October 27, 2005
Mr. Jim Allegretto
Senior Assistant Chief Accountant
Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, NE
Washington, DC 20549
| RE: | Consolidated Natural Gas Company |
|
| Virginia Electric and Power Company |
Dear Mr. Allegretto:
Consolidated Natural Gas Company (CNG) and Virginia Electric and Power Company (Virginia Power) received the Staff's letter dated September 28, 2005, which provided comments on the above-referenced documents. Both CNG and Virginia Power are wholly-owned subsidiaries of Dominion Resources, Inc. (Dominion). This response letter has been filed on EDGAR, and a copy has been sent by express mail.
As requested by the Staff, CNG and Virginia Power hereby acknowledge the following:
For your convenience, the Staff's comments are set forth below and are followed by our responses.
Consolidated Natural Gas Company Form 10-K for the year ended December 31, 2004
Item 2. Properties, page 6
1. Explain to us, or show us where it is discussed, the reasons why proved developed oil reserves have materially increased in 2004, as compared with 2003.
Response
Proved developed oil reserves increased in 2004 as compared to 2003, primarily due to the development and attendant reclassification of reserves associated with CNG's deepwater Mississippi Canyon 773 field. During 2004, tie back and hookup operations were completed and CNG's Mississippi Canyon 773 wells began producing through the Devils Tower production facilities. As a result, applicable Mississippi Canyon 773 reserves were reclassified from "Proved Undeveloped" to "Proved Developed" reserves.
Item 7. Management's Discussion and Analysis of Results of Operations, page 9
Energy, page 10
2. You disclose that variability in expenses for your non-regulated businesses relates, in part, to payments under financially-settled contracts. Explain to us in detail how financially-settled contracts result in variability in expenses and whether such expenses are offset by some other item. Quantify the variability for the past three years supplementally and prospectively. Please also explain to us how you are accounting for such contracts. If such contracts are designated hedges, explain the type and structure. A detailed example(s) of such transaction(s) which shows the mechanics of the contract and the journal entries used to record such contracts would facilitate our review.
Response
In drafting the description of the Energy segment's nonregulated operations addressed in this comment, CNG had attempted to describe all possible contributors to the variability of expenses. CNG intended the description to be relevant not only for the periods covered by the report, but also for future periods consistent with efforts to incorporate a forward-looking perspective. The reference to "payments under financially-settled contracts" was intended to provide for the possibility that the Energy segment could hold derivatives that are subject to financial settlement and are not designated as hedges.
The Energy segment reported net gains (losses) on derivatives subject to financial settlement and not designated as hedges, of $1 million, $(4) million and $(4) million for the years 2004, 2003 and 2002. Based on the Staff's comment, CNG now recognizes that inclusion of all possible contributors in this disclosure, without considering each factor's significance in the periods covered by the report, may cause confusion. In future filings, CNG will clarify this disclosure to assist the reader's understanding and to ensure compatibility with the actual results of operations reported for the periods covered by the report.
Operating Revenue, page 14
3. Help us understand the business reasons for the transactions which led to a $109 million increase in other revenue from sales of purchased oil by exploration and production operations. In this regard, you disclose that this increase was largely offset by corresponding increases in Liquids, pipeline capacity and other purchases expenses. Please provide us the accounting analysis used for gross reporting of these transactions and explain to us the physical flow of the product including whether it was inventoried or part of the buy/sell arrangements.
Response
The $109 million increase in revenue from sales of purchased oil was primarily due to increased buy/sell activity related to CNG's offshore oil production, including significant additional activity related to CNG's deepwater oil producing wells that commenced production in 2004. The increase in
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revenue from sales of purchased oil was offset by a $108 million increase in buy/sell related purchase activity.
As discussed in Note 2 to the Consolidated Financial Statements under the headingCrude Oil Buy/Sell Arrangements, CNG enters into buy/sell agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. CNG typically enters into either a single or a series of buy/sell transactions in which it sells its crude oil production at the offshore field delivery point and buys similar quantities at Cushing, Oklahoma for sale to third parties. CNG is able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, rather than restricting its sales to a limited number of refinery purchasers in locations proximate to its Gulf of Mexico field delivery points.
Under the primary guidance of Emerging Issue Task Force (EITF) Issue No. 99-19,Reporting Revenue Gross as a Principal versus Net as an Agent, CNG presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counterparty non-performance risk. CNG is currently assessing the impact that the recently ratified EITF Issue No. 04-13,Accounting for Purchases and Sales of Inventory with the Same Counterparty, may have on its income statement presentation of these transactions.
Other Operations and Maintenance Expenses, page 15
4. Tell us your rationale for classification of the $96 million charge related to the discontinuance of hedge accounting to operations and maintenance expense. Please specifically tell us why it was classified in the corporate segment as opposed to the segment in which it originated when it was an effective hedge. We note your disclosure in significant accounting policies that specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. Explain to us what this means including where you classify the effective portions of the accounting hedges. An example may be helpful to our understanding of your classification policy.
