Washington, D.C. 20549
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
At September 30, 2006, the latest practicable date for determination, 100 shares of common stock, without par value, of the registrant were outstanding.
The accompanying notes are an integral part of the Consolidated Financial Statements.
Financial Statements at that date.
The accompanying notes are an integral part of the Consolidated Financial Statements.
Financial Statements at that date.
The accompanying notes are an integral part of the Consolidated Financial Statements.
The accompanying notes are an integral part of the Consolidated Financial Statements.
CONSOLIDATED NATURAL GAS COMPANY (Unaudited)
Note 1. Nature of Operations
Consolidated Natural Gas Company (the Company), is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). Our subsidiaries operate in all phases of the natural gas business, explore for and produce gas and oil and provide a variety of energy marketing services. As of September 30, 2006, our regulated gas distribution subsidiaries serve approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia and our nonregulated retail energy marketing businesses serve approximately 1.4 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest regions of the United States. We operate an interstate gas transmission pipeline system, underground natural gas storage system and gathering and extraction facilities in the Northeast, Midwest and Mid-Atlantic states and a liquefied natural gas (LNG) import and storage facility in Maryland. Our producer services operations involve the aggregation of natural gas supply and related wholesale activities. Our exploration and production operations are located in several major gas and oil producing basins in the United States, both onshore and offshore.
We manage our daily operations through three primary operating segments: Delivery, Energy and Exploration & Production (E&P). In addition, we report our corporate and other functions as a segment. Our assets remain wholly owned by us and our legal subsidiaries.
The terms “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or operating segments or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries.
Note 2. Significant Accounting Policies
As permitted by the rules and regulations of the Securities and Exchange Commission (SEC), the accompanying unaudited Consolidated Financial Statements contain certain condensed financial information and exclude certain footnote disclosures normally included in annual audited consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). These unaudited Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes in our Annual Report on Form 10-K for the year ended December 31, 2005 and Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
In our opinion, our accompanying unaudited Consolidated Financial Statements contain all adjustments, including normal recurring accruals necessary to present fairly our financial position as of September 30, 2006, our results of operations for the three and nine months ended September 30, 2006 and 2005, and our cash flows for the nine months ended September 30, 2006 and 2005.
We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses for the periods presented. Actual results may differ from those estimates.
Our accompanying unaudited Consolidated Financial Statements include, after eliminating intercompany transactions and balances, our accounts and those of our majority-owned subsidiaries and those variable interest entities (VIEs) where we have been determined to be the primary beneficiary.
We report certain contracts and instruments at fair value in accordance with GAAP. Market pricing and indicative price information from external sources are used to measure fair value when available. In the absence of this information, we estimate fair value based on near-term and historical price information and statistical methods. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. See Note 2 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005 for a more detailed discussion of our estimation techniques.
The results of operations for interim periods are not necessarily indicative of the results expected for the full year. Information for quarterly periods is affected by seasonal variations in sales, rate changes, purchased gas expenses and other factors.
Certain amounts in our 2005 Consolidated Financial Statements and Notes have been reclassified to conform to the 2006 presentation.
Note 3. Newly Adopted Accounting Standards
EITF 04-13
We enter into buy/sell and related agreements primarily as a means to reposition our offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore and to facilitate gas transportation. In September 2005, the Financial Accounting Standards Board (FASB) ratified the Emerging Issues Task Force’s (EITF) consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, that requires buy/sell and related agreements to be presented on a net basis in the Consolidated Statements of Income if they are entered into in contemplation of one another. We adopted the provisions of EITF 04-13 on April 1, 2006 for new arrangements entered into, and modifications or renewals of existing arrangements after that date. As a result, a significant portion of our activity related to buy/sell arrangements is presented on a net basis in our Consolidated Statement of Income for the three months and nine months ended September 30, 2006; however, there was no impact on our results of operations or cash flows. Pursuant to the transition provisions of EITF 04-13, activity related to buy/sell arrangements that were entered into prior to April 1, 2006 and have not been modified or renewed after that date continue to be reported on a gross basis and are summarized below:
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | |
| Sale activity included in operating revenue | $37 | $195 | $540 | $479 |
Purchase activity included in operating expenses(1) | 40 | 199 | 539 | 485 |
(1) Included in other energy-related commodity purchases expense and purchased gas expense on our Consolidated Statements of Income.
