Search
`
August 13, 2024

Posted on

WEIM Yields $365M in Q2 Benefits with Hot Start to Summer

CAISO’s Western Energy Imbalance Market (WEIM) provided its 22 participants with $365.04 million in economic benefits from April to June this year, down 4% from the same period a year ago. 

Cumulative benefits since the 2014 launch of the real-time market have hit $5.85 billion, according to CAISO’s second-quarter WEIM benefits report, released July 30. 

June saw an extremely hot start to summer for most of the West. During that month, the solar-heavy CAISO area was the WEIM’s leading net exporter, sending more than 1.1 million MWh of energy to other market participants, up 7% from June 2023. In the WEIM, a net export represents the difference between total exports and total imports for a balancing authority area during a particular real-time interval. 

“The transfers helped balance supply and demand when some of the WEIM entities were experiencing higher electricity usage due to a heat wave that saw temperatures climb 7 to 16 degrees above normal for several days across the West,” CAISO said in a press release accompanying the report. 

The ISO also was the biggest net exporter over the full quarter at 2.86 million MWh, followed by PacifiCorp’s East and West BAAs’ combined exports of 584,555 MWh, NV Energy at 464,133 MWh and Salt River Project at 395,542 MWh. 

The largest net importers were Powerex (965,287 MWh), the Balancing Authority of Northern California (BANC) (534,382 MWh) and SRP (473,319 MWh). 

CAISO also was the location of the largest volume of wheel-through transfers during the quarter at 736,433 MWh, followed by Arizona Public Service (508,707 MWh), the Western Area Power Administration’s Desert Southwest Region (DSW) (430,880 MWh) and PacifiCorp-West (419,025 MWh). WEIM participants currently receive no financial benefits from facilitating wheel-throughs through the market, with only the source and sink of the transfers benefiting, although stakeholders have discussed the possibility of changing that in the future. 

“More recently, subsequent to the June 30 closing of the second quarter, the real-time market also provided an important platform for energy trading during the record-setting heat wave in July that caused triple-digit temperatures across much of California and the West,” the ISO said. “Market participants provided similar assistance with robust energy transfers throughout the region.” 

DSW, which joined the WEIM in 2023, reaped the greatest economic benefit during the second quarter, at $50.57 million. DSW this year withdrew from participating in the second phase of developing SPP’s Markets+ — a potential competitor to the WEIM — after finding it would see few benefits from participating in either Markets+ or CAISO’s Extended Day-Ahead Market. (See WAPA DSW Cites Lack of Benefits in Markets+ Withdrawal.) 

BANC realized the second-largest share of benefits ($49.9 million), followed by CAISO ($36.02 million), NV Energy ($33.65 million) and the Los Angeles Department of Water and Power ($30.52 million). 

CAISO’s report said WEIM operations in the third quarter also helped market participants avoid 55,921 metric tons of greenhouse gas emissions through reduced curtailments of emissions-free resources. The market has prevented over 1 million MT of emissions since 2015, the ISO estimates. 

Posted on

MISO in June: Unchanged Pricing, Lower Peak than Expected

June brought MISO a peak 2 GW lower than anticipated and unchanged real-time and fuel prices from last year, the RTO said in its monthly operations report.

MISO encountered a 113-GW peak on June 24 as a sustained heat wave sent temperatures into the high 90s across the Central and South portions of the footprint. However, the month’s peak was lower than MISO’s 115-GW probable demand forecast for June that it published in the days leading up to the season.

The peak demand for June this year was higher than last year’s 111-GW apex but well below 2022’s 121 GW. Load averaged 82 GW, slightly higher than last June’s 81-GW average.

The RTO’s average natural gas and coal prices did not budge from last June, staying about $2/MMBtu. Similarly, real-time LMPs reflected no change year over year, hovering at $28/MWh.

MISO matched a 6.2-GW all-time solar peak it set in May on June 14, when the collective panels of the footprint managed about 12% of load for a brief period.

The RTO’s approximately 56 TWh of production for the month were supplied 39% by natural gas generation, 28% by coal generation, and about 14% apiece by wind and nuclear generation. Hydro and solar power each contributed almost 3%.

