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Utilities Primer

Investor-owned utilities provide electricity and gas to commercial, industrial, and residential customers. Roughly 80% of the sector’s earnings are derived from electric operations, followed by 15% natural gas, and 5% for other. The utility sector should deliver 9-10% annual returns for investors over the next few years, driven by a 3.5-4.5% dividend yield and an average 5-7% EPS growth rate for most utilities. Given how low risk the sector is from an earnings or disruption standpoint, I view total returns as attractive from a risk adjusted standpoint.

The key factors when analyzing a utility include the percentage of earnings from rate regulated utilities compared to non-utility earnings, the regulatory environments the utility operates in, expected capex growth, and expected load growth in the service territory. As mentioned, the majority of the sector’s earnings are from electric and gas utilities, with the percentage of non-utility earnings less than 20% for most utilities. Historically, electric and gas utilities had diversified into non-utility businesses such as midstream, merchant power generation, and LNG facilities. However, that trend has recently reversed, and most utilities have sold or spun-off their non-utility businesses due to heightened concerns around decarbonization and regulatory risks.

Regulated utility earnings drivers

State regulation


At the state level, each state varies in terms of how they set rates for electric and gas utilities, although the process is similar from state to state. Rates are set to allow utilities to earn an ROE on their investments and to recover costs (operating expenses, taxes, depreciation), in a timely manner. State utility commissions also determine the timing and prudency of cost recovery.

Here is the formula for the utility revenue requirement:

=(Rate base * ROE) + operating expenses + depreciation + taxes

In 34 states, utilities are vertically integrated, meaning that the utility will earn a regulated ROE on their generation, transmission, and distribution assets. In the other 16 states, generation has been deregulated, and only transmission and distribution assets earn a regulated ROE. In the deregulated states, power is procured from independent power producers (IPP’s), or the merchant generation (non-regulated power generation) operations of a utility.

deregulated markets
Source: https://www.electricchoice.com/map-deregulated-energy-markets/

Rate Case Process

To request higher rates, Utilities file a rate case with the sate utility commission. The key components include the allowed ROE, the capital structure (typically 50% debt/50% equity), and the prudency of other expense. Rate cases are typically filed every few years, although this varies from state to state.

Rate cases are based on a test year, which is the reference point for the revenues and expenses. Test years can be based on historical results, forecasts, or a combination. Forward test years are best for utilities, as they allow costs to be recovered as incurred, minimizing any potential timing lags. Different rates are set for each customer class, with residential customers paying the highest rates, followed by commercial, and then industrial customers. Typically rate cases take a year to settle, so it is preferential for utilities to file less frequently and have riders in place to recover costs along the way.

To make this process more concrete, here is an example from one of XEL’s subsidiaries in North Dakota. They have requested a $22mn rate increase based on a 10.2% allowed ROE, a 52.5% equity ratio, and a 2021 forecasted test year. XEL expects a decision in 2H21, at which point the rate increase or decrease will be determined by the North Dakota state utility commission.


North Dakota rate case exampleSource: XEL 2021 Investor Presentation

Each state varies in terms of its attractiveness based on allowed ROE’s, cost recovery mechanisms, and other rate design elements. Alternative rate designs can include decoupling mechanisms where volumes are decoupled with revenue, to incentivize energy efficiency initiatives and reduce weather related revenue volatility. Rates can also include various expense trackers to provide for timely cost recovery of operating expenses that are typically outside the utility’s control such as fuel and purchased power, bad debt expense, and other unique circumstances. As mentioned, rates are set at a different level for each customer type, as well as for different times of day (peak vs. non-peak). The below chart shows one ranking of state regulatory environments, with the Southeast and Midwest considered the most favorable regions.

