5::BASE CASE FINANCIAL MODEL

Transcription

1 5::BASE CASE FINANCIAL MODEL Key Findings There are small cost savings due to differences in ownership structure. Ownership makes a minor difference in rates because there is an additional expense from the profit component or return on equity component of an IOU ownership model. Savings are on the order of one percent to 4.5 percent. Profit does not increase when expenses increase. Because of the way rate setting is regulated, there is no incentive for the BUC to increase expenses in order to increase profit. BUC earns additional profit by investing in capital. Fuel is the larger contributer to cost. Fuel makes up between 85 percent and 90 percent of the total costs to run a rural utility, particularly BUC. Rate reductions cannot occur in a substantial way without adjusting the cost of fuel. For purposes of this study, the value of the BUC plant is estimated at $6.2 million. A range of values for the plant are calculated and the figure assumed in this study is $6.2 million, based on the expected value method. Rate analysis of the higest estimated plant value of $14 million was also examined. Purpose of the Base Case The purpose of the base case financial model is to: Determine whether there is any inherent difference between how rates are calculated under the three ownership models, and subsequently, whether any of those differences result in lower electricity rates. Develop the set of assumptions for each ownership structure to model rates and apply sensitivy analysis, as described later in this study. This chapter describes the approach taken to develop the base case, explains how utilities set rates and how that process differs among ownership models, explains the difference in the profit component between ownership structures, lists the assumptions used in the base case, and summarizes the base case financial results. Approach to Developing the Base Case Based on the ownership options previously identified, a financial evaluation was performed to determine the potential rate savings to the City of Bethel s residents and businesses. This analysis is intended to provide broad direction in terms of going forward with a change in the current private ownership of BUC. The financial analysis is therefore broad in nature. All information regarding BUC operations and costs were taken from public documents or internal information from City staff, regulatory agency staff, and other stakeholders. In general, the financial benefit from different ownership options will depend on a great many issues that are not known with certainty. For example, the cost of purchasing the utility, the cost of borrowing, and the potential cost savings from wind and/or fuel procurement are highly Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-1

2 speculative and uncertain. For this reason, the results are generally presented in ranges, and the uncertainty affecting the results is discussed where appropriate. As a starting point, a baseline of historic financial data was gathered forr BUC based on their most recent rate case filing and the 2009 and 2010 Annual Report filing with the RCA. Once the business-as-usuamunicipal ownership, cooperative ownership, and non-buc investor ownership. For each of model was developed, separate 10-year forecast models were created for these options, it was assumed thatt the purchase price of BUC would be the same and that each owner type would continue to operate and maintain the utility in a similar manner. How Utilities Set Rates The revenue requirement of a utility is the determining factor for setting rates. The revenue requirement is the sum of total costs to operate and finance the utility less any other non-rate revenues, such as waste heat. Once the revenue requirement is determined for the utility, average rates can be calculated by dividing total revenue requirement by total kwh sales. There are different methodologies that exist for setting electric rates depending on the ownership type that is attempting to set the rates. The common factors (regardless of utility ownership) are power supply costs, delivery and distribution costs, customer service costs and administrative and general costs. Figure 5.1 provides shows the steps that utilities take to set rates. Figure 5.1 How Utilities Set Rates Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-2

3 Public/Cooperative Utilities versus Private Utilities The basis for the different rate setting methodologies is the type of utility that is attempting to set the rates. Utilities are generally divided into two types by ownership: public and private utilities. Public utilities are generally owned by a municipality, cooperative, county, or special district and are operated on a not-for-profit basis. Public/cooperative utilities are generally capitalized by issuing debt and soliciting funds from customers through direct capital contributions or user rates. Through statute, public/cooperative utilities typically do not pay state and federal income taxes. However, they might pay an in-lieu fee to the local jurisdiction, and cooperatives in Alaska do pay a gross receipts tax to the State. Finally, a public/cooperative utility is usually regulated by a publicly elected or appointed city council, board of commissioners, or board of trustees. In contrast, private electric utilities are capitalized by issuing debt or equity (stock) to the general public. The owners of the private utility are its equity contributors, or shareholders. Private utilities are taxable entities, and are generally regulated by state public utility commissions. Cash versus Utility or Accrual Accounting By virtue of differences noted above for a public/cooperative versus a private utility, their revenue requirements are based on different accounting methodologies: a cash basis for public/cooperative and an accrual basis for private utilities. The accounting methodologies reflect different business models that are based on the for-profit motivation of a private utility and the non-profit focus of a public/cooperative utility. Table 5.1 Cash versus Utility or Accrual Basis Comparison Cash Basis (Public/Cooperatives) Utility or Accrual Basis (Private) + O+M Expense + O+M Expense + Taxes + Taxes + Capital Improvements Financed with + Depreciation Expense Operating Revenues (Depreciation Expense) + Capital Improvements Financed with Debt Service + Fair Return on Capital Invested Σ = Revenue Requirement Σ = Revenue Requirement Cash Basis The convention used by most public utilities is called the cash basis of cost accounting. As the name implies, a public utility aggregates its cash expenditures to determine its total revenue requirement for a specified period of time. This methodology conforms nicely to most public utility budgetary processes, and is a very straightforward and easily understood calculation. Under the cash basis approach, there are four component costs. They are: operation and maintenance expenses, taxes (if applicable), capital improvements funded from rates, and capital improvements funded with debt service. Two portions of the capital expense component are necessary under the cash basis approach because utilities often cannot finance all capital facilities with long-term debt. Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-3