Response
As disclosed in Note 2 to the Consolidated Financial Statements under the headingDerivative Instruments Held for Other Purposes, under CNG's income statement classification policy, unrealized changes in fair value and settlements for financially-settled derivatives that are not designated as hedging instruments are classified withinOther operations and maintenance expense. In light of the disruption caused by Hurricane Ivan, it became probable that the forecasted sales being hedged would not occur, therefore these financially settled instruments were de-designated as hedges. The reclassification of the losses on those instruments reported inAccumulated other comprehensive income (loss) (AOCI) prior to the de-designation, as well as subsequent changes in unrealized fair value and settlements, were classified inOther operations and maintenance expense,based on CNG's policy for reporting gains/losses on derivative instruments that are subject to financial settlement and are not designated as hedging instruments.
Note 23 to the Consolidated Financial Statements describes the components of the Corporate and Other operating segment. That disclosure indicates that certain items are not allocated to the Energy, Delivery or Exploration & Production operating segments in the measure of profit and loss reported to the chief operating decision-makers (CODM). CNG evaluates the performance of its operating segments by consistently excluding such items. Under CNG's management reporting, segment managers are neither held accountable for, nor receive the benefit from, items that are not considered by the CODM to be representative of ongoing segment operations. These items generally include unusual or nonrecurring items, extraordinary items, cumulative effect of changes in accounting principle and expenses resulting from decisions made by senior management in the context of the enterprise as a whole rather than at the segment level. Under this approach, a charge related to the discontinuance of hedge account ing as a result of damage to certain offshore oil production facilities in
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the Gulf of Mexico caused by Hurricane Ivan, and the related loss of forecasted oil production, is an example of an item that management believes should be excluded from its operating segments' results.
CNG disclosed the specific items excluded from its primary operating segments' results of operations in Note 23 to the Consolidated Financial Statements, as well as in the Corporate and Other Results of Operations section of Management's Discussion and Analysis of Results of Operations (MD&A).
Specific line item classification for fair value changes of derivative instruments included in a hedge strategy is determined based on the nature of the riskunderlying the hedge strategy. For cash flow hedges, the effective portion of gains or losses are classified within AOCI until the forecasted transaction occurs or when it becomes probable that the forecasted transaction will not occur, at which time the hedging gains or losses are reclassified and included in earnings. The risk being hedged refers to whether CNG is hedging the risk of cash flow variability for commodity sales, commodity purchases, or interest payments, or the risk of changes in fair value of inventory or debt. In each case, gains or losses on the hedging instrument would be recorded in the income statement line item in which the hedged item is recognized. For example, if CNG is using a financially- settled instrument to hedge the risk of cash flow variability of future sales of CNG's oil productio n, the effective portion of the financially-settled instrument would initially be classified in AOCI and then would be reclassified to theGas and oil production revenueline item with the corresponding oil sales once the forecasted sale has occurred.
Exploration and Production Segment, page 16
5. You disclose average realized prices with and without hedging results for your gas and oil revenue although it is not clear to a reader what percentage of your production was actually hedged. We assume you sell forward a significant portion of your anticipated production. Prospectively, enhance your exploration and production segment disclosure to quantify the extent of your hedging activities including the extent to which you are "locked-in" to fixed prices and the duration.
Response
In future filings, CNG's disclosure will include quantification of the extent of our hedging activities, including the extent to which our production is "locked-in" to fixed prices and the duration.
Consolidated Statements of Income, page 23
6. Tell us what you have netted against interest expense.
Response
In order of significance, the following items are netted against interest expense: capitalized interest, gains/losses from debt-related accounting hedges (e.g., those involving interest rate swaps), amortization of debt premiums, and allowance for funds used during construction.
Consolidated Statements of Cash Flows, page 27
7. Explain to us what comprises other operating assets and liabilities cash outflow of $(220) million for the year ended December 31, 2004.
Response
The $(220) million change in other operating assets and liabilities primarily consists of $(165) million related to the change in derivative assets and liabilities (net of the related change in AOCI) and $(26) million related to changes in regulatory assets.
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8. Explain to us what comprises other plant investing cash outflows of $(378) million for the year ended December 31, 2004.
Response
The $(378) million cash outflow represents capital expenditures for the construction and improvement of gas transmission and distribution assets.
Note 2. Significant Accounting Policies - Property, Plant and Equipment, page 31
9. Composite rates of depreciation are generally acceptable for rate regulated PP&E. Accordingly, please make it clear in future filings which property is regulated. For PP&E not subject to rate recovery, we believe the composition of plant assets along with the range of lives is required by paragraph 14 of APBO no. 22 and prevailing practice. Please revise or advise.
Response
CNG disclosed the composition of plant assets individually for utility and non-utility property in Note 10 to the Consolidated Financial Statements. CNG will revise its disclosure in future filings to exclude non-utility property from its reported depreciation rates and will instead provide the range of lives for those assets.
