Clean energy costs are falling, driven by technological advancements, economies of scale, and federal tax credits that were significantly enhanced and extended by the Inflation Reduction Act (IRA). The most important improvements to the tax credits aim to unlock the benefits of clean energy for the customers of fossil-heavy electric utilities — making it more attractive for these utilities to reinvest in assets that can reduce energy bills and harmful emissions. RMI’s recent work on clean repowering suggests that 250 GW of wind, solar, and battery storage assets — equivalent to nearly 20% of the total existing generating capacity of the US power sector — could be built rapidly by sharing existing or retiring fossil plant grid connections without impacting system reliability. This would reduce emissions by 25%, increase utility earnings, and save customers more than $12 billion annually through 2035.

That’s good news, but it’s only part of a more complicated and less rosy picture. As regulated utilities and their customers look to seize upon attractive clean energy opportunities, they must also manage the legacy of prior investments. Put simply, the transition to clean means passing through a zone of overlapping financial obligations, with the front-loaded capital expenditures of the clean system layered on top of ever-growing costs and risks associated with continued operation of the fossil-intensive system. At a time when Americans are feeling pinched by inflation at just about every turn, bearing the burden of overlapping energy systems is hardly an inviting prospect.

To address this looming burden, the framers of the IRA purposefully created the Energy Infrastructure Reinvestment (EIR) Program to make available up to $250 billion in extremely low-interest federal loans for a cleaner power sector. The question before us is how to maximize the benefits of this massive allocation of taxpayer resources. If utilities do nothing more than use EIR loans to displace corporate debt, overall ratepayer savings will be minimal, since most utilities can already borrow at reasonably attractive interest rates without the added complication and expense of participating in a government program.

However, if utilities and their regulators cooperate to combine more ambitious usage of federal debt with ratemaking strategies that concentrate equity in the financially attractive assets of the clean system, EIR has the potential to deliver substantial rate relief to customers as well as sustained earnings opportunities for shareholders. This win-win approach is called “capital recycling.”

This insight brief, which builds on a February RMI article, describes how different EIR implementation choices will impact the financing costs that utility ratepayers will bear over the coming decades. The brief covers:

1. The legacy costs and risks of a fossil-intensive system and the challenges they pose for utility reinvestment in clean energy;
2. How the EIR program can be used to facilitate capital recycling;
3. Quantitative examples of capital recycling using EIR applied to our previously published Missouri and Iowa utility case studies;
4. The transaction costs of EIR lending and securitization; and
5. Compliance with the National Environmental Policy Act, the Davis-Bacon Act, and the Cargo Preference Act, all contingent requirements for federal financing such as EIR.

Over the past decade, utilities have been faced with growing amounts of unanticipated costs linked to the operation of their fossil-intensive electricity system — fuel price spikes tied to geopolitical instabilities, environmental controls for legacy assets, conflicting policy mandates simultaneously requiring and preventing accelerated retirement of many of those same assets, and liability and recovery impacts from wildfires and storms supercharged by climate change. This surge in costs has required financing to spread customer impacts over time. Unfortunately, financing the burdens of the past has actually made investment in utility debt and equity riskier and less attractive, even if the capital is used for building clean energy assets whose future costs are extremely predictable and stable.

To understand why this is the case, it helps to start by reviewing how regulated utilities make money. Utilities earn profits by investing capital in electricity infrastructure to serve their customers, whose bills in turn cover the costs of repaying that investment over time (“depreciation and amortization costs”) and providing a return to utility investors on any outstanding investment balance (known as the “rate base”). Utilities are also permitted by their regulators to recover unanticipated costs by including them in rate base (as “regulatory assets”) rather than passing them through to customers at the same time they are incurred, which could cause rates to spike.

