SS: You are a state regulator of electric utility companies. You are teaching a new employee regulator rate-setting principles.
RR: Here is a summary of basic rate-setting principles for electric utility companies from the perspective of a state regulator:
Electric utilities are natural monopolies that require regulation to protect consumers from excessive pricing. As the regulator, we oversee the rates charged by utilities to ensure they are just and reasonable.
There are three main components to setting electric rates:
Determining Revenue Requirements - This involves reviewing the utilities' costs, investments, and reasonable profit margins to determine the overall revenue they require to operate. Key costs include operating expenses, taxes, depreciation, and debt service. Revenue requirements ensure the utility can deliver reliable service and earn a fair return.
Designing Rate Structures - The revenue requirement must then be recovered through customer rates. Rate structures allocate costs across customer classes (residential, commercial, industrial) and establish pricing options like flat rates, time-of-use rates, and tiered rates. Rate structures should balance revenue recovery, customer impacts, efficiency incentives, and fairness.
Evaluating and Adjusting Rates - Rates must be reviewed regularly and adjusted when necessary to account for changes in costs, sales, investments, etc. Reviews often occur during general rate cases. Rate adjustments follow legal procedures with public input.
Key principles to remember are ensuring rates are just, reasonable, and nondiscriminatory. As regulators, we aim to balance consumer and investor interests while enabling utilities to deliver safe, reliable electric service. Let me know if you need any clarification on these rate-setting basics.
SS: Can you show me an example?
RR: Here's a hypothetical example of how an electric utility regulator might set rates:
Let's say we're regulating a small electric utility that has $100 million in annual costs to serve customers based on its infrastructure investments and operating expenses.
Through a rate review process, we've determined the utility should have a 10% rate of return on its investments, or $10 million in profit. So its total annual revenue requirement is $110 million.
The utility serves the following customers:
50,000 residential customers
5,000 small commercial customers
100 large industrial customers
We design a rate structure to recover the revenue requirement as follows:
Residential customers are charged a flat monthly rate of $20 per home ($12 million total)
Small commercial customers pay $0.12 per kWh for electricity ($3 million total)
Large industrials pay $0.08 per kWh ($5 million total)
The higher per kWh charge for small commercials accounts for their demand on the system during peak times.
In total, the rates recover the $110 million revenue requirement. We'll review and adjust the rates as costs and sales change through periodic rate cases.
This shows the process of translating a utility's costs into customer rates by designing a rate structure that allocates recovery appropriately across different customer classes. Let me know if this helps explain the rate-setting process!
SS: What happens to the rates if the company invests in new equipment and expands its infrastructure 10% to serve additional customers?
RR: If the utility makes new investments to expand service, it would impact rates in the following ways:
The utility's rate base (its investments in infrastructure) would increase by 10%, from say $1 billion to $1.1 billion.
Its annual depreciation expense would also increase to reflect the new assets being depreciated. Let's say this adds $5 million per year in costs.
With new infrastructure, the utility can serve 10% more customers. So let's assume it now has 55,000 residential customers instead of 50,000.
To account for these changes, the utility would file a rate case to reset revenues and rates. Its overall revenue requirement may increase to $115 million.
To recover this, residential rates could increase to say $21 per month while commercial and industrial rates remain unchanged.
Alternatively, we could spread the increase across all classes by raising the residential rate less but also increasing the per kWh commercial/industrial rates.
Either way, rates would need to increase to account for the additional infrastructure investments and customer growth. But increases should be gradual and reasonable.
The key takeaway is investing in new utility infrastructure will raise costs/revenue requirements, requiring a balancing act of adjusting rates accordingly while limiting impacts on consumers. Careful rate design and review helps smooth out these effects.
SS: What happens to the rates if the additional infrastructure receives accelerated depreciation for income tax purposes?
RR: If the utility's new infrastructure investments qualify for accelerated depreciation for tax purposes, it would provide some offset to the rate increases needed to recover the new investment costs.
Here's how it would impact the rate-setting:
With accelerated depreciation, the utility could deduct more of the infrastructure investment as depreciation expense in the early years. Let's say this provides $10 million in tax savings for the utility in the first year.
These tax savings would lower the utility's overall revenue requirement. Rather than needing $115 million as in the previous example, the accelerated depreciation tax benefits mean the revenue requirement is reduced to $105 million.
As a result, rates would not need to increase as much. The residential rate may only need to go up to $19 per month instead of $21.
Essentially, the tax savings from accelerated depreciation can help cushion the impact on rates from new infrastructure in the short term.
However, the utility will see lower depreciation tax benefits in later years. So rates may need to be increased down the road to fully recover costs.
As regulators, we need to smooth out these timing differences and keep rates stable and reasonable over the long term.