4 Utility or Accrual Basis Most private utilities use what is known as a utility or accrual basis of determining revenue requirements or setting rate levels. This convention calculates a utility s annual revenue requirement by aggregating a period s operations and maintenance expenses, taxes, depreciation expense, and a fair (as determined by the regulating agency) return on investment. Each of these components is described below: O+M Expenses: Similar to a public/cooperative utility. Taxes: Unlike most public and cooperatives, private utilities must also pay state and federal income taxes, along with any applicable property, franchise, sales or other forms of taxes. Depreciation Expenses: Private utilities use depreciation expense as a means of recouping the cost of capital facilities over the useful lives of those facilities and also as a means of generating internal cash. Depreciation expense represents the current investment of the utility and that portion that has become worn out or obsolete and must be renewed or replaced. Return on the Capital Invested: This pays for the utility s interest expense on indebtedness, provides funds for a return to the utility s equity holders in the form of dividends, and leaves a balance for retained earnings and cash flow purposes. The rate of return for this cost component is a function of approval by the regulating agency. Revenue Requirement Differences by Specific Ownership Model Table 5.2 provides specific information about the differences in the revenue requirements (which set the overall utility rates) by ownership model. This is described in detail in the following section. Table 5.2 Comparison of Utility Revenue Requirement by Ownership Category IOU (Accrual Basis) Municipal (Cash Basis) Cooperative (Cash Basis) O+M O+M O+M Power Supply Power Supply Power Supply Delivery/Distribution Delivery/Distribution Delivery/Distribution Customer Service Customer Service Customer Service Administrative + General Administrative + General Administrative + General Taxes Transfers to Genrl Fnd or In-Lieu Pmt Taxes (if applicable) Financing Costs Financing Costs Financing Costs Depreciation Debt Service (Principal + Interest) Interest Return on Rate base [1] Capital Improvements from Rates Capital Required from Tier Less: Other Revenues Less: Other Revenues Less: Other Revenues Total Revenue Requirement Total Revenue Requirement Total Revenue Requirement [1] Includes return on equity + return on debt Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-4

5 Investor-Owned An investor owned utility (such as BUC) uses the accrual basis for determining the revenue requirement in order to set rates. In general, the O+M expense does not vary depending on the ownership of the utility. Regardless of ownership structure, the utility must purchase fuel, generate power, transmit the power through the transmission and distribution systems, read the meters and bill customers. However, as described previously, the financing of assets (paying for capital improvements) does vary by utility ownership. Investor owned (or private) electric utilities are capitalized by issuing debt or equity (stock) to the general public. This is reflected in the return on rate base line item in Table 5.2. The owners of the private utility are its equity contributors, or shareholders. Private utilities are taxable entities, and finally, they are generally regulated by state public utility commissions. IOUs are allowed by the RCA to include depreciation of assets and a return on rate base (also called return on investment). The return on rate base is generally separated into two components: debt and equity. For example, in BUC s tariff filing dated April 2, 2010, percent of total capital was financed by debt at 5.5 percent, while the remaining percent was financed by equity (cash) at a return on equity of 14 percent. This resulted in a rate of return of percent (see Table 5.7). The allowable return included into rates is the percent times rate base. This amount (in addition to depreciation) is used to pay for principal and interest payments on loans, capital improvements on the system, new facilities and earnings to the equity owners (or the utility owners). Investor owned utilities do not increase earnings by increasing cost, but increase earnings by increasing capital facilities. One of the most contested areas of utility rate setting is the determination of the return on equity (14 percent in the above example). Municipal (City-Owned) A utility that is city-owned will include the same generation, transmission, distribution and customer service costs in its revenue requirement. However, instead of including depreciation and return on rate base, the city-owned utility will include capital improvement costs and interest and principal payment on loans. In addition, the city-owned utility may include general fund transfers, payments-in-lieu, or other payments to the City for the ownership of the utility. Cooperative A cooperative is a mix between an investor-owned and a city-owned utility. The cooperative s revenue requirement looks very similar to an investor owned utility, except that the rate of return is based on a required margin. The cooperative board determines the required margin (difference between revenue and expenses), which is needed for financial stability and to meet a required Times Interest Earned Ratio (TIER). The margin provides cash flow to the utility and allows the utility to continue to borrow funds needed for capital projects. For a cooperative, the margin is described as interest-free money borrowed from its members. Members then get the money back several years later as capital credits (or dividends). Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-5

