Exhibit 99.3
Reformatted Portions of Management’s Discussion and Analysis of Financial Condition and Results of Operations
Operating Segments
In general, management’s discussion of the Company’s results of operations focuses on the contributions of its operating segments. However, the discussion of the Company’s financial condition underLiquidity andCapital Resourcesis for the entire company. The Company’s two primary operating segments are:
| Energy manages the Company’s portfolio of generating facilities and power purchase contracts and its energy trading and marketing, hedging and arbitrage activities. It also manages the Company’s electric transmission system. Energy’s operating results reflect: the impact of weather on demand for electricity; customer growth as influenced by overall economic conditions; and changes in prices of commodities, primarily electricity and natural gas, that the segment actively markets and trades, uses for hedging purposes and consumes in generation activities. The cost of fuel used in generation operations and electric energy purchases incurred by the Company to serve Virginia and North Carolina retail customers is generally recoverable through rates charged to customers. |
| Delivery manages the Company’s electric distribution system and customer service. Delivery’s operating results reflect the impact of weather on demand for electricity and customer growth as influenced by overall economic conditions. The segment is subject to cost-of-service rate regulation and base rates are currently capped in Virginia and North Carolina. |
In addition, the Company also reports Corporate and Other as a segment. The Company includes certain expenses which are not allocated to the Energy and Delivery segments in Corporate and Other.
For more information on the Company’s operating segments, see Note 26 to the Consolidated Financial Statements.
Results of Operations
The Company’s discussion of its results of operations includes an overview of its operating revenue and operating results for 2002 and 2001 on a consolidated basis. These sections are followed by a more detailed discussion of the results of operations of the operating segments. For additional information about the Company’s operating segments, see Note 26 to the Consolidated Financial Statements.
Year Ended December 31, | |||||||||||||||||||||||||||||
Net Income | Operating Revenue | Operating Expenses | |||||||||||||||||||||||||||
2002 | 2001 | 2000 | 2002 | 2001 | 2000 | 2002 | 2001 | 2000 | |||||||||||||||||||||
(millions) | |||||||||||||||||||||||||||||
Energy | $ | 516 | $ | 432 |
| $ | 427 |
| $ | 3,918 | $ | 3,940 | $ | 3,796 | $ | 2,944 | $ | 3,052 | $ | 3,000 | |||||||||
Delivery |
| 253 |
| 178 |
|
| 188 |
|
| 1,042 |
| 994 |
| 991 |
| 559 |
| 614 |
| 618 | |||||||||
Corporate and Other |
| 4 |
| (164 | ) |
| (36 | ) |
| 12 |
| 10 |
| 4 |
| 9 |
| 279 |
| 87 | |||||||||
Total | $ | 773 | $ | 446 |
| $ | 579 |
| $ | 4,972 | $ | 4,944 | $ | 4,791 | $ | 3,512 | $ | 3,945 | $ | 3,705 | |||||||||
Overview of Operating Revenue—Consolidated
The following is a general discussion of factors that affect operating revenue for both the Energy and Delivery segments.
The majority of the Company’s operating revenue is provided through bundled rate tariffs. Regulated electric sales consist primarily of sales to retail customers at rates authorized by the Virginia Commission and the North Carolina Utilities Commission (North Carolina Commission), and sales to cooperatives and municipalities at wholesale rates authorized by the Federal Energy Regulatory Commission (FERC). Also included in regulated electric sales are amounts received from others for use of the Company’s transmission system to transport electric energy under tariffs authorized by FERC.
In addition, regulated electric sales include revenue from fuel rates which are subject to approval by regulatory authorities and are designed to recover the cost of fuel used in generating electricity from customers served under regulated tariffs.
Overview of 2002 Results—Consolidated
Net income increased $327 million to $773 million, as compared to 2001. Net income increased in 2002 due primarily to an after-tax charge of $136 million taken in the first quarter of 2001 in connection with the termination of certain long-term power purchase agreements under which the Company previously purchased electric energy. Comparably warmer temperatures in the summer of 2002 and customer growth in the Company’s regulated electric service territories resulted in higher regulated electric revenues for 2002. The increase in regulated electric revenue for 2002 included the effect of a $34 million decrease in revenues from wholesale customers served under requirements contracts. For further information, seeCapacity below in MD&A. The contribution from the Company’s electric and gas trading and power marketing activities decreased for 2002. Total operating expenses decreased, compared to 2001, primarily due to lower depreciation and other operations and maintenance expense.