Utility regulation by state

Federal Regulation

Federal regulation is largely driven by the Federal Energy Regulatory Commission (FERC) who regulates some interstate electric transmission lines, especially if they contribute to regional commerce. Additionally, FERC regulates non-utility assets such as interstate natural gas transmission pipelines, and wholesale power markets. FERC is considered one of the premium U.S. regulators, due to higher allowed ROE’s than state allowed ROE’s. Additionally, FERC allows for concurrent cost recovery through formulaic rates, minimizing the timing of cost recovery. As a result, utilities are highly focused on increasing their exposure to FERC regulated assets.

Allowed/Earned ROE’s

Allowed ROE’s for electric and gas utilities have trended downwards for years with declining interest rates. At YE20, allowed ROE’s nationally are roughly 9.4%, although there are large variations from state to state. Importantly, there is larger than average gap between allowed ROE’s and the 10YR UST (8.46% as of YE20) compared to the historical average of 6%. If interest rates rise, allowed ROE’s should increase as well, but likely with a lag considering utilities are effectively over earnings relative to history.


Allowed ROE vs. 10YR USTSource: S&P Global Market Intelligence / Regulatory Research Assoc. and EEI Finance Department / U.S. Federal Reserve

Capex Growth

For years utilities grew EPS at 2-4%/yr. driven by inflation and population growth, but more recently utilities have targeted 5-7% annual EPS growth driven by a massive capex buildout. Utility sector capex has increased from $74bn in 2010 to $140bn in 2020, driven by renewables and natural gas generation, as well as grid modernization and storm hardening of outdatd T&D infrastructure. Low natural gas prices have reduced the generation portion of customer bills, allowing for higher capex without a massive increase in electricity rates.


Utility sector capexSource: https://www.eei.org/issuesandpolicy/Finance%20and%20Tax/EEIIndustryCapexFunctional2020.pdf

One of the key drivers of capex has been the replacement of coal plants with natural gas and renewables generation. Natural gas and renewables are typically less expensive than coal generation and are better for the environment due to lower GHG emissions and lower air emissions (NOx, Sox, Particulate Matter). Natural gas generation produces roughly 50% of the GHG emissions of coal fired generation, while remaining cost competitive, due to the substantial increase in U.S. natural gas supply over the past decade.
Shifting generation mix

Renewables have become much more cost competitive as well, although the actual economics depend substantially on where in the U.S. you are located, as wind and solar resources vary meaningfully across the country.

Wind solar cost Source: NEE 2020 EEI Presentation

Going forward, federal policy will be a key driver of capex, as the Biden Administration has proposed to decarbonize the power sector by 2035. House Democrats recently put forth a bill to boost tax credits for renewables and carbon capture projects. The bill extends the existing tax credits for solar and wind through 2026 and makes certain storage technologies eligible for tax credits as well, ultimately incentivizing greater investments in these technologies.

Additionally, the Biden administration has discussed further investments in EV’s and EV infrastructure which would also benefit utilities through capex opportunities and additional load growth (discussed below). I also expect to see legislation supporting energy storage, provide additional investment opportunities.

Load Growth (electricity demand)

Demand for electricity is driven by population growth, customer mix (residential, commercial, industrial), and changes in the weather. Electricity demand has been stagnant since the Financial Crisis due to energy efficiency initiatives (improved building insulation, increased efficiency of appliances, and LED light bulbs) and the continued shift from a manufacturing to a services-based economy.

Electricity demand
Source: https://www.eia.gov/totalenergy/data/monthly/pdf/mer.pdf

EIA forecasts that electricity demand will increase by 0.6-1.2%/yr. through 2050, likely well below real GDP growth over that time frame. However, increased electrification of transportation and heating could potentially add up to another 1.5%/yr. of load growth, depending on federal legislation supporting clean energy. This would represent a meaningful shift in electricity demand and is one of the key sector trends to follow. For example, XEL expects a 0.6-0.7%/yr. increase in sales growth in CO from increased EV penetration and plans to spend $2bn through 2030 on EV charging infrastructure.

