1. Overview of Price Regulation and the Ratemaking Process Scott A. Struck, CPA Financial Analysis Division Public Utilities Bureau Illinois Commerce Commission

2. Overview General comments about the ICC’s approach to determining rates. General comments about the legal framework. Step through the ICC’s traditional process for determining rates. Please don’t hesitate to ask questions as I go through this presentation. 2

3. The ICC’s Rate Setting Approach Generally, rates are designed to recover the costs of providing utility service, including the cost of the capital invested. The ICC sets rates that are in effect for indefinite time periods. If the rates become insufficient, the utility files a rate case seeking to increase them. If the rates become excessive, the ICC initiates a rate case to consider reducing them. 3

4. Factors That Lead to Rate Changes Significant changes in operating expenses. New kinds of operating costs. Increased plant investment. Significant changes in the number of customers. Significant changes in the cost of capital. 4

5. Legal Framework for Setting Public Utility Rates The utility company is entitled to the opportunity to earn a fair return on its investment used to provide utility service to captive customers. The utility company’s customers are entitled to safe, reliable service at just and reasonable prices. The ratemaking process seeks to balance these two interests. 5

6. Rate Setting Formula “...it is important that there be enough revenue not only for operating expenses but also for the capital costs of the business. (FPC v. Hope Natural Gas)

7. Rate Base X = = + Rate of Return Revenues sufficient to cover capital costs ( $9 million) Cost to fund investment ( 9%) Revenue Requirement Calculation $30 million Net investment ($100 million) $39 million to be collected from ratepayers Required Operating Income Revenue Requirement Expenses If current revenues are $35 million, this represents a rate increase of $4 million or 11.43%.

8. Rate Base and Operating Expenses

9. Rate Base and Operating Income Statement We begin with the company’s accounting records. Utility companies are required to keep their accounting records in accordance with the ICC’s Uniform System of Accounts. (Corresponds to ERO’s RAG’s) Although the ICC requires utilities to maintain and present financial information in this way, the ICC also retains flexibility with respect to setting rates: “The Commission does not commit itself to the approval or acceptance of any item set out in any account, for the purpose of fixing rates or in determining other matters before the Commission.” 9

10. Rate Base and Operating Income Statement We apply ratemaking principles to the company’s accounting records to determine the revenue requirement. Test Year Rate Base (RAB f ) Operating Income Ratemaking Adjustments 10

11. Test Year A consecutive 12-month period of operations and investment. Adjusted to reflect conditions expected during the period of the new rates. 2 options are available in Illinois: Historical test year – Based on 12 months of historical data (with pro forma adjustments) Future test year – Based on 12 months of projected data (a pro forma test year) 11

12. Historical Test Year Based on 12 consecutive months of historical data. Must begin no later than 24 months prior to when utility files the rate case and must end before the date on which the company files the rate case. Pro forma adjustments: Known and measurable changes to the operating results of the test year. Reasonably certain to occur within 12 months of the start of the rate case. Advantage – Historical data is objective and verifiable. Disadvantage – May not be forward looking in a rapidly changing environment. 12

13. Future Test Year Based on 12 consecutive months of forecasted data. Must begin after the date on which the rate case is filed and end no later than 24 months after the date on which the rate case is filed. Requires additional information to support the forecast. Requires certification of forecast from independent auditor. Advantage - More forward looking. Disadvantage – Forecast can be subjective. 13

14. Rate Base The net investment used to provide utility service. (RAB f ) How to value the investment for ratemaking purposes? Investment cost. Fair value/replacement cost. Most jurisdictions in the USA use the investment cost approach. Reflects cost recovery. Assigns cost of investment to those who benefit from the investment. Risk of value fluctuation stays with investors. Original cost – the cost to the entity first devoting the investment to public service. 14

15. Rate Base - Components Utility Plant in Service Less:Accumulated Depreciation Plus:Working Capital Items + Cash Working Capital + Materials & Supplies + Fuel Inventory Less:Cost-Free Non-Investor Supplied Capital - Accumulated Deferred Income Taxes - Customer Deposits - Customer Advances Equals: Rate Base (RAB f ) 15

