That seemed entirely doable until those dang data centers became such an energy suck (shaking my fist like I just got caught by the Scooby Doo crew).

Google’s greenhouse gas emissions are headed in the wrong direction, fast- they’ve increased nearly 48% since 2019.

“This result was primarily due to increases in data center energy consumption and supply chain emissions,” an annual Google environmental report read. In 2023, Google’s data centers consumed about 24 terawatt hours (TWh) of electricity.

Goldman Sachs Research estimates that data center power demand will grow 160% by 2030. A single ChatGPT query uses 2.9 watt-hours of electricity, nearly 10 times as much as a classic Google search (.3 watt-hours). As consulting firm Slalom’s Tim Stafford put it recently: think before you check the Yankees score on ChatGPT.

Now Google more or less admits the uncertainty around an AI arms race for more and more computational power may make achieving such targets… difficult.

But the company that allows you to type drivel like “Boyband 90’s not NSYNC or Backstreet or 98 Degrees” and find the O-Town song you’re looking for is coming out of the corner swinging.

Google’s new renewables

This week, Google announced a 1.5 GWp solar development contract with Energix Renewables and closed on a tax equity investment with Swift Current Energy on the massive 800 MWdc Double Black Diamond project in southern Illinois.

In the first deal, Energix will supply electricity and Renewable Energy Credits (RECs) generated from its solar projects to Google and the agreement includes an option for future expansion. The parties have already signed the first two Power Purchase Agreements (PPAs) under this agreement. That’s some much-needed good news in PJM territory, as expressed by Asa (Asi) Levinger, CEO of the Energix Group.

“This joint effort with Google not only strengthens our position in the PJM market but also opens up opportunities for future expansion into other power markets, we expect to deliver the 1.5 GW in the next 2-3 years,” he said.

“There is no one-size-fits-all solution when it comes to decarbonizing our electricity grids and no one company can do it on their own. We are proud of our work with Energix Renewables to unlock new clean energy in PJM,” added Amanda Peterson Corio, Google’s global head of data center energy. “This type of collaboration is essential as we continue to progress towards our ambition to run on 24/7 carbon-free energy on every grid where we operate every hour of every day.”

Google’s tax equity financing of Double Black Diamond Solar, expected to be the largest solar project east of the Mississippi when it reaches commercial operations in early 2025, utilizes Energy Communities and domestic content adders in the Inflation Reduction Act. That project is expected to reduce regional carbon dioxide emissions by about one million tons per year.

“As we work to responsibly grow our infrastructure, we need to partner with companies like Swift Current who understand the nuances of the energy markets where we operate and can help unlock new clean energy at a rate that matches the pace and scale of demand growth on electric grids today,” said Google’s Amanda Peterson Corio, pulling double duty in the press release statement department.

Constellation NewEnergy will purchase a portion of the energy and RECs generated by Double Black Diamond Solar to serve seven big customers: The City of Chicago (O’Hare International Airport and Midway International Airport), Cook County Illinois, CVS Health, Loyola University of Chicago, PPG, State Farm, and TransUnion.

In June, Google entered into an agreement with Berkshire Hathaway electric utility NV Energy to power some of its Nevada data centers with about 115 MW of geothermal energy. A little further back in 2022, Google teamed up with ENGIE on a 100 MW PPA to provide more than 5 TWh of renewable energy from Scotland’s Moray West wind farm.

Google reports more than 7 GW of renewable energy projects worldwide, as colorfully displayed on the site tracking Google’s carbon-free energy progress.

But what about the other guys?

Google’s data center growth-driven compatriots are finding themselves in similar predicaments, and a couple of the big ones, notably Microsoft and Amazon, are amping up their commitments to renewable energy in kind.

Microsoft’s total carbon emissions have risen by nearly 30% since 2020, according to its latest Environmental Sustainability Report. That is bad news bears for a company aiming to be carbon-negative by 2030, removing more carbon from the atmosphere than Microsoft and its supply chain emits. By 2050, the company wants to have removed as much carbon as it ever emitted since it was founded in 1975.

Fittingly, this year there has been a flurry of announcements tying Microsoft to renewable energy development.