6 Magnitude of the Profit Component As described previously, the major difference between the three methodologies is the way in which capital costs are viewed and handled. The underlying difference is the for-profit (private) and not-for-profit (public and cooperative) motivations of each ownership model. When a utility decides whether to invest in new equipment, alternative ways of doing business that require new equipment or assets, or make other decisions about the future of the utility, the mathematical calculation for the profit/financing component is different. For example, a municipal utility has to collect adequate revenue from rates to make improvements, an IOU applies the appropriate rate of return (as regulated by the RCA) to any investment, and a cooperative has to cover expenses by an adequate margin. While the profit/non-profit motivations may be different (and subsequently, the mathematical calculations), the net impact to rate payers is relatively minimal because of the regulatory environment within which the private utility operates. As shown in Table 5.3, the annual difference in revenue collected under an IOU to meet all three profit components is about $250,000 to $350,000 more than cooperative and municipal ownership models, respectively. With an annual revenue requirement of close to $16 million, this additional expense represents approximately one to two percent of the overall costs to provide electricity. Additionally, as described previously, there is no truth to the notion that increases in operating costs increase the profit attributed to an IOU. As shown in Table 5.3, the formula to increase the dollar amounts due to the rate of return (14 percent for return on equity and 5.5 percent for return on debt) is a function of increased equity or increased debt. The IOU would need to put more money into improving the plant and equipment in order to realize any additional revenues from the return on investment. Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-6

7 Table 5.3 Comparison of Profit Component among Ownership Models Item Definition Formula Annual Revenue Attributed to the Profit Component IOU (not BUC) Muni. Coop. Depreciation Accounts for aging facility. Revenue used to replace aging equipment Value of facility reduce by an equal amount each year $271,667 N/A N/A IOU Return on Equity Return rate on equity contribution by owner 14% of equity contribution $483,269 N/A N/A Return on Debt Cost to borrow funds. 5.5% on loan amount $154,170 N/A N/A Capital Expenditures Revenue available to improve facilities Generally based in a CIP plan. Assumed equal to depreciation. N/A $271,667 N/A MUNI Debt Service Revenue spent to pay back loans for improved facilities (Principal & Interest) Based on the cost to borrow money. 4.5% on loan amount. N/A $384,005 N/A Interest Interest Payments on loans Assumed same as Muni. 4.5% on loan amount N/A N/A $276,826 COOP Cash for Tier Cash available to pay for principal loan payment, dividends, capital expenditures, etc. (Revenues less expenses plus Interest) /Interest N/A N/A $271,667 TOTAL N/A N/A $909,106 $655,672 $548,529 Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-7

