The solar and battery storage system will help match the electricity consumed by Google’s forthcoming data center campus in Mesa, Arizona. Energy not needed by the data center will be used to meet other SRP customer needs.

Also supporting Google is the newly developed Storey Energy Center, an 88-MW solar and battery storage system, located in Coolidge, Arizona. Both facilities are operated by subsidiaries of NextEra Energy Resources. SRP and NextEra Energy Resources’ under-development wind facility, Babbitt Ranch Energy Center, will also support Google. This is a 161-MW wind project, on Babbitt Ranches property in Coconino County, north of Flagstaff.

Google is pursuing net-zero emissions across its operations and value chain by 2030, supported by a goal to run its data centers and office campuses on 24/7 carbon-free energy. The Sonoran, Storey, and Babbitt Ranch projects contribute to these commitments by supporting the energy needs of Google’s future data center in Mesa, which the company announced in 2023 with plans to use air-cooled technology.

“We’re aiming for every Google campus to operate on clean electricity every hour of every day by 2030, including in Arizona where we are excited to put down roots with our first data center in the state currently under construction,” said Amanda Peterson Corio, Global Head of Data Center Energy, Google. “The collaboration with Salt River Project and NextEra is accelerating decarbonization in Arizona and our own carbon-free journey in the region.”          

Through its Integrated System Plan, SRP found it will need to at least double the number of power resources on its power system in the next 10 years as it completes the planned retirement of 2,600 MW of coal resources, and amid growing energy demand.

“These renewable energy centers will generate low-cost, homegrown energy and provide millions of dollars in additional revenue to both Maricopa and Pinal counties over the life of the projects,” said Anthony Pedroni, Vice President of Renewables and Storage Development at NextEra Energy Resources. “We are pleased to work with SRP and Google to bring online Arizona’s newest renewable energy centers.”  

Originally published in Renewable Energy World.

(THE CONVERSATION) During the most recent total solar eclipse visible in the U.S., on Aug. 21, 2017, the skies darkened as the Moon crossed in front of the Sun. It blocked out all sunlight – except for that from a golden ring visible around the Moon’s shape, called the corona. Not surprisingly, solar power generation across North America plummeted for several hours, from the first moment the Moon began to obscure the Sun to when the Sun’s disk was clear again.

On April 8, 2024, another total solar eclipse will track across the U.S., causing perhaps an even greater loss of solar power generation. Although this will be the second total solar eclipse visible in the U.S. in under seven years, these events are a rare occurrence. Nevertheless, they present a unique challenge to power grid operators.

I am a space scientist with a passion for teaching physics and astronomy. Though I have seen many partial eclipses of the Sun, I have yet to witness a total solar eclipse. My road trip to Bryce Canyon National Park in Utah in October 2023 to see the “ring of fire” annular solar eclipse was unforgettable, and April 8 will surely find me handing out eclipse glasses once again.

When the Moon’s shadow blocks the Sun

During a solar eclipse, the Moon partially or completely blocks the view of the Sun. Since the Moon is nearly 400 times smaller than the Sun and nearly 400 times closer, the Moon’s shadow, visible from Earth, tapers to a width of 70 to 100 miles (112 to 161 kilometers).

Within this region, called the path of totality, observers see a total solar eclipse. Observers close to but outside this path witness a partial eclipse of the Sun, where the Moon covers a fraction of the Sun’s disk.

During the April 8, 2024, total solar eclipse, the path of totality in the continental U.S. will extend from Texas in the south to Maine in the northeast. Elsewhere in the U.S., Miami will see a partial eclipse in which a maximum of 46% of the Sun’s disk obscured. In Seattle, far from the path of totality, the Moon will cover only a maximum of 20% of the Sun. In southern Texas, where the path of totality first crosses into the U.S., the eclipse will last just under three hours, with totality a mere 4 minutes and 27 seconds.

Increasing reliance on solar power

The worldwide trend toward renewable energy has seen a significant increase in solar, or photovoltaic, power generation in the last decade. Solar power generation capacity is set to double worldwide between 2022 and 2028, and the U.S. now has the capacity to generate three times more solar energy than at the time of the 2017 total solar eclipse.

The most obvious obstacle to solar power generation is cloud cover. On a cloudy day, the energy produced by solar panels drops to 10% to 25% of its output on a sunny day.