This month, Pivot Energy announced an ambitious five-year framework agreement with Microsoft to develop up to 500 megawatts (MWac) of community-scale solar energy projects across the United States between 2025 and 2029. The agreement will enable Pivot to develop approximately 150 U.S. solar projects in roughly 100 communities across 20 states. Microsoft will purchase the project Renewable Energy Credits for a 20-year term, and the first projects are expected to come online before the end of this year.

In May, Microsoft inked two 15-year PPAs with developer RWE for two new onshore wind farms in Texas with a combined capacity of 446 MW and shook hands with Canada’s Brookfield Asset Management on the largest single corporate PPA ever, agreeing to develop more than 10.5 gigawatts of new renewable energy capacity.

Microsoft is partnering with Google and Nucor Corporation to develop new business models and aggregate their demand for advanced clean electricity technologies, intending to accelerate the development of “first-of-a-kind” and early commercial projects, including advanced nuclear, next-generation geothermal, clean hydrogen, long-duration energy storage (LDES), and more.

Microsoft also recently announced a partnership with the Department of Energy’s Pacific Northwest National Laboratory (PNNL) to use high-performance computing in the cloud and artificial intelligence to accelerate scientific discovery, with an initial focus on chemistry and materials science for battery solutions.

Amazon aims to reach net-zero across its operations by 2040, co-founding The Climate Pledge in 2019 and investing more than $2 billion in support of sustainable technologies. Last year, Amazon claimed 100% of the electricity it consumed globally was matched with renewable energy, initially a 2030 goal for the company.

Some recent Amazon PPAs include a 98.4 MW wind project with Avangrid, a couple of solar farms in Ohio, one in Japan, and a 473 MW deal with ENGIE on the Moray West offshore windfarm Google signed with back in 2022.

According to BloombergNEF, in 2023 Amazon purchased more solar and wind power than the next three companies combined, announcing 74 PPAs totaling 8.8 GW of capacity. The other top PPA purchasers: Meta (3 GW), LyondellBasell Industries (1.3 GW), and the aforementioned Google (1 GW). More than 200 corporations announced PPAs in 2023, highlighting how the agreements are being used to promote decarbonization efforts, per BloombergNEF.

Is this “matching” or actual matching matching?

How much of an impact PPAs actually make is a more complex question that deserves digging into. Offsetting carbon in bulk doesn’t necessarily belay the larger impact of that carbon.

In some cases, there’s an opportunity to go beyond a PPA and more effectively decarbonize the grid through hourly load matching, or 24/7 matching, according to an analysis by RMI. RMI defines hourly load matching as “where a buyer attempts to procure sufficient carbon-free energy to match a given facility’s load in every hour.” RMI’s Clean Power by the Hour determined that costs increased with the level of hourly load matching compared to costs for meeting annual procurement targets, near-term emissions reductions for hourly load matching depend on the regional grid mix, and hourly procurement strategies can create new markets for emerging technologies.

Google has been carbon-neutral since 2007 through carbon offsets, and was one of the first companies to purchase renewable energy directly through PPAs in 2017. The company is now in the process of transitioning from 100% annual renewable energy matching to 24/7 matching as part of its 2030 goals.

Microsoft has been signing 24/7 hourly matching agreements with projects fueling its data centers, including one with Powerex Corp and another with ENGIE in Texas. 100s of global companies have signed the 24/7 Carbon-Free Energy Compact, including Google and Microsoft but notably not Amazon, which has yet to announce plans for 24/7 matching.

The assessment focuses on the viability of the council’s 2021 Power Plan resource strategy and finds implementing it — specifically achieving energy efficiency consistent with the high end of the council’s target, pursuing renewable deployment of around 6,600 MW by 2029, and ensuring sufficient balancing resources and demand response — will provide for an adequate system.

That analysis comes with a caveat, however. Pursuing the low end of the council’s energy efficiency target would not provide for an adequate system, and if data center load growth accelerates and more closely aligns with utility projections in the region by 2029, the resource strategy will be insufficient, indicates the report.