Non-utility businesses:

Merchant power generation (Primarily EXC, PEG, NEE, and SO)

IPP’s make money from two revenue streams: payment for electricity produced (volume and pricing model), and separately for capacity payments which are designed to incentivize power plants to remain in service for regional reliability. As these prices are set in competitive markets, there is much less FCF stability compared to regulated utility operations. IPP’s can also sign Purchase Power Agreements (PPA’s) with customers to sell them electricity for a period of typically 10-20 years. Usually, these contracts include inflationary price escalators and provide much greater FCF stability. New renewables projects are largely backed by PPA’s.

Midstream (Primarily DTE, D, SRE, and BRKHEC)

While there are many different midstream asset types, utilities typically own large natural gas pipelines and storage assets, given the prominence of natural gas for electricity generation and for the connection to natural gas distribution. For the most part FCF for these assets is backed by long-term contracts with high quality counterparties (typically other utilities), however revenues can be tied to transportation volumes and occasionally commodity price differentials depending on the asset type. These assets are riskier than regulated utility assets as you don’t have regulated cost recovery, and there can be greater FCF volatility due to changes in commodity prices.

LNG (Primarily, D, SRE, BRKHEC)

Liquefied Natural Gas (LNG) facilities have been built to import and more recently export, liquefied natural gas. LNG exports are primarily to Asia as well as to Europe. LNG contracts are typically for 10-20 years with high quality counterparties (foreign governments, oil and gas majors), and provide relatively stable FCF, as these contracts are usually written for set rates and LNG volumes. The biggest risk for LNG is around cost over-runs as well as over-supply of LNG infrastructure.

Sector Risks

Customers exiting the grid
This could happen as a result of increased rooftop solar penetration for residential customers and large-scale solar investments by commercial and industrial customers. Currently, this is not economical for most utility customers, as renewables need to be paired with energy storage to truly exit the grid. In many parts of the country, customers would need several days’ worth of back up battery storage.

However, even if customers don’t exit the grid, net metering could have a negative impact for utilities. Net metering is the ability to sell back power to the grid at the retail price, which is 2-3 the wholesale price. In most states, Utilities have won the war on rooftop solar/net metering as regulators have only allowed customers to sell back excess power at the wholesale rate. This substantially reduces the economic incentive for customers to invest in solar. This dynamic varies substantially by state is a key risk to monitor. But for the time being it is more economical for the utilities and merchant generators to invest in utility scale renewables and provide clean energy broadly.

Interest rate sensitivity
Outside of recessions, Utilities typically trade inversely to interest rates as utilities are viewed as a bond proxy. So an increase in interest rates will usually negatively impact valuations for the sector, and vice versa.

Inflationary pressure
As mentioned, utilities frequently recover expenses with a time lag, which is exacerbated during a period of high inflation. As a result, earned ROE’s may undershoot allowed ROE’s during an inflationary period. However, the extent of the impact from high inflation will depend on the specific rate setting mechanisms in each state.

Large project risk
This risk primarily relates to large non-utility projects. Recently Duke Energy and Dominion cancelled the Atlantic Coast Pipeline (ACP) interstate natural gas pipeline project, after spending more than $3bn, due to delays and significant cost over-runs. None of the money spent on the project will be recoverable, as this was a non-utility project.

Additionally, there have been some expensive generation projects such as Kemper coal gasification project which was abandoned in 2017 after Southern spent more than $7.5bn on the project. Another large project in process is the Vogtle Nuclear project which currently has a $25bn price tag and is substantially over budget. When costs dramatically exceed expectations, there can be political pressure for the utility to absorb some of the cost and not fully pass on costs to rate payers.

Comps

Comps

Disclaimer
This article is not to be taken as financial advice and is not recommending the purchase or sale of any particular securities. This information is meant merely for informational and discussion purposes only. Please do your own research or seek out a licensed financial professional for help with personal finance and investment decisions.

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