Note 4. Recently Issued Accounting Standards
SFAS No. 158
In September 2006, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of their benefit plans as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur as a component of other comprehensive income. The funded status is measured as the difference between the fair value of the plan’s assets and its benefit obligation. In addition, SFAS No. 158 requires an employer to measure benefit plan assets and obligations that determine the funded status of a plan as of the end of its fiscal year, which we already do. The prospective requirement to recognize the funded status of a benefit plan and to provide the required disclosures will become effective for us on December 31, 2006. The adoption of SFAS No. 158 will have no impact on our results of operations or cash flows. We are currently evaluating the impact that SFAS No. 158 will have on our financial condition.
SAB 108
In September 2006, the SEC issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 provides guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated. The provisions of SAB 108 are required to be applied beginning December 31, 2006. We do not expect the adoption of SAB 108 to impact our Consolidated Financial Statements.
FIN 48
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. In addition, FIN 48 requires new disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, information about potential significant changes in estimates related to tax positions and descriptions of open tax years by major jurisdiction. The provisions of FIN 48 will become effective for us beginning January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to retained earnings. We are currently evaluating the impact that FIN 48 will have on our results of operations and financial condition.
SFAS No. 157
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under EITF Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.
Note 5. Sale of Regulated Gas Distribution Subsidiaries
On March 1, 2006, we entered into an agreement with Equitable Resources, Inc., to sell two of our wholly-owned regulated gas distribution subsidiaries, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), for approximately $970 million plus adjustments to reflect capital expenditures and changes in working capital. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. The transaction is expected to close by the first quarter of 2007, subject to state regulatory approvals in Pennsylvania and West Virginia, as well as approval under the federal Hart-Scott-Rodino Act. The carrying amounts of the major classes of assets and liabilities classified as held for sale in our Consolidated Balance Sheet are as follows:
| (millions) | | September 30, 2006 |
ASSETS | | |
Current Assets | | |
| Cash | | $ 2 |
| Customer accounts receivable | | 93 |
| Unrecovered gas costs | | 28 |
| Other | | 126 |
| Total current assets | | 249 |
Investments | | 2 |
Property, Plant and Equipment | | |
| Property, plant and equipment | | 1,098 |
| Accumulated depreciation, depletion and amortization | | (374) |
| Total property, plant and equipment, net | | 724 |
Deferred Charges and Other Assets | | |
| Regulatory assets | | 100 |
| Other | | 1 |
| Total deferred charges and other assets | | 101 |
| Assets held for sale | | $1,076 |
| | | |
LIABILITIES | | |
Current Liabilities | | |
| Accounts payable | | $ 68 |
| Payables to affiliates | | 23 |
| Deferred income taxes | | 13 |
| Other | | 95 |
| Total current liabilities | | 199 |
Deferred Credits and Other Liabilities | | |
| Asset retirement obligations | | 33 |
| Deferred income taxes | | 166 |
| Regulatory liabilities | | 10 |
| Other | | 11 |
| Total deferred credits and other liabilities | | 220 |
| Liabilities held for sale | | $ 419 |
The following table presents selected information regarding the results of operations of Peoples and Hope:
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | |
| | | | | |
| Operating Revenue | $63 | $60 | $512 | $472 |
| | | | | |
| Income (loss) before income taxes | (6) | (9) | (134) | 37 |
In the nine months ended September 30, 2006, we recognized a $163 million ($100 million after-tax) charge, recorded in other operations and maintenance expense in our Consolidated Statement of Income, resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, since the recovery of those assets is no longer probable. We also established $96 million of deferred tax liabilities on our Consolidated Balance Sheet in accordance with EITF Issue No. 93-17, Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation. EITF 93-17 requires that the deferred tax impact of the excess of the financial reporting basis over the tax basis of a parent’s investment in a subsidiary be recognized when it is apparent that this difference will reverse in the foreseeable future. We recorded an adjustment since the financial reporting basis of our investment in Peoples and Hope exceeds our tax basis. This difference and related deferred taxes will reverse and will partially offset current tax expense recognized upon closing of the sale.