Operating revenue increased $28 million to $4.9 billion for 2002, as compared to 2001. Regulated electric sales increased $237 million, and other revenue decreased $209 million. Favorable weather conditions, reflecting increased cooling and heating degree-days, as well as customer growth, are estimated to have contributed approximately $195 million and $60 million, respectively, to the $237 million increase in regulated electric sales. Fuel rate recoveries increased approximately $65 million for 2002. These recoveries are generally offset by related increases in electric fuel expense and do not materially affect income. Partially offsetting these increases was a net decrease of $83 million due to other factors not separately measurable. These factors include the impact of economic conditions on customer usage, especially non-residential customers, as well as variations in seasonal rate premiums and discounts. There were 31 percent more cooling degree-days in 2002 and 2 percent more heating degree-days, as compared to 2001. The Company served, on average, 43,000 more retail customers during 2002.
Other revenue from energy trading activities decreased $218 million. For further information, see theEnergy Segment below. Miscellaneous revenue increased by $9 million over the comparable period in 2001.
Operating expenses decreased $433 million to $3.5 billion for 2002, as compared to 2001. Electric fuel and energy purchases, net and purchased electric capacity increased in 2002. The Company incurred restructuring costs in both 2001 and 2000, primarily associated with Dominion’s acquisition of Consolidated Natural Gas (CNG) and subsequent integration of the combined companies’ operations. Other operations and maintenance expenses were lower in 2002, primarily due to additional costs incurred in 2001 associated with the termination of certain long-term power purchase contracts. For further information on these restructuring costs and termination of the power purchase contracts, see theCorporate and Other Segment discussed below. Depreciation and amortization decreased, primarily due to changes in the estimated useful lives of the Company’s fossil-fueled generating plants and transmission and distribution properties, offset by the effect of routine property additions. These changes in the estimated useful lives reduced depreciation expense by approximately $40 million for 2002. See Note 2 to the Consolidated Financial Statements. Other taxes decreased, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.
Interest and related charges decreased, primarily as a result of lower interest rates on outstanding debt. Expenses associated with the preferred securities of subsidiary trusts increased, primarily due to the higher amount of outstanding trust preferred securities at December 31, 2002. In addition, the Company’s effective income tax rate decreased. See Note 7 to the Consolidated Financial Statements.
Overview of 2001 Results—Consolidated
Operating revenue increased $153 million to $4.9 billion for 2001, as compared to 2000. The increase was due primarily to higher fuel rate recoveries, growth in the number of retail customers and increased wholesale sales to cooperatives and municipalities under requirements contracts. These factors were offset by milder weather conditions in 2001. While there were 6 percent more cooling degree-days in the summer of 2001, as compared to 2000, the 10 percent decline in 2001 heating degree-days more than offset the benefit from the higher summer sales. The Company served, on average, 40,000 more retail customers during 2001.
The results of the Company’s electric and gas trading and marketing operations also contributed approximately $24 million to the increase in operating revenue.
Operating expenses increased $240 million to $3.9 billion for 2001, as compared to 2000. Higher prices for commodities consumed contributed to increased electric fuel and energy purchases, net. Purchased electric capacity expense decreased as the Company terminated certain contracts in early 2001. See Note 21 to the Consolidated Financial Statements. Depreciation and amortization decreased primarily due to a change in the estimated useful lives of the Company’s nuclear plants in connection with the expected re-licensing of those plants, offset by routine property additions. The change in useful lives of the nuclear facilities reduced depreciation expense by approximately $72 million for 2001. For further information, see theEnergy Segment and Note 2 to the Consolidated Financial Statements. The Company incurred restructuring costs in both 2001 and 2000 primarily associated with Dominion’s acquisition of CNG and subsequent integration of the combined companies’ operations. Other operations and maintenance expenses increased primarily due to costs associated with the termination of certain long-term power purchase contracts. For further information on these restructuring costs and termination of the power purchase contracts, see theCorporate and Other Segment discussed below. The Company’s effective income tax rate increased and other taxes decreased in 2001 due to its utility operations in Virginia becoming subject to state income taxes in lieu of gross receipts taxes.