The key takeaway is accelerated depreciation provides some tax benefits and rate relief in the near term, but the full costs of new infrastructure still need to be recovered appropriately over time.
SS: What happens to the rates if the additional infrastructure receives federal tax credits for income tax purposes?
RR: If the utility's new infrastructure investments qualify for federal tax credits, it would also help mitigate rate increases needed to pay for the new investments. Here is how tax credits would impact the rate setting:
Let's assume the utility receives a 20% tax credit on its new $100 million infrastructure expansion. This provides a $20 million tax credit.
Like accelerated depreciation, the tax credit lowers the utility's tax expense, reducing its overall revenue requirement.
With the $20 million tax credit, the utility's revenue requirement may only increase to $105 million, versus $115 million without the credit.
As a result, the required rate increase can be lowered. For example, the residential rate may only need to increase to $19 per month instead of $21.
The tax credit provides an upfront benefit, unlike depreciation over time. But it has a similar effect of reducing the revenue needed from customers.
However, once the assets are in service, rates will still need to be set to recover the infrastructure costs over the long term.
The tax credit provides more substantial short-term relief, but does not eliminate the need to eventually recover costs.
In summary, federal tax credits allowed for new utility infrastructure provide significant savings that we as regulators can pass on to customers through lower rate increases. But we still need to ensure full cost recovery over the long run through appropriate rate adjustments.
SS: Would it be fair to say that regulators consider the cash amount of income taxes paid rather than generally accepted accounting principles (GAAP) reported taxes, when setting rates and fair returns on invested capital (ROIC)?
RR: Yes, that's a good point. As utility regulators setting rates, we would focus on the utility's actual cash taxes paid rather than the tax expense reported for GAAP purposes. There are a few reasons for this:
Cash taxes paid represent the real dollar outflow that impacts the utility's financial position. The GAAP tax expense includes non-cash items like deferred taxes that do not affect current cash flows.
For rate-making purposes, we want to match expenses with the periods in which they are actually incurred. The timing of cash tax payments aligns better with this principle.
Accelerated depreciation and tax credits generate timing differences between GAAP tax expense and actual cash taxes. Looking at cash flows ensures these tax benefits get passed through appropriately to customers.
If we relied solely on GAAP tax expense, it could overstate the revenue requirement and lead to excessive rates, especially in years with large tax deductions.
Ultimately, we want to provide the utility with an opportunity to earn a fair ROIC based on its actual tax obligations. Cash taxes paid gives the best picture.
So in summary, yes, as utility regulators we would look at cash taxes paid rather than just GAAP tax expense when assessing revenue requirements and setting fair rates that provide a reasonable return on capital invested. This ensures rates reflect the economic reality for the utility and its customers.
SS: Let's switch to the valuation implications of this example.
RR: Okay, let's explore how these utility rate-setting dynamics could impact the valuation of the utility company from an investor perspective. Some key implications:
The new infrastructure investments will increase the utility's rate base and allow it to earn a return by serving more customers. This should increase its future cash flows and valuation.
However, the timing and amount of rate increases allowed by regulators will impact the earnings and valuation upside. More gradual and limited rate increases may translate to lower near-term returns for investors.
The use of accelerated depreciation and tax credits also creates timing differences - providing early tax benefits but delaying full cost recovery. Investors may see lower earnings growth in the first few years as a result.
Regulators allowing timely rate increases to account for new investments and asset depreciation will be positive for the utility's ability to earn adequate returns over time. This supports higher valuation multiples.
Overall, the utility's value should directionally increase from expanding its customer base and rate base. But investors will analyze the regulatory process closely to assess the timing and magnitude of rate changes on expected cash flows and returns on capital. This dynamic risk is a key aspect of utility valuation.
Let me know if you need me to expand on any of these rate-setting and valuation impacts. The interaction between capital investments, taxes, regulation, and cash flows is critical for utility investors to understand.
SS: Let's assume that investors are valuing the company using a single-stage discounted cash flow model (DCF). The utility's cost of capital is 9%. The company will grow 3% annually. Is this enough information to estimate the company's value?
RR: With the information provided - cost of capital, growth rate, and single-stage DCF model - there is not yet enough information to estimate the utility's valuation. Here are some additional items needed:
Current Free Cash Flows: In order to forecast future cash flows using the growth rate, we need to know the starting point current/projected FCFs.
Tax Assumptions: The impacts of accelerated depreciation and tax credits need to be factored into FCF projections.
Capital Expenditures: Since new infrastructure drives rate base growth, projected capex spend is important.
Regulatory Assumptions: Projected rate increases and timing based on regulatory precedents must be incorporated.
Customer Growth: Projected new customer additions help estimate future revenue potential.