8 Revenue Requirement Assumptions in the BUC: Business as Usual BUC is an investor owned utility and as such uses the accrual basis for developing revenue requirement and setting rates. Table 5.4 provides 2009 and 2010 electricity sales and Table 5.5 provides the financial information for the same years as filed in the 2010 Annual Report for BUC. As can be seen from Table 5.4, BUC sells approximately 38.7 kwh per year to 2,690 customers. Residential customers use approximately 500 kwh per month, while the single phase commercial customers use approximately 700 kwh per month and three phase commercial customers use approximately 17,000 kwh per month. Table 5.4 Annual Customer and Consumption Data: BUC Electricity Sales (kwh) 2009 Electricity Sales (kwh) 2010 Number of Customers 2009 Number of Customers 2010 Revenue ($) 2009 Revenue ($) 2010 Single phase 17,858,618 18,188,951 2,591 2,580 $8,908,692 $8,075,632 Residential 9,959,097 10,144,403 1,620 1,632 $4,995,215 $4,526,748 Commercial 7,899,521 8,044, $3,913,477 $3,548,884 Three Phase 20,239,463 20,464, $9,614,828 $8,596,006 Commercial 20,239,463 20,464, $9,614,828 $8,596,006 Wholesale 646, , $299,046 $295,200 Total 38,744,771 39,371,140 2,692 2,682 $18,822,566 $16,966,838 Based on BUC s annual filings, the business as usual revenue requirement for BUC is provided in Table 5.5 below. Table 5.5 BUC Actual Expenses and Revenue Requirement Power Production $16,450,458 $14,614,584 Distribution O+M $249,252 $224,071 Customer Service $224,617 $221,392 Administrative + General $2,018,842 $2,025,674 Total O+M $18,943,169 $17,085,721 Taxes $280,383 $317,402 Depreciation $268,175 $262,977 Return $256,783 $306,824 Less Other Revenues ($925,944) ($1,006,086) Total Revenue Requirement $18,822,566 $16,966,838 Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-8

9 Power Production BUC currently owns six diesel generating units that provide electricity and waste heat sales to customers. The total power production cost includes fuel costs and operation and maintenance of the diesel generating units. This cost makes up approximately 86 percent of the total revenue requirement. BUC purchases approximately 3-4 million gallons of diesel every year. Based on 2009/2010 data, BUC s units generate approximately 13.8 kwh per gallon of diesel. The efficiency depends on the resource mix, the type, age and size of the generating equipment and the load profile of the energy demanded. Based on data published for 2009 and 2010 in the Annual PCE reports, the efficiency of BUC s generating equipment is similar to other rural utilities. Table 5.6 Comparison of Fuel Efficiency in Rural Alaska 2009 Efficiency (Generated kwh/gallon) 2010 Efficiency (Generated kwh/gallon) Bethel Utilities Corporation Alaska Village Electric Coop Naknek Electric Nushagak Electric Kotzebue Electric Association Nome Joint Utility System Akiak Akiachak Atmauluak Aniak Kalsag Non-Power Production Operations and Maintenance (O+M) The non-power production O+M consists of expenses related to operations and maintenance of the distribution system, customer service and administrative and general. The majority of costs are included in the administrative and general category, which includes labor and benefits costs. Taxes BUC pays federal (34 percent) and state (9.4 percent) income tax. In addition, a six percent city franchise tax is applied to customer s bills. Depreciation Depreciation expense based on straight-line depreciation is also included in BUC s revenue requirement. Return As discussed previously, BUC is capitalized by issuing debt or equity (stock). The return on investment (or return on rate base) is generally separated into two components: debt and equity. BUC s return calculation approved in the last rates case is provided below: Electric Utility Ownership Model BASE CASE FINANCIAL MODEL 5-9

10 Table 5.7 Summary of BUC Return on Rate base Components and Rates Source: BUC 2010 RCA Filing Debt = 44.8% Borrowing rate = 5.5% Equity = 55.2% Allowable return = 14.0% Return = 44.8% * 5.5% = 2.46% 55.2% * 14.0% = 7.73% 100% 10.19% BUC has been allowed 14 percent return on equity for decades and this rate continues to be used. According to the current owner, the justification for 14 percent is related to size, location and ownership structure of BUC. Other Revenues Other revenues collected by BUC consist of revenues from waste heat sales and miscellaneous electric service revenues. This revenue is used to reduce the electric rate revenue requirement. Revenue Requirement Assumptions in the Base Case The reported electricity sales, number of customers and revenue combined with actual annual expenses for BUC form the foundation for the base case analysis of each of the alternative ownership options. Each of the three ownership structures is compared to the status quo, which is ownership by the BUC as an IOU. A base case model was prepared to assess the rates and PCE amounts under each of the ownership models. It is assumed that BUC would sell the utility assets to a new owner, and rates were calculated under each new ownership structure. In developing the base case ownership analysis, it was assumed that the majority of cost components remained the same as under the BUC Business as Usual case. However, four areas of assumptions were made: Valuation: It was assumed that the new owner would purchase the utility at a value based on standard utility valuation. Financing costs: Differences were assumed in the financing and capital costs of the new utility depending on ownership option. Administrative costs: It was assumed that efficiency could be obtained in labor costs under new ownership. Taxes: Differences were assumed in taxes paid by ownership option. Each of these assumptions is further discussed in the following pages. Plant Value There are three commonly accepted methods for valuing utility electrical properties based on recognized and objective industry standards. The ultimate goal of these methodologies is to Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-10