EITF Issue No. 03-13, Applying the Conditions of Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations, provides that the results of operations of a component of an entity that has been disposed of or is classified as held for sale shall be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the component have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. While we do not expect to have significant continuing involvement with Peoples or Hope after their disposal, we do expect to have continuing cash flows related primarily to our sale to them of natural gas production from our E&P operations as well as natural gas transportation and storage services provided to them by our transmission operations. Due to these expected significant continuing cash flows, the results of Peoples and Hope have not been reported as discontinued operations in our Consolidated Statements of Income. We will continue to assess the level of our involvement and continuing cash flows with Peoples and Hope for one year after the date of sale in accordance with EITF 03-13, and if circumstances change, we may be required to reclassify the results of Peoples and Hope as discontinued operations in our Consolidated Statements of Income.
Note 6. Operating Revenue
Our operating revenue consists of the following:
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | |
| | | | | |
| Gas sales: | | | | |
| Regulated | $96 | $122 | $1,071 | $1,117 |
| Nonregulated: | | | | |
| External customers | 221 | 256 | 1,095 | 910 |
| Affiliated customers | 100 | 293 | 393 | 751 |
| Nonregulated electric sales | 82 | 123 | 259 | 277 |
| Other energy-related commodity sales | 108 | 183 | 704 | 461 |
| Gas transportation and storage | 192 | 184 | 683 | 653 |
| Gas and oil production | 418 | 296 | 1,324 | 1,007 |
| Other | 297 | 20 | 358 | 255 |
| Total operating revenue | $1,514 | $1,477 | $5,887 | $5,431 |
Note 7. Income Taxes
The statutory U.S. federal income tax rate reconciles to our effective income tax rate as follows:
| | Nine Months Ended September 30, |
| | 2006 | 2005 |
| | | |
| U.S. statutory rate | 35.0% | 35.0% |
| | | |
| Increases (decreases) resulting from: | | |
| Employee pension and other benefits | (0.4) | (2.7) |
| State taxes, net of federal benefit | 2.9 | 6.7 |
| Changes in valuation allowances | (2.0) | (1.3) |
| Recognition of deferred taxes - stock of subsidiaries held for sale | 7.8 | -- |
| Other, net | 0.6 | 0.1 |
| Effective tax rate | 43.9% | 37.8% |
Our effective tax rate for the nine months ended September 30, 2006 reflects the recognition of $96 million of additional deferred income taxes related to the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope in accordance with EITF 93-17. In addition, in anticipation of the capital gain expected to result from the pending sale of Peoples and Hope, we reduced the valuation allowances on deferred tax assets, representing certain federal and state tax loss carryforwards.
Note 8. Comprehensive Income
The following table presents total comprehensive income (loss):
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | |
| | | | | |
| Net income (loss) | $340 | $(298) | $ 691 | $ 240 |
| Other comprehensive income (loss): | | | | |
| Net other comprehensive income (loss) associated with effective portion of changes in fair value of derivative cash flow hedges, net of taxes and amounts reclassified to earnings | 592(1) | (588)(2) | 1,158(1) | (1,263)(2) |
| Total comprehensive income (loss) | $932 | $(886) | $1,849 | $(1,023) |
(1) Primarily due to the settlement of certain commodity derivative contracts and favorable changes in fair value resulting from a decrease in gas prices.
(2) Primarily due to unfavorable changes in the fair value of certain commodity derivatives resulting from an increase in commodity prices.
Note 9. Hedge Accounting Activities
We are exposed to the impact of market fluctuations in the price of natural gas, oil, electricity and other energy-related products as well as the interest rate risks of our business operations. We use derivative instruments to mitigate our exposure to these risks and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes as allowed by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Selected information about our hedge accounting activities follows:
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | | | | |
| Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income: | | | | |
| Fair value hedges | $ (1) | $ 3 | $ (3) | $ 4 |
Cash flow hedges(1) | (1) | (29) | 19 | (41) |
| Net ineffectiveness | $ (2) | $(26) | $ 16 | $(37) |
| (1) | Represents hedge ineffectiveness, primarily due to changes in the fair value differential between the delivery location and commodity specifications of derivatives held by our E&P operations and the delivery location and commodity specifications of our forecasted gas and oil sales. |
Gains and losses on hedging instruments that were excluded from the measurement of effectiveness and included in net income for the three and nine months ended September 30, 2006 and 2005 were not material.
As a result of a delay in reaching anticipated production levels in the Gulf of Mexico, we discontinued hedge accounting for certain cash flow hedges in March 2005 since it became probable that the forecasted sales of oil would not occur. The discontinuance of hedge accounting for these contracts resulted in the reclassification of $30 million ($19 million after-tax) of losses from accumulated other comprehensive income (loss) (AOCI) to earnings in March 2005.