The council uses an adequacy model called GENESYS to simulate the region’s bulk power system. In each simulation (which represents one year), a simulated shortfall event occurs over a time period when load cannot be served by resources in the model. Each modeled shortfall signals that emergency measures are necessary to avoid a blackout, like expensive cost resources not in an active utility portfolio, high-priced market purchases above normal import limit (such as those that occurred during January 2024’s winter storm event), calls for conservation by government officials (as in September 2022 California heatwave), or curtailment of fish and wildlife hydro operations (as happened during the 2001 Energy Crisis).

The assessment accounts for system changes that will be implemented by 2029, including load growth, in-region resource developments, and out-of-region market fundamentals. Electric load is expected to substantially increase by 2029, thanks to data centers and electric vehicles. However, announced changes to thermal plant retirements, such as Valmy 1 & 2 and Jim Bridger 1 & 2 conversions from coal to gas fueling, and anticipated transmission expansion throughout the WECC, including Boardman-to-Hemingway in the region, appear to alleviate some of the challenges associated with the increased loads when coupled with the 2021 Plan’s resource strategy.

The Pacific Northwest’s hydroelectric system provides more than half the grid’s nameplate capacity. The region has historically had an excess of peaking capacity but continues to be limited by the water supply that powers the hydroelectric system. Due to significant increases in variable energy resources, changes in hydroelectric operating constraints, and other added complexities, the region can no longer assume that it has sufficient capacity to meet all demand; thus, it is important to include a metric to protect against excessively high-capacity shortfalls, argues the report.

From an adequacy perspective, while hydropower is slightly reduced, based on the limited subset of studies used for a comparative study, the changes do not lead to a significantly different regional adequacy result. Offsetting the reduced hydropower is a small increase in regional thermal generation and market reliance, yet within the market reliance limit, throughout most of the year, especially at night.

The 2021 Power Plan’s resource strategy recommends that between 750 and 1,000 average MW of cost-effective energy efficiency, at least 3,500 MW of renewable resources, and 720 MW of low-cost and frequently deployable demand response be acquired, as well as increasing balancing up reserve requirements to 6,000 MW to respond to growing short-term uncertainty in variable energy resources (primarily wind and solar) by 2027.

The report acknowledges other changes to the regional power system that are important to consider since the 2027 assessment, including announced thermal retirement changes of coal-to-gas conversion, expanded transmission capacity, and hydro changes from the Resilient Columbia Basin Agreement to the Lower Snake and Lower Columbia projects.

U.S. wind installations produced 45.9 gigawatt hours (GWh) of electricity in March 2024, eclipsing the 38.4 GWh generated by coal-fired power plants. The following month, coal-fired generation dropped to 37.2 GWh while wind generation blew away its previous high mark, churning out 47.7 GWh.

EIA included this lovely chart which demonstrates the steady growth of wind generation and the slow decline of our reliance on coal:

Installed wind power generating capacity has grown from 2.4 GW in 2000 to 150.1 GW in April 2024, according to the EIA. By contrast, many coal plants have retired over the past 25 years, and coal capacity has been roughly cut in half, from 315.1 GW in 2000 to 177.1 GW by April 2024. 22.3 GW of U.S. coal-fired electric generating capacity has been retired over the past two years, and operators plan to retire 2.8 GW more in 2024, data from EIA’s July Monthly Energy Review show.

Other sources of electricity generation have also increased as coal-fired generation has declined, notes the EIA. Since 2000, electricity from solar power has increased by 99.1 GWh, and generation from natural gas, which is often more price competitive than coal in electricity market dispatch, has gone up by 287.6 GWh.

And all good things, they say, never last

Wind power typically produces the most electricity in the springtime in the United States, so it’s not likely wind will permanently remain ahead of coal generation (at least not yet). During the first four months of 2024, coal-fired generation was 15% greater than wind generation in the United States.

You may recall something like this happening last year- when U.S. wind generation exceeded coal-fired generation for the first time in April 2023. It took 11 months later for that to happen again. But if you’re searching for silver linings, this spring marks the first time U.S. wind generation has exceeded coal-fired generation for two months in a row.