Segment Results
Energy Segment
2002 | 2001 | 2000 | |||||||
(millions) | |||||||||
Operating revenue | $ | 3,918 | $ | 3,940 | $ | 3,796 | |||
Operating expense |
| 2,944 |
| 3,052 |
| 3,000 | |||
Net income contribution |
| 516 |
| 432 |
| 427 | |||
Energy supplied |
| 76 |
| 75 |
| 76 | |||
The Company provides electricity primarily from the following fuel sources: nuclear, coal, oil and purchased power. System energy output by energy source and the average fuel cost for each are shown below. Fuel cost is presented in mills (one tenth of one cent) per kilowatt-hour.
2002 | 2001 | 2000 | ||||||||||||||||
Source | Cost | Source | Cost | Source | Cost | |||||||||||||
Nuclear(1) | 32 | % | $ | 4.63 | 31 | % | $ | 4.64 | 33 | % | $ | 4.48 | ||||||
Coal(2) | 43 |
|
| 16.72 | 40 |
|
| 16.55 | 42 |
|
| 14.04 | ||||||
Oil | 4 |
|
| 36.58 | 5 |
|
| 36.41 | 3 |
|
| 35.89 | ||||||
Purchased power, net | 19 |
|
| 27.36 | 21 |
|
| 24.38 | 20 |
|
| 23.97 | ||||||
Other | 2 |
|
| 53.72 | 3 |
|
| 42.37 | 2 |
|
| 44.58 | ||||||
Total | 100 | % | 100 | % | 100 | % | ||||||||||||
Average fuel cost |
| 16.46 |
| 16.35 |
| 14.20 | ||||||||||||
| (1) | Excludes Old Dominion Electric Cooperative’s (ODEC) 11.6 percent ownership interest in the North Anna Power Station. |
| (2) | Excludes ODEC’s 50 percent ownership interest in the Clover Power Station. |
2002 Results
Energy’s net income contribution increased $84 million to $516 million for 2002, as compared to 2001. The increase in net income primarily reflects a $108 million decrease in operating expenses, partially offset by a $22 million decrease in operating revenue.
Comparably warmer temperatures during the summer of 2002 and customer growth contributed approximately $142 million and $44 million, respectively, to the $189 million increase in the Energy’s segment regulated electric sales, partially offset by other factors as discussed above inOverview of 2002 Results—Consolidated.
In addition, Energy manages the Company’s energy trading, hedging, arbitrage and power marketing activities through the Dominion Energy Clearinghouse (the Clearinghouse). The Company’s electric trading revenue, representing net gains and losses from contract settlements and unrealized changes in the fair value of contracts not yet settled, decreased by approximately $32 million, as compared to 2001. This decrease reflects the effect of unfavorable price changes and lower trading margins. Power marketing sales decreased by approximately $74 million, as compared to 2001. Less generation was available for sale in the wholesale markets primarily due to the higher demand of the Company’s utility service territory customers during 2002. Gas trading revenue, net of cost of sales, decreased approximately $112 million. Approximately $70 million of this decrease relates to contracts held by one of the Company’s unregulated subsidiaries as part of Dominion’s consolidated price risk management strategy associated with anticipated sales of Dominion’s 2002 and 2003 natural gas production. Other revenue increased by approximately $7 million over the comparable period in 2001 primarily due to a $14 million increase in sales of other commodities partially offset by a $7 million decrease in other miscellaneous revenue.
