Spending on utility infrastructure and renewable energy projects in the US and Canada is expected to continue full speed ahead despite any challenges posed by higher interest rates.
But the increased spending, associated regulatory cost recovery and long lead times for commercializing emerging technology could all begin to weigh on the power and renewables sector’s ability to secure funding for building infrastructure, industry experts told S&P Global Commodity Insights.
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The industry has been spending more than $150 billion annually since at least 2020, and S&P Global Ratings forecasts capital spending by investor-owned electric, gas and water utilities in the US and Canada to be about $200 billion in 2023. These rising capital expenditures are exerting pressure on the credit quality of North American regulated utilities, S&P Global Ratings analyst Gabe Grosberg said.
Building power generation and transmission infrastructure as the US undergoes a sweeping transition to a cleaner system is expensive, and investor-owned utilities taking on large amounts of debt have traditionally done so with the expectation of recovering those costs from ratepayers.
Despite high spending across the sector, S&P Global Ratings revised its outlook on the regulated utility industry in May back to stable after maintaining a negative outlook since early 2020. NextEra Energy Inc., the largest utility in the US by market capitalization, is expected to spend nearly $18 billion alone in 2023, according to S&P Global Market Intelligence data.
“First of all, the economic indicators appear to be somewhat improving. Inflation appears to be somewhat slowing,” Grosberg said, adding that natural gas prices have “come down substantially over the last several months,” creating more cushion in customer bills.
CreditSights analyst Andrew DeVries agreed that interest rates are not pressuring utility debt.
“I don’t see anyone doing anything differently owing to the higher rates,” he told S&P Global Commodity Insights. “Two-thirds of the debt is at the [operating companies], so those higher rates are a direct pass-through to consumers.”
Financial cushions
But S&P Global Ratings also pointed out that rising interest rates, higher capital spending and “the strategic decision by many companies to operate with only minimal financial cushion from their downgrade thresholds” will continue to put pressure on the industry.
“Typically, companies that operate within 100 basis points of the downgrade trigger, we consider that to be minimal financial cushion,” Grosberg said. “Roughly, today about 35% of the industry is actively managing their financial operations in a manner that only has minimal financial cushion toward their downgrade trigger.”
Some equity analysts have suggested that percentage might be smaller. Mizuho Securities recently highlighted PPL Corp., with electric utilities in Kentucky, Pennsylvania and Rhode Island, as “one of the few utilities with a credit cushion” due to its funds-from-operations-to-debt target of 16% to 18%, compared to S&P Global Ratings’ downgrade threshold of 16%.
Debt continues to be the primary way large utilities are raising capital, particularly as investors react with clear aversion to any sign of potential equity issuance.
For example, FirstEnergy Corp.’s stock fell about 3% during intraday trading April 28 after the company disclosed in a Form 10-Q filing that it “may utilize instruments other than senior notes to fund its liquidity and capital requirements, including hybrid securities.”
“What we’ve seen is names like [Duke Energy Corp.] and PPL and a few others issue convertible bonds and converts obviously have dilution for shareholders,” CreditSights’ DeVries said. “If you do a convert, it implies more equity is going to be issued,” prompting questions on whether long-term earnings growth is at risk.
“That is what everyone is focused on, any sort of hit to the EPS story,” DeVries said. “Is that hit going to come from higher rates? Absolutely not.”
Regulatory risk
Lillian Federico, energy research director at Regulatory Research Associates (RRA), a group within S&P Global Commodity Insights, said the high-interest and high-spending environment signals there will continue to be an uptick in utilities seeking cost recovery through base rate increases imposed on captive customers.
“I don’t think they’re going to have a choice,” Federico said in an interview, adding that the challenge will be navigating “regulators’ sensitivity to costs” and customer tolerance for rate increases.
“The thing I worry about is authorized ROEs and will they follow the trend of an increase at pace with interest rates,” Federico said.