Additionally, due to interruptions in Gulf of Mexico and south Louisiana gas and oil production caused by Hurricanes Katrina and Rita, we discontinued hedge accounting for certain cash flow hedges in August and September 2005, since it became probable that the forecasted sales of gas and oil would not occur. In connection with the discontinuance of hedge accounting for these contracts, we reclassified $423 million ($272 million after-tax) of losses from AOCI to earnings in the third quarter of 2005.
The following table presents selected information related to cash flow hedges included in AOCI in our Consolidated Balance Sheet at September 30, 2006:
| | AOCI After-Tax | Portion Expected to be Reclassified to Earnings During the Next 12 Months After-Tax | Maximum Term |
| (millions) | | |
| Commodities: | | | |
| Gas | $ (241) | $(229) | 54 months |
| Oil | (366) | (250) | 39 months |
| Electricity | (3) | (3) | 8 months |
| Interest Rate | (1) | -- | 98 months |
| Total | $(611) | $(482) | |
The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the anticipated amounts presented above as a result of changes in market prices and interest rates.
Note 10. Ceiling Test
We follow the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves assuming period-end hedge-adjusted prices. Approximately 9% of our anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Whether period-end market prices or hedge-adjusted prices were used for the portion of production that is hedged, there was no ceiling test impairment as of September 30, 2006.
Note 11. Variable Interest Entities
In accordance with FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R), we consolidate a variable interest lessor entity through which we have financed and leased the Armstrong generation facility. The Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005 reflect net property, plant and equipment of $203 million and $207 million, respectively, and $234 million of debt related to this entity. The debt is non-recourse to us and is secured by the entity’s property, plant and equipment. The lease under which we operate the power generation facility terminates in November 2006. We intend to take legal title to the facility through repayment of the lessor’s related debt at the end of the lease term.
In September 2006, we, along with three other gas and oil exploration companies, entered into a long-term contract with an unrelated limited liability corporation (LLC) whose only current activities are to design, construct, install and own the Thunder Hawk facility, a semi-submersible production facility to be located in the deepwater Gulf of Mexico. Certain variable pricing terms and guarantees in the contract protect the equity holder from variability, and therefore, the LLC was determined to be a VIE. After completing our FIN 46R analysis, we concluded that although our 25% interest in the contract, as a result of its pricing terms and guarantee, represents a variable interest in the LLC, we are not the primary beneficiary. Our maximum exposure to loss from the contractual arrangement is approximately $63 million. As of September 30, 2006 we have not made any payments to the LLC.
Note 12. Significant Financing Transactions
Joint Credit Facilities
We use short-term debt, primarily commercial paper, to fund working capital requirements and as a bridge to long-term debt financing. The level of our borrowings may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, we utilize cash and letters of credit to fund collateral requirements under our commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels and the credit quality of our companies and their counterparties. In February 2006, we entered into a $3.0 billion five-year revolving credit facility with Dominion and Virginia Electric and Power Company (Virginia Power), a wholly-owned subsidiary of Dominion. The credit facility is scheduled to terminate in February 2011. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion, Virginia Power and us and for other general corporate purposes. This credit facility can also be used to support up to $1.5 billion of letters of credit.
At September 30, 2006, total outstanding commercial paper supported by the joint credit facility was $165 million, of which our borrowings were $80 million. At September 30, 2006, total outstanding letters of credit supported by the joint credit facility were $302 million, none of which were issued on our behalf.
At September 30, 2006, capacity available under the joint credit facility was $2.5 billion.
On November 1, 2006, we repaid our $500 million 2001 Series B 5.375% Senior Notes which matured on that date, using proceeds from a short-term borrowing under our $1.7 billion credit facility.
Other Credit Facilities
In February 2006, we entered into a $1.70 billion five-year revolving credit facility, which is scheduled to terminate in August 2010. Also in February 2006, we entered into a $1.05 billion 364-day credit facility, which is scheduled to terminate in February 2007. These credit facilities are being used to support our issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative contracts used in risk management strategies for our gas and oil production. At September 30, 2006, outstanding letters of credit under these facilities totaled $705 million and capacity available under the facilities totaled $2.05 billion.
