In Conversation with Massif Capital - NA Utilities Executive

At Massif Capital, we possess valuable and unique insights into fundamental, technical, and operational aspects of the businesses and industries we invest in. These insights do not exist in a vacuum and can be applied broadly. By incorporating our insights into your broader investing decisions, we can help you achieve superior returns and mitigate risk beyond your investment with Massif Capital.

Besides in-depth research, our unique insights are generated by our network of contacts in the real asset industries we focus on. Those contacts provide us with valuable insights that are difficult to generate in any way other than being an industry participant. In the future, we will publish a monthly series called In Conversation with Massif Capital that will provide readers with either excerpts from a single conversation we had during the previous few months or excerpts from multiple conversations, along with some Massif Capital color commentary. 

This series will not be published on our blog or website and will only be available to existing and accredited investors who sign up to receive these monthly discussions.

The following are excerpts from a conversation we held with a North American Utility executive who spent his career focused on growth and development opportunities for NA Utilities. The excerpts have been edited for readability. The goal of the conversation was to gain a deeper understanding of some of the growth challenges utilities face, specifically those focused on growth via renewables, which is the case for most utilities in the United States and Canada.

Why we think this is a timely and vital conversation:

The American electrical system has undergone significant change in the last 20 years. Natural gas quickly replaced coal in the early 2000s, and a focus on heavily deregulated economic structures has been sidelined. Renewable energy has quickly gained traction during the last ten years, accounting for 30% of total generation capacity, a deeply deceptive statistic as renewables (excluding Hydo) generate only 18% of power in the US due to capacity factors.

In theory, the Inflation Reduction Act, which has given utilities incentives to switch from fossil fuels to renewable energy sources, presents an appealing investment opportunity. It could change utilities' earnings growth and shareholder base, eventually leading to stronger multiple premiums. Over the next five years, Goldman Sachs expects to see a 27% increase in capital investment compared to the previous five, which will result in a 5-year EPS CAGR of 6% as opposed to the 10-year average of 4%.

We are less convinced this environment will yield meaningful returns for investors. In the 1930s investment classic Security Analysis by Benjamin Graham and David Dodd, the authors note that “a business which sells at a premium, does so because it earns a large return on capital; this large return attracts competition; and, generally speaking, it is not likely to continue indefinitely.” The return on capital that businesses earn and the influx or ignominious exit of competition to an industry are critical variables in defining the industry capital cycle, and the capital cycle provides investors a framework to investigate the complex relationships between share prices and replacement values and between investment returns and changes in the competitive environment.

Currently, the utility industry in the United States has a messy set of variables that make defining where the utility industry is in the capital cycle difficult. The industry has failed to invest sufficiently in the grid; in certain places, it has invested sufficiently in a generation, but not in all areas, and certainly not if the electrification of the economy picks up. The industry is consistently beset by regulatory challenges that make even the most straightforward investments time-consuming administrative challenges. Most importantly, the industry has forgotten how to invest in profitable growth.

The costs of future investments are likely enormous and can only be covered by electricity costs far higher than the current rates.  We would suggest that investors look to the situation in California to understand what is in store for the rest of the United States, as the incentives laid out in the IRA promote the further Californication of the US electricity system. We believe the following statistic captures the problem with the Californication of the US Electrical system nicely: the average cost of a kWh of electricity for an industrial customer in the US is roughly $8.1; in California, the current price is $17.9, down from a $22 peak in the middle of last year.[1]

Over the last five years, industrial demand for electricity in the United States has grown by 20%, and across all sectors, demand has increased by 22%. At the same time, industry debt, as captured by the Dow Jones Utility Average, has risen by 36%, capital expenditures have increased by 37%, free cash flow has fallen by 13%, and margins are largely flat.

It hardly needs saying, but the North American Utility industry faces many difficult years ahead as it navigates a once-in-a-generation transition from a period of stable/falling demand[2] to growing demand. At the same time, the portfolio of generating assets is being changed, and the transmission infrastructure requires replacement. This transition will create winners and losers and more opportunities for active management to generate differentiated returns within the utility industry than at any time in decades.  

Transcript Excerpts

What are the most significant challenges and investment opportunities for utilities at the moment?