Note 7. International Investments, page 33
10. Please tell us why the impairment losses were not included in income from operations pursuant to paragraph 25 or 45 of SFAS no. 144. Additionally, tell us why the impairment loss on the Australian pipeline business for 2003 of $62 million on page 15 does not equal the impairment loss classified in corporate and other on page 17. Furthermore, explain to us if you applied the equity method of accounting to your investment in the Australian pipeline business, and if so, the nature of the $18 million benefit you recognized related to this investment. If you did not apply the equity method, tell us what you meant by your statement, "CNG International Corporation (CNGI) was engaged in energy-related activities outside of the continental United States, primarily through equity investments in Australia and Argentina." We may have further comment.
Response
In 2000, management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on its core business. As of that date the CNGI assets, which included the equity investment in the Australian pipeline business that was accounted for using the equity method, were classified as held-for-sale in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.
SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets, was effective for financial statements issued for fiscal years beginning after December 15, 2001. Paragraph 51 of SFAS No. 144 indicated, however, that assets classified as held-for-disposal as a result of activities initiated prior to SFAS No. 144's initial application should continue to be accounted for in accordance with SFAS No. 121. Furthermore, in accordance with the transition guidance in paragraph 51 of SFAS No. 144, CNG evaluated and concluded at the end of 2002 that the criteria in paragraph 30 of SFAS No. 144 were met and therefore continued to classify the CNGI assets as held-for-sale pursuant to SFAS No. 121.
Paragraphs 15 and 17 of SFAS No. 121 direct that assets held-for-sale be reported at the lower of carrying amount or fair value less cost to sell. Subsequent revisions in estimates of fair value less cost to sell are permitted as long as the carrying amount of the asset does not exceed the carrying amount before an adjustment was made to reflect the decision to dispose of the asset. Pursuant to this guidance, CNG recognized a $62 million impairment loss on its Australian pipeline investment during 2003 and
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a subsequent $18 million gain in the first quarter of 2004, which reflected CNG's then-current evaluations of fair market value less estimated cost to sell. In the second quarter of 2004, CNG recognized an additional $13 million gain on the sale of the Australian pipeline business. The valuation adjustments, as well as the gain on sale, were recorded as a component of income from continuing operations before income taxes in accordance with SFAS No. 121, paragraph 18. Although paragraph 18 also indicates that such gains and losses should be classified within income from operations, CNG classified them below income from operations, inOther income, to be consistent with its recording of equity earnings (losses) from the investment in the Australian pipeline which were classified therein pursuant to guidance in Regulation S-X, Rule 5-03.
The $78 million impairment loss described on page 17 in the Corporate and Other segment includes the $62 million impairment loss on the Australian pipeline business described on page 15 under the headingOther Income as well as the $16 million impairment loss on the wholly-owned CNGI generation facility in Hawaii that was sold in December 2003, described on page 15 under the headingOther Operations and Maintenance Expense.
Note 9. Hedge Accounting Activities, page 36
11. Explain to us the nature of the cash flow hedges that led to the recording of $103 million of income attributable to the time value of the options. We assume that since you have the physical commodity that to qualify for hedge accounting you are either writing calls or purchasing put options on gas or oil. In this regard, we do not understand why income resulted from changes in time value of options given the increasing prices of gas and oil through 2004. Please explain the economic events that caused the time portion of the option to increase in value. If our understanding is incorrect, please clarify it. Please also explain to us how you determine the time value of an option. We may have further comment.
Response
CNG is producing the physical commodity contemplated by this hedge strategy. Under this strategy, CNG held purchased call options in combination with swaps (receive fixed price/pay variable price) as hedging instruments. This combination of derivatives was used to hedge anticipated sales of CNG's future oil production over a range of prices, with that range capped at specified commodity unit prices. For example, the combination of a swap with a fixed price of $25 per barrel of crude oil (bbl) and a purchased call option with a strike price of $48 per bbl hedged CNG's exposure to cash flow variability over a range of prices from $0 to $48 per bbl. During periods when market prices for crude oil were at or below $48 per bbl, the fair value of the swap in this example would reflect the difference between its fixed price and the market value of crude oil at the specified future date of delivery/settlement. During those same periods and market price assumptions, the fair value of the option s would change, but such change would relate solely to the "time value" component of fair value, i.e., the fair value would not reflect any "intrinsic value." As permitted under paragraph 63 of SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, CNG elected to exclude changes in time value (sometimes referred to as extrinsic value) from the measurement of effectiveness. In this example (if potential ineffectiveness is ignored), during periods when market prices for crude oil were at, or below, $48 per bbl, the results of this hedging strategy, combined with the sale of the physical commodity, would result in $25 per bbl net revenue from sales of oil production.