RRA recently identified 11 states that could see a shift in their regulatory climate and investor risk based on the outcome of ongoing proceedings or policy developments. RRA also sees inflation, rising interest rates and the potential for a recession posing unique hurdles for the capital-intensive industry.
Moody’s Associate Managing Director Michael Haggarty noted that the rating agency has had a negative outlook on regulated utilities since January.
“To the extent regulators start to not be able or willing to provide the rate increases a utility needs, that’s when the pressure on ratings starts,” Haggarty said.
Project funding
For renewables, any broad risk to project-level debt for proven technologies like wind and solar would require a sustained economic downturn, specifically, long periods of high inflation or declining power prices, according to Alex Nouvakhov, Fitch Ratings’ senior director for global infrastructure and project finance.
But those projects also usually have fixed-rate amortizing facilities, avoiding any exposure to short-term interest and events like the Silicon Valley Bank collapse, while “refinancing volatility is baked into a lot of our cases,” Nouvakhov said.
Projects using nascent technologies boosted by new federal tax credits in the Inflation Reduction Act (IRA), on the other hand, cannot yet access that kind of commercial debt.
Fitch has started rating project debt for emerging technologies like hydrogen, Nouvakhov said, adding that projects with “strong offtake contracts can get to investment grade.” But he also acknowledged that “whenever you have something with technology or scale-up risk it may not be the best strategy to go straight to commercial markets.”
Enter the US Department of Energy’s Loan Programs Office (LPO), which “has a much easier time managing … perceived technology risk,” according to the office’s director, Jigar Shah.
The LPO had $77 billion of applications before the IRA passed and is now reviewing $121 billion, he said in an interview. Thanks to that legislation, the office has $100 billion of additional loan authority for existing programs as well as another $250 billion for a new program focused on energy infrastructure reinvestment, bringing the LPO’s total potential lending capacity to $412 billion.
Unlike traditional lenders, the office can also issue longer-term debt for companies looking to build new nuclear, transmission, hydrogen, carbon capture and critical minerals facilities.
“The commercial markets are really only comfortable doing about seven years, but this is infrastructure so you need to go out 20 or 30 years, so LPO is uniquely capable of providing the duration necessary to unlock certain projects,” Shah said.
With regard to the timeline for newer technologies to become commercially viable enough for more traditional debt funding, he pointed to the LPO’s experience with solar.
“We approved the first five 100-MW solar projects in 2010, 2011, and those projects were built by 2013,” Shah said, “but it wasn’t until 2018, 2019 that the markets were properly functioning for solar projects.”
Private credit
Private credit is also stepping in as an alternative to banks, with firms like Blackstone Inc., Ares Management Corp. and Copenhagen Infrastructure Partners K/S establishing debt funds targeting the North American energy transition. Credit funds and accounts managed by KKR & Co. Inc., for example, in May agreed to buy $550 million of solar energy loans made to customers of residential solar and storage provider SunPower Corp.
“Private credit continues to stand out with its speed of execution, certainty and flexibility, which makes it attractive for borrowers,” Rob Horn, who heads the global sustainable resources group for Blackstone’s credit platform, said in an email. “We are able to transact at scale with an efficient cost of capital which is uniquely suited to the dynamic needs of borrowers in the energy transition.”
“[T]he IRA can help bring new technologies down the cost curve, putting them in the position where private capital can fund them — we saw that trend with solar and wind 10 to 15 years ago,” Horn added.
Private credit is also starting to work with banks on project financing deals, S&P Global Commodity Insights Climate and Cleantech Executive Director Peter Gardett said in an interview.
“If we’re talking about one of these big hydrogen projects on the Gulf Coast, they generally create a special-purpose vehicle that’s a company in its own right and that project finance has been difficult to obtain because banks aren’t really lending at the moment,” Gardett said. “By bringing in private credit to take on some of the risk banks don’t want to take, it gives private credit a role and also makes the projects themselves bankable.”
“That could be a new model for the way some of this stuff gets done,” Gardett added.
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