Daily generation outages stood at an average of 35 GW, lower than 2022 and 2021’s 40 GW and 2023’s 38 GW.

MISO ultimately issued conservative operations instructions for its North region on June 25 and for its North and Central regions on June 28 because of above-normal temperatures.

However, MISO has yet to issue emergency instructions this summer. Although MISO issued a capacity advisory for its North and Central regions and conservative operations for the entire footprint on July 15, the combination of forced generation outages, hot weather and transfer capability issues did not rise to an emergency level.

MISO is navigating a capacity advisory for its Central and North regions and conservative operations for the entire footprint through July 31 because of heat, forced generation outages and higher-than-forecasted load.

On July 30, MISO relied heavily on its coal (41 GW) and gas (44 GW) resources to meet a 115-GW peak. Prices ranged from $39 to $49/MWh.

Posted on

DC Circuit Vacates Pipeline Approval FERC Issued over NJ’s Objections

The D.C. Circuit Court of Appeals on July 30 vacated and remanded an order by FERC approving a natural gas pipeline in New Jersey that state regulators said was unneeded (23-1064).

FERC last year approved Transcontinental Gas Pipe Line Co.’s Regional Energy Access Expansion Project to boost gas delivery by 829,400 dekatherms/day to bring gas from Pennsylvania into New Jersey over the objections of New Jersey regulators and others (CP21-94). (See FERC Approves Pipeline Expansion Despite New Jersey’s Worries.)

Before the gas project came to FERC for approval, the New Jersey Board of Public Utilities opened a proceeding on the future of natural gas in the state, which determined it did not need more pipeline capacity through at least 2030. That proceeding was opened in February 2019; Transco applied to FERC in March 2021; the BPU issued a final order in the proceeding in June 2022; and FERC approved the pipeline expansion in January 2023.

About 73.5% of the project’s gas was destined for customers who signed contracts in New Jersey, but the rest was for Delaware, Maryland and Pennsylvania.

The New Jersey Conservation Foundation, New Jersey Division of Rate Counsel, New Jersey Attorney General’s Office and others challenged FERC’s approval after the commission upheld it on rehearing.

The court found that FERC failed to make a significance determination when it came to the project’s greenhouse gas emissions and failed to discuss mitigation measures.

FERC quantified the emissions associated with the project, finding construction could add 43,548 metric tons of CO2 equivalent, while operation would add 562,044 metric tons per year. Using the fuel downstream from the pipeline would add just over 16 million metric tons. The higher estimates are the project would use 39% of the total annual emissions budgets of New Jersey and Maryland.

The commission said counting the emissions was enough and it did not have to weigh their significance for the project as it had an open proceeding looking into such issues generically.

FERC “did not explain, however, how the pendency of that generic proceeding affects its ability in the meantime to make a case-specific determination here, when it was able to do so in Northern Natural,” the court said, referencing the first time the commission assessed the greenhouse gas emissions of a proposed natural gas infrastructure project and its impact on global climate change. (See FERC Assesses Climate Impact of Gas Project for 1st Time.)

“The anticipated emissions from this project are more than a hundredfold higher than the 100,000 metric tons per year of CO2e that the commission’s interim guidance suggests as a significance threshold,” the court said. Even if FERC was not obliged to make a determination, choosing not to do so on the basis of an arbitrary explanation is a violation of the Administrative Procedure Act, it said.

The court also found FERC acted arbitrarily in granting the certificate under the Natural Gas Act because it failed to explain why it discredited New Jersey’s study finding no need of new pipelines for the rest of the decade. It also failed to give weight to the state’s climate law that requires sizeable and continuous cuts in natural gas use by utilities.

FERC criticized the New Jersey study for relying on the continued availability of 619 million dekatherms/day of off-system peaking resources that are not under long-term, firm contracts.

“The commission did not, however, identify any past event in which such resources — despite being subject to short-term contracts — were unavailable when needed,” the court said. “In fact, the commission recognized that ‘downstream capacity has been available to New Jersey shippers in the past through short-term peaking contracts and may be available in the future on the same short-term basis.’”