Regulatory assets are repaid in bills relatively quickly — in just 5 to 15 years — in part because utilities worry that regulators in the future may disallow costs that are not directly tied to current service delivery and could in hindsight be deemed imprudent or excessive. We refer to these types of assets as “low-quality” rate base components. This is because they are a lose-lose proposition with unattractive profiles for both utility shareholders (higher risk and rapidly declining earnings) and customers (high annual depreciation and amortization costs associated with shorter recovery periods).

Clean energy assets, on the other hand, are very capital intensive with long recovery periods (usually at least 30 years) and practically no risk of disallowance or early retirement. From the utility earnings perspective, this is rate base of the highest quality. Further, clean energy investments are eligible for tax credits that, as a result of IRA enhancements, can readily be used by utilities to directly offset rate impact.

But while new clean energy assets are ideally suited to enlarge high-quality rate base, they do nothing to remove the shareholder risks and ratepayer costs that derive from low-quality rate base components. These remain until recovery is complete, locking-up scarce ratepayer revenues and negatively impacting the balance sheet financing of new assets by raising a utility’s forward-looking borrowing and equity-raising costs.

But what if utilities and ratepayers could instantly transform low-quality rate base into the high-quality version, improving earnings prospects for investors and extending depreciation and amortization pathways for energy consumers. Imagine, for instance, that long-term, low-interest loans were readily available to utilities and could help free up balance sheet capital to be recycled into wind turbines, solar arrays, and batteries. Ratepayers would see immediate rate relief from lengthier recovery periods and lower carrying charges on refinanced assets, while utilities would benefit from steadier forward-looking pathways for both earnings and rates. Avoiding near-term rate shocks would in turn make it easier for utilities to press the case for more rapid investment in additional clean energy projects to take advantage of IRA tax incentives to reduce energy burdens, meet growing loads, and improve shareholder value. This is the promise of “capital recycling,” and the EIR program created by the IRA can help utilities make it a reality.

Overseen by DOE’s Loan Programs Office (LPO), the EIR offers lower-cost debt (at an interest rate just 0.375% above US Treasuries of similar tenor). Loan terms as long as 30 years are permissible. At a minimum, this lending can displace slightly higher-cost utility debt. However, with $5 billion in credit subsidy appropriation and authority to make up to $250 billion in loans to cover up to 80% of project costs, it can also allow more leverage than would be achievable using normal financing channels without adversely impacting the borrower’s credit rating, thereby displacing not only utility debt but also even more costly utility equity. While utilities and regulators may be wary of allowing leverage on the utility’s balance sheet that is higher than the level in the utility’s approved capital structure, LPO has the flexibility to lend to off-balance sheet special purpose vehicles (SPVs). Off-balance sheet accounting insulates the utility’s capital structure, which means that the EIR debt can be taken on at a higher leverage ratio than the utility’s approved capital structure with minimal risk to future private financing.

EIR loans can make accelerated reinvestment in existing utility systems more attractive for both utility customers and shareholders. And since the EIR requires reinvestment with a locational nexus to the assets being replaced or reduced, the loans can also help ensure that energy communities retain jobs and tax base. To the extent that components of energy infrastructure such as interconnection points and transmission capacity can be repurposed, ratepayers will likely benefit from further total cost reductions.

Specifically, a regulated utility can work with DOE and its regulator to use the EIR to implement capital recycling by taking the following five steps:

1. 1. Identify a reinvestment portfolio that qualifies for the EIR such as new clean energy projects, grid improvements, or upgrades for existing clean energy infrastructure that meet the requirements to qualify for the EIR program and can complete construction by September 30, 2031.[1]
   2. Request a high-leverage EIR loan to finance up to 80% of the total costs for the reinvestment portfolio and, if desired, structure part or all of the loan to use an off-balance sheet, bankruptcy-remote SPV to mitigate potential negative credit rating implications.
   3. Introduce a dedicated non-bypassable surcharge for EIR repayment, which will be separated from base rates on customer bills and cover the cost of repaying the EIR loan to the SPV.
   4. Designate an amount equivalent to some or all of the EIR proceeds for regulatory purposes to recover low-quality rate base.
      1. 1. As utility financial resources are fungible at the corporate level, regulators may deem funds up to the amount being recovered through the surcharge as providing cost recovery of low-quality rate base. This amount no longer needs to be recovered through base tariffs in subsequent rate proceedings.
         2. To balance this move, the regulator deems that less of the cost of the new assets is being recovered by the collections flowing to the SPV. An amount equivalent in size to the expunged low-quality rate base is now treated in base rates as if it were high-quality rate base (e.g., clean assets to be recovered over thirty years).