The North American power transmission grid is divided into six major regions and more than 150 local and regional subgrids. Electrical system operators in each local grid continuously balance the amount of electricity production with the “load,” or the demand for electricity by consumers.

System operators can tap into energy from various power generation mechanisms like solar, wind, hydroelectric, natural gas and coal. Local grids can also import and export electricity to and from their grid as needed.

System operators have accurate models for the amount of solar power generated across the U.S. on a daily basis, and these models account for the parts of the continental U.S. that may have cloudy skies. By pairing solar power generation with battery storage, they can access electricity from solar even when the Sun isn’t shining – on cloudy days or at night.

To plan for an eclipse, electrical system operators need to figure out how much the energy production will drop and how much power people will draw from the reserves. On the day of the 2017 total solar eclipse, for example, solar power generation in the U.S. dropped 25% below average.

Because solar power production falls quickly during the eclipse’s peak, grid operators may need to tap into reserves at a rate that may strain the electrical transmission lines. To try to keep things running smoothly, grid operators will rely on local reserves and minimize power transfer between grids during the event. This should lessen the burden on transmission lines in local grids and prevent temporary blackouts.

Renewable energy during eclipses

Solar isn’t the only type of renewable energy generation that goes down during an eclipse. Since it’s not as sunny, temperatures along the path of the eclipse fall by as much as 10 degrees Fahrenheit (5.5 degrees Celsius). Lower temperatures lead to slower wind speeds and less wind power generation.

During the August 2017 eclipse, the loss of renewable power generation added up to nearly 6 gigawatts. That’s equivalent to the energy usage of 600 million LED lightbulbs or 4.5 million homes.

Grid operators compensated by planning ahead and increasing power generation at natural gas and coal-powered plants, which don’t depend on sunlight.

Over the duration of the eclipse, this increase in nonrenewable energy use led to approximately 10 million pounds of extra carbon dioxide emissions. That’s about the annual carbon dioxide emissions of 1,000 cars.

On April 8, eyes across the U.S. will turn upward to catch a glimpse of the eclipsed Sun.

Thanks to the vigilance of electric grid operators, the lights should stay on, and observers won’t have to worry about anything but the stunning show in the sky.

The Inflation Reduction Act created two new credit delivery mechanisms—elective pay (or direct pay) and transferability—that are meant to help enable state, local, and Tribal governments; non-profit organizations; Puerto Rico and other U.S. territories; and other entities to take advantage of clean energy tax credits.

Until the Inflation Reduction Act introduced these new credit delivery mechanisms, governments, many types of tax-exempt organizations, and some businesses could not fully benefit from tax credits like those that incentivize clean energy deployment.  

“The Inflation Reduction Act’s new tools to access clean energy tax credits are a catalyst for meeting President Biden’s historic economic and climate goals,” said Secretary of the Treasury Janet L. Yellen. “They are acting as a force multiplier, bringing governments and nonprofits to the table for the first time and enabling companies to realize greater value from incentives to deploy new clean power and manufacture clean energy components. More clean energy projects are being built quickly and affordably, and more communities are benefitting from the growth of the clean energy economy.”

The Inflation Reduction Act allows tax-exempt and governmental entities to receive elective payments for 12 clean energy tax credits, including the major Investment and Production Tax (45 and 48) credits, as well as tax credits for electric vehicles and charging stations. Businesses can also choose elective pay for three of those credits: the credits for Advanced Manufacturing (45X), Carbon Oxide Sequestration (45Q), and Clean Hydrogen (45V). 

The Inflation Reduction Act also allows businesses to transfer all or a portion of any of 11 clean energy credits to a third party in exchange for tax-free immediate funds, so that businesses can take advantage of tax incentives if they do not have sufficient tax liability to fully utilize the credits themselves. Entities without sufficient tax liability were previously unable to realize the full value of credits, leaving only corporations able to take advantage of federal tax incentives. Final rules on transferability will be finalized in the near future.

Treasury’s elective pay final rules are intended to provide certainty for applicable entities to understand the law’s scope and requirements for eligibility. The final rules also lay out the process and timeline to claim and receive an elective payment.

Along with final rules on elective pay, Treasury today also issued a separate Notice of Proposed Rulemaking (NPRM) that is intended to provide further clarity and flexibility for applicable entities that that co-own clean energy projects and would like to utilize elective pay.