Operating expenses decreased $108 million for 2002, as compared to 2001. Electric fuel and energy purchases, net increased $29 million as a result of a $66 million increase in electric fuel and energy purchases subject to rate recovery, partially offset by a $37 million decrease in fuel expenses attributable to less wholesale marketing of utility plant generation. Purchased electric capacity costs increased by $11 million due to additional capacity acquired to serve utility demand in 2002. Depreciation expense decreased by $27 million, reflecting the effect of changes in the estimated useful lives of fossil-fired generation and electric transmission property, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements. Other operations and maintenance decreased $104 million in 2002, primarily reflecting a $68 million decrease in scheduled outages and routine maintenance costs at both nuclear and fossil plants and a $36 million decrease in general and administrative expenses. Other taxes decreased approximately $17 million, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.
2001 Results
Customer growth and the increase in fuel rate recoveries contributed to the increase in Energy’s regulated electric sales. SeeOverview of Operating Revenue—Consolidated and Overview of 2001 Results—Consolidated.The results of the Company’s electric and gas trading and marketing operations also contributed approximately $24 million to the increase in operating revenue for the Energy segment.
Operating expenses increased $52 million for 2001, as compared to 2000. Electric fuel and energy purchases, net were higher in 2001, reflecting higher fuel prices for coal and oil consumed. The effect of such expenses on net income was mitigated by increased fuel rate revenue, including higher levels of recovery for previously deferred fuel costs. Purchased electric capacity costs decreased as a result of the termination of long-term power purchase agreements in the first quarter of 2001. The decrease in depreciation and amortization expense primarily reflects a $72 million decrease from a change in the estimated useful lives of the Company’s nuclear plants. This change was based on the Company’s expectation that 20-year extensions of the operating licenses for its nuclear facilities will be granted. The application was filed with the Nuclear Regulatory Commission (NRC) in May 2001. The Company expects to receive a renewed license for these units in 2003. This decrease was partially offset by additional depreciation expense related to other recent generation-related capital expenditures. Other operations and maintenance increased due to scheduled outages at both nuclear and fossil plants. Other taxes decreased reflecting a change in Virginia whereby the Company became subject to state income taxes in lieu of gross receipts taxes effective January 2001.
Selected Information—Energy Trading Activities
As discussed earlier, Energy manages the Company’s energy trading, hedging and arbitrage activities through the Clearinghouse. The Company believes these operations complement its integrated energy business and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including natural gas, electricity and oil. Settlement of a contract may require physical delivery of the underlying commodity or, in some cases, an exchange of cash. These contracts are classified as energy trading contracts for financial accounting purposes, and are included in the Consolidated Balance Sheets as components of current and non-current derivative and energy trading assets and liabilities. Gains and losses from energy trading contracts, including both realized and unrealized amounts, are reported net in the Consolidated Statements of Income as revenue.
In accordance with generally accepted accounting principles, the Company reports energy trading contracts in its financial statements at fair value. For a discussion of how the Company determines fair value for its energy trading contracts, seeCritical AccountingPolicies presented earlier in MD&A. The Clearinghouse enters into contracts with the objective of benefiting from changes in the prices of energy commodities. Clearinghouse management continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity, seeking arbitrage opportunities. For example, after entering into a contract to purchase a commodity, the Clearinghouse typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or sometimes will pay a net cash margin(a realized loss).
Until the contracts are settled, however, the Company must record the changes in the fair value of both contracts. These changes in fair value represent unrealized gains and losses. To the extent purchase and sales contracts with identical or similar terms are held by the Clearinghouse, the changes in their fair values will generally offset one another. Although the Clearinghouse may hold purchase or sales contracts for delivery of commodities at particular locations and times that have not been offset, such exposures are monitored and actively managed on a daily basis. The Company’s risk management policies and procedures are designed to limit its exposure to commodity price changes.
For additional discussion, seeMarket Rate SensitiveInstruments and Risk Managementand Notes 2, 9, and 23 to the Consolidated Financial Statements. Also, see Note 4 to the Consolidated Financial Statements, for a discussion of the Company’s implementation of new accounting requirements effective January 1, 2003 to reflect the decisions of the Emerging Issues Task Force (EITF) in Issue No. 02-3,Issues Involved in Accounting for Contracts under Issue No. 98-10. As a result, some energy-related contracts are no longer subject to fair value accounting.