      Purely as a matter of regulatory accounting, this intervention effectively allows refinancing of legacy system costs and frees up previously raised shareholder equity for clean portfolio reinvestment. The utility’s equity reinvestment risk has been addressed. And the EIR loan repayment has not been compromised in any way.

   5. Assets remaining in rate base are billed to customers at the utility’s regulator-approved cost of capital. Any amount assigned to rate base, including any fraction of the reinvestment portfolio costs that will not be recovered through the surcharge, earns a financial return at the utility’s rate of return (calculated including any EIR debt kept on balance sheet).

This approach is possible because steps three through five can be undertaken by a utility with approval from its regulator without impacting the terms and conditions of its loan agreement with DOE. These steps change how costs are recovered but do nothing to impact the ultimate source, amount, or timing of cash flows used by the utility to repay the federal government. Nevertheless, with this approach, the utility, its regulators, and its customers can remove the financial legacy of existing energy infrastructure from the ratemaking equation and focus all stakeholders on a clean energy future, even though the EIR application is entirely tied to financing a clean reinvestment portfolio and not tied in any way to refinancing retired assets.

The driver of customer savings in a capital recycling is still the opportunity to refinance higher-cost utility capital — which generally includes roughly equal shares of debt and equity — with lower-cost EIR debt. These savings will be greatly diminished if utilities and regulators countervail the benefit of increased leverage in future rate proceedings. Effectively, regulators and utilities must chart a course between these two options:

1. If EIR debt simply serves as a substitute for future corporate debt in the utility capital structure, the benefits of EIR for customers will be small. This would be the result if regulators and utilities choose to reduce or eliminate future issuances of utility debt to restore the utility’s overall debt-to-equity ratio to a level that existed without the EIR. Put simply, EIR debt would be a 1:1 substitute for future utility corporate debt. In practice, this could be achieved by adjusting downward the leverage on future projects, thereby offsetting the smaller deployment of shareholder equity in the EIR project and leaving the long-term capital structure unaffected. This approach effectively reduces ratepayer benefits from EIR debt to just the spread between the total EIR debt and utility corporate debt, net of any additional EIR transaction and compliance costs.
2. If, however, the utility makes future capital structuring decisions using a leverage ratio that excludes the EIR debt, the benefits can be much greater. In this case, the utility would accept the higher leverage on the EIR project without demanding any offsetting increase of equity deployed in other projects. This approach would lead to a greater reduction in the total utility cost of capital over the duration of the EIR loan through a lowering of the equity share of the capital stack. Nevertheless, the impacts could be credit neutral or even slightly credit positive as well as being beneficial on a risk-adjusted basis for shareholders, especially if there is
   1. the use of off-balance sheet financing through a bankruptcy-remote SPV and a dedicated surcharge to protect the utility’s balance sheet;
   2. an overall increase in high-quality rate base and cash flows tied to utility investment in clean reinvestment projects;
   3. a reduction in overall utility investor risk tied to reduced rate pressure and disallowance risk as a result of shifting utility equity from riskier, low-quality rate base to high-quality clean reinvestment portfolios with attractive, transferable tax credits; and/or
   4. greater certainty around, and potential acceleration of, earnings growth and expected cash flows due to more attractive rate impacts increasing the likelihood of regulatory approval for rapid deployment of the clean reinvestment portfolio.

