Energy & Commodities

Renewables at a Crossroads: The Inflation Reduction Act and Utilities

The IRA mostly impacts two players disparately: vertically integrated utilities developing renewables on the balance sheets and unregulated competitive developers who typically work with tax equity investors to take advantage of previous tax credit policies.

The IRA levels the playing field between these two players through four major provisions:

Transferability of tax credits allows utilities to take advantage of tax credits and significantly reduces, if not eliminates, the need for tax equity investors
Production tax credits for solar makes previously unavailable credits available to utilities, as the investment tax credit (ITC) was not utilizable
Exemption of storage from tax normalization allows utilities to develop storage without tax normalization
Prevailing wage requirements favor regulated utilities and their tendency to access unionized labor on future renewable projects since most unregulated renewables developers have historically used non-union labor

The combination of these changes eliminates the advantage that the unregulated renewables players have enjoyed to date. Further, it creates an essentially irresistible and unprecedented investment incentive for utilities: The more capital utilities invest in building renewables, the lower their customer rates will be. This is because, in most circumstances, the production tax credits substantially offset the total cost of installing and operating renewables—including the utilities’ allowed return on equity—and they can pass these savings to ratepayers.

Rate-regulated utilities have another fundamental advantage in renewables development. Utilities are largely insulated from development and even most operational risk. Risks such as cost and schedule increases permit delays, and ratepayers now bear many operational risks so long as the utilities can demonstrate a lack of negligence. For example, the utilities exposed to losses in February 2021’s Winter Storm Uri in Texas will largely recover those losses through securitization.

Of course, many utilities were “unbundled” from generation as a part of market deregulation in the 1990s. However, most U.S. power markets are a hybrid of deregulated and unbundled markets. Even a largely unbundled market like ERCOT still has vertically integrated utilities. SPP and MISO are comprised of approximately 70 percent vertically integrated utilities. There is even a longer-term question about whether the competitive markets can survive this large intervention in the markets.

Therefore, unregulated renewables developers will need to compete with vertically integrated utilities in most U.S. power markets and the utilities can be expected to maximize their renewables investments to the highest amount allowed by their regulators.

This increased level of investment in renewable projects will drive a substantial increase in the volume of renewable energy projects. Ultimately, this will exacerbate challenges to interconnection queues, tighten transmission constraints and increase competition for resources across the supply chain and in the labor markets.Arguably, utilities have an inherent advantage with respect to interconnection costs with their ability to tie projects into their own existing infrastructure. This will likely create oversupply and congestion for all participants in the market and exacerbate basis risk for those at disadvantaged interconnection points.

Ever since the Energy Policy Act of 2005, wholesale power markets have been impacted by the combination of federal tax credits and state renewable portfolio standards that have brought renewable projects into the wholesale markets, often bidding at zero or negative costs. For this reason, prices in the U.S. wholesale markets for nearly two decades have not been sufficient to justify investment in, or even support the economics of existing, dispatchable power resources.

This has led to enormous retirements of dispatchable assets with little replacement. This, in turn, has created enormous volatility in power markets with high levels of renewable penetration. When the intermittent resources are not available, this can lead to shortages, price spikes and oversupply when the wind blows or the sun shines. For example, the 2023 winter storms in Texas froze power for 430,000 customers.

These swings drive significant volatility in the markets and are problematic for any players with exposure to spot prices. The IRA will likely only accelerate and exacerbate this problem by fast-tracking the deployment of unreliable renewables without a reliable safety net.

Renewable projects structured with tax equity investors are complex and require millions of dollars' worth of legal, accounting and tax work. These projects are time-consuming to negotiate; this can create friction in pulling together all the elements required to get a project to a final investment decision: permitting, power purchase agreements, tax equity financing, construction lending, etc.

This friction is a natural limiting force in the pace at which renewable projects can currently be brought to the market. The IRA and the transferability of tax credits can be expected to remove a significant amount of this friction. This not only disadvantages the tax equity investors that still must bear all of these burdens, but it also means that the pace of renewable projects coming to market can be expected to accelerate significantly.