The Changing Structure of the Electric Power Industry: Stranded Costs in Electricity Deregulation: Appendix D - Brief Characteristics of the Oak Ridge Financial Model (ORFIN)

Appendix D

Brief Characteristics of the Oak Ridge Financial Model (ORFIN)

ORFIN is a simplified version of a utility integrated planning model developed by the Oak Ridge National Laboratory. The model includes a production-costing module, utility financial statements (income statement, balance sheet, and cash-flow statement), and a rate-design module (functionalization, classification, and allocation of costs to customer classes).⁽¹⁾

ORFIN simulates a single utility interacting with a single wholesale market. The utility serves bundled retail customers through its integrated generation, transmission, and distribution system. The utility also buys and sells power on the wholesale market when economical, subject to certain system constraints, such as the utility's wholesale transmission capacity. Wheeling customers purchase electricity directly from the wholesale market but receive electricity through the utility's transmission and distribution (T&D) network.

Figure D1 defines the boundaries of the assessment framework. To meet this framework, ORFIN contains many user inputs to permit examination of the effects of a wide variety of variables on utility production costs, assets, incomes, losses, and rates. Table D1 lists the key categories of user inputs. The user provides information on the initial state of the utility. These initial conditions include information on the utility's power plants, power-purchase contracts, operations and maintenance (O&M) costs, and customer characteristics. The user also specifies the initial fuel prices and wholesale prices and their escalation over time. This initial state of the utility defines the base case.

The dispatch module uses data from each year to calculate the generation, contract purchases, and wholesale-market activity (purchases and sales) for the utility. The module dispatches up to 10 distinct utility resources. These resources can be utility-owned generating units, long- term power-purchase contracts, or a new resource (a utility-owned plant or a contract). New plants may be added in small increments each year to ensure that the utility meets its designated reserve requirements. The model matches production and loads for a peak period (that includes no planned outages) and an off-peak period (where plants are derated so that their annual availability accounts for user-defined forced and planned outage rates). The production-costing results are then used by the financial portions of ORFIN to estimate O&M expenditures.

The dispatch module first calculates load-duration curves for the peak and off-peak seasons. The resources are then sorted in order of their variable costs. Must-run plants are assigned a zero bid price for dispatching purposes. The percentage of the season a plant operates is calculated for up to 22 power levels. For each season, these 22 points are sorted by increasing power level before calculating the equivalent load duration curve for each plant.

After calculating the operating times for all plants for the year, ORFIN determines if it is economical to sell any excess power on the wholesale market or to displace some of its own production with wholesale purchases. The user defines the wholesale market using up to four wholesale prices for different portions of the year. ORFIN then compares the variable cost for each plant with the wholesale purchase and sale prices for each period. When a plant's variable cost is lower than the current wholesale sale price and the plant has excess capacity, the plant will sell into the market. When its variable costs exceed the wholesale purchase price and it is producing at that time, then ORFIN backs down the plant and, instead, purchases wholesale power. ORFIN compares each possible transaction with the user-defined transmission-capacity constraint and limits wholesale sales and purchases accordingly.

ORFIN's income statement reflects the results of the utility's operations for a calendar year. The income statement includes detail about revenues, expenses, and income. Income is the difference between revenues and expenses. Revenues are the product of electricity sales and prices, summed over the relevant customer classes. Operating expenses include production and nonproduction costs, book depreciation, taxes, and interest payments. Production expenses include fuel and O&M costs for the utility's power plants, power-purchase-contract costs, and purchases and sales on the wholesale market. Net income is the return to utility shareholders.

ORFIN yields what is called a bottom-up ex ante administrative valuation of transition costs. The annual transition costs are the annual difference in net income between the retail-wheeling scenario and the base case. The total transition costs are the sum of these annual differences, discounted to present value dollars.

Transition costs are calculated as net present value at the utility's return on equity for the years t = 1 through year T. Net Income_rw,t is from the retail wheeling case for year t while Net Income_bc,t is from the base case for the same year.