And there’s more capacity on the way. Operators expect 7.1 GW of wind capacity to come online in the United States in 2024, according to EIA’s July Monthly Energy Review. That’s a substantial amount, albeit a far cry from the 14 GW+ added in both 2020 and 2021, which were record years for growth in the industry.

And finally- a parting gift for those who either didn’t get the headline or understood the reference and now have that Prince slow jam stuck in their heads:

The U.S. Department of Energy (DOE) has announced it will enter into realty negotiations with Hecate Energy for a solar project capable of delivering up to 1 gigawatt of clean energy within an 8,000-acre area of the former nuclear weapons production site.

The Hanford site, established in 1943 as part of the Manhattan Project to produce plutonium for national defense, made materials for the Trinity Test and atomic bombs used to help end World War II. Weapons construction at Hanford contaminated the site and created millions of gallons of radioactive waste.

The project is planned for DOE-owned land at the Hanford Site as part of the Cleanup to Clean Energy initiative, which aims to repurpose parts of DOE-owned grounds— portions of which were previously used in the nation’s nuclear weapons program — to support the growth of clean energy in the U.S.

Hecate Energy will have the opportunity to negotiate a realty agreement for the development of a gigawatt-scale solar photovoltaic system with battery storage. The selection was made through a competitive qualifications-based process for evaluating and ranking proposals. It comes after public comments on a request for information in August 2023, a Cleanup to Clean Energy Information Day at Hanford in September 2023, and a request for qualifications issued in March 2024.

Since announcing the Cleanup to Clean Energy initiative in July 2023, DOE has announced the selection of developers for carbon pollution-free electricity projects in Idaho, Nevada, South Carolina, and now in Washington state. Home to the Hanford Site, Pacific Northwest National Laboratory, a vibrant community, and tribal nations, this part of Washington has been critical to the nation for decades and is well-positioned to become a center of carbon-free power solutions.

Nuclear reactors at the Hanford site began to be decommissioned in the 1960s, with others later placed on standby after it was determined that a sufficient amount of weapons-grade plutonium had been produced. 53 million gallons of liquid radioactive waste, 25 million cubic feet of solid radioactive waste, and contaminated groundwater remained after operations slowed down. Cleanup operations began in the 1980s and are still ongoing, with focuses on restoring the nearby Columbia River corridor, converting a section of the land for long-term waste treatment and storage, and future-proofing the site.

Hecate Energy recently made news by submitting an unsolicited lease to the Bureau of Ocean Energy Management (BOEM) to acquire commercial offshore wind energy lease(s) on the Outer Continental Shelf (OCS) in the Gulf of Mexico. In response, BOEM is seeking information regarding whether competitive interest exists in the areas included in Hecate Energy’s request.

PJM Interconnection, the largest electrical grid operator in the United States, held its annual power market auction Tuesday, and the results are staggering.

The auction produced a price of $269.92/MW-day for most of the PJM footprint, compared to $28.92/MW-day for the 2024/2025 auction. Capacity auction prices fluctuate annually based on the need for investment in generation resources, but a more than 800% increase will have a massive ripple effect across PJM’s 13-state footprint.

“PJM’s capacity auction has competitively secured resources to meet the RTO reliability requirement for the 2025/2026 Delivery Year,” reads PJM’s press release. That is a true statement, I suppose.

The auction secured 135,684 megawatts for the period from June 1, 2025, through May 31, 2026. The power mix from generators included 48% gas, 21% nuclear, 18% of coal, 1% of solar, 1% of wind, 4% of hydro, 5% of demand response, and 2% from other resources, PJM said. The total Fixed Resource Requirement (FRR) obligation is an additional 10,886 MW for a total of 146,570 MW. The total procured capacity in the auction and resource commitments under FRR represents an 18.5% reserve margin, compared to a 20.4% reserve margin for the 2024/2025 Delivery Year.

“The significantly higher prices in this auction confirm our concerns that the supply/demand balance is tightening,” PJM CEO Manu Asthana said. “The market is sending a price signal that should incent investment in resources.”

How did we get here?

The short explanation behind the price hikes: supply and demand. A longer line of reasoning includes insufficient future transmission planning, the retirement of fossil fuel generation, long interconnection queues, and the implementation of FERC-approved market reforms.