Commodity prices increased during this period, approaching the strike price in the purchased call options. With these increases in commodity prices (and attendant effect on price volatility) and the increasing likelihood that market prices could exceed the strike prices in the purchased call options, the market value of the options increased, specifically related to the time value component of the options' fair value. Note 2 to the Consolidated Financial Statements describes the valuation methods used for calculating fair value, including the use of actively quoted market prices when available. The option values that resulted in the gains described above, including the intrinsic and extrinsic (time value) components, were valued using actively quoted market prices as market indicators were clearly available for the type and term for these specific options. The intrinsic value of an option is a reflection
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of whether the option is "in the money" or "out of the money". For example, when the forward market price of crude oil (at specified delivery date and location) is $58, a purchased call option for crude oil (at same delivery date and location) with a strike price of $48 has intrinsic value or "in the money" value of $10. The extrinsic value of an option is the difference between the fair value of an option and the intrinsic value. The extrinsic value of an option depends on the following factors:
As discussed above, the extrinsic value of the purchased call options increased, reflecting the effect of increasing prices and price volatility.
Note 10. Property, Plant and Equipment, page 36
12. Please explain why you have recorded the cash receipts from the sales of your overriding royalty interests as an investing cash inflow, as opposed to an operating or financing cash inflow. See also paragraph 45A of SFAS no. 133, as added by SFAS no. 149.
Response
Derivatives Implementation Group Issue B11,Embedded Derivatives: Volumetric Production Payments,considers the treatment of volumetric production payments under SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. Production payments that satisfy the requirements of paragraph 47(a) of SFAS No. 19 are accounted for as a sale of a mineral interest (and referred to as a volumetric production payment). The seller of a volumetric production payment is obligated to continue operating the properties and to deliver, free and clear of all expenses associated with operation of the property, the purchaser's share of the production. Issue B11 provides that a volumetric production payment is effectively a hybrid instrument composed of a debt host instrument embedded with a commodity forward that would need to be evaluated separately as an embedded derivative. However, the embedded commodity forward may be eligible for the normal sales exception and, if so, would not be subject to the accounting requirements of SFAS No. 133 for the party to whom it is a normal sale. If it is a normal sale, the entire volumetric production payment is accounted for under SFAS No. 19.
CNG's volumetric production payments satisfied the requirements in paragraph 47(a) of SFAS No. 19 and were determined to be eligible for the normal sales election; therefore, CNG accounted for the volumetric production payments under SFAS No. 19, not SFAS No. 133. Under SFAS No. 19, the volumetric production payments are recognized as sales of mineral interests. As mineral interests are considered tangible property and are classified as property, plant and equipment in CNG's Consolidated Balance Sheets, the cash flows are classified as an investing activity, representing receipts from sales of property, plant, and equipment.
Note 23. Operating Segments, page 46
13. Explain to us how you determined your operating segments and what reports your chief operating decision maker reviews regarding these segments. Furthermore, explain what criteria you used to aggregate your operating segments into your reportable segments. In this regard, we note that you are aggregating regulated distribution operations with non-regulated distribution operations, please explain why such aggregation is appropriate under SFAS no. 131.
Response
CNG's operating segments are determined using the "management approach" provided for in SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information. CNG's chief
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operating decision-makers review on a quarterly basis reports that provide operating statistics, net income contribution and an analysis of the variance in net income contribution versus prior year for the following business components: Energy, Delivery, Exploration & Production and Corporate and Other. Each of these components meets the definition of an operating segment and is also a reportable segment; there has been no aggregation pursuant to paragraph 17 of SFAS No. 131.
Although CNG's regulated distribution operations and nonregulated distribution operations both engage in business activities from which they earn revenues and incur expenses, that information is not provided to the chief operating decision-makers; therefore, those components do not meet the definition of an operating segment.
14. Prospectively, separately disclose the amount of revenue from external customers to the extent such item meets the criteria contain in paragraph 27 of SFAS no. 131.
Response
CNG believes its disclosure meets the requirements of SFAS No. 131, paragraph 27, which states:
"...An enterprise also shall disclose the following about each reportable segment if the specified amounts are included in the measure of segment profit or loss review by the chief operating decision maker;
a. Revenues from external customers
b. Revenues from transactions with other operating segments of the same enterprise..."
"Total revenue from external and affiliated customers" satisfies paragraph 27a since it represents revenue earned from third parties and from affiliated companies that are external to CNG. "Intersegment revenue" satisfies paragraph 27b as it represents revenues from transactions with other operating segments within CNG. In order to clarify the disclosure, CNG will separately disclose revenue from external third party customers and revenue from external affiliated customers in future filings.
Item 15. Exhibits and Financial Statement Schedules, page 66
15. Please explain why you have omitted Schedule II - Valuation of Qualifying Accounts.
Response
Regulation S-X Rule 5-04(b) states: "If the information required by any schedule (including the notes thereto) may be shown in the related financial statement or in a note thereto without making such statement unclear or confusing, that procedure may be followed and the schedule omitted."
CNG separately discloses its only material valuation allowances, the allowance for doubtful accounts and deferred income tax asset valuation allowance, on the face of its Consolidated Balance Sheets and in Note 8 to the Consolidated Financial Statements, respectively. All other valuation and qualifying accounts are immaterial individually and in the aggregate. Based on its disclosure of the information required by Schedule II in the financial statements and notes thereto and consideration of the guidance provided in Regulation S-X, CNG opted to omit Schedule II from its Annual Report on Form 10-K for the year ended December 31, 2004.
