The Energy Infrastructure Reinvestment Program: Federal financing for an equitable, clean economy
A deep dive into additional options for how utilities could use EIR financing to invest in clean energy, benefitting their ratepayers and improving grid resilience.
It has been a year and a half since the United States passed the most significant climate legislation in the nation’s history, the Inflation Reduction Act (IRA). Over the next few months, regulatory guidance for most of the programs created or expanded by the law will be finalized, and funding will begin to make its way from the federal government’s coffers into the clean technologies that must scale — and do so rapidly — if we are to stave off climate disaster.
In keeping with this urgency, several IRA programs have already moved past the initial application phase, including the US Department of Agriculture’s New ERA Program for rural electric cooperatives, which will channel tens of billions of dollars in grants and low-cost financing into this vital — and often undercapitalized — segment of the electric sector. An even larger IRA program — the US Department of Energy’s Energy Infrastructure Reinvestment (EIR) program — is currently vetting a pipeline of potential projects requesting over a hundred billion dollars’ worth of long-term loans priced just above the yield of US Treasury bonds — in other words, a borrowing cost lower than that commanded by even the most creditworthy of corporate issuers.
RMI has previously called the EIR the most important clean energy policy you’ve never heard about, because of its potential to revitalize local communities historically dependent on fossil fuel infrastructure while saving electricity ratepayers money and building new clean energy resources — a triple win for communities, customers, and the climate. EIR is administered by the Department of Energy’s Loan Programs Office (LPO). While the LPO has traditionally lent to help commercialize advanced technologies — including providing financing for some of the country’s earliest utility-scale wind and solar projects and kick-starting the electric vehicle industry — EIR’s remit is to reutilize and repurpose existing energy infrastructure and build new clean energy assets that use already proven technologies like solar, wind, and battery storage.
With a $5 billion credit subsidy appropriation and authority to make up to $250 billion in loans, EIR has a huge bankroll to go along with its encompassing technological scope. In addition, the statute explicitly includes a provision allowing funds to be used for refinancing as well as for remediation or decommissioning costs, addressing two substantial risks that can add significant costs when retiring and replacing energy infrastructure. The program’s concerning constraint, however, is its statutory requirement to approve loans by the end of September 2026. (However, while applications must be greenlit for funding by this date, loan disbursements and project construction are permissible through 2031.) With under three years left until the approval deadline, the sprint is on for utilities and other owners of retiring energy infrastructure to access this extremely affordable financing.
While EIR applications remain confidential at this point, utilities from all corners of the country have publicly announced their intention to apply to the program, including Portland General Electric in Oregon, Consumers Energy in Michigan, Duke Energy in the Carolinas, and Alliant Energy in Wisconsin and Iowa. Additionally, public utility commissions and staff in other states, such as Arkansas, Louisiana, and Colorado, have directed utilities under their purview to study how EIR could be utilized.
EIR can be particularly effective in managing competing community, customer, and shareholder interests in cases where power plants are already slated to cease operations. EIR loans can be used to refinance the obligation of customers to provide cost recovery to utilities for prudently incurred energy infrastructure costs (including remediation and decommissioning costs) and can be structured as off-balance sheet financing vehicles repaid through a dedicated bill surcharge. With tenors of up to 30 years, borrowing costs just slightly above the federal government’s, and the flexibility to cover up to 80 percent of total project costs, EIR loans can make accelerated reinvestment in existing fossil sites much more attractive for both utility customers and shareholders. Since EIR loans require any refinancing of legacy investments be tied to reinvestment activities, their use also helps ensure that local communities can retain jobs and tax base while ratepayers benefit from additional cost reductions resulting from ongoing use of assets such as interconnection points and transmission capacity.
To highlight the potential of using EIR to refinance unrecovered legacy asset costs and reinvest in new clean energy, we look in detail below at two utilities, Interstate Power and Light (Alliant) in Iowa and Union Electric Company (Ameren) in Missouri, both of which are currently engaged in regulatory proceedings to manage the rate and financial implications from agreed-upon coal plant closures. LPO guidance requires EIR loans to total no more than 80 percent of project costs, which are defined as the new reinvestment in clean energy, transaction costs, and, where included, remediation and decommissioning costs with retiring fossil infrastructure and any refinanced plant balance. In our modeling, we assume that 20 percent of the new clean capital stack is financed with EIR, and 100 percent of the fossil plant balance is refinanced with EIR; transaction costs are capitalized and included in the project costs. (Note that for loan volume values and initial project cost comparisons, we use nominal dollars, but use net present value [NPV] dollars when comparing overall costs and savings).