11 determine the fair market value for the subject property and equipment in a hypothetical open and free market transaction with a willing buyer and a willing seller. The three valuation methods are: (1) The Cost Approach, (2) the Market Approach, and (3) The Income Approach. Within the Cost Approach are the Replacement Cost Approach and the Original Cost Approach. The above methodologies result in different values for the system. The range of results is between approximately $6.2 and $8.4 million for the assets including materials and supplies, plus the value of fuel and any additional costs (or credits) that may occur due to the sale. Table 5.8 Summary of Valuation Results (2011 Dollars) Approach Appropriate Value With Working Capital Original Cost Approach $2.4 million $6.2 million Market Approach $ million $ million Income Approach EBITDA $ million $ million High Value $14 million $14 Million Based upon the aforementioned analysis, it is the opinion of EES Consulting that the BUC s electric utility has a current fair market value of roughly $6.2 million plus all closing adjustments (i.e., fuel, current accounts receivable/payables, etc.). This value could decrease if any contingent liabilities are found during due diligence by a potential buyer. Appendix A provides a detailed summary of the four valuation methodologies. Borrowing Rate IOUs generally obtain taxable financing. Therefore, the borrowing rate for IOUs tends to be higher than the borrowing rate for cooperatives and municipal utilities. However, IOUs in Alaska have access to tax-exempt financing from AIDEA, in addition to access to AEA grants. Municipal and cooperative utilities may have access to additional grants but they still use conventional and tax-exempt sources. Based on BUC s current borrowing rates, the IOU borrowing rates was assumed at 5.5 percent, while the borrowing cost for municipal and cooperative options was assumed at 4.5 percent. Administrative Cost Savings Based on a review of BUC s labor costs, it was assumed that the current labor budget would be reduced after a change of ownership. The major change assumed was that the Anchorage office would no longer be needed. While additional efficiencies may be possible, these were not included in the analysis. Taxes Taxes paid by a utility also differ by the type of ownership. IOUs pay federal tax (34 percent) and state tax (9.4 percent) on any income earned. Cooperatives in Alaska pay a gross receipts inlieu of property tax of $ per kwh to the State. Municipal utilities are not subject to federal or state tax, but can elect to charge a municipal tax. For this analysis, we did not assume any additional municipal tax, as the City of Bethel already charges a six-percent sales tax on all Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-11

12 electricity sold to customers and all diesel purchased by the utility. This tax is assumed to remain in place regardless of ownership option. Base Case Results Based on the data available for BUC and the assumptions listed previously, the following base case revenue requirement was calculated by ownership type. Table 5.9 provides the 10-year net present value (NPV) of total cost by ownership type. The majority of the cost categories are the same across ownership options, except for administrative and general (A+G), taxes and financing costs. Table 5.9 Chart of Revenue Requirement by Ownership Category: Base Case Revenue Requirement (10 Year NPV) Investor-Owned BUC Utility Municipality Cooperative Power Supply Fuel $141,586,281 $141,600,517 $141,600,517 $141,600,517 Non-Fuel $9,340,781 $9,340,781 $9,340,781 $9,340,781 O&M 2,066,389 $2,066,389 $2,066,389 $2,066,389 Customer Service 2,041,683 $2,041,683 $2,041,683 $2,041,683 A&G 18,680,824 $15,075,232 $15,075,232 $15,075,232 Taxes 2,045,527 $2,214,544 $0 $190,596 Financing Costs Depreciation 2,237,665 $2,246,355 $0 $0 Return on Debt 4,217,735 $5,270,850 $0 $0 Capital Expenditures $0 $0 $2,246,355 $0 Debt Service $0 $0 $3,175,257 $0 Interest $0 $0 $0 $2,103,826 Cash for TIER $0 $0 $0 $2,246,355 Less Non-Rate Revenue (11,005,788) ($11,005,788) ($11,005,788) ($11,005,788) Total Revenue Requirement $171,211,097 $168,850,563 $164,540,426 $163,659, Avg. Rate ($/kwh) $ $ $ $ The analysis shows that BUC is the most expensive option, while the generic IOU ownership is a close second. The municipal and cooperative options result in the lowest 10-year NPV revenue requirement. The average rates for the years 2011 through 2019 are provided in Figure 5.2 for each ownership option. Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-12