In addition to the facilities above, we have also entered into several bilateral credit facilities in order to provide collateral required on derivative contracts used in risk management strategies for our gas and oil production operations. At September 30, 2006, we had the following letter of credit facilities:
Facility Limit | Outstanding Letters of Credit | Facility Capacity Remaining | Facility Inception Date | Facility Maturity Date |
| (millions) | | | | |
| $100 | $ 25 | $ 75 | June 2004 | June 2007 |
| 100 | 100 | -- | August 2004 | August 2009 |
200(1) | --- | 200 | December 2005 | December 2010 |
| $400 | $125 | $275 | | |
| (1) | This facility can also be used to support commercial paper borrowings. |
Note 13. Commitments and Contingencies
Other than the matters discussed below, there have been no significant developments regarding commitments and contingencies disclosed in Note 19 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005, or Note 13 to the Consolidated Financial Statements in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006, nor have any significant new matters arisen during the three months ended September 30, 2006.
Insurance for E&P Operations
In the past, we have maintained business interruption, property damage and other insurance for our E&P operations. However, the increased level of hurricane activity in the Gulf of Mexico led our insurers to terminate certain coverages for our E&P operations; specifically, our Operator’s Extra Expense (OEE), offshore property damage and offshore business interruption coverage was terminated. All onshore property coverage (with the exception of OEE) and liability coverage commensurate with past coverage remained in place for our E&P operations. Recently our OEE coverage for both onshore and offshore E&P operations was reinstated under a new policy. However, efforts to replace the terminated insurance for our E&P operations for offshore property damage and offshore business interruption with similar traditional insurance on commercially reasonable terms were unsuccessful. This lack of insurance could adversely affect our results of operations.
In 2005, Hurricanes Katrina and Rita (2005 hurricanes) struck the Gulf of Mexico, causing interruptions to expected gas and oil production and damage to certain facilities in and along the Gulf of Mexico. During the third quarter of 2006, we reached a settlement on our business interruption insurance and property damage claims for the 2005 hurricanes in the amount of $309 million. Of the total proceeds, we received $304 million during the third quarter of 2006 and expect to receive the remaining $5 million during the fourth quarter of 2006.
Lease Commitment
In September 2006, we, along with three other gas and oil exploration companies executed agreements with a third party to design, construct, install and own the Thunder Hawk facility, a semi-submersible production facility to be located in the deepwater Gulf of Mexico. We anticipate that mechanical completion of the Thunder Hawk facility will occur in 2009 and that the processing of our production will start by 2010. The agreements require a demand charge of approximately $63 million payable over five years starting on the day after the mechanical completion of the Thunder Hawk facility. The agreements also require the payment of production processing fees including a minimum processing fee if yearly production processing fees are below specified amounts. The maximum amount of our minimum processing fee obligation would be approximately $3 million per year. Our obligation for the payment of such processing fees will terminate upon the cessation of production.
Guarantees
In 2005, we, along with two other gas and oil exploration and production companies, entered into a four-year drilling contract related to a new, ultra-deepwater drilling rig that is expected to be delivered in mid-2008. The contract has a four-year primary term, plus four one-year extension options. Our minimum commitment under the agreement is for approximately $99 million over the four-year term; however, we are also jointly and severally liable for up to $394 million to the contractor if the other parties fail to pay the contractor for their obligations under the primary term of the agreement, which we view as highly unlikely. We have not recognized any significant liabilities related to this guarantee arrangement.
As discussed above in Lease Commitment, in September 2006, we, along with three other gas and oil exploration companies executed agreements with a third party to design, construct, install and own the Thunder Hawk facility, a semi-submersible production facility to be located in the deepwater Gulf of Mexico. Due to current offshore insurance market conditions, it is anticipated that the Thunder Hawk facility will only be partially insured against a catastrophic full or partial loss. We, along with the three other participating producers will be required to continue to make demand payments in the event of a catastrophic loss if insurance payments are not sufficient to pay the lessor’s outstanding debt incurred for the Thunder Hawk facility. Our obligation will terminate upon the earlier event of full payment of the lessor’s debt incurred for the Thunder Hawk facility or the full payment of our demand charge obligation. We believe that it is unlikely that we would be required to perform under this guarantee and have not recognized any significant liabilities for this arrangement.