Consolidated Natural Gas Form 10-Q for the quarterly period ended June 30, 2005
Consolidated Balance Sheet, page 6
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16. Explain to us why your derivative liabilities have increased by 85% since December 31, 2004. In this regard, explain to us the nature of these derivatives. Also, explain how Hurricane Katrina could impact your results of operations and cash flows with respect to cash flow hedges that are no longer effective. If you have business interruption insurance which will mitigate such losses, then please discuss your coverage, and the anticipated timing of receiving financial recovery. If applicable, tell us how you plan to address this issue in your Form 10-Q for the period ended September 30, 2005.
Response
Derivative liabilities increased 85% from December 31, 2004 to June 30, 2005, primarily as a result of the impact of the increase in forward oil and gas commodity prices on swap instruments (receive fixed price/pay variable price) executed in connection with hedging forecasted sales. CNG also entered into additional swap instruments in 2005 that have been impacted by the pricing discussed above.
CNG is still evaluating the effects of both Hurricane Katrina and Hurricane Rita. Uncertainty remains about the timing for restoration of operations primarily as a result of CNG's reliance on "down-stream" third party pipelines and processing facilities. Due to disruptions caused by the hurricanes, CNG will be reporting its de-designation of some cash flow hedges related to commodity sales that did not occur in the period ended September 30, 2005, since such sales did not occur as originally forecasted (and it is probable that they will not occur within the additional two-month period thereafter specified in paragraph 33 of SFAS No. 133). Likewise, CNG will be evaluating its hedges of forecasted sales for periods beginning October 1, 2005, to determine the extent of de-designations that may be required due to the forecasted sales no longer being probable of occurrence. With the de-designations of hedges for which it is probable that such sales will not occur, CNG will reclassify the mark-t o-market losses related to the affected hedging instruments from AOCI to earnings.
CNG is covered by business interruption insurance up to certain policy maximums. Under terms of the policy, coverage did not apply to the first 30 days after the Hurricane Katrina disruption and does not apply to the first 45 days after the Hurricane Rita disruption. After the deductible period, the policy provides CNG with cash recoveries for delayed production sales revenue, representing estimated commodity sales that would have otherwise occurred, absent the disruption. Based on CNG's recent experience with the Hurricane Ivan disruption, CNG intends to seek partial business interruption insurance claim settlement payments as part of the overall settlement process associated with each hurricane. The timing of when such payments will be recognized in earnings will be governed by SFAS No. 5,Accounting for Contingencies, EITF Issue No. 01-10,Accounting for the Impact of the Terrorist Attacks of September 11, 2001, and other applicable accounting literature.
In its upcoming Quarterly Report on Form 10-Q for the period ended September 30, 2005, CNG will recognize as discussed above, and disclose the effects of the de-designation of hedges due to the forecasted sales no longer being probable of occurrence in both MD&A and the Notes to its Consolidated Financial Statements. CNG will also discuss the effects of delayed production on its results of operations in MD&A.
Virginia Electric and Power Company Form 10-K for the year ended December 31, 2004
General
17. Your authorized rates of return are useful information. Prospectively, please disclose such information.
Response
Virginia Power's current regulated retail base rates have been established by rate cap legislation in Virginia and a state commission approved settlement in North Carolina. No authorized rates of return are specified in the legislation or settlement agreement for the periods in which the provisions of the rate caps are effective. When authorized rates of return are specified in determining future retail rates, Virginia Power will reevaluate and consider disclosing them.
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Critical Accounting Policies and Estimates, page 10
Use of Estimates in long-lived asset impairment testing, page 10
18. You indicate that the company did not test any significant long-lived assets in 2004 as no circumstances arose that indicated impairment might exist. Item 2, Properties indicates that approximately 21% of your owned generation capability is gas fired generation. Furthermore, your Generation Segment Results of Operations on page 15 indicates that your gas energy output has been 5% or less of total output for the 3 years ended 2004. Given the recent price history of natural gas and decreased spark spreads, your limited use of these power plants, and the elimination of deferred fuel accounting in connection with the April 2004 amendments to the Virginia Restructuring Act, help us understand why you have not conducted any impairment testing on any gas fired units. Please be detailed in your explanation.
Response
SFAS No. 144 indicates that a long-lived asset or asset group shall be tested for recoverability whenever events or changes in circumstances indicate that its carrying amount may not be recoverable. SFAS No. 144 also provides examples of events or changes in circumstances that would indicate when an asset or asset group may not be recoverable.
One potential impairment indicator referenced in the above question relates to the output of Virginia Power's gas-fired generation versus the total output of all of its generation facilities. From 2003 to 2004, gas-fired generation rose from 3% to 5% of system energy output and rose from 19% to 21% of total generation capacity. The actual output of Virginia Power's gas fired generating stations, which are primarily designed to meet peak demand, not base load demand, has been in line with forecasted amounts. Based on these factors, management did not consider there to have been a significant adverse change in the extent to which or the manner in which the gas-fired units were used that could have indicated the potential for impairment.