Under the IRA, entities treated as partnerships for federal tax purposes are not eligible for elective pay, regardless of whether one or more of its partners is an applicable entity. However, the proposed elective pay regulations clarified, and the final regulations confirm, that there are pathways for an applicable entity to access elective pay for credits it earns through a joint ownership arrangement including validly “electing out” of partnership tax treatment. Treasury and IRS agreed with commenters that existing guidance on making a valid election out of partnership tax treatment for clean energy arrangements was limited, and updates were needed for these arrangements to be more effective.

The section 761(a) NPRM issued provides a broader and more accessible pathway for applicable entities that co-own renewable energy projects to elect out of partnership tax status and therefore access elective pay. To qualify under these proposed rules, co-ownership arrangements must be organized exclusively to produce electricity from their applicable credit property, have one or more applicable entity co-owners that will claim elective pay, and meet certain other requirements.

Specifically, these proposed regulations would:

• Permit renewable energy investments to be made through a noncorporate entity, rather than requiring direct co-ownership of the property or facility by the applicable entity;
• Modify certain joint marketing restrictions to provide that multi-year power purchase agreements would not violate the requirements to elect out of partnership tax treatment.

This article was originally published on Renewable Energy World.

This order allows NV Energy to move forward with ceasing coal operations at North Valmy Generating Station and transition to a natural gas-fired plant by the end of 2025. North Valmy is the company’s final coal plant in its portfolio. The two-unit, 522 MW facility is jointly owned by NV Energy and Idaho Power.

Unit 1, which went into service in 1981, produces 254 MW with a Babcock & Wilcox Boiler and Westinghouse turbine/generator. Unit 2 came online in 1985 and generates 268 MW with a Foster Wheeler Boiler and GE turbine/generator. Coal for the plant is shipped via railroad from various mines in Utah, Wyoming and Colorado.

PUCN also approved NV Energy’s plan to build additional transmission infrastructure to support continued growth in the state, including in the Apex area in the city of North Las Vegas – a growing center of economic development in Southern Nevada.

NV Energy also received conditional approval to begin developing the Sierra Solar project, a 400 MW solar site with a four-hour battery storage system in Northern Nevada.

While regulators approved the project, they expressed concern about its cost and said there would need to be ratepayer protections in the case of cost overruns.

The commission capped Sierra Solar’s construction costs at $1.5 billion and said NV Energy would need to pay credits to customers if the project doesn’t meet its completion goal of April 2027. Sierra Solar would be “the most expensive project ever proposed to be built or owned by NV Energy.”

The state of Nevada is aiming for a renewable portfolio of 50% by 2030 and 100% by 2050.

The floating PV array was built row-by-row over the retention pond behind Orange County’s Southern Regional Water Supply Facility. The 1.2 MW project powers the county facility.

“What you’re looking at here is the largest floating solar array in the Southeast U.S.,” said Tchividjian. “It directly offsets the consumption of the water plant.”

More than 40 DISTRIBUTECH International attendees got an up-close at the project, which in total includes just over 2,000 solar panels. There are 66 anchors all the way around the manmade pond to secure the array in place.

“What we do when we design the anchoring system is think of like a mooring system for a boat,” Tchividjian told attendees. “You take into account the highest water level possible and then the lowest water flow possible. And then you have enough slack in those mooring lines for that array to be able to rise and fall.”

D3Energy, which is exclusively a floating solar developer, built the project last year. Tchividjian believes floating solar has a “great story.”

One drawback of ground-mounted solar is it needs a lot of space, with proposed projects often receiving pushback from neighbors. Tchividjian said that makes floating solar a great alternative.

“When you start looking at places like Orlando or urban areas, the idea of finding a lot of space to put solar becomes more and more difficult,” he said. “This idea of utilizing bodies of water we have to deploy solar has really become an appeal.”

While floating solar is generally more expensive to build than its ground-mounted cousin, Tchividjian said the benefits include lower O&M costs.

For one, hardly any vegetation management is required. Because the panels are out on the water, they are also naturally staying cleaner compared to a grass field, where soiling is more a concern.

Tchividjian said crews only need to access the PV system at the water supply facility for maintenance once or twice a year.

“Very little love and care is required for these systems, which we’ve seen as a big plus for them,” he said.

Tchividjian added that because the panels are so close to the water, they stay a lot cooler than roof or ground-mounted systems would. Because of that cooling effect, he said the panels are more efficient and produce more power.