The project had contracts for the new capacity. Normally such precedent agreements are used to show a market need, but the court faulted FERC for failing to respond to challenges to its reliance on those. While New Jersey local distribution companies signed up for capacity, it is not guaranteed they will use it to serve their customers.

“If ratepayers assume the cost even when they do not need the capacity, LDCs can afford to contract for additional unneeded capacity, which they can then resell at a profit, even in a soft capacity market,” the court said. “Because the commission failed to respond to that challenge to its reliance on precedent agreements with LDCs who subscribed to a majority of the pipeline’s capacity, the commission acted arbitrarily.”

Posted on

NREL Examines Gulf of Mexico OSW Transmission Needs

A National Renewable Energy Laboratory report offers insight on transmission infrastructure needs for future offshore wind development in the Gulf of Mexico. 

NREL said the needs are significant but have not been researched previously.  

Offshore wind development in the Gulf presents challenges beyond those facing present-day efforts along the northeast U.S. coast. And developers so far have shown little willingness to meet those challenges — the Gulf wind lease auction planned for later this year was canceled for lack of interest. 

But the Gulf is believed to hold 37% of the nation’s potential offshore wind generation capacity, and federal leaders hope to exploit it. 

NREL’s report looks at some of the steps that would need to be taken well in advance of wind turbine construction so their megawatts of power could be brought ashore. 

A key takeaway: The oil and gas industry already has infrastructure and personnel in the Gulf. Shared transmission systems and workforce could support offshore wind. 

Also, about 18,000 miles of abandoned pipelines remain on the seabed and could be used to transmit clean hydrogen — generation of which is a potential use of offshore wind energy. 

But the NREL report also suggests that offshore wind transmission planning in the Gulf is not so different from other regions: Planners will have to limit the impact of their projects on existing communities, industries and ecosystems while navigating local, state, federal and tribal regulations and sensibilities. 

The report’s authors identify some gaps in existing planning and knowledge needed for buildout: 

    • RTOs and utilities have not incorporated Gulf of Mexico offshore wind power in their long-term transmission planning. 
    • Siting considerations for offshore wind transmission routing in the region have not been identified in published literature. 
    • Focused community and workforce engagement on stakeholder priorities has been lacking. 
    • Engagement and research would inform how offshore wind transmission would fit into the region’s energy generation portfolio and how it serves the needs of industries in the Gulf Coast states. 

The NREL report recommends the Department of Energy and Bureau of Ocean Energy Management convene a Gulf Coast version of the Atlantic Offshore Wind Transmission Study workshop series they began hosting in 2022. 

The Biden administration, as part of its push to build a new emissions-free power sector, envisions fixed-bottom wind turbines in shallower parts of the Gulf and floating turbines in deeper areas. 

But slower average wind speeds punctuated by severe winds from hurricanes and tropical storms present a significant engineering challenge for designers of the wind turbines to be placed in the Gulf. (See Hurricane Threat to OSW Turbines Quantified.) 

In 2023, the first of four planned Gulf wind energy area auctions drew only three bids from two bidders on one of the three areas offered. The single sale came at a rock-bottom price. (See Gulf of Mexico Wind Energy Auction Falls Flat.) 

The planned 2024 auction drew early interest from only one potential bidder and was called off. (See BOEM Cancels Gulf of Mexico Wind Lease Auction.) 

As the 2024 auction was heading to cancellation, however, another developer submitted an unsolicited request to BOEM for two other lease areas off the Texas coast. 

And Louisiana has been advancing offshore wind development in state waters closer to shore. The Climate Action Plan developed during the administration of Gov. John Bel Edwards (D) set a goal of 5 GW of offshore wind capacity by 2035, and the state signed agreements with two developers in late 2023, during the closing days of his administration. 

A previous NREL study identified 25 plausible points of interconnection for offshore wind export cables but concluded that, as in other regions, many of them would need significant upgrades to handle gigawatt-scale injections. 

The new NREL report was funded by the DOE’s Wind Energy Technologies Office and Grid Development Office. 