Massif Capital Thoughts:  We think this commentary has two interesting takeaways:

• The first is the often-discussed challenge with transmission interconnection in the US. Lawrence Berkeley National Laboratory recently published its annual review of the US interconnections (Link). As has been the case for many years, the wait for interconnection has gotten longer, and the backlog has gotten longer. As of 2023, there are 2.6 TW of generating projects in the queue, with solar and storage projects accounting for 95% of active capacity in the queues and gas making up most of the rest. The median duration in the interconnection queue for projects over 20 MW is now 30 months, and the time from initial interconnection request to commercial operations has reached roughly five years. Utilities are historically conservative in outlook, but we are entering a period in which the slow growth of the past looks to be giving way to more rapid growth. Regulators and management teams must reassess processes and urgency to prevent the grid from falling behind.

•  As of the 4^th Qtr 2023, US Utilities and Transmission operators were in various stages of development on 556 individual lines spanning 18,000 circuit miles that had the potential to unlock 380 gigawatts of new transmission capacity by 2030. These projects depend on a tripling of annual investment into the grid from $65 billion in 2022 to $150 billion in 2030. Unfortunately, these projects are being pursued piecemeal, with coordination between Interconnection regions. Grid expansion could continue to follow the pure regional buildout. Still, the development of the grid without an overall strategy or long-range planning could be detrimental to resilience in the future.  

Regarding EPC (engineering, procurement, and construction) and cost increases, is that primarily driven by labor costs?

Massif Capital Thoughts: If we focus on the significant growth sector for US utilities in the last 12-24 months, it is impossible to say interest rates have not impacted development and buildout. However, it is also unclear how significant that impact has been. Evidence of this can be found in the levels of investment in US solar and wind, which hit a record $88 billion of new asset finance investments in 2023, up 78% over the 2022 total, despite rising cost of capital.

Despite the investment boom, our expert's comments on project IRRs getting squeezed are spot on. In 2H 2023, the spread between the equity hurdle internal rate of return (of a US wind or solar project) and the risk-free rate was at its lowest level in over a decade. 

While our expert believes that the most significant impact on economics would be felt and worked through in the first half of 2024, we are less confident. Starting in 2020, utilities, which had been issuing bonds with an average tenor of 10 years for more than five years, began issuing shorter and shorter tenor bonds, dropping to a historic low last year of 5 years. At the same time, the average coupon inflected in 2020/2021 from a low of between 2.6% to a 2023 average of 5.4%. Meanwhile, loans and project finance costs in 2023 reached 7% to 8%, depending on the project. In the last few years, due to the cost of project finance and loans vs. bonds, the larger, more established utilities or project developers have opted to raise capital via bonds. At the same time, the smaller players have had to endure the increased cost of borrowing that comes with loans/project finance.

Either way, bonds or loans, most utilities and project developers hope to refinance existing debts when interest rates come down. Many power utilities have large tranches of existing debt due for maturity over the next two years. We believe that some firms may have to consider asset sales to raise capital if the lender's appetite for refinancing loans dries up, the companies do not have enough cash to pay for the maturing debt, or interest rates remain high, a scenario which has a reasonable probability that we believe is mostly being dismissed.

Will regulated or unregulated utilities survive the current environment better? There was a period when the unregulated thrived versus the regulated. Are we now transitioning to the opposite situation?

Looking at the utility space now, there are a couple of apparent centers of demand growth. One is data centers, presumably tied with AI and things of that nature in the cloud. The other is the growth in demand for EVs, heat pumps, etc. When utilities think through their development pipelines in the future, what role do those demand drivers play in their analysis? 

You can't speak for everyone, but based on your experience, what are Utilities thinking/saying internally about the idea of a principally renewably powered grid and the loss of things like coal and the baseload power that is on all the time? Do they find that idea realistic? Do they find it outlandish? Do they say, "Well, we can probably do it, but it's going to be much harder than everyone thinks?" 

Massif Capital Thoughts: We find little evidence to support the idea that a 100% renewable electrical grid is currently feasible, save for unique situations, none of which we believe are in the US. Based on other conversations with utility industry folks, we find little reason to question this expert's claim that the industry, by and large, does not think 100% renewables plus storage grid is feasible in the near term.

The idea in the future, at least your idea, is that those who have a regulated component that can help create a rock-solid balance sheet have the opportunity to benefit in the long run from owning unregulated but volatile electricity assets.

This series will not be published on our blog or website and will only be available to existing and accredited investors who sign up to receive these monthly discussions.

[1] EIA Data

[2] Between 2008 and 2020 total US electricity demand only increased 8.2%.