According to PJM, the drivers of higher prices in this auction include:

• Decreased supply offers into the auction due mainly to generator retirements
• Increase in projected peak load
• FERC-approved market reforms, including improved reliability risk modeling for extreme weather and accreditation that more accurately values each resource’s contribution to reliability

National trade association Advanced Energy United points out PJM scored a “D-” in a recent scorecard of how all grid operators are managing “generator interconnection,” the process of connecting energy projects to the power grid. PJM’s interconnection process was going so poorly it shut down its interconnection queue until sometime in 2025. Hundreds of projects are still stuck waiting in line. A 2023 report from Americans for a Clean Energy Grid graded PJM a “D” for its process of building new transmission lines, which are needed to connect energy projects to population centers.

“Electricity prices are skyrocketing because the grid operator PJM is failing to plan for the kind of energy infrastructure we need to affordably keep the lights on,” said Jon Gordon, Director at Advanced Energy United. “PJM didn’t prepare for an energy transition we all saw coming, and now consumers are going to pay the price.”

“PJM fell behind on interconnection and long-term transmission planning years ago, and now the problems are just cascading and piling up,” added Gordon, who leads United’s engagement with PJM. “With transmission planning improvements on the docket and further interconnection reforms urgently needed, these auction results should send a clear message that change can’t come too soon.”

Is change coming?

The price increase within PJM’s service territory is set to take effect in June 2025. Capacity prices are one component of wholesale costs that ultimately get factored into the price paid by end-use customers; electric bills also reflect the cost of other wholesale services like energy and transmission, as well as distribution services, state programs, and other fees.

The total amount of supply resources in the auction decreased again this year, continuing a trend across recent auctions and underlining PJM’s stated concerns about generation resources facing pressure to retire without replacement capacity being built quickly enough to replace them. About 6,600 MW of generation have retired or have must-offer exceptions (signaling intent to retire), compared to generators which offered in the 2024/2025 Base Residual Auction (BRA).

Meanwhile, the peak load forecast for the 2025/2026 Delivery Year has increased from 150,640 MW for the 2024/2025 BRA to 153,883 MW for the 2025/2026 Delivery Year. Additionally, FERC-approved market reforms contributed to tightening the supply and demand balance by better estimating the impact of extreme weather on load and more accurately determining resource reliability value.

These reliability concerns associated with reducing supply and increasing demand are not limited to PJM; the North American Electric Reliability Corporation has identified elevated risk to the reliability of the electrical grid for much of the country outside of PJM.

To facilitate the entry of new resources, PJM is implementing its FERC-approved generation interconnection reform, with approximately 72,000 MW of resources expected to be processed in 2024 and 2025. However, PJM remains concerned with the slow pace of new generation construction. Approximately 38,000 MW of resources currently have already cleared PJM’s interconnection queue but have not been built due to external challenges, including financing, supply chain, and siting/permitting issues.

“Interconnection process reform is proceeding, but hurdles remain for many projects outside of our process,” said Stu Bresler, executive vice president of market services and strategy. “We are considering ways to accelerate those who can successfully overcome those challenges and build.”

Auctions are usually held three years in advance of the delivery year. The 2025/2026 auction was originally scheduled to be held in May 2022, but auctions had been suspended while FERC considered approval of new capacity market rules. PJM has compressed its auction calendar to return to a three-year-forward basis. The next BRA, for the 2026/2027 Delivery Year, is currently scheduled for December 2024.

A detailed report of the auction is available on PJM’s capacity market page.

“Battery storage is a key element to building a green economy here in New York, and we have taken comprehensive efforts to ensure the proper safety standards are in place,” Governor Hochul said. “With updating fire codes, we’re ensuring that New York’s clean energy transition is done safely and responsibly.”

Governor Hochul convened the Working Group in 2023 to ensure the safety and security of energy storage systems, following fire incidents at facilities in Jefferson, Orange, and Suffolk Counties. The Working Group was tasked with independently examining energy storage facility fires and safety standards and creating a draft fire code Recommendations Report.