Utilities and regulators should work together to implement capital recycling and ensure that the full benefit of the higher leverage from EIR debt is not eroded through future ratemaking. Such an approach would also aid compliance with the statutory requirement that electric utilities applying for an EIR loan provide assurance that financial benefits from the loan guarantee will be passed on to the customers of, or associated communities served by, that utility.

In the case studies that follow, we will show the results of RMI financial modeling that reflects the five steps outlined above. In our modeling scenarios, we implement capital recycling to varying degrees and assess the impacts of undoing the benefits of greater leverage in future rate proceedings. Note that in comparing the shareholder impacts of EIR scenarios with and without capital recycling, we account for the potential of capital recycling to convert low-quality rate base into higher quality rate base. By shifting deployed equity from short-term assets in jeopardy of disallowance to longer-term assets of unassailable prudency, risk-adjusted shareholder earnings will be higher even if the utility accepts the higher leverage EIR loan without an offsetting increase in equity deployment in other areas of rate base.

[1] There is a statutory requirement to approve loans by the end of September 2026. While applications must be greenlit for funding by this date, loan disbursements and project construction are permissible through September 2031.

In February 2024, we presented two case studies from Iowa and Missouri to show how utilities could utilize the EIR to save ratepayers money while recovering the costs of retiring coal plants and building new clean energy assets such as wind turbines and solar PV. In those studies, we achieved ratepayer savings in part by increasing the volume of lending requested from the EIR program to cover refinancing of unrecovered coal plant balances (we call this the “refinancing method” to distinguish it from the “capital recycling method”).

Here, we’ll use those same case studies to illustrate the potential benefits of the “capital recycling method.” We will also provide additional information concerning transaction costs and compliance requirements that are important to keep in mind when evaluating the feasibility and net benefits of using the EIR. Note that while the “refinancing method” is permissible under statute and can achieve similar outcomes, we believe that the “capital recycling method” outlined in this article is easier for DOE to execute, albeit at the expense of some increase in regulatory complexity at the utility commission level.

Alliant Iowa

In Iowa, Alliant Energy Corporation 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 Clean Energy Blueprint, 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. Alliant has already indicated that it is applying for EIR financing. However, given that the portfolio of projects in the application has not been disclosed, we rely on the company’s Clean Energy Blueprint, along with the Lansing unrecovered plant balance. We estimate that the total nominal costs of this portfolio will be $888 million (see Modeling Appendix for assumptions).

Exhibit 1: Alliant EIR Financing Structure Comparison

Our financial analysis compares the NPV of costs, first-year costs, and forward earnings impacts of Alliant taking one or more of the steps we outlined in the previous section, including the possibility that EIR financing ultimately only substitutes for future utility debt issuances. Our reference scenario is a business-as-usual scenario.

• Business as Usual (BAU) – We estimate the cost of traditional utility financing for full recovery of Lansing and the new portfolio of renewables at $977 million (NPV 2024$), with $271 million coming from the Lansing recovery and $706 million coming from new clean energy. We estimate that the combination of the reinvestment portfolio and Lansing recovery results in three-year forward earnings of $35 million after the full portfolio is deployed in 2029.

We compare this reference point to five EIR scenarios:

• 48% EIR (replaces utility debt), No Capital Recycling – This is a conservative EIR scenario, in which Alliant obtains just enough EIR financing to displace utility debt in the company’s regulator-approved capital structure for its reinvestment portfolio. In this case, EIR debt would provide $426 million of the clean energy portfolio capital stack, while the remaining $462 million would be financed by utility equity. This scenario costs ratepayers $965 million (NPV 2024$), $12 million less than the traditional utility finance reference.
• 60% EIR, High EIR leverage, No Capital Recycling – Here we assume both a larger EIR loan of $533 million and that any future rate base retains the same pre-approved equity ratio without regard for the increased leverage of the EIR projects. As a result, ratepayer savings would be significant, $217 million (NPV 2024$) less than the traditional utility financing reference point. Savings now also come from displacing some of Alliant’s total equity — reducing three-year forward earnings by 63% or $22 million relative to BAU due to foregone equity investment in high-quality rate base. This is a very affordable approach for ratepayers, but it is the least attractive for shareholders both absolutely and on a risk-adjusted basis as it retains low-quality rate base while sacrificing high-quality rate base to leverage.
• 29% EIR, Capital Recycling only – Alliant could also choose to use low EIR leverage, sufficient only for capital recycling of the Lansing plant — in other words, a loan of $265 million. Unlike in the previous scenarios, we assume that the EIR loan is recovered via a dedicated surcharge. As all utility financial resources are fungible at the corporate level, the regulator deems that, for ratemaking purposes, an amount equivalent to the EIR proceeds to be repaid through the surcharge has provided the utility cost recovery for Lansing. Therefore, in subsequent rate proceedings, Lansing costs would be deemed to be recovered through the dedicated surcharge and would no longer need to be recovered in base rates. Ratepayer savings are $94 million (NPV 2024$) relative to traditional utility financing. The low-quality rate base components are now financed with low-cost EIR debt over thirty years (as opposed to 13 years). As a result of these decisions, Year 1 costs are $63 million — $19 million lower than traditional utility finance and $18 million lower than the scenario with 48% EIR but no capital recycling.
• 40% EIR, Moderate leverage, Capital Recycling – This capital recycling scenario assumes a larger $355 million EIR loan. The loan is recovered through a dedicated surcharge. For ratemaking purposes, an amount equivalent to the full EIR proceeds is assumed to cover Lansing cost recovery as well as $90 million in utility capital (both debt and equity at the authorized rate of return) for the reinvestment portfolio. The utility sees net growth of $622 million in rate base. The utility also benefits from having $265 million in relatively short-duration Lansing rate base with uncertain prospects for cost recovery “recycled” into $265 million of longer-duration clean energy rate base. As is the case with securitization, for regulatory purposes, the company’s approved capital structure and rate of return are calculated excluding the off-balance sheet EIR debt.
  ‌‌
  Ratepayer savings are $128 million (NPV 2024$) or 13% lower than BAU. Year 1 costs fall to $59 million, and three-year forward earnings are $25 million, or 72% of the earnings in the BAU scenario. This is an attractive outcome for ratepayers (who benefit from higher leverage across the rate base) and on a risk-adjusted basis for shareholders (who now earn on a rate base comprising only high-quality components).
• 60% EIR, High EIR leverage, Capital Recycling – This scenario increases the EIR loan size to $533 million. Ratepayer saving grow to $204 million, only slightly below the savings in the 60% leverage scenario without capital recycling. This is the second-worst outcome for shareholders (the worst being the 60% leverage without capital recycling); three-year forward earnings are $18 million.

Based on this analysis, we find that a scenario that uses capital recycling with moderate EIR leverage offers Alliant the best prospects for balancing the interests of shareholders and customers, providing 13% consumer savings relative to the BAU while delivering 72% of the BAU earnings with lower risk.

Exhibit 2: Alliant Savings Comparison

Exhibit 3: Summary of Alliant Outcomes

Ameren Missouri

In Missouri, Ameren is retiring its Rush Island coal plant and seeking to recover $513 million, inclusive of both the remaining plant balance as well as additional decommissioning costs and community transition funding. Ameren has proposed using securitization to achieve recovery of this amount in order to reduce its impact on customers. Securitization is a utility financing mechanism employing highly rated bonds made possible by credit enhancements anchored in state legislation. Securitization is available in several US states, including Missouri; however, most states, Iowa among them, do not have such legislation in place. While securitization is less expensive than traditional utility financing (which includes shareholder equity as well as corporate debt), it is more costly than EIR debt for two reasons. First, securitization transaction expenses are typically larger than those charged by LPO. Second, securitization interest rates are higher than EIR rates, in part because of a 2022 decision by Bloomberg to reclassify these instruments as “asset-backed securities,” a move that has reduced the pool of eligible investors and increased interest rates relative to other AAA-rated bonds.