Other potential impairment indicators referenced in the above question, such as the recent price history of natural gas, decreased spark spreads and the elimination of deferred fuel accounting, relate to whether there have been current-period operating or cash flow losses combined with a history of operating cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of Virginia Power's gas-fired generating units. An analysis of why those factors were not considered to be indicators of potential impairment follows.
The Virginia Electric Utility Restructuring Act (the Virginia Restructuring Act), which was enacted in 1999 and amended in April 2004, does not define specific generation-related costs to be recovered, but does provide for generation-related cash flows (through the combination of capped rates and wires charges billed to customers), which are intended to compensate Virginia Power for continuing to provide generation services. Since the cash flows provided by the generation portion of capped rates are not specific to plant or groupings of plant by fuel type (i.e., nuclear, coal, gas, etc.), a potential impairment indicator would need to impact Virginia Power's total generation asset base. Virginia Power does not believe that the factors listed above indicate that its total generation asset base may not be recoverable.
In December 2003, the Virginia State Corporation Commission approved an increase to Virginia Power's fuel rates. This increase was based on Virginia Power's best estimate of future commodity prices including natural gas, coal, oil and purchased power. In the April 2004 amendment of the Virginia Restructuring Act, Virginia Power's fuel rates were frozen until the earlier of July 1, 2007 or the termination of capped rates. The Virginia Restructuring Act provides for a one-time adjustment of the fuel rates effective July 1, 2007; those fuel rates will remain in effect through December 31, 2010 with no adjustment for previously incurred over-recovery or under-recovery thus eliminating deferred fuel accounting for Virginia Power's Virginia jurisdiction customers. The elimination of deferred fuel
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accounting was not considered an impairment indicator, as Virginia Power's fuel rates had recently increased to reflect forecasted future commodity prices. While commodity prices have since exceeded the levels contemplated in Virginia Power's fuel rates, the fuel rates are subject to adjustment again in July 2007. Therefore, the impact of higher fuel prices on income and cash flows from the generation asset base is believed to be temporary and is not expected to impact the recoverability of these assets.
FIN 46, page 11
19. Provide to us the qualitative analysis and quantitative model used to conclude you were the primary beneficiary of the variable interest leased power plant. In this regard, your step-by-step analysis of the lease as well as the structure of the transaction would be helpful to our understanding.
Response
Summary of Transaction:
Dominion, through its subsidiary, Dominion Equipment II, Inc. (DEI Sub), entered into agreements with special purpose entities (Lessor) in order to finance and lease a power generation project. Funding for the project, except for a small portion of equity provided by Lessor, was based on an underlying commercial paper facility. DEI Sub served as construction agent for Lessor in connection with the design and construction of the facility. Upon completion of the project, DEI Sub entered into a lease for the facility from Lessor. At the end of the lease term, DEI Sub may renegotiate the lease based on project costs and current market conditions, subject to Lessor's investors' approval; purchase the project at its original construction costs; or sell the project, on behalf of the Lessor, to an independent third party. If the project is sold and the proceeds from the sale are insufficient to repay the Lessor's investors, DEI Sub will be required to guarantee up to 89.9% of the lease balance at the time of sale. Supplementally, Dominion provided a parental guarantee for all lease obligations in the event that DEI Sub is unable to perform.
Virginia Power leased the facility from DEI Sub under a sublease (Sublease) which will end on August 22, 2007. The Sublease has the same terms and conditions as the lease between DEI Sub and Lessor; therefore, Virginia Power effectively assumed the lease commitment and residual value guarantee from DEI Sub. Dominion continues to provide its parental guarantee for the obligations under the Sublease in the event that Virginia Power is unable to perform.
See Exhibit A attached for a diagram of the lease arrangement.
Prior to the adoption of FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities (FIN 46R), Virginia Power accounted for the transaction as an operating lease. On December 31, 2003, Virginia Power adopted FIN 46R for its interests in special purpose entities. In order to assess the impact of applying FIN 46R, Virginia Power completed a checklist (See Exhibit B attached) to analyze the special purpose entities through which Dominion constructed, financed and leased the power generation facility and Virginia Power subleased the facility.
As documented in the checklist, it was determined that Lessor and DEI Sub are variable interest entities requiring consolidation by Virginia Power as a result of the residual value guarantee provided in the Sublease. As a result of its guarantee, Virginia Power would be required to absorb a majority of the entity's expected losses if they occur and is therefore the primary beneficiary. Although Dominion provides a parental guarantee of the lease obligations, that guarantee is secondary to Virginia Power's residual value guarantee and accordingly, Dominion is not the primary beneficiary. The Lessor's investors are not the primary beneficiary of Lessor since they do not have the requisite equity at risk to absorb expected losses. Similarly, Dominion, as equity owner of DEI Sub, is not the primary beneficiary of DEI Sub since they also do not have the requisite equity at risk to absorb expected losses. Therefore, since the design of the entity and responses on the qualitative analysis indicat ed that Virginia Power is the primary beneficiary, no additional detailed quantitative analysis was performed.