Proposed recommendations include:

• Requiring industry-funded independent peer reviews for all BESS installations exceeding energy capacity thresholds established for lithium-ion batteries;
• Requiring that qualified personnel or representatives with knowledge of the BESS installation are available for dispatch within 15 minutes and able to arrive on scene within four hours to provide support to local emergency responders in the event of a BESS fire.
• Extending safety signage requirements beyond the BESS unit itself to include perimeter fences or security barriers and include a map of the site, BESS enclosures, and associated equipment.
• Removing the fire code exemption for BESS projects owned or operated by electrical utilities to ensure that all projects comply with the fire code.
• Including a requirement that every BESS facility is equipped with an Emergency Response Plan (ERP) and site-specific training to be offered for local fire departments to familiarize them with the project, hazards associated with BESS, and procedures outlined in the ERP.
• Including a fire code requirement in all BESS installations for monitoring of fire detection systems by a central station service alarm system to ensure timely, proper notification to the local fire department in the event of a fire alarm.
• Introducing a new provision in the fire code mandating regular industry-funded special inspections for BESS installations to ensure thorough safety and compliance.

“Lithium-ion batteries and energy storage facilities play a large role in New York’s work toward achieving our clean energy goals,” said Secretary of State Walter T. Mosley. “Governor Hochul recognized the importance of putting the proper safety standards in place for this new, but critical, technology, and this draft language based on recommendations from the Governor’s Working Group will help ensure the safe operation of these facilities into the future.”

15 draft recommendations were proposed by the working group after examining existing FCNYS and other energy storage fire safety standards. The group previously released initial data finding no reported injuries nor harmful levels of toxins detected following fires at battery energy storage systems in Jefferson, Orange, and Suffolk Counties last summer.

It’s a question Texas is being forced to address amidst a miserable month for wind generation, but the initial answer lends a promising prognosis to ratepayers. So far, electricity prices have remained stable despite nearly one-quarter of ERCOT’s generation profile being hampered by Mother Nature.

According to preliminary data from the U.S. Energy Information Administration (EIA), wind power in the contiguous United States produced only 302,615 megawatt hours (MWh) on Tuesday, July 23. That’s the lowest amount since… The day before, when wind power produced 335,753 MWh. Six of the 10 worst days for wind power this year have been this month (July), but previous to this week’s abysmal totals, there hadn’t been a comparably bad day since October 4, 2021.

Wind farms are on track to produce an average of just 4% of power generation this week, down from 7% last week and 12% so far in 2024, per the EIA.

So how are electricity prices fairing in ERCOT territory, which counts on wind for 28% of its fuel mix in Q2 2024? Well…

Is anyone else surprised that Texas (ERCOT) can now have very boring price days MID SUMMER when wind output is sub 200 MW

I shouldn't be, the solar obviously was going to compliment a wind profile, but this is a paradigm shift in terms of price forecasting. pic.twitter.com/SgcunfUo3b

— Andrew Gelston (@agelston) July 24, 2024

“A paradigm shift in terms of price forecasting” may sound strong, but “boring days” are far better than blackouts. Boring days are welcomed in any territory, especially during the heat of summer.

Of course, ERCOT isn’t relying entirely on renewables to keep electricity prices in check- far from it. In the lower 48, gas-fired power plants are producing an average of 48% of generation this week, up from 46% last week, according to the EIA. U.S. plants generated 6.9 million MWh of electricity from natural gas in the lower 48 states on July 9, 2024, probably the most on any day in history, says the EIA.

Texas has generally lingered between 30,000 and 40,000 MWh of natural gas generation over the last week.

The stable pricing is not just ERCOT passing gas, though (sorry, had to).

ERCOT’s commitment to diversifying its fuel mix deserves recognition, as energy research scientist Joshua D. Rhodes points out:

Updated (through Q2 2024) ERCOT fuel mix shows solar's rapid growth and that ERCOT has run on about 47% clean electricity for the first half of 2024!