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 integrated resource plan (IRP). We estimate that the total nominal costs of this portfolio will be $4.78 billion.

Exhibit 4: Ameren EIR Financing Structure Comparison

For Ameren, paralleling what we did for Alliant, we model a BAU, a capital recycling-only scenario, and moderate (40%) and high (50%) leverage EIR scenarios with capital recycling, but we also include securitization scenarios, as this mechanism for the cost recovery of retiring plants is available. We model securitization with a 15-year bond tenor to achieve Rush Island cost recovery, doing so in combination with either full traditional utility financing for new clean assets or a low/moderate (30%) leverage EIR loan for new clean assets.

• Business as Usual – For our initial reference point, we estimate the cost of traditional utility financing for full recovery of Rush Island and the new portfolio of renewables at $3.9 billion (NPV 2024$), with $529 million coming from Rush Island recovery and $3.4 billion coming from new clean energy.
• Securitization of Rush Island – Using state-enabled securitization for cost recovery of the retiring plant while relying on traditional utility finance for the new clean assets lowers the NPV of ratepayer costs to $3.8 billion, around $103 million cheaper than BAU. Year 1 ratepayer costs are $362 million, compared to $381 million in the BAU; the medium-length tenor of the envisioned securitization bonds limits the refinancing benefit. Three-year forward-looking earnings decline to $173 million from $190 million in the BAU, since the utility no longer earns any equity return on Rush Island’s low-quality rate base, which has been securitized using AAA-rated bonds with an estimated yield of 5.2%.
• 30% EIR, Low/moderate leverage, Securitization of Rush Island. – Combining low/moderate leverage EIR financing with securitization decreases the NPV of ratepayer costs to $3.3 billion, around $599 million cheaper than BAU. Year 1 ratepayer costs drop significantly to $294 million, but three-year forward-looking costs also drop to $111 million.
• 11% EIR, Capital Recycling only – Ameren could also choose to use low EIR leverage, sufficient only for capital recycling of the Rush Island plant — in other words, a loan of $513 million. Unlike in the previous scenarios, we assume that the EIR loan is recovered via a dedicated surcharge. As all utility financial resources are fungible at the corporate level, the regulator deems that, for ratemaking purposes, an amount equivalent to the EIR proceeds to be repaid through the surcharge has provided the utility cost recovery for Rush Island. Therefore, in subsequent rate proceedings, Rush Island costs would be deemed to be recovered through the dedicated surcharge, and no longer need to be recovered in base rates.
  ‌‌
  Ratepayer savings are $103 million (NPV 2024$) relative to traditional utility financing. The low-quality rate base components are now financed with low-cost EIR debt over thirty years (as opposed to 13 years). As a result of these decisions, Year 1 costs are $340 million — $41 million lower than the BAU exclusively relying on traditional utility finance and $21 million lower than the approach employing securitization for Rush Island and traditional utility finance for new clean assets.
• 40% EIR, Moderate leverage, Capital Recycling– This capital recycling scenario assumes a $1.9 billion EIR loan. The loan is recovered through a dedicated surcharge. For ratemaking purposes, an amount equivalent to the full EIR proceeds is assumed to cover Rush Island cost recovery as well as $2.9 billion in utility capital (both debt and equity at the authorized rate of return) for the reinvestment portfolio.
  ‌‌
  The utility sees net growth of $2.9 billion in rate base. The utility also benefits from having $513 million in relatively short-duration Rush Island rate base with uncertain prospects for cost recovery “recycled” into $513 million of longer-duration clean energy rate base. As in the case with securitization, for regulatory purposes, the company’s approved capital structure and rate of return are calculated excluding the off-balance sheet EIR debt. Ratepayer savings are $689 million (NPV 2024$) or 18% lower than BAU. Year 1 costs fall to $271 million, and three-year forward earnings are $110 million, or 58% of the earnings in the BAU scenario. This is an attractive outcome for ratepayers (who benefit from higher leverage across the rate base) and on a risk-adjusted basis for shareholders (who now earn on a rate base comprising only high-quality components).
• 50% EIR, High leverage, Capital Recycling– This scenario increases the EIR loan size to $2.4 billion. Ratepayer saving grow to $862 million, the highest savings scenario we analyzed. This is the least attractive outcome for shareholders; three-year forward earnings are $88 million.