We also enter into guarantee arrangements on behalf of our consolidated subsidiaries primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of our consolidated subsidiaries, that liability is included in our Consolidated Financial Statements. We are not required to recognize liabilities for guarantees issued on behalf of our subsidiaries unless it becomes probable that we will have to perform under the guarantees. No such liabilities have been recognized as of September 30, 2006. We believe it is unlikely that we would be required to perform or otherwise incur any losses associated with guarantees of our subsidiaries’ obligations. At September 30, 2006, we had issued the following subsidiary guarantees:
| | Stated Limit | Value(1) |
| (millions) | | |
Subsidiary debt(2) | $ 205 | $ 205 |
Offshore drilling commitments(3) | --- | 493 |
Commodity transactions(4) | 1,188 | 632 |
| Other | 415 | 258 |
| Total subsidiary obligations | $1,808 | $1,588 |
| (1) | Represents the estimated portion of the guarantees’ stated limit that is utilized as of September 30, 2006 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by our subsidiaries, the value includes the recorded amount. |
| (2) | Guarantees of debt of Dominion Oklahoma Texas Exploration and Production Inc. (DOTEPI). In the event of default by this subsidiary, we would be obligated to repay such amounts. |
| (3) | Performance and payment guarantees related to an offshore day work drilling contract, rig share agreements and related services for certain subsidiaries. There are no stated limits for these guarantees. |
| (4) | Guarantees of contract payments for certain subsidiaries involved in natural gas and oil production, natural gas delivery and energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, we would be required to satisfy such obligation. We and our subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits. |
Surety Bonds and Letters of Credit
As of September 30, 2006, we had also purchased $48 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $855 million. We enter into these arrangements to facilitate commercial transactions by our subsidiaries with third parties.
Note 14. Credit Risk
We sell natural gas and provide distribution services to residential, commercial and industrial customers and provide transmission services to utilities and other energy companies. In addition, we enter into contracts with various companies in the energy industry for purchases and sales of energy-related commodities and extracted products,
including natural gas and oil. Except for our gas and oil exploration and production business activities, these transactions principally occur in the Northeast, Midwest and Mid-Atlantic regions of the United States. We do not believe that this geographic concentration contributes significantly to our overall exposure to credit risk. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers.
Our exposure to potential credit risk results primarily from our sales of gas and oil production, extracted products and energy marketing, including our hedging activities. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At September 30, 2006, our gross credit exposure totaled $552 million. Of this amount, investment grade counterparties represented 66% and no single counterparty exceeded 8%. We held no collateral for these transactions at September 30, 2006.
Note 15. Related Party Transactions
We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our accounts receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. We are included in Dominion’s consolidated federal income tax return and participate in certain Dominion benefit plans. A discussion of significant related party transactions follows:
Transactions with Affiliates
We transact with affiliates for certain quantities of natural gas, electricity and other commodities at fixed and market prices in the ordinary course of business. We also enter into certain commodity derivative contracts with affiliates. We use these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks primarily associated with the purchases and sales of natural gas and other energy-related commodities. We designate the majority of these contracts as cash flow or fair value hedges for accounting purposes.
Presented below are significant affiliated transactions, including net realized gains and losses on affiliated commodity derivative contracts, recorded in operating revenue and operating expenses:
| | Three Months Ended September 30, | Nine Months Ended September 30, |
| | 2006 | 2005 | 2006 | 2005 |
| (millions) | |
| | | | | |
| Sales of natural gas | $100 | $293 | $393 | $751 |
| Gas transportation and storage services provided | 5 | 15 | 14 | 24 |
| Sales of electricity | 9 | 16 | 17 | 26 |
| Loss on other energy-related commodity contracts | 5 | -- | 8 | -- |
| Purchases of natural gas | 161 | 124 | 520 | 420 |
| Purchases of electric fuel and energy | 22 | 67 | 85 | 155 |
At September 30, 2006 and December 31, 2005, our Consolidated Balance Sheets include derivative assets with affiliates of $252 million and $431 million, respectively, and derivative liabilities with affiliates of $216 million and $120 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of those derivative contracts that have been designated as cash flow hedges, are included in AOCI on our Consolidated Balance Sheets.
Dominion Resources Services, Inc. (Dominion Services) provides certain administrative and technical services to us, which totaled $52 million and $45 million in the three months ended September 30, 2006 and 2005, respectively, and $153 million and $136 million for the nine months ended September 30, 2006 and 2005, respectively. We provide
certain services to other affiliates, including technical services to other Dominion subsidiaries, which totaled $2 million in the three months ended September 30, 2006 and 2005, and $8 million for the nine months ended September 30, 2006 and 2005.