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Results of Operations, page 12
Overview, page 12
20. Explain to us why you are classifying impairment charges associated with long-term power tolling arrangements in your Corporate and Other Operating Segment.
Response
Virginia Power has defined its operating segments in accordance with the requirements of paragraph 10 of SFAS No. 131. Virginia Power's CODM regularly reviews the aggregated operating results of the following four business components: Generation, Energy, Delivery, and Corporate and Other.
Note 23 to the Consolidated Financial Statements describes the components of the Corporate and Other operating segment. That disclosure indicates that certain items are not allocated to the Generation, Energy, or Delivery operating segments in the measure of profit and loss reported to the CODM. Virginia Power evaluates the performance of its operating segments by consistently excluding such items. Under Virginia Power's management reporting, segment managers are not held accountable for, nor do they receive the benefit from, items that are not considered by the CODM to be representative of ongoing segment operations. These items generally include unusual or nonrecurring items, extraordinary items, cumulative effect of changes in accounting principle and expenses resulting from decisions made by senior management in the context of the enterprise as a whole rather than at the segment level. Under this approach, charges related to Virginia Power's valuation of its interest in a long-term pow er tolling contract and the termination of three long-term power tolling contract agreements are examples of items that management believes should be excluded from its operating segments' results.
Analysis of Consolidated Operations, page 13
21. If applicable, prospectively quantify the impact of higher fuel rates and increased sales volume on regulated electric sales revenue.
Response
Virginia Power will prospectively quantify the impact of fuel rates and changes in sales volumes on regulated electric sales revenue, to the extent they are material.
Other Revenue, page 14
22. Explain to us if you are taking delivery of the coal that you are purchasing for resale. In this regard, explain to us your basis for gross presentation.
Response
Virginia Power does not take physical delivery of the coal that it purchases for resale; however, based on an analysis of the indicators in EITF Issue No. 99-19, we concluded that gross income statement presentation of these purchases and sales is appropriate. The following indicators support gross presentation of these transactions:
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Consolidated Statements of Cash Flows, page 36
23. Provide us a detail of what comprised other operating assets and liabilities operating cash flows for the years ended 2004, 2003, and 2002. Unless apparent by the description, please narrate why each cash flow is operating.
Response
The change in "Other operating assets and liabilities" in the Operating Activities section of the Consolidated Statements of Cash Flows consists of the following:
| 2004 | 2003 | 2002 |
(millions) |
|
|
|
Derivative assets & liabilities* | $194 | $140 | $(51) |
Prepaid pension cost | 40 | (85) | (30) |
Accrued liabilities | (43) | 59 | (40) |
Other | 20 | 24 | 8 |
Other operating assets and liabilities | $211 | $138 | $(113) |
* Energy trading and risk management activities
Note 3. Newly Adopted Accounting Standards, page 39
SFAS no. 143, page 40
24. We note you recognized a gain upon adoption of SFAS no. 143. We presume such gain is due to amounts that were previously collected from ratepayers for decommissioning but exceed the amount of the legal liabilities required to be recorded as a liability under SFAS no. 143. If our presumption is not correct, please clarify it. If correct, please advise us how you determined that there is no refund obligation associated with the amounts previously collected from ratepayers. Clarify our understanding as to the current accounting and whether capped base rates include a provision for decommissioning. If so, tell us how you are accounting for it and how it affects net income. We may have further comment.
Response
The $139 million after-tax gain recognized as a cumulative effect of a change in accounting principle upon adoption of SFAS No. 143,Accounting for Asset Retirement Obligations, on January 1, 2003 was due to the difference between the fair value of the asset retirement obligations recorded under SFAS No. 143 and the amounts previously recognized in the Consolidated Balance Sheets as the accumulated provision for decommissioning, which included amounts accrued for future nuclear decommissioning that had been reflected in rates collected from ratepayers as well as realized and unrealized earnings on trust investments dedicated to funding the decommissioning of Virginia Power's nuclear plants.
Except for that portion of operations subject to regulation by the North Carolina Utilities Commission (North Carolina Commission), Virginia Power's electric generation operations involved in serving its utility customers are no longer subject to SFAS No. 71,Accounting for the Effects of Certain Types of Regulation.
Paragraph 11 of SFAS No. 71 provides: "Rate actions of a regulator can impose a liability on a regulated enterprise. Such liabilities are usually obligations to the enterprise's customers."
Paragraph 11.b of SFAS No. 71 further provides:
A regulator can provide current rates intended to recover costs that are expected to be incurred in
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the future with the understanding that if those costs are not incurred future rates will be reduced by corresponding amounts. If current rates are intended to recover such costs and the regulator requires the enterprise to remain accountable for any amounts charged pursuant to such rates and not yet expended for the intended purpose, the enterprise shall not recognize as revenues amounts charged pursuant to such rates. Those amounts shall be recognized as liabilities and taken to income only when the associated costs are incurred.