As with Alliant, we find that Ameren can best balance the interests of its customers and shareholders with a scenario that makes use of capital recycling along with moderate EIR leverage, providing 18% consumer savings relative to the BAU while delivering 58% of the BAU earnings with lower risk. Securitization is still an attractive alternative but has higher transaction costs and has become less attractive due to recent changes to bond indexing that have increased the interest rate on securitization bonds.

Exhibit 5: Ameren Savings Comparison

Exhibit 6: Summary of Ameren Outcomes

For securitization transaction costs, we relied on Ameren’s stated transaction costs of $6.6 million up-front and $792,000 annually. This roughly matches our own experience — our securitization modeling typically assumes $3 million plus 0.7% of the issuance size in up-front transaction costs ($6.6 million total on the $513 million needed for Rush Island), and $300,000 plus 0.05% of the issuance size in annual costs ($556,000).

Exhibit 7: Ameren Transaction Costs Comparison

To estimate EIR transaction costs we referred to LPO guidance, which notes a facility fee of 0.6% of loan principal up to $2 billion and 0.1% thereafter. There are also third-party expenses ranging from $1 million to $4 million; we adopt the lower bound of $1 million, as the due diligence for EIR applications is expected to be simpler than previous Title 17 projects that required innovative and emerging technologies. LPO guides to an annual maintenance fee of between $150,000 and $500,000 depending on complexity; we put these annual fees at $300,000.

The NPV of the transaction costs for securitizing Rush Island is $10.5 million based on Ameren’s given numbers. In the scenario where a 30% EIR leverage loan is used for new assets alongside securitization of Rush Island, the NPV of total transaction costs rises to $17.2 million. However, when a moderate leverage 40% EIR loan is used without any securitization, the NPV of total transaction costs is only $7.8 million — a decrease of 55% relative to the 30% EIR leverage plus securitization scenario, while the NPV of ratepayer savings increases by 15% and three-year forward earnings decline by only 1%.

For large EIR loans, the amount exceeding $2 billion is subject to a lower facility fee of 0.1%. If Ameren chooses to utilize 50% EIR leverage and forego securitization, transaction costs are only $8.2 million, a 4% increase over the transaction costs of the 40% EIR scenario, while the NPV of ratepayer savings increases by 25% and three-year forward earnings decline by 20%.

We have seen that EIR with capital recycling can be an attractive way for utilities to balance the needs of shareholders and customers, allowing them to mitigate the risks and costs associated with the legacy of their existing system while investing in lower-risk, low-cost, long-term clean assets. However, the use of EIR financing also brings federal compliance requirements that may delay implementation — and must be considered when weighing the potential benefits of using the EIR for capital recycling relative to other options. Here, we provide a brief overview of these challenges and link to resources that can help utilities and regulators better understand how to address them.

NEPA

EIR-financed projects must comply with the National Environmental Policy Act (NEPA), which can lead to time-consuming and costly reviews to determine if proposed projects will have significant environmental effects. Review under NEPA can occur in three forms:

1. Projects that will “significantly affect the quality of the human environment,” require a full Environmental Impact Statement (EIS), which typically takes 1.5 to 2 years to complete.
2. Projects determined to have no significant impact only require an Environmental Assessment (EA), which typically takes 6 to 9 months.
3. Categories of projects that have been predetermined not to have a significant effect on the environment require Categorical Exclusions (CATEX) reviews, which typically take only 1 to 3 months.