The bottom-line is this: using EIR to refinance the entirety of remaining fossil plant balances as well as just a portion of the new clean energy assets that the utilities are planning to deploy through 2030 could save Iowa ratepayers $124 million and Missouri ratepayers $413 million in NPV terms.
Alliant Iowa Analysis
In Iowa, Alliant is asking to recover the remaining $265 million balance of its Lansing coal plant using a regulatory asset amortized over the plant’s previously expected remaining operating life of 13 years. According to Alliant’s integrated resource plan (IRP), the utility is also planning to bring 400 MW of solar online in the coming year, along with 99 MW of repowered wind, 28 MW of storage, and 94 MW of solar plus storage by 2030.
For Alliant, total project costs for just EIR financing the clean energy portfolio would be $899 million: $173 million for the 20 percent of the clean energy portfolio capital stack financed by EIR, $710 million for the remaining 80 percent of the clean energy portfolio capital stack financed by the utility, and $15 million in transaction costs. Thus, total EIR loan volume for just EIR financing the clean energy portfolio inclusive of transaction costs would be $189 million, or 24 percent of total project costs net of transaction costs, well below the 80 percent threshold. For ratemaking, this $189 million would be financed at EIR loan rates and recovered via a dedicated rate surcharge, while the remaining clean energy costs would be recovered normally at the utility’s rate of return.
When combining the Lansing refinancing of $265 million, total project costs would be $1.17 billion: the $173 million for the 20 percent of the clean energy portfolio capital stack financed by EIR, $710 million for the remaining 80 percent of the clean energy portfolio capital stack financed by the utility, $265 million for the Lansing refinancing, and $17 million in transaction costs. Total EIR loan volume would equal $455 million, or 43 percent of project costs. For ratemaking purposes, the $455 million again would be financed at EIR rates and recovered via the dedicated rate surcharge; however, the $265 million of remaining Lansing balance would be removed from rate base. With the plant balance out of rate base, the Lansing capital from the EIR loan is “recycled” back into the utility’s balance sheet and can be used for the new clean energy assets. And the 80 percent of the clean capital stack, now with the $265 million directly from the EIR loan for Lansing, is recovered at the utility’s rate of return.
As for the overall cost comparison, using traditional utility financing for full recovery of costs associated with Lansing and the new portfolio of renewables, we estimated total ratepayer costs at $1.08 billion (NPV 2024$), with $246 million coming from the Lansing recovery, and $835 million coming from new clean energy.
Next, we looked at how these costs would change if we instead used EIR to finance a portion of the new clean energy. We assume 20 percent of the capital stack is financed by 30-year EIR loans, with the remainder financed through traditional utility financing with roughly equal fractions of utility debt and equity. We estimate that EIR transaction costs would add approximately $4.6 million in NPV to overall financing costs but would reduce net costs for the new clean energy by $57 million.
If EIR were also used to refinance the remaining Lansing balance, an additional $63 million could be saved, for a total of $123 million in ratepayer savings. Given that Alliant has already stated its intention to apply for EIR funding for new clean energy projects, our analysis shows only an additional $1.6 million in NPV transaction costs from including the remaining plant balance of Lansing in a broader EIR loan package, which amounts to a 90:1 benefit-to-cost ratio.
Ameren Missouri Analysis
In Missouri, Ameren is retiring its Rush Island coal plant and seeking to recover $512 million, inclusive of both the remaining plant balance as well as additional decommissioning costs and community transition funding. Ameren is also proposing to build 1,800 MW of solar, 1,000 MW of wind, and 400 MW of battery storage by 2030 according to its IRP.