13 Figure 5.2 Rate Differences by Ownership Category: Base Case Projected Rates by Customer Type The next step in the analysis used the revenue requirement by ownership and projected energy sales to project rates under each of the ownership options. Rates were calculated for several categories of customers with and without PCE credits. Only the residential customers and some city facilities receive PCE credits. Therefore these two groups of customers were separated from all other customers. The first step in calculating rates was to determine the overall average rate for all customers. This is titled All customers in the figures and tables below. The second step allocated revenue requirement based on 2010 revenues to residential, cityy facilities and all other commercial customers. The resulting rates are shown in the figures and tables below as Residential, City Facilities and All Other Customers. The results aree shown in the following tables and figures. Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-13

14 Figure 5.3 Comparison of Utility Rates by Ownership Category: Base Case Only withoutt PCE $ $ Average Rate ($/kwh) $ $ $ $ $ $ All Customers Residential City Facilities All Other Customers BUC IOU Muni Coop Table 5.10 Comparison of Utility Rates by Ownership Category: Base Case Only without PCE All Customers Residential City Facilities All Others Avg. Rate % Impact Avg. Rate % Impact Avg. Rate % Impact Avg. Rate % Impact BUC $ $ $ $ IOU $ % $ % $ % $ % Muni $ % $ % $ % $ % Coop $ % $ % $ % $ Note: Percent change is the comparison between each alternative and the BUC business as usual option. -4.3% Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-14

15 Figure 5.4 Comparison of Utility Rates by Ownership Category: Base Case Only with PCE $ $ Average Rate ($/kwh) $ $ $ $ $ $ All Customers Residentia al City Facilities All Other Customers BUC IOU Muni Coop Table 5.11 Comparison of Utility Rates by Ownership Category: Base Case Only with PCE All Customers Residential City Facilities All Others Avg. Rate % Impact Avg. Rate % Impact Avg. Rate % Impact Avg. Rate % Impact BUC IOU Muni Coop $ $ $ $ % -1.2% -3.9% -4.5% $ $ $ $ % -0.2% -4.4% -5.2% $ $ $ $ % -1.0% -4.0% -4.6% $ $ $ $ % -1.4% -3.8% -4.3% Note: Percent change is the comparison between each alternative and the BUC business as usual option. Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-15

16 Base Case Revenue Requirement Results: High Purchase Price The base case results assume a purchase price of $6.2 million. However, BUC has previously been offered $14 million for the utility by AVEC. In order to examine the impact to rates of a higher purchase price, the model was run assuming $14 million would need to be financed by the new utility owner. Table 5.12 provides the ten-year net present value (NPV) of total cost by ownership type for this higher purchase price scenario. The analysis shows that if the purchase price is too high, or if the new owner will have significant capital investments, rates may have to increase after the sale. In this example, the IOU option results in rates higher than rates projected for BUC. The rate options for the municipal or cooperative ownership options are still lower than BUC. Table 5.12 Revenue Requirement by Ownership Category: High Purchase Price Revenue Requirement (10 Year NPV) Investor-Owned BUC Utility Municipality Cooperative Power Supply Fuel $141,586,281 $141,600,517 $141,600,517 $141,600,517 Non-Fuel $9,340,781 $9,340,781 $9,340,781 $9,340,781 O&M 2,066,389 $2,066,389 $2,066,389 $2,066,389 Customer Service 2,041,683 $2,041,683 $2,041,683 $2,041,683 A&G 18,680,824 $15,075,232 $15,075,232 $15,075,232 Taxes 2,045,527 $2,214,544 $0 $190,596 Financing Costs Depreciation 2,237,665 $2,246,355 $0 $0 Return on Debt 4,217,735 $11,797,236 $0 $0 Capital Expenditures $0 $0 $2,246,355 $0 Debt Service $0 $0 $7,106,873 $0 Interest $0 $0 $0 $4,708,791 Cash for TIER $0 $0 $0 $2,633,541 Less Non-Rate Revenue (11,005,788) ($11,005,788) ($11,005,788) ($11,005,788) Total Revenue Requirement $171,211,097 $175,376,949 $168,472,042 $166,651, Avg. Rate ($/kwh) $ $ $ $ Electric Utility Ownership Model BASE CASE FINANCIAL MODEL5-16