Posted on

AEP Planning for 15 GW of Data Center Load

American Electric Power executives say they’re embracing large loads and, fortunately for them, they say they have firm commitments for more than 15 GW of load coming from just data centers by 2030.

AEP told financial analysts during its July 30 second quarter earnings call with financial analysts that it’s seeing “unprecedented” load growth, split primarily between Texas and its PJM footprint. Commercial load has increased 12.4% over the second quarter of last year as new data processing facilities came online, the company said.

“We continue to see strong interest in Ohio and Texas, as well as several of our vertically integrated states, from customers looking to develop new data processing facilities,” interim CEO Ben Fowke said during the company’s call. “Affordability remains top of mind, and we’re working to ensure that the investments made in the grid to support this increased demand are allocated fairly and provide benefits to all customers.”

Noting AEP’s system-wide peak at the end of last year was 35 GW, Fowke said the company continues working with data center customers to meet their increased demand, but also ensuring contracts and new initiatives are “fair and beneficial” for all customers. He said AEP would provide details on its generation and transmission capital investment necessary to meet demand later this year.

“I want to emphasize that it’s critically important that costs associated with these large loads are allocated fairly and the right investments are made for the long-term success of our grid,” Fowke said.

AEP subsidiary Public Service Co. of Oklahoma (PSO) in June announced it will seek regulatory approval of an agreement to purchase Green Country, a 795-MW natural gas facility. Peggy Simmons, executive vice president of utilities, said the transaction will help PSO meet SPP’s higher planning reserve margin, which was increased to 15% from 12%.

“This was a very proactive approach that the team took to go out and find some affordable assets that we can bring onto the system,” she said.

AEP reported second-quarter earnings of $340 million ($0.64/share), down from 2023’s second quarter earnings of $521 million ($1.01/share). The company reaffirmed its 2024 operating earnings guidance range of $5.53-$5.73/share and its 6%-7% long-term growth rate.

Incoming CEO Bill Fehrman, who takes over AEP’s top job Aug. 1, did not participate in the call. Fehrman replaced Julie Sloat in June after his predecessor parted ways with AEP in February following just one year as CEO. (See AEP Selects Industry Veteran as Next CEO.)

“With Bill’s expertise and diverse background, you can anticipate a smooth transition and continuity of strategic direction. Expect more focus on execution,” said Fowke, who served as interim CEO and will advise Fehrman during a transition period.

The company’s share price rallied late July 30 to close at $98.14, up $1.07 from its previous close.

Posted on

ISO-NE Capacity Accreditation Reforms Spur Energy Storage Concerns

As ISO-NE undertakes major capacity market accreditation reforms, New England storage developers are voicing concerns that potential flaws in the RTO’s modeling methodology could discourage new investments in storage resources. 

The resource capacity accreditation (RCA) project has been in motion for more than two years, and the development process could continue into 2027 following the RTO’s three-year delay of its 19th capacity auction, which applies to the 2028/29 capacity commitment period. (See NEPOOL Markets Committee Restarts Work on Capacity Market Changes.) 

The RCA project is intended to better align the capacity procurements with real-world reliability benefits, mirroring similar reform efforts in MISO, NYISO and PJM.  

Prior to FERC’s approval of the full three-year delay — which will give ISO-NE time to reform the timing of the capacity auction process along with accreditation — the RTO published RCA impact analysis results that painted a dire picture for storage resources. (See FERC Approves Additional Delay of ISO-NE FCA 19.) 

While the analysis indicated that the accreditation changes would increase the overall pool of capacity revenue by 11%, it showed a 37% revenue reduction for storage resources, equivalent to about $58 million. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

While these results are subject to change as ISO-NE refines the methodology and accounts for the transition from a forward annual capacity market to a prompt-seasonal capacity market, the analysis served as a wakeup call for many of storage companies participating in the capacity market. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

The concerns about storage accreditation derating come as several New England states are looking to rapidly ramp up the deployment of storage resources; Connecticut, Massachusetts, Maine and Rhode Island all have storage targets in the hundreds of megawatts. 

