitments to net zero. 

Sen. Angus King (I-Maine) was more supportive of the pause, noting it was prudent to examine exports’ impacts given how quickly they have grown. 

“Our low domestic gas prices are a huge asymmetric advantage around the world,” King said. “And I’m concerned that we will, in effect, export that advantage.” 

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FERC Approves NYISO’s 10-kW Minimum for DERs in Aggregations

FERC on April 15 approved NYISO’s proposed tariff revisions that set rules for distributed energy resources seeking to participate in its markets, including a 10-kW minimum for individual resources to be included in an aggregation (ER23-2040). 

The commission sent two deficiency letters in response to the proposal, submitted by NYISO last year, over the 10-kW rule, directing it to provide more explanation for how it decided on that figure and why it would not be unduly discriminatory. (See NYISO Defends 10-kW Minimum for DER Aggregation Participation.) 

FERC ended up accepting the entirety of the proposal without directing any compliance filings, finding that the ISO had “demonstrated that, at this time and based on the record herein, the 10-kW minimum capability requirement reasonably balances the benefit of enabling NYISO to implement its DER and aggregation participation model immediately against the drawback of maintaining a limited barrier to certain DERs so that NYISO may feasibly enroll and monitor individual DERs in an aggregation and efficiently administer the wholesale markets.” 

The commission rejected complaints that the rule was contrary to Order 2222, which directed RTOs and ISOs to open their markets to DER aggregations. Although the order did not institute a minimum requirement, it also did not preclude grid operators from instituting one, FERC said. 

It also noted that NYISO said the rule was not necessarily permanent and subject to re-evaluation. To that end, FERC did order the ISO to submit an informational filing in two years describing its experience administering the new rules and “the estimated effect that the 10-kW minimum capability requirement has had on potential participation, including on the total number of DERs under 10 kW in” New York. 

FERC Chair Willie Phillips and Commissioner Allison Clements said in a joint concurrence that although they approved the minimum rule, they did not “arrive at this finding lightly.” 

They cited the New York Public Service Commission’s arguments in its protest that DERs are expected to increase significantly in the next few years based on state policies. “Despite commenters’ valid concerns about the potential limiting effect of the 10-kW minimum capability requirement in the future,” Phillips and Clements said they based their decision “on the record before us.” 

“We find persuasive NYISO’s explanation that the 10-kW minimum capability requirement is necessary for NYISO to implement its DER participation model immediately and that the lack of such a requirement would substantially delay rollout of the participation model,” they said. “Rejecting NYISO’s filing would therefore have significantly delayed DERs’ eligibility to participate in NYISO’s markets — thereby depriving NYISO and market participants an opportunity to gain valuable experience that can improve the participation model going forward. … 

“We are only now leaving the starting gates in unlocking the potential of DERs to provide reliability value to our grid, but that value will be essential to ensuring we meet new and emerging reliability challenges in the future in an efficient manner that protects customers.” 

Commissioner Mark Christie issued his own concurrence, a brief and somewhat terse statement that “NYISO — in what can only be described as a ‘Groundhog Day’ experience — was required to repeatedly explain” its reasoning for the 10-kW minimum. In a footnote, he noted that he “was not consulted nor asked my opinion on the issuance of” the two deficiency letters. 

Christie also complimented the ISO for “airing its suspicions that … ‘[FERC] may have preferred the NYISO to develop one or more alternatives to its proposal’” and “reminding this commission of its obligations under [Federal Power Act] Section 205 to limit its review to” whether the proposal before it was just and reasonable, and not whether there was a better alternative. 

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Gas, Electric Trade Associations Call for More Gas Infrastructure

ISOs and RTOs should take a more prominent role in expanding gas networks, gas and electricity industry representatives emphasized at a webinar April 15.  

Convened by Texas RE, the talk focused on improving gas-electric coordination to prevent extreme weather risks like the issues that stemmed from Winter Storm Uri in February 2021 and Winter Storm Elliott in December 2022. 

The FERC/NERC reports on power system performance during Uri and Elliott found that gas generators were the largest source of outages during the events. Gas supply issues accounted for about 27% of generator outages during Uri and 20% during Elliott, while mechanical and freezing issues accounted for about 65% of outages during Uri and 72% during Elliott. Mechanical and freezing issues accounted for about 65% of outages during Uri and 72% during Elliott. 