DOE has issued a proposed rulemaking to make it far easier for many clean energy projects to qualify for CATEX. The proposal would:

1. Modify the categorical exclusion for upgrading and rebuilding existing powerlines (existing CATEX B4.13) to remove a previously imposed requirement that projects be no longer than 20 miles and also to allow “small” (but no longer necessarily “minor”) segments to be relocated “within an existing right of way or with otherwise disturbed or developed lands;”
2. Establish a new categorical exclusion (CATEX B4.14) for the construction, operation, upgrade, or decommissioning of battery or flywheel energy storage system “within a previously disturbed or developed area or within a small area contiguous to a previously disturbed or developed area;” and
3. Modify the categorical exclusion for the installation, modification, operation, and removal of solar photovoltaic systems (existing CATEX B5.16) “on a building or other structure or, if located on land, within a previously disturbed or developed area” to remove the current area limitation of 10 acres and also to cover “decommissioning” activities.

For EIR loan disbursement to take place, projects with a value at or exceeding the amount of the disbursement must have demonstrated NEPA compliance. Ameren Missouri aims to retire Rush Island in late 2024; EIR clean energy projects that qualify for CATEXes or EAs could be ready for EIR funding at that same time. Environmental consultants experienced with NEPA reviews could help applicants navigate the NEPA process and properly determine which clean energy projects would be subject to which types of NEPA reviews — and ensure robust documentation of potential project impacts to reduce the risk of successful litigation of DOE’s NEPA decision. EIR applicants can further mitigate potential risks of delay due to litigation (particularly, in rare cases, the issuance of an injunction halting project construction) by incorporating robust community engagement around potential project impacts in developing their community benefits plans, an important requirement for all loan applicants.

The Davis-Bacon Act and the Cargo Preference Act

The Davis-Bacon Act imposes certain wage requirements on contractors or subcontractors working on projects financed by LPO. The IRA itself is not a Davis-Bacon-related act, but the IRA clean energy tax credits do require that workers be paid prevailing wages no less than wages determined by the Department of Labor for compliance with the Davis-Bacon Act or, failing the payment of such wages, to have the credit values divided by a factor of five. Full Davis-Bacon Act compliance, which is necessary for EIR lending, entails additional recordkeeping beyond what is needed to obtain IRA tax credits without the factor of five haircut, though these incremental administrative costs are likely to be small relative to the impact of the wage boost.

The Cargo Preference Act requires the use of US-flag vessels to ship cargo financed by the US government. For the purposes of LPO, this typically means that at least 50% of gross tonnage must be shipped on US-flag ships.

Entities applying for LPO financing are required to include cost assumptions of complying with the Davis-Bacon Act and Cargo Preference Act in their Part 2 applications.

• 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 for resource costs, utilizing moderate learning curves over a 30-year cost recovery period.
• Tax Credits: We assume that the production tax credit 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 no-adder assumption is also conservative, as it is likely that the energy communities adder will apply for some of the projects.
• Utility Financial Metrics: We relied on the latest Alliant and Ameren rate cases and the companies’ 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 weighted average cost of capital (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. 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 as a baseline EIR financing equivalent to the debt ratio of the utility for new clean energy. For capital recycling scenarios, additional EIR financing equivalent to the unrecovered plant balance of the identified retiring coal plants is assumed to finance the recovery of the coal plant balance, and the remainder of EIR financing goes toward the new clean assets. We also look at what happens when that additional debt displaces future corporate debt, as well as what happens when it does not, and thus alters the utility’s approved equity ratio. For the scenarios that do not alter a utility’s equity ratio, we estimate that the additional savings are achieved through displacing future corporate debt. The remainder of required capital is modeled as traditional utility financing. 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. Finally, we assume EIR loans are structured as off-balance sheet financings for capital recycling scenarios 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’ 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 close to what Ameren modeled — we estimate $103 million in savings, while Ameren estimates $75 million in savings. All NPV savings are in 2024 dollars.