Elective payment of energy tax credits could be transformational for public power utilities wanting to own wind, solar, storage, geothermal, and other projects.
The elective payment mechanism, also known as direct payment, was created by the Inflation Reduction Act of 2022 as part of an expansion and extension of existing energy tax credits and has the potential to offer benefits for public power utilities and joint action agencies interested in the development of renewable energy, storage, carbon capture, and electric vehicle projects. These benefits include savings for customers, more funds to make further investments, and operational control of assets previously obtained primarily through power purchase agreements.
Historically, tax-exempt entities, including public power utilities, could not directly benefit from energy tax credits for facilities they owned. Instead, public power utilities have indirectly benefited from such credits by entering long-term agreements, such as a power purchase agreement, with taxable entities that can claim these credits. Elective payment will allow a public power utility to claim these credits when it directly owns eligible assets. However, the American Public Power Association has warned that how Treasury and the Internal Revenue Service implement elective payment could determine its success or failure.
While some aspects of implementation continue to be developed, here is a snapshot of how different public power entities are weighing whether to tap into the value of elective pay for planned projects.
Maximizing Benefits
The Indiana Municipal Power Agency has multiple solar park projects that help serve the joint action agency’s 61 member cities across Indiana and Ohio. From 2015 through 2022, Jack Alvey, president and CEO of IMPA, said that the agency worked with a third party to receive a portion of the benefits available from the federal government to taxable entities for the solar park projects.
“Those deals were structured such that we would receive half of all of the benefits available to the taxable entity,” he said. The deals were complicated and required many different contracts, which also included the option for repurchase of the sites at a certain date.
IMPA entered the third-party power purchase arrangements because elective payment was not an option until 2023.
Alvey noted ways the agency maximized the benefits member communities for its solar program through the power purchase agreements. “We wanted to make sure the solar parks were located in our member communities to keep the benefits local to our member communities as opposed to the solar park being built elsewhere and IMPA paying for and receiving the power and energy. We wanted to keep the personal property taxes we pay local and to have the local presence and visibility of the solar,” he said.
Now, due to the elective pay option, IMPA is looking to directly own, from the outset, the solar park projects it is developing.
The elective pay provisions “should both simplify the development phase by eliminating all third-party negotiations and documents and deliver more savings to us by not having to share the benefits with a third party,” Alvey noted.
“It is also a better use of federal dollars. Instead of diverting a substantial portion of the credit to a third party, whose only reason to be in the deal is to monetize the tax credits, the elective pay credit is now being passed along as a benefit to our members and their customers,” he said.
As for how IMPA expects elective pay credits to help save it money on the solar parks it is planning to develop, Alvey listed the following benefits:
- Increased portion of the tax credits to be received.
- Decreased staff time spent structuring and managing deals with third parties.
- Decreased time to negotiate the fair market value for repurchase and no-repurchase cost risk at the time of the buyback option.
“Overall, we see elective pay provisions requiring fewer internal resources and time for our solar project developments. We do foresee it requiring additional outside tax review to ensure compliance as we enter this program from a new direction with direct pay,” he said.
“In the past, we still were determined to add additional solar to our portfolio because it is a low-cost source of energy,” said Alvey. “But if federal dollars are going to solar installations, our customers should get the benefit of their tax dollars like any other project.”
Alvey also provided insight into what else public power utilities should keep in mind when weighing whether to pursue projects that would use the elective pay credits.
“With the expected increased benefits, there is also additional time required to research and comply with all of the new rules,” he said. “Regulatory guidance has been very slow in coming, but it is vital to understand and comply with the elective pay regulations. Failure to follow prevailing wage or domestic content requirements can severely limit or even eliminate the credits available.”
Increasing Accountability
Terry Crowley, utility director for the City of Healdsburg, California, also weighed in on the key factors driving whether to pursue direct ownership or enter into a power purchase agreement for a project.
Crowley noted that, historically, public power utilities couldn’t gain access to tax credits for renewable energy projects.
“[Our] only option was to contract with a for-profit third party to develop new renewable resources. Under the elective pay option, we are now able to shop the financing of the project and gain significant savings for our customers,” Crowley said. “This allows us to better support our goals of providing both affordable and clean energy.”