“Organized power markets do not support the long-term commitments needed to expand gas infrastructure,” said Joan Dreskin of the Interstate Natural Gas Association of America. 

Dreskin said most contracts for firm gas capacity cover relatively short durations and do not provide the certainty needed for large, long-term investments. She added that RTOs should take steps to enable power generators to serve as anchor customers for pipeline expansion projects. 

“There’s so many issues with getting a pipeline built,” said Patricia Jagtiani of the Natural Gas Supply Association . Along with the difficulties of finding capacity offtakes, Jagtiani highlighted organized opposition, permitting delays and financing as major roadblocks to expanding gas networks. 

The panelists said reliability issues could worsen as renewables proliferate and shift the role of gas generation from base load to peaking and balancing gaps left by clean energy, increasing power plant ramping requirements. 

“We’re going to need additional infrastructure on the power side and on the gas side,” said Nancy Bagot of the Electric Power Supply Association. “It’s probably the greatest challenge.” 

Gas expansion projects nationwide have faced opposition in large part due to the emissions associated with gas production, transport and combustion.  

Gas generators accounted for about 43% of U.S. power plant emissions in 2022, according to data from the U.S. Energy Information Administration. Meanwhile, independent studies have shown repeatedly that U.S. emissions inventories significantly undercount emissions related to gas system methane leaks due to inadequate detection methods.  

Beyond capacity additions, the panelists also called for market mechanisms to ensure generators secure adequate gas supply before extreme weather events, instead of as they occur.  

In a white paper published in fall of 2023, the three associations wrote that most of the gas generator outages during Winter Storm Elliott occurred when RTOs called on the resources to run in real time. The groups noted that uncertainties related to when they will be dispatched and fuel cost recovery can dissuade generators from making gas purchases in advance. 

To better incentivize generators to secure gas supply ahead of reliability events, RTOs should “develop market-based mechanisms to better signal expected power dispatch, avoid uplift and include fuel costs to reflect the cost of reliability in the market price,” the coalition wrote.  

If the market rules can be properly aligned with reliability risks, “the gas system is reliable [and] gas generators are reliable,” Dreskin said. 

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Wind Energy Development Set Records Worldwide in 2023

The wind energy sector installed record capacity worldwide in 2023 and is on pace for continued strong growth in the next five years, an international trade organization for the industry said. 

However, wind turbine installation rates must increase sharply to meet emissions reduction targets, the Global Wind Energy Council said in its 2024 report, issued April 16. 

Some 117 GW of wind energy generation was installed in 2023, but the total must jump to at least 320 GW a year by 2030 if the world is to stay on the pathway set at COP28 and limit global warming to 1.5 degrees Celsius, GWEC said.  

“It’s great to see wind industry growth picking up, and we are proud of reaching a new annual record,” CEO Ben Backwell said in introduction to the report. “However, much more needs to be done to unlock growth by policymakers, industry and other stakeholders to get on to the 3X pathway needed to reach net zero. Growth is highly concentrated in a few big countries like China, the U.S., Brazil and Germany, and we need many more countries to remove barriers and improve market frameworks to scale up wind installations.” 

Regional differences between wind energy facility construction in 2022 and 2023 | Global Wind Energy Council

Within the record-high 117 GW installation total, some milestones and firsts were recorded in 2023: 

    • It was the first year new onshore wind capacity exceeded 100 GW. 
    • Total installed capacity surpassed 1 TW, reaching 1,021 GW by year end, a 13% year-over-year increase. 
    • China had its busiest year ever; the 75 GW it brought online accounted for nearly two-thirds of the global construction total. 
    • Offshore wind development did not set a record, but the 10.8 GW completed in 2023 was the second-highest annual total ever. 

Based on these and other factors, GWEC predicts the world will reach 2 TW of installed wind energy capacity by the end of 2029 — a year earlier than it projected in its 2023 report. 

While this is strong progress, it leaves the world far short of the COP28 goal of tripling renewable energy, said GWEC Chair Jonathan Cole. 

He called for nations to de-risk and accelerate buildout of renewables by prioritizing investment in transmission infrastructure and streamlining permitting. He said political leaders need to send clear market signals that the energy transition will happen, take steps to encourage supply chain growth and remove barriers to free trade. 

“Global Wind Report 2024” focuses on four areas — investment, supply chains, system infrastructure and public consensus — that GWEC considers key to wind energy growth. 