State programs also are a key revenue component for storage developers, as the current levels of revenue from ISO-NE wholesale markets alone are not enough to support the resources, said Alex Chaplin of New Leaf Energy, adding that “storage provides significant reliability benefits to New England which need to be adequately measured and compensated for in the ISO-NE markets.” 

Chaplin noted that most storage in the region is concentrated in Connecticut and Massachusetts due to their state incentives for storage. Massachusetts’ clean peak energy standard, which is aimed at cutting emissions and air pollution from fossil peaker plants, is a key revenue source for storage resources in the state. (See Panel Provides Update on Energy Storage in Mass.) Decreasing capacity revenue could lead to more pressure on states to support the resources to hit their storage deployment goals and cut emissions. 

“Capacity market revenues are typically an irreplaceable and indispensable source of revenue for the financeability and viability of resources, and storage is no exception,” said Alex Lawton of Advanced Energy United. He added that the energy market and ancillary services market do not provide “the scale or certainty needed for investors to back storage projects.” 

The crux of the issue, Lawton said, appears to stem from how ISO-NE is artificially scaling up load in its model to evaluate the reliability benefits of different resource types, which ultimately will determine how much capacity each resource can sell into the market. This modeling shows capacity scarcity events that significantly exceed the duration of events historically experienced in the region.  

While the longest capacity scarcity condition New England has experienced since the implementation of pay-for-performance rules in 2018 lasted two hours and 40 minutes, the RCA project is modeling events that typically exceed four hours, and — according to a March presentation — 36% of modeled shortfall events lasted more than eight hours.  

“As soon as you exceed four hours in duration — because most storage is between two and four hours — the marginal reliability impact (MRI) of storage just tanks,” Lawton said. 

There is broad consensus that the region’s power grid will face longer-duration periods of shortfall risk in the future as it trends toward a winter peaking system, but there is uncertainty around when these longer-duration risks will show up, and how they should be weighed against higher-likelihood, shorter-duration events.  

Over the long term, ISO-NE has stressed the need for dispatchable resources that can balance intermittent generation over extended periods of time. (See ISO-NE Outlines Economic Challenges of Decarbonization.) 

Frank Swigonski of Jupiter Power said the weighting of extreme winter storms in the methodology compared to more frequent, shorter-duration events “is an open question … that stakeholders should explicitly discuss in this process.” 

Swigonski noted the stakeholder engagement process for PJM’s accreditation reforms did not spend significant time discussing this question, which led to rehearing requests with FERC. 

“It ultimately had a massive impact on the final accreditation numbers,” Swigonski said. “We’re hoping that we don’t have the same experience in New England.” 

Swigonski also disagreed with the notion that shorter-duration storage resources are unable to provide significant resource adequacy benefits during longer-duration events. Storage resources likely still will be able to recharge off-peak during extended events, and operators eventually will gain experience with dispatching storage to avoid depleting all available storage in the first hours of an event, he said. 

Responding to questions about the RCA methodology, ISO-NE spokesperson Mary Cate Colapietro emphasized that the methodology is still a work in progress and that stakeholder engagement is ongoing. ISO-NE recently solicited comments on the scope of its Capacity Auction Reform (CAR) project, which included requests from storage companies for ISO-NE to evaluate the underlying modeling methodology. 

“Establishing a durable capacity market that provides the necessary reliability services as the power system evolves is a vital component of New England’s clean energy transition,” Colapietro said. “While we plan to continue pursuing an accreditation design based on capacity’s marginal reliability impact, the additional time afforded by the delay gives us time to work with stakeholders on possible improvements to that design.” 

Bruce Anderson of the New England Power Generators Association declined to comment on the treatment of specific resource types but stressed the need for ISO-NE to prioritize implementing a “sound market design” that provides efficient signals for resources to enter and exit the market. 

Posted on

ERCOT Evaluating RMR, MRA Options for CPS Plant

ERCOT has issued a request for proposal seeking alternatives to a reliability-must-run contract with CPS Energy, compensating for the utility’s planned retirement of a power plant. 