Fun fact: it looks like solar is growing about twice as fast as wind did; wind: 2%->10% in 7 years, solar: 2%->10% in 4 years. pic.twitter.com/1HlTabNyDy

— Joshua D. Rhodes (@joshdr83) July 24, 2024

Rhodes’ graph makes it easy to see how rapidly solar and wind are driving coal (and to a lesser extent, natural gas) out of the fuel mix. The fact that solar is expanding nearly twice as quickly as wind generation did in Texas is likely a testament to the success of the IRA and to the staying power of the industry (and all that land fit for utility-scale installations) .

In totality, the data indicates we may have reached a tipping point- hopefully, one that keeps electricity prices stable.

Here are some of the highlights:

• Shortens judicial review timelines before, during, and after litigation on all types of federal authorizations for energy and mineral projects; Sets a 150-day statute of limitations from the final date of agency action on a project, requires expedited review of legal challenges, and sets a 180-day deadline for federal agencies to act.

• Sets a new goal to authorize 50 GW of renewable energy on federal land by 2030. Adds energy storage as an eligible project under Section 3101 of the Energy Act of 2020, including it in the scope of the Renewable Energy Coordination Office (RECO) programs.

• Accelerates leasing and permitting decisions on federal lands without bypassing environmental and land-use laws. Sets deadlines and doubles production targets for renewable energy permitting on federal lands. Streamlines environmental reviews for low-disturbance renewable, electric grid, and storage projects, modernizes geothermal leasing and permitting processes, and more.

• Requires the Secretary of the Interior to hold at least one offshore wind lease sale and one offshore oil and gas lease sale per year from 2025 through 2029, subject to minimum acreage requirements, without bypassing environmental reviews. At least 400,000 acres must be offered per year in sales. and the Secretary must establish a national goal of 30 GW for offshore wind energy production, set a target for achieving that goal, and periodically revise it as necessary.

• Reforms existing backstop siting authority for interstate electric transmission lines and requires interregional transmission planning. For more on the bill’s impact on electric transmission, check out John Engel’s write-up on POWERGRID International.

• Requires FERC and NERC to assess future federal regulations significantly affecting power plants, and offer formal comments to federal agencies on reliability. If FERC determines a rule, regulation, or standard proposed by another agency is likely to result in a violation of a mandatory electric reliability standard or resource adequacy requirement or process on file with FERC, NERC is required to conduct an assessment and report back to FERC.

• Allows FERC to extend start-construction deadlines for certain existing hydropower licenses by four additional years.

You can peruse a section-by-section breakdown of the bill here.

Reaction to the legislation

“It has long been too difficult to build some of the critical energy infrastructure America needs, and this bipartisan proposal provides a good foundation on which to build a comprehensive package of legislative reforms,” said Harry Godfrey, managing director of the national trade association Advanced Energy United. “Both parties agree that unreasonable timetables and fragmented planning processes are making it too difficult to invest and build, providing Congress a unique opportunity to pass legislation that unlocks America’s innovative industries and improves grid reliability and energy costs for households and businesses.”

“The United States of America is blessed with abundant natural resources that have powered our nation to greatness and allow us to help our friends and allies around the world,” said Chairman Manchin. “Unfortunately, today our outdated permitting system is stifling our economic growth, geopolitical strength, and ability to reduce emissions. After over a year of holding hearings in the Senate Energy and Natural Resources Committee, thoughtfully considering input from our colleagues on both sides of the aisle, and engaging in good faith negotiations, Ranking Member Barrasso and I have put together a commonsense, bipartisan piece of legislation that will speed up permitting and provide more certainty for all types of energy and mineral projects without bypassing important protections for our environment and impacted communities. The Energy Permitting Reform Act will advance American energy once again to bring down prices, create domestic jobs, and allow us to continue in our role as a global energy leader. The time to act on it is now.”

“For far too long, Washington’s disastrous permitting system has shackled American energy production and punished families in Wyoming and across our country. Congress must step in and fix this process,” added Ranking Member Barrasso. “Our bipartisan bill secures future access to oil and gas resources on federal lands and waters. We fix the disastrous Rosemont decision so that we can produce more American minerals instead of relying on China. We permanently end President Biden’s reckless ban on natural gas exports. And we ensure we can strengthen our electric grid while protecting customers. This legislation is an urgent and important first step towards improving our nation’s broken permitting process.”