Transactions with Dominion
We have borrowed funds from Dominion under short-term borrowing arrangements. At September 30, 2006 and December 31, 2005, our outstanding borrowings, net of repayments, under the Dominion money pool totaled $2.2 billion and $1.9 billion, respectively. The short-term demand note borrowings were $2 million at September 30, 2006. There were no short-term demand note borrowings at December 31, 2005. Net interest charges incurred by us related to these borrowings were $34 million and $19 million in the three months ended September 30, 2006 and 2005, respectively, and $90 million and $39 million for the nine months ended September 30, 2006 and 2005, respectively.
Note 16. Employee Benefit Plans
The following table illustrates the components of the provision for net periodic benefit cost for our pension and other postretirement benefit plans for employees represented by collective bargaining units:
| | Pension Benefits | Other Postretirement Benefits |
| (millions) | 2006 | 2005 | 2006 | 2005 |
Three Months Ended September 30, | |
| Service cost | $ 3 | $ 3 | $ 4 | $ 4 |
| Interest cost | 8 | 8 | 7 | 6 |
| Expected return on plan assets | (27) | (26) | (5) | (4) |
| Amortization of transition obligation | -- | -- | 1 | 1 |
| Amortization of net loss | -- | -- | 3 | 1 |
| Net periodic benefit cost (credit) | $(16) | $(15) | $10 | $8 |
Company’s net periodic benefit cost (credit)(1) | $(27) | $(25) | $13 | $12 |
| | | | | |
Nine Months Ended September 30, | | | | |
| Service cost | $ 9 | $ 9 | $ 11 | $11 |
| Interest cost | 24 | 23 | 20 | 18 |
| Expected return on plan assets | (80) | (77) | (14) | (12) |
Curtailment loss(2) | -- | -- | 3 | - |
| Amortization of transition obligation | -- | -- | 3 | 4 |
| Amortization of prior service cost (credit) | -- | 1 | (1) | - |
| Amortization of net loss | -- | -- | 8 | 4 |
| Net periodic benefit cost (credit) | $(47) | $(44) | $30 | $25 |
Company’s net periodic benefit cost (credit)(1) | $(81) | $(76) | $43 | $36 |
| (1) | Amounts represent all benefit plans in which we participate, including benefit plans covering multiple Dominion subsidiaries. |
| (2) | Relates to the pending sale of Peoples and Hope. |
Employer Contributions
We made no contributions to our defined benefit pension plans or other postretirement benefit plans during the first nine months of 2006. We expect to contribute at least $45 million to our other postretirement benefit plans during the fourth quarter of 2006. Under our funding policies, we evaluate pension and other postretirement benefit plan funding requirements annually, usually in the second half of the year after receiving updated plan information from our actuary. Based on the funded status of each plan and other factors, the amount of additional contributions to be made in 2006 will be determined during the fourth quarter.
Note 17. Condensed Consolidating Financial Information
We have fully and unconditionally guaranteed $200 million of senior notes issued by our wholly-owned subsidiary, DOTEPI. The senior notes mature in December 2007. In the event of a default by this subsidiary, we would be obligated to repay such amounts. Condensed consolidating financial information for the Company, DOTEPI and our other subsidiaries are presented below:
Condensed Consolidating Statement of Income Information
| Three Months Ended September 30, 2006 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | | | | | |
| Operating revenue | $ -- | $212 | $1,455 | $(153) | $1,514 |
| Operating expense | 4 | 123 | 921 | (152) | 896 |
| Income (loss) from operations | (4) | 89 | 534 | (1) | 618 |
| Other income (loss) | 62 | -- | -- | (66) | (4) |
| Interest and related charges | 53 | 26 | 64 | (66) | 77 |
| Income before income taxes | 5 | 63 | 470 | (1) | 537 |
| Income tax expense | 1 | 24 | 174 | (2) | 197 |