Virginia Power believes that the North Carolina Commission requires Virginia Power's utilityoperations to remain accountable for amounts attributable to collections from North Carolina customers for funding future decommissioning activities. Accordingly, in its adoption of SFAS No. 143, Virginia Power considered the accounting requirements of SFAS No. 71 and recognized a $13.6 million regulatory liability in relation to its North Carolina retail jurisdictional utility operations. The regulatory liability represents the excess of the accumulated provision for nuclear decommissioning accrued under the prior accounting policy, which was based on amounts being collected from Virginia Power's North Carolina jurisdictional customers to fund future decommissioning activities and earnings on the related trust investments, over the amounts recognized under SFAS No. 143.
Under the Virginia Restructuring Act, Virginia Power's Virginia jurisdictional utility generation operationsare nolonger subject to cost-of-service rate regulation. As a result, Virginia Power discontinued the application of SFAS No. 71 to the Virginia jurisdictional portion of its generation operations. The Virginia Restructuring Act allows Virginia Power to file with the Virginia Commission its plan to assure full funding of the decommissioning of its Surry and North Anna nuclear generating units, including the amount of revenue to be collected from customers and deposited into the trust accounts to fund the future decommissioning costs. However, there are no provisions in the Virginia Restructuring Act that would require refunds to customers or the recording of regulatory liabilities related to the reversal of the Virginia jurisdictional portion of the provision for decommissioning recognized under the previous accounting policy.
As services are rendered to customers under the capped rates, Virginia Power recognizes regulated electric sales revenue. The base rates established in the settlement of Virginia Power's last rate proceeding prior to the effective date of the Virginia Restructuring Act became the capped rates. Although those rates were designed to cover Virginia Power's cost of generation, transmission and distribution operations, including a provision for nuclear decommissioning, the Virginia Restructuring Act provides that generation operations are no longer subject to cost-of-service rate regulation, effective January 1, 2002.
Note 7. Hedge Accounting Activities, page 43
25. You indicate foreign exchange rates will affect the amount of other comprehensive income that will be reclassified into net income. Please explain to us the nature of the foreign currencies hedge(s) you have in place. Tell us the specific risk being hedged.
Response
Virginia Power has contracts for Euro-denominated uranium enrichment services in connection with procurement of fuel for use in its nuclear generating units. As a result, Virginia Power enters into derivative instruments to hedge its Euro foreign currency exchange risk. More specifically, Virginia Power enters into currency forwards with a counterparty whereby it pays fixed U.S. dollars to the counterparty, and the counterparty pays fixed Euros. These derivative contracts qualify for cash flow hedging treatment as hedges of the Euro-denominated foreign currency exposure of the payments for uranium enrichment services under the contracts. The effective portion of hedging gains/losses is attributed to particular nuclear fuel assemblies and is reclassified from AOCI to earnings as the amortization (based on unit-of-production method) of the nuclear fuel is included in earnings.
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Virginia Electric and Power Company Form 10-Q for the quarterly period ended June 30, 2005
Segment Results of Operations - Delivery, page 22
26. Prospectively, please ensure that reported changes in net income numerically foot. In this regard, the numerical changes that you present to explain Delivery's net income contribution does not foot for the second quarter analysis.
Response
Virginia Power will ensure that reported changes in net income numerically foot in future filings.
Investing Cash Flows, page 28
27. Explain to us the rationale for reporting purchases and sales of investments in the company's nuclear decommissioning trust funds in investing cash flows. In this regard, we assume all activity flows through the external fund, which also holds any excess cash after investment purchases (sales) are made, if our assumption is not correct, please clarify our understanding. Similarly, help us understand how you reflect realized gains (losses) and earned income from your nuclear decommissioning trust funds in your statement of cash flows.
Response
As disclosed in Note 8 to the Virginia Power's Consolidated Financial Statements for the year ended December 31, 2004, Virginia Power holds marketable debt and equity securities in nuclear decommissioning trust funds and classifies these investments as available-for-sale. Although the funds are held by external trusts, the trusts are included in Virginia Power's consolidated financial statements.
Virginia Power reports gross purchases and sales of these investment securities in investing activities within its Consolidated Statements of Cash Flows in accordance with paragraph 18 of SFAS No. 115,Accounting for Certain Investments in Debt and Equity Securities. Realized gains (losses) and earned income on the trust funds included in net income are deducted (added back) as adjustments to reconcile net income to net cash from operating activities in the Consolidated Statements of Cash Flows. Realized gains (losses) are reflected in theProceeds from sales of securities line item, while earned income is reported in other investing activities.
If you have any questions or require further information, please call me at (804) 819-2410.
Sincerely,
/s/ Steven A. Rogers
Steven A. Rogers
Vice President (Principal Accounting Officer)
Virginia Electric and Power Company
Vice President and Controller
Consolidated Natural Gas Company
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