On Friday, the CPUC proposed an initial need determination of up to 7.6 GW of offshore wind, up to 1 GW of enhanced geothermal systems, up to 1 GW of multi-day long-duration energy storage (LDES), and up to 1 GW of LDES with a discharge period of at least 12 hours.

This proposal stems from provisions of Assembly Bill 1373 (Stats. 2023, Ch.367), signed by Governor Gavin Newsom in 2023. AB 1373 authorizes the CPUC to request that the Department of Water Resources (DWR) conduct centralized procurement of certain eligible long lead-time (LLT) resources on behalf of customers of all load-serving entities (LSEs) under the Commission’s integrated resource planning (IRP) purview. Those long lead-time resources include offshore wind.

The plan will be heard, at the earliest, at the Commission’s meeting on August 22, 2024. By September 1, the Commission is required to make an initial need determination for procurement using a centralized procurement mechanism. If a need is found, within six months the Commission may then request DWR to exercise the centralized procurement mechanism.

The amounts selected are maximum amounts, according to the CPUC. Once a procurement request is made, DWR will conduct solicitations and evaluate the quality of bids received, including costs and ratepayer risk provisions, and may procure anywhere between zero and the upper limits included in this decision. This flexibility will facilitate cost containment and minimize ratepayer risks.

The resources selected by CPUC will help California achieve its greenhouse gas (GHG) emissions reduction goals for 2045 and represent emerging technologies that need to achieve economies of scale to bring costs down, the Commission says. However, the cost of these investments will ultimately impact electricity bills. In its proposal, CPUC maintains all possible efforts should be made to contain costs, reduce ratepayer risk, and seek other sources of funding to reduce development costs and share in the long-term costs and benefits.

This proposal also requests that, for this LLT procurement, DWR convene a procurement group that includes representatives from LSEs. In addition, the decision sets a tentative schedule of solicitations, asking DWR to conduct two rounds of solicitations for LDES and EGS, beginning in 2026, and three rounds of solicitations for OSW beginning in 2027. The Commission will reevaluate the need determination for additional LLT resources in every IRP cycle when considering a Preferred System Plan portfolio. In the next IRP cycle, the Commission will specifically evaluate LSE progress toward LLT procurement requirements in D.21-06-035, and consider whether an additional need determination for conventional geothermal resources for CPE procurement is necessary.

Earlier this month, the California Energy Commission (CEC) adopted a comprehensive strategic plan guiding the development of offshore wind. The plan outlines analysis and strategies to deploy floating turbines off the state’s central and northern coasts with a goal of 25,000 MW of capacity by 2045, enough to power 25 million homes. There are nearly 35 GW of renewable resources on California’s grid today, but the state is believed to need an additional 148 GW to reach its 2045 goal, likely requiring ocean development.

The battery energy storage system (BESS) will have a 20-year guaranteed capacity of 25 megawatts (MW) and 100 megawatt-hours (MWh). A 25-year tolling agreement positions Ameresco as the asset owner and Snohomish PUD as the exclusive customer of the project. It allows Ameresco to provide Snohomish PUD the flexibility to utilize the battery energy storage system for charging and discharging activities under the agreement.

“This project represents a paradigm shift in the Pacific Northwest energy industry,” said Nicole Bulgarino, executive vice president at Ameresco. “By collaborating with Snohomish PUD, we are pioneering a unique model where the owner and the customer are distinct entities, showcasing the versatility and scalability of utility-scale storage solutions.”

Ameresco says the BESS will provide the PUD with enhanced electrical system reliability and flexibility while reducing exposure to energy price volatility.

“We’re excited to work with Ameresco on making this new battery energy storage project a reality,” stated John Haarlow, Snohomish PUD CEO/General Manager. “Energy storage is a critical component to helping us keep the grid reliable and affordable while also meeting our clean energy goals.”

Construction is expected to begin in late 2024 and the BESS could be operational in late 2025.

The largest non-standalone BESS project in the Northwest is located at Wheatridge Renewable Energy Facility (30 MW, 60 MWh) in Morrow County, Oregon. That site features first-of-its-kind wind, solar, and storage co-location.