16. Rate Base - Issues Used and Useful – The investment is necessary to meet customer demand or economically beneficial in meeting such demand. Prudent Investment – The investment will be used and useful in providing service to customers at the time of its completion. Reasonable Cost - A utility's decisions, construction, and supervision resulted in efficient, economical and timely construction considering the knowledge and circumstances prevailing at the time of each relevant utility decision or action. Shareholder Investment – The item is supported by investor capital. 16

17. Re-Cap: Rate Base is multiplied by ROR to calculate the Required Operating Income. Next, we will examine the determination of Expenses to add to the Required Operating Income in order to calculate the Revenue Requirement. (Allowed Revenues) 17

18. 18 Operating Expenses Cost of operating the system to provide service to customers for a given period, usually 1 year. The cost of activity over a given period rather than and amount of investment.

19. 19 Operating Expenses - Components Purchased Power Operation and Maintenance Expenses General and Administrative Expenses Depreciation Income Taxes (including tax effect of interest expense) Other Taxes

20. 20 Operating Expenses - Issues Cost of Service – Is it a cost of providing utility service? Reasonable Amount – Is the amount excessive? Normal Level – Is it a normal recurring level that is expected to continue? Annual Amount – Are more than 12 months worth included? Out of Period – Does the item belong to another period? Pro Forma Amount – Do pro forma adjustments reflect changes that are known and measurable and reasonably certain to occur within the required time frame?

21. 21 Operating Income Statement Utility Operating Revenues (Revenue Requirement) Less:Utility Operating Expenses - Operation and Maintenance - Depreciation - Income Taxes - Other Taxes Equals:Operating Income (Rate Base x ROR) Plus:Total Other Income and Deductions Less:Interest Expense Less:Dividends Paid on Preferred Stock Equals:Net Income Available for Common Stock

22. 22 Rate of Return (WACC)

23. 23 Overview Rate of Return (WACC) Cost of Short and Long-Term Debt Cost of Preferred Stock Cost of Common Equity Capital Asset Pricing Model (CAPM) Discounted Cash Flow (DCF) Model Comparable Samples Capital Structure

24. 24 Cost of Capital Rate of return is developed from a utility’s cost of capital. Cost of capital equals sum of component costs of the capital structure after each is weighted by its proportion to total capital.

25. 25 Cost of Capital Cost of short-term debt, long-term debt, and preferred stock are usually directly observable. Their costs can be calculated from the interest or dividend rate on the security (e.g. bond, note, preferred share) and the expenses incurred to issue the security (e.g., legal and underwriting fees). Cost of common equity is not directly observable. Financial models are used to estimate this cost. The ICC and its Staff most often rely on the Discounted Cash Flow (“DCF”) model and Capital Asset Pricing Model (“CAPM”).

26. 26 Components of an Asset’s Rate of Return Time Value of Money (Real risk-free rate): compensation to investors to induce them to divert wealth from consumption to savings (i.e., investment). Based on premise $1 today is worth more than $1 tomorrow. Expected Inflation: compensation for anticipated decline in purchasing power. Risk Premium: compensation for bearing the risk that the real return on the investment will be less than anticipated (e.g., default risk, liquidity risk).

27. 27 Risk and Return Long Term Government Bonds Small Company Stock Large Company Stock Source: Ibbotson Associates SBBI 2006 Yearbook. Data for 1926-2005. Mean Return: 5.8% Standard Deviation: 9.2% Mean Return: 12.3% Standard Deviation: 20.2% Mean Return: 17.4% Standard Deviation: 32.9% Investors are averse to risk. Thus, they require higher returns from investments in securities with greater risks. Standard deviation measures dispersion or variability. A higher standard deviation means greater variability, hence greater risk.

28. 28 Cost of Common Equity Capital Asset Pricing Model (CAPM) Risk-free rate (R f ): the return available on a security with no risk. Proxies often considered to measure R f are U.S. Treasury bills and bonds. Beta (β j ): the measure of market risk for security j. Market risk premium (R M – R f ): the expected rate of return for the market portfolio (R M ) minus the risk-free rate (R f ). Rate of Return j = R f +  j  (R M  R f ) A risk premium model based on the theory that the market-required rate of return for a risk bearing security equals the risk-free rate of return plus a risk premium that investors expect in exchange for assuming the risk associated with that security. Risk premiumRisk-free rate

29. 29 What is Beta (β)? Beta measures the quantity of market risk in a security. The higher the quantity of risk, the higher the beta. The beta of the market equals one by definition. Thus, beta is 1 for companies riskier than the market. Since the rates of return on utility common stocks are less variable than the market of common stocks as a whole, utility betas are lower than one.