It also looks at potential obstacles, including too-rapid innovation that puts quality control at risk; effective opposition by interest groups via social media; workforce planning disruption by robotics and artificial intelligence; and the digital divide between nations and regions that limits some countries’ ability to carry out the energy transition. 

GWEC’s projected increase of installed wind energy capacity. | Global Wind Energy Council

GWEC flagged 12 key takeaways from the 2024 edition of its annual report: 

    • Meaningful action will be needed to mobilize larger volumes of investment into wind energy. 
    • Stable and ambitious policy environments that offer reasonable returns on investment will foster growth at scale. 
    • Collaboration is needed to build a secure global supply chain with healthy, managed competition. 
    • Trade policy should foster competitive industries, not push higher costs onto end-users. 
    • New production models are needed to industrialize and decelerate the race for ever-bigger turbine platforms. 
    • The advantages of AI and machine learning must outweigh the drawbacks. 
    • Grids must become a national policy priority for countries to meet their energy security, climate and economic growth goals. 
    • Policymakers should prepare to utilize storage, demand-side response and other solutions to scale modern and flexible power systems. 
    • Permitting should be accelerated through early, extensive and effective engagement and a shared understanding of its effects for communities, nature and users of land or sea spaces. 
    • Community engagement is more critical than ever. 
    • Planners should guard against misinformation that sows doubt in wind and renewable energy.  
    • The global wind industry must help deliver a just and equitable transition. 
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EPA Rejects Stationary Combustion Turbine Emissions Request

EPA has rejected an industry petition to exempt stationary combustion turbines from hazardous air pollutant regulations. 

EPA announced its decision April 15 and said it was part of a continuing, comprehensive approach to limit climate- and health-harming pollution from these sources. 

EPA said stationary combustion turbines typically are located at power plants, compressor stations, landfills and industrial facilities, and burn a variety of fuels ranging from natural gas to distillate oil to landfill gas. 

EPA said its regulations under Section 112 of the Clean Air Act limit emissions of air toxics, also called hazardous air pollutants, including formaldehyde, toluene, benzene, acetaldehyde and metals such as cadmium, chromium, manganese, lead and nickel.  

In August 2019, the petitioners had asked EPA to remove stationary combustion turbines from the list of sources subject to Section 112 because they create a cancer risk of less than one in 1 million and therefore meet the statutory threshold to be delisted.  

EPA said it rejected the petition because it was incomplete and because the agency could not conclude there was adequate data to determine that delisting thresholds were met. 

An EPA database last updated in October 2023 shows nearly 1,000 turbines at just over 500 facilities nationwide were subject to the regulations. 

“Today’s action will ensure people who live, work and play near these facilities are protected from harmful air pollution,” EPA Administrator Michael S. Regan said in a news release. “EPA is committed to ensuring every community has clean air to breathe, especially those that have been overburdened and disproportionately impacted by poor air quality for too long.” 

The petitioners were the American Fuel & Petrochemical Manufacturers, the American Petroleum Institute, the American Public Power Association, the Gas Turbine Association, the Interstate Natural Gas Association of America and the National Rural Electric Cooperative Association. 

American Petroleum Institute spokesperson Scott Lauermann said in a prepared statement: “While we are disappointed with this decision, we will continue to work with the EPA to ensure any new or revised emissions standards for combustion turbines are cost effective and technically feasible.” 

But Earthjustice and other environmental groups applauded EPA’s announcement. 

“Today’s decision upholds critical environmental protections that are essential for safeguarding public health, particularly in communities that have historically borne the brunt of industrial pollution,” Earthjustice Director of Federal Clean Air Practice James Pew said. “EPA did the right thing by rejecting industry’s attempt to dodge these requirements and get a free pass to pollute.” 

The Sierra Club said it had been pushing back against the exemption request for five years. 

“The EPA’s denial of the petrochemical industry’s bid to ease regulations for these major sources of toxic air pollution is a victory for public health and the environment,” said Jane Williams, who chairs the organization’s National Clean Air Team. “The EPA’s commitment to upholding these standards reinforces the importance of robust regulatory frameworks prioritizing our planet’s health and its people over industrial convenience.”  

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Feds Cut Renewable Costs, Boost Fossil Costs on Public Land

The federal government has finalized rules that will decrease the cost of siting renewable energy generation on public land and increase the cost of leasing it for oil and gas development. 