The ISO said in a July 25 market notice that CPS Energy’s decision to retire three aging coal-fired units, with a combined summer seasonal net maximum sustainable rating of 859 MW, would have a “material impact on identified ERCOT system performance deficiencies.” The grid operator’s staff has said the units’ retirement would load existing transmission facilities above their normal ratings under pre-contingency conditions.  

ERCOT’s determination triggered the grid operator’s obligation to issue an RFP for must-run alternatives (MRAs) and begin RMR negotiations with CPS Energy. The San Antonio utility has proposed suspending the three V.H. Braunig units after March 2025. (See CPS Energy Plans to Retire 859 MW of Gas Resources.) 

Qualified scheduling entities (QSEs) can submit proposals for one or more MRA resources to address system performance deficiencies more cost effectively than by committing one or more Braunig units through a more expensive RMR contract. QSEs can offer the resources for one or more seasons during April 1, 2025, through March 31, 2027. Eligible resources include types of generation, storage and demand response. 

RFP offers are due Sept. 9. ERCOT will host a workshop Aug. 15 to discuss the RFP and answer questions. After reviewing all proposals, staff will make a recommendation to the ISO’s board during its October meeting. 

An RMR contract would be ERCOT’s first since 2016. The grid operator entered into an agreement with NRG Texas Power over a previously mothballed gas unit near Houston. The RMR contract ended in 2017, thanks partly to transmission facilities that increased imports into the region. (See ERCOT Works to Address Loss of San Antonio Units.) 

$24.4B in Energy Fund Requests

The Public Utility Commission said July 29 it has received 72 applications for loans through the Texas Energy Fund’s in-ERCOT Generation Loan Program. The applications request $24.41 billion to finance 38.37 GW of proposed dispatchable, or thermal, power generation. 

Lawmakers have set aside $5 billion for this TEF program, one of four. 

“Texans have made it clear that they expect reliable electricity today and well into the future, and I am pleased to see industry leaders responding to that call and planning for major investments in dispatchable power for the state,” PUC Chair Thomas Gleeson said in a news release. 

Commission staff will evaluate the applications before the commission determines which projects will proceed to due diligence during the PUC’s Aug. 29 open meeting. The in-ERCOT program will provide low-interest loans to finance up to 60% of new construction or upgrades to existing dispatchable facilities. A proposed project must add at least 100 MW of new generation to the ERCOT grid to be eligible. Approved loans’ initial disbursements will be issued by Dec. 31, 2025.  

The in-ERCOT program and three other TEF programs were established in March because of state legislation passed last year. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

Posted on

Electric Sector Added just 55 Miles of New Transmission in 2023

The U.S. electricity industry added just 55 miles of new high-voltage transmission to the grid last year, despite estimates the system will need to expand rapidly in the near future, Americans for a Clean Energy Grid said in a report released July 30. 

“Fewer New Miles: The US Transmission Grid in the 2020s” was prepared by Grid Strategies with support from ACEG. 

“The findings of this report are a wakeup call. With only 55 new miles of transmission built in 2023, we are not keeping pace with the growing demand for power,” ACEG Executive Director Christina Hayes said in a statement. “The slowdown in new construction not only impacts our ability to meet future energy needs, but also risks increasing costs for consumers and reducing grid resilience. It is essential that we address these challenges to ensure a secure, reliable and affordable energy future for all Americans.” 

The U.S. Department of Energy’s Transmission Needs Study found the grid should expand by 57% by 2035, while Princeton University’s “Net-Zero America Study” found it would need to double or 80% of the potential greenhouse gas cuts from the Inflation Reduction Act would not be met, said the ACEG report. (See Will DOE’s Transmission Needs Study Spur New Regional, Interregional Lines?) 

While 2023 saw few miles of new lines built, the industry spent $25 billion on the grid (a record high), with 90% driven by reliability upgrades and the replacement of aging equipment. The decline has been felt for years, with the country building only 20% as much transmission so far this decade as it did in the early 2010s. 

“This trend began over a decade ago, when the average of 1,700 miles of new high-voltage transmission built per year from 2010 to 2014 dropped to only 925 miles from 2015 to 2019, and has fallen further to an average of 350 miles per year from 2020 to 2023,” the report said. 