Table D1. Key Inputs to ORFIN

Nongeneration operating costs Transmission, distribution, customer service, A&G, O&M ($/year), and public-policy-program costs ($/year), and O&M cost escalation percent per year

Nongeneration capital costs Transmission, distribution, and general capital costs ($/year, $/customer, $/kW)

Power-purchase contracts Capacity (MW), offline date (year), forced and planned outage rates (percent), fixed costs ($/kW-year), and variable costs (¢/kWh)

Utility-owned generating units Capacity (MW), initial cost ($/kW), start and offline dates (year), tax and book depreciation lives (years), forced and planned outage rates (percent), fixed O&M cost ($/kW-year), variable O&M cost (¢/kWh), O&M escalation rate (percent per year), heat rate (Btu/kWh), fuel type, and fuel prices ($/MBtu) by year

Wholesale-market prices Prices (¢/kWh) by time period (percent per year), escalation rates (percent per year), difference between wholesale purchase and sale price (¢/kWh), and transmission capacity (MW)

Customers By class: number of customers, consumption (kWh/customer-month), load factor, growth rates (percent per year) in number of customers and in per-customer consumption, and T&D energy and demand losses

Retail wheeling Percentage of customers from each class that wheel by year, percentage of A&G costs paid by wheelers, and ancillary-service cost adder (¢/kWh)

Finances Long-term bonds and common equity (percent of total capitalization and return in percent per year), inflation rate (percent per year), federal/state income tax rate (percent), revenue-sensitive tax rate (percent), property tax rate (percent), frequency and type (historic vs future test year) of rate cases, and regulatory assets

A&G = Administrative and general.
O&M = Operations and maintenance.
MW = Megawatts.
$/kW = Dollars per kilowatt.
¢/kW = Cents per kilowatt.
Btu = British thermal unit.
$/Mbtu = Dollars per million Btu.
Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak Ridge, TN, August 1996).

End Notes

1. Oak Ridge National Laboratory, ORFIN: AnElectric Utility Financial and Production Simulator, ORNL/CON-431 (Oak Ridge, TN, March 1996).

Proceed to Appendix E
Return to Appendix C

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Contact:: Robert Schnapp; robert.schnapp@eia.doe.gov; Phone: (202) 287-1787

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Nongeneration operating costs	Transmission, distribution, customer service, A&G, O&M ($/year), and public-policy-program costs ($/year), and O&M cost escalation percent per year

Nongeneration capital costs	Transmission, distribution, and general capital costs ($/year, $/customer, $/kW)

Power-purchase contracts	Capacity (MW), offline date (year), forced and planned outage rates (percent), fixed costs ($/kW-year), and variable costs (¢/kWh)

Utility-owned generating units	Capacity (MW), initial cost ($/kW), start and offline dates (year), tax and book depreciation lives (years), forced and planned outage rates (percent), fixed O&M cost ($/kW-year), variable O&M cost (¢/kWh), O&M escalation rate (percent per year), heat rate (Btu/kWh), fuel type, and fuel prices ($/MBtu) by year
Wholesale-market prices	Prices (¢/kWh) by time period (percent per year), escalation rates (percent per year), difference between wholesale purchase and sale price (¢/kWh), and transmission capacity (MW)

Customers	By class: number of customers, consumption (kWh/customer-month), load factor, growth rates (percent per year) in number of customers and in per-customer consumption, and T&D energy and demand losses

Retail wheeling	Percentage of customers from each class that wheel by year, percentage of A&G costs paid by wheelers, and ancillary-service cost adder (¢/kWh)

Finances	Long-term bonds and common equity (percent of total capitalization and return in percent per year), inflation rate (percent per year), federal/state income tax rate (percent), revenue-sensitive tax rate (percent), property tax rate (percent), frequency and type (historic vs future test year) of rate cases, and regulatory assets
A&G = Administrative and general. O&M = Operations and maintenance. MW = Megawatts. $/kW = Dollars per kilowatt. ¢/kW = Cents per kilowatt. Btu = British thermal unit. $/Mbtu = Dollars per million Btu. Source: Oak Ridge National Laboratory, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431 (Oak Ridge, TN, August 1996).