DTE is issuing a Request for Proposal (RFP) for approximately 1,075 MW of new wind and solar projects to achieve commercial operation by March 31, 2027. Proposed projects must be located in Michigan and interconnected to the Midcontinent Independent System Operator (MISO) or distribution level transmission.

DTE’s renewable energy portfolio currently includes 20 wind parks and 33 solar parks. The company plans to add 1,000 MW of new wind and solar each year starting in 2026. By 2042, DTE expects to possess more than 15,000 MW of renewable energy generation capacity.

Originally published by Renewable Energy World.

In 2023, New England had nearly 400 dispatchable generators and about 30,700 MW of generating capability, with 99.3% of electricity provided by natural gas, nuclear, hydropower, and imported electricity (mostly in the form of hydropower from Eastern Canada) and renewables. About 40,000 MW of new capacity is proposed to be built, the report said, and more than 7,000 MW of generation have retired since 2013 or may retire in the next few years, composed of mostly coal-fired, oil-fired and nuclear power plants. The region’s remaining two zero-carbon-emitting nuclear facilities, Millstone and Seabrook, supply a quarter of the electricity New England consumes in a year.

New England also had about 3,800 MW of of demand capacity resources (DCRs) and about 350,000 distributed solar power installations totaling 6,500 MW, with most installed behind the meter.

This number was calculated by adding total electricity generation and price-responsive demand reduction within New England to net imports from and exports to neighboring regions. The energy used to operate pumped storage power plants is then subtracted from that sum. Numbers are preliminary, pending the resettlement process.

Output from solar installations increased by 6% from 2022, rising to 3,851 GWh or 3% of the NEL. Wind power was relatively steady from year to year at 3% of NEL.

Oil-fired resources produced less electricity in 2023 than in 2022, accounting for 322 GWh, or 0.32% of the NEL, compared to the previous year’s 1,844 GWh. Production from coal-fired resources decreased from 320 GWh to 182 GWh, accounting for .16% of NEL for 2023.

All six New England states have renewable portfolio standards, which require electricity suppliers to provide customers with increasing percentages of renewable energy, ISO-NE said. Because large-scale renewable resources typically have higher up-front capital costs and different financing opportunities than more conventional resources, they have had difficulty competing in the wholesale markets. Therefore, the New England states are promoting, at varying levels and speed, the development of specific clean-energy resources to meet their public policy goals.

Several states have established public policies that direct electric power companies to enter into ratepayer-funded, long-term contracts for large-scale carbon-free energy that would cover most, if not all, of the resource’s costs.

About 97% of resources currently proposed for the region are grid-scale wind, solar and battery projects. As of January 2024, about 40,000 MW have been proposed in the ISO New England Interconnection Request Queue.

Energy storage represented 46% of the projects in the Interconnection Request Queue as of January 2024, and solar power accounted for 10%. Most solar power in New England is connected behind the meter directly at retail customer sites. Because such projects do not follow the ISO interconnection process, they aren’t reflected in the Interconnection Request Queue numbers.

The region had a total of about 350,000 distributed solar power installations as of December 2023 with a combined nameplate generating capability of approximately 6,500 MW. 

The facility broke ground January 18 and is expected to be operational by April, 2025. It will provide Arizona Public Service (APS) customers with energy, support increased power demand, and will also store energy from solar power plants on its grid to use when it is needed, particularly in the summertime when extreme heat and electricity demand is high in Arizona. In May 2023, Strata forged a 20-year tolling agreement with APS.

“The successful financing for the Scatter Wash battery storage complex marks a significant step forward in our mission to drive the transition to clean energy,” said Markus Wilhelm, Chief Executive Officer of Strata Clean Energy. “This opportunity to collaborate with our financing partners to bring this critical project to fruition will create a lasting, sustainable impact on a region that struggles with grid challenges and extreme heat.”

The development of Scatter Wash is supported by the Investment Tax Credit (ITC) for standalone energy storage created by the Inflation Reduction Act (IRA) of 2022. Last year, Strata was one of the first to take advantage of the tax incentive for energy storage for two projects in Vermont.

Strata has more than 270 solar and storage projects completed, per the company, and it has been involved in the development and construction of 3,000 MW of solar energy and 3,200 MWh of utility-scale energy storage. Its current development pipeline contains 8,400 MW of solar capacity and 31,800 MWh of storage.