For Ameren, total project costs for just EIR financing the clean energy portfolio would be $4.79 billion: $933 million for the 20 percent of the clean energy portfolio capital stack financed by EIR, $3.82 billion for the remaining 80 percent of the clean energy portfolio capital stack financed by the utility, and $39 million in transaction costs. Total EIR loan volume for just EIR financing the clean energy portfolio would be $971 million, or 26 percent of total project costs net of transaction costs, well below the 80 percent threshold. For ratemaking, this $971 million would be financed at EIR loan rates and recovered via a dedicated rate surcharge, while the remaining clean energy costs would be recovered normally at the utility’s rate of return.
When combining the Rush Island refinancing of $513 million, total project costs would be $5.31 billion: $932 million for the 20 percent of the clean energy portfolio capital stack financed by EIR, $3.82 billion for the remaining 80 percent of the clean energy portfolio capital stack financed by the utility, $513 million for the Rush Island refinancing, and $42 million in transaction costs. Total EIR loan volume would equal $1.5 billion, or 35 percent of project costs. For ratemaking purposes, the $1.5 billion again would be financed at EIR rates and recovered via the dedicated rate surcharge; however, the $513 million of remaining Rush Island balance would be removed from rate base. With the plant balance out of rate base, the Rush Island capital from the EIR loan is “recycled” back into the utility’s balance sheet and can be used for the new clean energy assets. And the 80 percent of the clean capital stack, now with the $265 million directly from the EIR loan for Rush Island, is recovered at the utility’s rate of return.
As for the cost comparison analysis, Missouri has state legislation in place authorizing the use of securitization for financing coal plant cost recovery, which Ameren has proposed to utilize in this case. As such, we also model separate scenarios using either securitization or EIR to achieve Rush Island cost recovery.
Using traditional utility financing for both the recovery of Rush Island’s remaining plant balance and the new clean energy portfolio, the costs would total $4.5 billion (NPV 2024$), with $482 million coming from the Rush Island recovery and $4 billion coming from new clean energy.
EIR financing for 20 percent of the clean energy portfolio while maintaining traditional utility financing for Rush Island would save ratepayers $278 million, net of $6.6 million in NPV of EIR transaction costs.
Under Ameren’s proposal to securitize Rush Island cost recovery with a 15-year bond, Ameren ratepayers would save $72 million, net of $15.6 million in NPV of transaction costs. Combined, EIR financing for a portion of the new clean assets along with securitization of the fossil plant balance would result in $350 million in savings, with $22.2 million in NPV of transaction costs.
The use of EIR for Rush Island cost recovery delivers even greater savings than securitization. If Ameren is already applying for EIR financing for a portion of its clean energy portfolio, the NPV of marginal transaction costs of bundling together the Rush Island recovery with this EIR package would be just over $1.3 million, a substantial cost reduction compared with the NPV $15.6 million in securitization transaction costs. Lower transaction costs, a lower interest rate from EIR, and a longer loan tenor as allowed by EIR would lead to a further $131 million in savings from Rush Island, for a total savings of $413 million versus traditional utility financing for fossil plant cost recovery and new clean deployment.
The Need to Move Quickly
Given the savings available to ratepayers, as well as the time-constrained authority of the EIR program, Alliant and Ameren should move quickly to take advantage of this program, and regulators should ensure utilities are looking into this program as an option that will help reduce costs. With an application approval deadline set for the end of September 2026 and a disbursement deadline at the close of 2031, utilities nationwide have a critical opportunity to refinance their retiring coal plants, build new clean energy, and increase their earnings, all while reducing costs to ratepayers.
Modeling Appendix
- Clean Portfolios: We look at the latest IRPs for Alliant and Ameren. Specific deployment dates and costs are not publicly available for all resources, so we have made simplifying assumptions for modeling purposes. We assume clean technologies are deployed in the single earliest year, which is a very conservative assumption that would overestimate costs due to technological cost declines. Specifically, for Alliant, because exact deployment dates were not available for all resources, we assume 459 MW of solar and 99 MW of repowered wind come into service by the end of 2024, and that 63 MW of storage comes into service by the end of 2029. For Ameren, we conservatively assume that all clean technologies are built in the same year, with 1,800 MW of solar in 2025, 1,000 MW of wind in 2026, and 400 MW of storage in 2027. In reality, Ameren will spread this deployment over later dates, and these costs would be lower due to technological cost declines. We use NREL's 2023 annual technology baseline (ATB) for resource costs, utilizing moderate learning curves over a 30-year cost recovery period.