The public power utility is looking at potentially using the elective payment option to secure energy credits for projects including a new solar facility, to develop hydrogen at an existing natural gas facility, and for adding battery storage at an existing solar project.
Crowley said that regardless of a power purchase or elective pay arrangement, “any entity can either staff-up and provide those local jobs or choose to contract for ongoing monitoring and maintenance. Largely, the need for staffing is determined by type of generation. Once built, solar and battery storage don’t require a lot of ongoing staff time. Other types of renewable generation will create additional, ongoing jobs, which is always a plus for the local economy.”
“In the past, we understood there would be some sharing of the tax credit, but to what extent is largely unknown,” said Crowley. “For Healdsburg, we expect elective pay to reduce renewable energy costs by as much as 20% versus traditional PPA contracts,” he said. “Also, ownership of the project provides additional security in maintenance and operation of the plant. With a PPA, the third-party owner makes the decisions on maintenance, operations, and the sale of the project to other, unknown third parties after the tax benefits expire.”
As for what else public power utilities should be aware of when weighing whether to pursue projects that would use the elective pay credits, Crowley noted that the rules and guidelines around elective pay credits “are in their infancy, and actual implementation is not well understood.”
He said that this “provides uncertainty regarding joint power agencies owning and operating a project on behalf of several smaller public power entities and will likely delay some projects. Also, rules around bonus payments for certain types of projects (low income, prevailing wage, apprenticeships, etc.) need to be well understood to maximize the benefits.”
This is where public power’s “long-term relationship with federal policymakers can help assure the intentions and functionality of elective pay are met,” Crowley said.
A Return to Tradition
“Traditionally we have owned the generation and transmission assets needed to serve our members so another party has not been earning a ‘return’ on those assets, which helps keep our power supply costs lower,” said Greg Fritz, CEO of the North Iowa Municipal Electric Cooperative Association.
“With the inability to access various tax credits, our best option was to enter into PPAs with private entities that developed the projects,” he added. “While the projects have been favorably priced, someone is earning a return on their investment, and we are paying for it,” he said.
The joint action agency is now weighing whether to directly own or enter power purchase agreements for solar projects in each of its 13 member communities.
Fritz said the key factors that drive whether a project should pursue direct ownership or a third-party power purchase agreement include “the size of the project, location, transmission/interconnection issues, staffing, and financing-related issues,” such as cost of debt and debt service coverage.
“Ongoing project operation after construction, particularly staffing and maintenance, is a major concern for us,” he said.
With respect to how the joint action agency expects elective pay credits to help save money on renewable energy projects that it is planning to develop, “We are exploring options for development of solar projects, and the ability to access direct pay will hopefully put us back on our traditional path of ownership and lower costs,” he said.
As for what else public power utilities and JAAs should pay attention to when weighing whether to pursue projects that would use the elective pay credits, Fritz said, “Long-term reliability of the projects is another concern for us. While companies may provide a warranty of 10, 20, or 25 years, will they still be in business five years from now? What will long-term [operating and maintenance] costs be?”
Factoring All Costs
“Not being able to utilize any federal tax credits has pushed every in-town [distributed generation] project to date into the third-party PPA model,” shared Clint Allen, assistant utility director for the Town of Danvers Electric Division in Massachusetts. For Danvers, he said these types of agreements have historically inflated the dollar-per-kilowatt-hour cost for the project 40%–50%.
The public power utility is currently pursuing several solar projects, including at its schools and at a landfill.
“The primary factor is total project cost. We look at the expected energy production versus equipment lifetime and determine the average unit cost per [kilowatt-hour],” he said. “When assessing an ownership model, we factor in maintenance costs and any [payment in lieu of tax] payments into the formula. The objective is to have a direct comparison on total energy cost that we can use to make a business decision.”
Allen noted that Danvers is in the process of developing a 3- to 5-megawatt ground-mount solar array. “With the now available federal tax credit, our preliminary analysis shows the ownership model may be competitive with the third-party PPA,” he said. “The biggest variable is the total lifetime cost of ownership, factoring in maintenance and replacement costs.”
“In my experience, the elective pay credits may put the initial construction costs below a competitive PPA. However, when you factor in panel/battery replacement and annual repair and refresh, the third-party PPA may still come in at a better project lifetime energy cost,” he said.