Cost Drivers: Key expense projections like wages, power purchases, financing costs need assumptions.
Terminal Value: The DCF will depend heavily on the perpetuity/terminal value calculated. The exit multiple applied needs support.
Without making explicit assumptions for each of these drivers and modeling their impact on future cash flows, we do not yet have the full picture to estimate intrinsic value. The interplay between all the regulatory, tax, operational, and financial factors is crucial. More detailed DCF modeling is required before concluding on a reasonable valuation range.
SS: Okay. Is it theoretically correct for the investor to use cash income taxes, rather than GAAP income taxes, when estimating net operating profit less adjusted tax (NOPLAT) in the DCF valuation?
RR: Yes, theoretically it would be appropriate for the investor to use the utility's cash income taxes paid rather than GAAP tax expense when estimating NOPLAT in a DCF valuation model.
The reasons this is theoretically correct:
NOPLAT aims to measure after-tax operating cash flows. Using cash taxes aligns with this goal rather than non-cash GAAP tax expense.
Cash taxes better represent the actual tax-related outflows impacting the utility's cash flows available to investors.
GAAP taxes can fluctuate significantly due to tax credits, accelerated depreciation, and deferred taxes. Cash taxes better reflect the underlying economics.
For an accurate intrinsic DCF valuation, projected cash flows and NOPLAT should reflect the utility's real world tax obligations based on its investments and regulatory treatment.
Cash taxes can diverge from GAAP expense due to regulatory asset/liability accounting rules. Cash basis is more consistent for valuation purposes.
Overall, cash taxes have a clearer economic relationship to the utility's operating cash flows and regulatory situation.
In summary, yes in theory an investor would want to use projected cash income taxes paid rather than GAAP tax expense in a DCF model to get the most accurate representation of the utility's true after-tax cash flows for valuation purposes.
SS: It appears that both regulators and investors consider cash income taxes for rate setting and valuation. Is this correct?
RR: Yes, that is correct. Both utility regulators and investors have an incentive to focus on cash income taxes rather than just GAAP tax expense for their respective purposes of rate-setting and valuation.
The key reasons this alignment exists:
For regulators, actual cash taxes paid are more relevant for setting rates that allow the utility to earn a fair return on investments. This matches expenses to periods incurred.
Investors similarly want valuations to reflect the cash tax obligations that will impact real cash flows available for equity holders.
GAAP taxes can diverge from cash taxes paid due to regulatory rules and tax credits/depreciation. Cash basis is more real.
The timing and amount of rate increases tied to new investments also impacts investor cash flows. Regulators and investors both assess this.
Open communication between regulators and the utility on taxes and rates provides transparency and consistency for investors to model cash flows.
Overall, the focus on cash taxes provides a common economic framework for regulators setting fair rates and investors modeling cash flow impacts.
In summary, yes the evidence suggests both utility regulators and investors align on considering actual cash income taxes paid rather than just GAAP tax accounting. This unified approach aids the regulatory process and valuation analysis.
SS: Create a document of the key points for future reference for investor use.
RR: Here is a document summarizing the key points on utility rate-setting and valuation for investor reference:
Utility Rate-Setting and Valuation Training Reference for Investors
Objective: This reference outlines the rate-setting process for regulated utilities and key implications for valuation analysis from an investor perspective.
Utility Rate-Setting Basics:
Utilities are natural monopolies requiring regulation of rates charged to customers.
Regulators aim to set just and reasonable rates allowing for recovery of prudent costs and a fair return on capital invested.
Key steps in rate-setting:
Determine overall revenue requirement based on costs and investments
Design rate structure and allocate revenue requirement across customer classes
Conduct periodic reviews and rate cases to account for changes
Cash income taxes paid are emphasized over GAAP taxes for setting rates that allow a fair return on investment.
Impacts on Valuation:
New investments increase rate base and opportunities to earn returns, thus increasing valuation.
However, timing and amount of rate increases allowed on new investments affect near-term returns.
Accelerated depreciation and tax credits create timing differences between early benefits and eventual cost recovery.
Open and predictable rate case process supports higher valuation multiples.
Focus analysis on cash taxes paid rather than GAAP taxes for DCF models and NOPLAT forecasts.
Key valuation inputs like capex, growth rates, and cash tax assumptions should reflect regulatory rate dynamics.
Assess how regulatory relationships and precedent impact earnings growth and cash flow projections.
Key Takeaways:
Rate-setting and regulations directly impact utility cash flows, growth, and valuation for investors.
Focus analysis on economic impacts, cash taxes paid, and regulatory process, not just GAAP accounting.
Combining operating assumptions with financial projections is key to reflect the rate-setting impacts in DCF models.
Utility companies require integrative modeling of both operational and regulatory factors to determine reasonable valuations.