30. 30 Cost of Common Equity Basic Discounted Cash Flow Model The DCF model shows that the cost of equity is a combination of the dividend yield on the stock plus growth in future cash flows (i.e., dividends). This model posits the stock price equals the sum of the discounted value of each dividend. Dividends are cash distributions from the company to stockholders of a portion of the company’s earnings. Earnings equals revenues less accrued costs. Dividend Yield (Dividend/Price) Expected Dividend Growth Rate Cost of Equity

31. 31 Cost of Common Equity Quarterly Discounted Cash Flow Model The ICC and Staff estimate the cost of common equity with this DCF model. Unlike the basic DCF model, it takes into consideration the precise timing of quarterly dividends payments (D 1,q ). Cost of Equity Future value of expected quarterly dividends Current Stock Price Expected Dividend Growth Rate

32. 32 Measuring Cost of Equity with Samples Most electric, gas and large water utilities in Illinois are subsidiaries of holding companies. Hence, their common stocks are not market-traded. DCF model and CAPM cannot be applied directly to non-market- traded common stock. 9-230 of the PUA prohibits reflecting increases to utilities’ costs of capital due to affiliation with non-utility affiliates. This effectively prohibits using holding companies as proxies for their Illinois utility subsidiaries. Further, measurement of cost of equity is difficult; cost of equity estimates for individual companies include significant degrees of measurement error. Therefore, cost of equity for Illinois utilities is measured indirectly using samples of utilities that are as similar in risk to that Illinois utility.

33. 33 Methods for Selecting Samples “Pure Play” Companies that operate primarily in the same industry as the Illinois utility service for which rates are under review. Credit Ratings measure default risk of fixed income securities rather than common equity risk but are a function of the same business and financial risks as common equity. Financial Ratio Analysis selects those utility companies with operating and financial ratios that are closest to Illinois utility.  These three methods are NOT mutually exclusive. Staff often combines three or four approaches to select and evaluate samples.

34. 34 Capital Structure The weighted average cost of capital is the sum of the weighted cost of each component of the capital structure. Each capital structure component cost is weighted by the ratio of the amount of that component to the amount of total capital.

35. 35 Weighted Average Cost of Capital Debt to Total Capital (%) Financial Leverage Cost of Equity Cost of Debt Relationship Between Financial Leverage and the Cost of Capital With Taxes and Financial Distress Costs Cost of Capital (%) Range of reasonable capital structures (Representational Only) 0100 Capital Structure

36. 36 Capital Structure: Summary DEBT All else equal, raising the proportion of debt would decrease the cost of capital due to the tax-deductibility of interest. All else is not equal: As the proportion of debt rises, the probability of financial distress and its attendant costs (payments to outside parties, loss of business and tax benefits) also rises, which increases the costs of debt and equity. COMMON EQUITY More expensive than debt, thus, all else equal, raising the proportion of common equity would increase the cost of capital. All else is not equal: As the proportion of common equity increases, financial risk declines, which decreases the costs of debt and equity.

37. 37 Capital Structure: Summary (Cont.)  CONCLUSION: Neither 100% debt nor 100% common equity is optimal. An optimal capital structure is a mix of debt and equity that minimizes the cost of capital. Impossible to identify the optimal capital structure since cost of capital is a function of dynamic market costs and operating risk.

38. 38 Rate Setting Process After the revenue required by the utility is identified, the next step is determining how that revenue will be collected from the utility’s various types of customers, that is, developing customer rates.

39. 39 Overview Developing Customer Rates Definitions: basic terms, types of charges, rate characteristics Cost of Service Study (COSS) Rate Design

40. 40 Basic Terms A rate is a standard unit charge for service rendered by a utility to its customers and is applicable under general circumstances. A tariff is a published document setting forth the types of rates charged for specific utility services and the general terms and conditions under which such services will be provided.  To be effective, a utility tariff must be filed with, and approved by, the ICC.  Sec. 9-201 of the Public Utilities Act requires tariffs in effect to be made publicly available.