The Department of the Interior announced the final Renewable Energy Rule on April 11. It reduces rent and capacity fees, streamlines the application process, allows for noncompetitive bidding and makes the process more predictable. 

The department announced the final Fluid Mineral Leases and Leasing Process Rule the next day. It increases bonding requirements, adds protection for key wildlife habitat and cultural sites, increases royalty rates, boosts the minimum bid amount and creates a per-acre fee for expressions of interest. 

Reaction fell along likely lines, with environmental advocates praising both rules and the petroleum industry panning the mineral rule. 

Renewable Energy

The renewable rule derives from the Energy Act of 2020. According to a fact sheet, it reduces capacity fees 80% until 2035, then steps the discount down to 20% by 2039. It also establishes incentives for solar and wind projects that entail project labor agreements and use U.S.-made materials. 

And it gives the Bureau of Land Management discretion to hold competitive bidding in places where the greatest competitive interest exists; the process for this will be standardized.  

DOI said in a news release that the revisions are intended to reduce consumer energy costs and promote clean energy development. 

But even as President Joe Biden presses the energy transition away from fossil fuel use, U.S. natural gas output has set records and the U.S. is producing more crude oil than any other nation, ever, according to the Energy Information Administration. 

Oil and Gas

The mineral rule is BLM’s first major update to the onshore oil and gas leasing framework since 1988 and entails the first increase in royalty rates since 1920. Some of the provisions in the update were set in the Inflation Reduction Act and the Infrastructure Investment and Jobs Act. 

The intention is to “increase returns to the public and disincentivize speculators and irresponsible actors,” DOI said in a news release. 

Among the changes, summarized in a fact sheet, are that royalty rates for new oil and gas leases on public land will increase from 12.5% to 16.67%; minimum rental rates will start at $3/acre and rise to $5 and $15 in years three and nine, respectively, of a lease; noncompetitive leasing is eliminated; minimum lease bond is increased to $150,000 and statewide bond to $500,000; and wells will be considered idled after four years rather than seven. 

Also, the revisions will guide BLM as it tries to steer leasing toward areas with existing infrastructure and high oil and gas potential — the areas most likely to be developed — and away from areas with sensitive wildlife habitats, high recreational use and cultural resources. 

The higher bonding amounts are an attempt to shield taxpayers from the cost of cleaning up orphan wells. 

Reactions

“These new regulations are the kind of common-sense reforms the federal oil and gas leasing program has needed for decades,” the Sierra Club said. “The days of oil and gas companies locking up public lands for decades for pennies on the dollar and leaving polluted lands, water and air in their wake are over.” 

Friends of the Earth praised the oil and gas lease changes but said the underlying issues remain unaddressed. 

“While we support BLM’s steps to curb financial giveaways to Big Oil, this rule fails to confront the massive tide of climate emissions stemming from its leasing program,” FOE said. “If Interior intends to manage our public lands for the public good, then it must account for the future generations living under the threat of catastrophic climate change. Interior must do what the science demands and end the expansion of fossil fuels.” 

Fossil industry groups had a different reaction. 

The Independent Petroleum Association of America said the Biden administration was trying to “placate a small group of environmentalists” and “further reduce” American oil and natural gas production. 

“The final rule will not improve stewardship of federal lands, as BLM claims, but will have the effect of driving mineral production off of these areas. The regulatory environment has become so hostile to American oil and natural gas producers operating on federal land that it’s clear the Biden administration intends for ‘multiple use’ lands to only be used for conservation and recreation. The true losers with this misguided policy are states and localities that rely on revenues from federal land extractive industries to meet their budget obligations year after year.” 

The BLM rule will drive small producers off public lands, the Western Energy Alliance said. “The bonding amounts are excessive when there are just 37 orphan wells out of more than 90,000 wells on federal lands. Increasing bonding amounts twentyfold in order to take care of a problem on just 0.004% of wells is way out of proportion. This is another rule by the Biden administration meant to deliver on the president’s promise of no federal oil and natural gas. Western Energy Alliance has no other choice but to litigate this rule.” 

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26 Western Entities Signal Continued Support for Markets+

More than two dozen Western electricity sector entities sent a letter to SPP expressing support for the continued development of the RTO’s Markets+, which is competing for participants with CAISO’s Extended Day-Ahead Market (EDAM). 