- Tax Credits: We assume that the production tax credit (PTC) is taken for solar and wind, and the investment tax credit (ITC) is taken for storage and that utilities opt out of the ITC normalization requirements. We assume a tax credit transferability discount of 5% (for example, the utility sells its tax credits in the transfer market made possible by the IRA for 95 cents on the dollar) and do not assume any bonus adders for domestic content adder or location in energy communities. This is also conservative, as these adders, especially the energy communities adder, will likely apply for some of the projects.
- Utility Financial Metrics: We looked at the latest rate cases, utility proposed capital metrics, and recent balance sheets to identify the utilities’ returns on equity (ROE) and the equity ratios. For Alliant, the metrics are a 10% ROE, with a 10.75% ROE for clean projects as approved by the Iowa Utilities Board, and a 52% equity ratio. For Ameren, the metrics are a 10% ROE and 52.37% equity ratio. For corporate debt costs as well as securitization bond rates and EIR loan rates, we calculate forward-looking interest rates based on Treasury yield curves, with appropriate spreads added to the rates based on credit metrics. We calculate that Alliant’s forward-looking WACC ranges between 7.5% and 7.9% and Ameren’s WACC ranges between 7.6% and 7.7%, when accounting for future interest rates at these utilities’ credit ratings. EIR loan rates are 37.5 basis points above Treasury rates, and securitization bonds assume a AAA-rating.
- Securitization Modeling Assumptions: For securitization, we analyze Ameren’s proposal of a 15-year bond tenor. We rely on Ameren’s given transaction costs of $6.6 million up-front and $792,000 annually. For interest rates, for simplicity, rather than calculating two separate tranches at different tenors as Ameren proposes, we assume a single tranche with a AAA-rated bond and an expected tenor of 15 years.
- EIR Modeling Assumptions: For EIR loans, we assume the maximum tenor allowed under the law, 30 years. We assume full plant balance refinancing for coal plants and analyze EIR as 20% of the capital stack for new clean energy, with the remainder financed through traditional utility financing. This is in fact, conservative, given that EIR can be used to finance up to 80% of project costs and greater leverage of EIR loans would result in even lower costs. Since EIR serves to reduce customer costs, both in the near-term and on an NPV basis, it frees up rate headroom and can make it possible for utilities to pull forward new clean asset deployments. As such, swapping out a portion of utility equity with EIR debt can still leave utility shareholders in an improved position by accelerating practicable opportunities to deploy capital, albeit with slightly more leverage, rather than delaying equity-richer investments into a less certain future. For EIR transaction costs, we look at LPO guidance, which states there is a facility fee of 0.6% of project costs up to $2 billion, and 0.1% after that initial $2 billion in costs. There are also third-party expenses, which range from $1–$3 million, and we use the lower bound of $1 million given these types of transactions, as the due diligence expected is simpler than most Title 17 projects that focus on innovative and emerging technologies. There is an annual maintenance fee of $150,000–$500,000, depending on the complexity (we assume annual maintenance fees of $300,000). Finally, we assume EIR loans are structured as off-balance sheet financings without recourse to the utility’s balance sheet.
- Cost Differences: For simplicity, we assume securitization bonds and EIR loans are issued at the beginning of the year, rather than mid-year. Additionally, rather than using utilities’ weighted average costs of capital (WACC) as the discount rate for NPV calculations, we use 7%. This is higher than Ameren’s stated 6.82% WACC; however, WACCs approved a year ago now face a higher interest rate environment, which raises the cost of borrowing. Still, our analysis comparing securitizing Rush Island and traditional utility financing delivers results very close to what Ameren modeled — we estimate $72 million in savings, while Ameren estimates $75 million in savings. All NPV savings are in 2024 dollars.
Correction as of February 16, 2024: A previous version of this article incorrectly stated the Clean Project Costs with Utility Financing for Alliant as $591 million, when it is $710 million; and for Ameren as $2.77 billion, when it is $3.82 billion. This has been corrected both in the text and in the EIR Project Cost Comparison graphics.