J.P. Morgan and Nomura acted as coordinating lead arrangers and joint bookrunners. J.P. Morgan also fulfilled roles as administrative agent, depositary agent, and collateral agent. The financing was further supported by U.S. Bancorp Impact Finance and CoBank as coordinating lead arrangers with the Korea Development Bank and Norddeutsche Landesbank as joint lead arrangers. Furthermore, Siemens and Regions contributed as lenders in this transformative project, and U.S. Bancorp Impact Finance was also the primary tax equity investor.

Originally published in Renewable Energy World.

The site is a public-private partnership with the U.S. Air Force, located on a mixture of private land and land belonging to Edwards Air Force base – making it the largest public-private collaboration in the history of the U.S. Department of Defense. The site supplies power to the city of San Jose, Southern California Edison, Pacific Gas & Electric Co., the Clean Power Alliance, and Starbucks, among others.

The 4,660-acre project, developed by Terra-Gen and constructed by Mortenson, began construction in early 2021, with “substantial completion” reported last year. Construction efforts included installing over 98 miles of MV Wire, over 361 miles of DC Wire, 120,720 LG Chem, Samsung, and BYD batteries, and more than 1.9 million First Solar panels. [Editor’s note: I’m reading this like this meme.]

Last month, NASA’s Landsat 9 satellite captured an image of the project as seen from space.

The Air Force Civil Engineer Center, a primary subordinate unit of the Air Force Installation and Mission Support Center, worked with Edwards AFB to solicit lease proposals for the underutilized parcel of land on the northwest corner of the base using the Air Force Enhanced Use Lease (EUL) program. The Air Force and Terra-Gen signed a 35-year EUL agreement in November 2018.

“Through the program, Air Force installations can lease non-excess, underused land to private sector developers in return for rent or in-kind consideration subject to approval by the Deputy Assistant Secretary of the Air Force for Installations,” said Jeffrey Domm, Director for AFCEC’s Installations Directorate.

The Edwards array is the fifth and largest solar EUL project in the Air Force, with the others located at Luke Air Force Base, Arizona; Eglin Air Force Base, Florida; and two at Joint Base McGuire-Dix-Lakehurst, New Jersey.

Originally published in Renewable Energy World.

This “All-Source” RFP eliminates specific technology requirements, opening the application process for full competition of all non-emitting resources that are widely deployed and consistent with Oregon’s energy policy, PGE said.

The utility said this is its largest open application process to date and is the first in the company’s recent history to provide a flexible timeline for the start of operations.

This RFP, which accepts proposals for resources with a start date between 2025 and the end of 2027, is meant to be consistent with the objectives described in PGE’s 2023 Integrated Resource Plan (IRP), which was acknowledged by the Oregon Public Utility Commission (OPUC) on January 25, 2024. PGE will accept and evaluate bids throughout the first quarter of 2024 and present a shortlist of top-performing projects for OPUC acknowledgment later in the year.

Last year, PGE released a new Clean Energy Plan in addition to its IRP, which both focus on the addition of more community-based renewable energy (CBRE). In its IRP, PGE forecasts a significant capacity need of 1136 MW in summer, 1004 MW in winter and a significant energy need of 905 MWa (~2,500 MW nameplate) by 2030. To help meet that need, it plans to add up to 155 MW of CBRE resources by 2030 with plans to pursue at least 66 MW by 2026.

At the time, the utility said it also planned to conduct one or more RFPs for an additional 181 MWa (~520 MW nameplate) of non-emitting generation and sufficient capacity to remain resource-adequate each year.

The Clean Energy Plan includes:

• New utility scale renewable projects like wind and solar installations, both in-state and out-of-state.
• Non-emitting capacity such as batteries.
• CBRE resources, small distributed energy resources that include battery storage and solar, which can make customers more resilient and save them money.
• Customer-sited solutions including energy efficiency and demand response programs.
• Upgrades to local transmission lines and new regional transmission solutions to accommodate growth and bring a greater geographic diversity of resources to PGE’s portfolio.

PGE said 2030 emissions targets can be met with technologies and resources that are currently known and commercially available. The utility said to meet 2040 targets, new technologies not yet commercially available that can replicate thermal generation dispatchable capacity, such as advanced nuclear, hydrogen or carbon capture and storage, will be needed to support decarbonization and resource adequacy.

PGE also said its natural gas-fired plants would continue to play a role in meeting resource adequacy needs during the clean energy transition. The utility said it would “continue to invest in the efficiency, safety and emissions controls of those facilities as appropriate.”