41. 41 Major Types of Rates Customer Charge – A flat monthly charge to cover the fixed costs incurred to provide service to the customer (e.g., cost of the service line from the distribution system to the home, fixed overhead costs such as billing and customer service). Usage Charge (a.k.a. Energy, Delivery or Distribution Charge) – A cents per unit charge multiplied by the customer’s usage volume. It’s a “base rate” developed in a rate case that mostly recovers the cost of delivering utility service. In some electric utilities, this includes a portion of fuel costs. Demand Charge (a.k.a. Capacity Charge) – Generally a flat charge multiplied by the size of the customer’s load (where “load” is the maximum kw used per month). Typically applied to medium or larger, non-residential customers. It recovers the incremental cost of building larger facilities to meet these customers’ higher load demands. Meter Charge – Usually part of the customer charge but is itemized separately for electric delivery service. A flat monthly charge that covers, among others, the cost of the meter and meter reading.

42. 42 Rate Characteristics Seasonal rate – Different rate applies depending on time of year. Example: some electric utilities have summer and non- summer month rates. Flat rate – Same rate applies regardless of usage volume or season. Declining Block – Rates decrease as usage increases. Example: 8 cents/kwh up to 1,000 kwh; 6 cents/kwh for the next 5,000 kwh; and 4 cents/kwh for > 6,000 kwh. Inclining Block - Rates increase as usage increases. Example: 8 cents/kwh for up to 1,000 kwh; 9 cents/kwh for the next 5,000 kwh; and 11 cents/kwh for > 6,000 kwh.

43. 43 Rate Characteristics (Electric Only) Time-of-day rate - different rate applies depending on time of day. Example: 8 cents/kwh from 10 a.m. to 8 p.m., Monday – Friday 5 cents/kwh for all other kwh in a month. Real time pricing rate - charge for the supply of electricity changes by the hour based on the published price at PJM or MISO.

44. 44 How Customer Rates Are Developed A Cost of Service Study (COSS) develops charges that will apply to each rate class. Rate classes are determined by grouping customers with similar usage patterns.  Why? Customers with similar usage characteristics impose similar costs on the utility. Examples: Residential, Commercial, and Industrial Class Some classes are further divided into Sub-Classes as needed. Examples: Residential Sub-Classes Residential Space Heating Residential Non-Space Heating Residential Time of Day

45. 45 Cost of Service Study (COSS) Cost Allocation : The costs of providing service are caused by all customers and, therefore, are charged to all customers on a weighted basis in a COSS. How does it work? By applying allocation factors developed by analyzing the relationships (i.e., cause and effect) among various cost categories. Examples:  Customer Records and Collection Expenses are allocated to customer classes based on the average number of customers per class.  Meter Reading Expenses are allocated based on the number of meters in each customer class.

46. 46 Types of COSS Embedded Costs Based on historical information Information can be verified Less complex than marginal Marginal Costs Based on projected information and assumptions Much more complex than embedded. Other than ComEd, most utilities do not have the capabilities in-house, and the expense for consultant capabilities can be very high. Resulting rates may not be very different from rates under an embedded approach.

47. 47 3 Basic Steps in a COSS Functionalize  Identification of costs as related to functions within each type of utility service. How much cost is identifiable with generation, transmission, and distribution? Allocate  Determine how much of each functionalized cost is apportioned to each customer class. All costs are allocated. Allocation factors are developed to appropriately weight costs to the customer classes. Classify  Determine how much of each allocated cost should be in the customer charge, the demand charge, or the usage charge. All costs that have been allocated to the customer classes are designated either to the customer charge, the demand charge or the usage charge.

48. 48 Rate Design The Cost of Service Study does not provide a precise and inflexible set of rates for each customer class, but rather a starting point for designing rates. The resulting rates from a COSS must then be adjusted for other items such as social and economic concerns (e.g., size of customer bills, potential rate shock, who should pay for programs, environmental considerations). This entire process is referred to as rate design.

49. 49 Typical Rates Issues in a Rate Case Embedded COSS vs. Marginal COSS Allocation Factors Coincident Peak vs. Average and Peak Use of Minimum Distribution System method (tends to favor large customers) Environmental/Conservation Issues Bill Impacts on Customer Classes