So far this year up to May, the industry has completed one major transmission line, adding 125 new miles from completion of the 500-kV Delaney-Colorado Transmission Project that links Arizona and California. 

About 50% of recent spending is based on local planning criteria, which is usually below 345 kV and does not go through regional planning processes. Such lines focus only on reliability, ignoring maximized ratepayer benefits from multivalue projects, the report said. 

The 2010s saw massive greenfield projects, especially in Texas and the Midwest. Texas’ Competitive Renewable Energy Zone program saw $7.5 billion invested in ERCOT lines to bring wind power to population centers, cutting wind curtailment from 17 to 0.5% and leading to unexpected benefits like solar development in West Texas and electrification of oil and gas drilling in the regions. 

MISO’s Long Range Transmission Planning (LRTP) Tranche 1 Portfolio is another example, investing $10.3 billion to build out 2,000 miles of lines that offer at least 2.6:1 benefits to load. 

Recent federal action like FERC Order 1920 and DOE’s Transmission Facilitation Program to help finance new transmission lines should help, but the report said private capital needs to be invested to expand the grid. 

“Utilities are still currently incentivized to prioritize low- voltage upgrades focused on reliability and asset replacement,” the report said. “Both policymakers and regulators must capitalize on FERC’s issuance of Order No. 1920 to ensure the momentum brought about by federal action truly changes the incentives for transmission investment and helps spur a massive investment in the construction of new high-voltage transmission lines to ensure a reliable and affordable transition to a cleaner grid.” 

Posted on

Company Briefs

EQT, Equitrans Merge in $5.45B Deal

EQT Corp. has agreed to a deal with former subsidiary Equitrans Midstream Corp., closing on a $5.45 billion acquisition. EQT, the nation’s largest natural gas producer, announced its intention to reunite with Equitrans in March. The two were part of the same company until Equitrans spun out in 2018 as a pipeline and compression provider. 

More: Pittsburgh Post-Gazette 

Tesla’s Net Income Falls 45% in Q2

Tesla last week reported a second-quarter net income of nearly $1.5 billion, a 45% decline from the $2.7 billion a year earlier, as sales of its core cars dipped 5%. Total revenue was $25.5 billion in the quarter ended, a record, up 2% from $24.9 billion a year earlier. 

More: Houston Chronicle 

Nexamp, Starbucks Partner on Community Solar Projects

Nexamp and Starbucks have announced a partnership to deploy 40 MW across six Illinois community solar farms. Starbucks will receive a portion of the project’s RECs for its support of Nexamp’s Illinois operations. Construction has begun on the solar projects, which are expected to come online next year. 

More: Solar Industry Magazine 

Posted on

Federal Briefs

Campaign Official: Harris Does not Support Fracking Ban

Vice President Kamala Harris will not seek to ban fracking if she’s elected president, an official with her campaign said last week. 

While she was one of several Democrats vying for the 2020 nomination, Harris said, “There’s no question I’m in favor of banning fracking.” However, since that time, she joined the Biden campaign and administration, neither of which supports a ban on fracking. 

More: The Hill 

Republicans Ask Supreme Court to Pause New EPA Rules on Emissions

More than 20 Republican state attorneys general have asked the Supreme Court to temporarily block the EPA from enforcing new rules that aim to curb carbon emissions from power plants. 

The filing came days after a federal appeals court turned down a similar emergency request from the officials and industry groups. They want the new rules shelved while their legal challenge plays out. 

The EPA’s new rules compel existing coal and new natural gas power plants to either cut or capture 90% of their emissions by 2032. The rules are expected to reduce carbon dioxide emissions from the sector by 75% compared to a peak in 2005. The challengers say the rules would be too costly for power plants and could force them to close. 

More: CNN 

DOI Advances Clean Energy Projects on Western Public Lands

The Department of the Interior has announced that the Bureau of Land Management will advance nine solar projects on public lands. The actions follow the department’s April announcement that the BLM has permitted more than 25 GW of clean energy projects – surpassing a major milestone ahead of 2025. 

More: Department of Interior