The April 12 letter from the 26 entities, addressed to SPP CEO Barbara Sugg, arrived nearly three weeks after the RTO filed the Markets+ tariff with FERC and two weeks after Bonneville Power Administration staff issued a tentative recommendation that the federal agency choose Markets+ over EDAM. (See SPP Files Proposed Markets+ Tariff at FERC and BPA Staff Recommends Markets+ over EDAM.) 

“We collectively appreciate the effort and process that has resulted in the filing of the Markets+ tariff, and we look forward to participating in the ongoing development of the protocols and other market details,” the organizations said. 

SPP noted that the signers include organizations from the Pacific Northwest, Desert Southwest and Mountain West and represent about 57 GW of peak demand across 10 states and one Canadian province. 

“SPP is proud to receive support from a broad and diverse group of stakeholders across the Western Interconnection for the continued development of Markets+,” Vice President of Markets Antoine Lucas said in a statement issued April 15. 

Twelve of the U.S.-based signatories represent balancing authorities that will face a choice between the two day-ahead market offerings. They include Arizona Public Service, Avista, BPA, NorthWestern Energy, Public Service Company of Colorado, Puget Sound Energy, Salt River Project, Tacoma Power, Tucson Electric Power, and the Chelan, Douglas and Grant county public utility districts in Washington state. Another, Powerex, is the marketing arm for BC Hydro, the BA for the province of British Columbia. 

The other signers consist mostly of publicly owned utilities in the Northwest, most of which are in BPA’s BA area, as well as Tri-State Generation and Transmission Association, whose members span four states, three of which are in the Western Interconnection. 

The letter highlighted the “preferred aspects” of Markets+ for the signatories. Key among them is the market’s “independent, inclusive and robust governance structure,” a point BPA staff heavily emphasized in its recommendation. 

“As most of us were Phase 1-funding participants of Markets+, we have seen first hand the benefits and importance of the Markets+ governance structure. Critically, Markets+ has had independent governance from Day 1, including the establishment of an Interim Markets+ Independent Panel,” the organizations said. 

They also lauded SPP’s “stakeholder-driven decision-making” process, for which RTO staff provide a supporting role but do not lead. Some Northwest stakeholders have criticized CAISO for its more staff-driven stakeholder process, saying it creates a bias in favor of California interests. 

“We believe that the Markets+ framework would provide a level playing field for participants at the outset,” they said. 

WRAP Integration

The organizations also praised the fact that Markets+ will require participants to take part in a common resource adequacy framework, the Western Power Pool’s Western Resource Adequacy Program. 

“This requirement would help ensure that there are adequate resources to reliably serve load throughout the footprint and that such resources are installed and/or secured well ahead of market operations. It would also ensure that all market participants are equitably contributing to the reliability of the market footprint and that no participants are systemically leaning on others,” they said. 

They also noted that many of them “express specific support for the concept of the Markets+ design choice to deliver congestion rents to those participants with monthly or longer firm transmission rights, including both network service and point-to-point transmission rights.” 

The congestion rent mechanism would provide two benefits, they said. 

“First, it could help ensure equitable outcomes for firm transmission customers by providing the appropriate revenues (or hedges) to each customer on a path-specific basis. Second, it could create an appropriate ongoing investment incentive for firm transmission service, which helps protect transmission providers’ main source of revenue, preventing cost shifts between customers,” they said. 

They pointed favorably to other aspects of the Markets+ tariff, including “a must-offer requirement ensuring resource sufficiency that supports market liquidity and reliability,” treatment of greenhouse gases “that supports state requirements” and “prioritization of load service inside the Markets+ footprint over low-priority exports.” 

“We’re glad to see Western entities base their support on characteristics of our market design that we think make Markets+ a wise choice for the West, including enhanced system reliability, the affordability of wholesale energy, support for goals related to sustainability and equity in everything from governance to market pricing,” SPP’s Lucas said. 

The letter did not indicate financial commitments for the second phase of developing Markets+. 

“Each of us have different requirements around our decision process regarding moving forward with participation in a day-ahead market, and some of the undersigned stakeholders do not expect to make decisions about funding and joining a day-ahead market until the end of this calendar year,” the signatories wrote. 

Thirty-six entities participated in Phase 1 of Markets+.