A summary of the changes in the unrealized gains and losses in the Company’s energy trading contracts during 2002 follows:
Energy Trading Contracts | ||||
(millions) | ||||
Net unrealized gain at December 31, 2001 | $ | 154 |
| |
Contracts realized or otherwise settled during the period |
| (65 | ) | |
Net unrealized gain at inception of contracts initiated during the period |
| 31 |
| |
Changes in valuation techniques |
| — |
| |
Other changes in fair value |
| (9 | ) | |
Net unrealized gain at December 31, 2002 | $ | 111 |
| |
The balance of net unrealized gains and losses in the Company’s energy trading contracts at December 31, 2002 is summarized in the following table based on the approach used to determine fair value and the contract settlement or delivery dates:
Maturity Based on Contract Settlement or Delivery Date(s) | |||||||||||||||||||
Source of Fair Value | Less Than 1 Year | 1-2 Years | 2-3 Years | 3-5 Years | In Excess of 5 Years | Total | |||||||||||||
(millions) | |||||||||||||||||||
Actively quoted(1) | $ | (7 | ) | $ | 16 | $ | 12 |
| — |
| — | $ | 21 | ||||||
Other external sources(2) |
| — |
|
| 14 |
| 6 | $ | 5 |
| — |
| 25 | ||||||
Models and other valuation techniques(3) |
| 19 |
|
| 7 |
| 6 |
| 10 | $ | 23 |
| 65 | ||||||
Total | $ | 12 |
| $ | 37 | $ | 24 | $ | 15 | $ | 23 | $ | 111 | ||||||
| (1) | Exchange-traded and over-the-counter contracts. |
| (2) | Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models. |
| (3) | Values based on the Company’s estimate of future commodity prices when information from external sources is not available and use of internally-developed models, reflecting option pricing theory, discounted cash flow concepts, etc. |
Delivery Segment
2002 | 2001 | 2000 | |||||||
(millions) | |||||||||
Operating revenue | $ | 1,042 | $ | 994 | $ | 991 | |||
Operating expense |
| 559 |
| 614 |
| 618 | |||
Net income contribution |
| 253 |
| 178 |
| 188 | |||
Electricity delivered to utility customers (million mwhrs) |
| 75 |
| 72 |
| 74 | |||
2002 Results
Delivery’s net income contribution increased $75 million to $253 million for 2002, as compared to 2001. The increase in net income reflects a $48 million increase in operating revenue and a $55 million decrease in operating expenses. These amounts were partially offset by increases in income tax expense.
Comparably warmer temperatures during the summer of 2002 and customer growth contributed approximately $53 million and $16 million, respectively, to the $48 million increase in the Delivery segment’s regulated electric sales, partially offset by other factors as discussed above inOverview of 2002Results—Consolidated.
Operating expenses were $559 million in 2002, as compared to $614 million in 2001. Operations and maintenance expense decreased approximately $48 million, reflecting a decrease in general and administrative salaries, materials and supplies and expenditures for contractors. Also, Delivery’s operating expenses can be impacted by severe weather. Hurricanes, major thunderstorms and ice storms can damage the Company’s distribution system. There was an approximate $6 million increase in service restoration costs recorded in other operations and maintenance expense due to ice storms in late 2002. Depreciation expense decreased by $2 million, reflecting the effect of changes in the estimated useful lives of distribution property, partially offset by the impact of new property additions. See Note 2 to the Consolidated Financial Statements. Other taxes decreased $9 million, as compared to 2001, primarily due to a reduction in average business and occupation tax rates and the impact of a favorable resolution of prior year sales and use tax issues.
2001 Results
Customer growth was the main contributor to the increase in the Delivery’s segment regulated electric sales. Also, seeOverview of Operating Revenue—Consolidatedand Overview of 2001 Results—Consolidated.
Operating expenses were $614 million in 2001, as compared to $618 million in 2000. During 2001 and 2000, there were no unusual levels of storm restoration activities. Depreciation and amortization increased slightly as a result of routine property additions. Other operations and maintenance expenses included a moderate increase in provisions for uncollectible customer accounts. Other taxes decreased, reflecting a change in Virginia whereby the Company’s utility operations became subject to state income taxes in lieu of gross receipts taxes effective January 2001.