| Equity in earnings of subsidiaries | 336 | -- | -- | (336) | -- |
| Net income | $340 | $ 39 | $ 296 | $(335) | $ 340 |
| Nine Months Ended September 30, 2006 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | | | | | |
| Operating revenue | $ -- | $584 | $5,771 | $(468) | $5,887 |
| Operating expense | 7 | 381 | 4,507 | (450) | 4,445 |
| Income (loss) from operations | (7) | 203 | 1,264 | (18) | 1,442 |
| Other income | 183 | -- | 21 | (192) | 12 |
| Interest and related charges | 160 | 62 | 191 | (192) | 221 |
| Income before income taxes | 16 | 141 | 1,094 | (18) | 1,233 |
| Income tax expense | 100 | 67 | 382 | (7) | 542 |
| Equity in earnings of subsidiaries | 775 | -- | -- | (775) | -- |
| Net income | $691 | $ 74 | $ 712 | $(786) | $ 691 |
| Three Months Ended September 30, 2005 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | | | | | |
| Operating revenue | $ -- | $199 | $1,420 | $(142) | $1,477 |
| Operating expense | 1 | 120 | 1,897 | (137) | 1,881 |
| Income (loss) from operations | (1) | 79 | (477) | (5) | (404) |
| Other income | 55 | -- | 8 | (55) | 8 |
| Interest and related charges | 51 | 16 | 48 | (53) | 62 |
| Income (loss) before income taxes | 3 | 63 | (517) | (7) | (458) |
| Income tax expense (benefit) | -- | 31 | (188) | (3) | (160) |
| Equity in losses of subsidiaries | (301) | -- | -- | 301 | -- |
| Net income (loss) | $(298) | $ 32 | $ (329) | $297 | $ (298) |
| Nine Months Ended September 30, 2005 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | | | | | |
| Operating revenue | $ -- | $561 | $5,265 | $(395) | $5,431 |
| Operating expense | 2 | 323 | 4,955 | (382) | 4,898 |
| Income (loss) from operations | (2) | 238 | 310 | (13) | 533 |
| Other income | 154 | -- | 22 | (156) | 20 |
| Interest and related charges | 151 | 47 | 123 | (154) | 167 |
| Income before income taxes | 1 | 191 | 209 | (15) | 386 |
| Income tax expense (benefit) | (2) | 74 | 80 | (6) | 146 |
| Equity in earnings of subsidiaries | 237 | -- | -- | (237) | -- |
| Net income | $240 | $ 117 | $ 129 | $(246) | $ 240 |
Condensed Consolidating Balance Sheet Information
| At September 30, 2006 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | |
Assets | | | | | |
| Current assets | $1,821 | $ 465 | $ 3,862 | $(2,088) | $ 4,060 |
| Investment in affiliates | 5,244 | -- | 125 | (5,181) | 188 |
| Loans to affiliates | 2,181 | -- | -- | (2,181) | -- |
| Property, plant and equipment, net | -- | 4,679 | 9,073 | (828) | 12,924 |
| Deferred charges and other assets | 155 | 531 | 2,229 | (131) | 2,784 |
| Total assets | $9,401 | $5,675 | $15,289 | $(10,409) | $19,956 |
| | | | | | |
Liabilities & Shareholder’s Equity | | | | | |
| Current liabilities | $898 | $2,692 | $ 7,180 | $(3,770) | $ 7,000 |
| Long-term debt | 2,506 | 199 | -- | -- | 2,705 |
| Notes payable to affiliates | 206 | -- | 1,092 | (1,092) | 206 |
| Deferred credits and other liabilities | 37 | 1,130 | 3,431 | (307) | 4,291 |
| Common shareholder’s equity | 5,754 | 1,654 | 3,586 | (5,240) | 5,754 |
| Total liabilities and shareholder’s equity | $9,401 | $5,675 | $15,289 | $(10,409) | $19,956 |
| At December 31, 2005 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | |
Assets | | | | | |
| Current assets | $2,019 | $ 539 | $6,529 | $(3,659) | $5,428 |
| Investment in affiliates | 3,697 | -- | 147 | (3,634) | 210 |
| Loans to affiliates | 2,188 | -- | -- | (2,188) | -- |
| Property, plant and equipment, net | -- | 4,079 | 8,370 | (103) | 12,346 |
| Deferred charges and other assets | 373 | 555 | 3,621 | (631) | 3,918 |
| Total assets | $8,277 | $5,173 | $18,667 | $(10,215) | $21,902 |
| | | | | | |
Liabilities & Shareholder’s Equity | | | | | |
| Current liabilities | $ 1,026 | $2,646 | $ 9,976 | $ (4,746) | $ 8,902 |
| Long-term debt | 2,508 | 200 | -- | -- | 2,708 |
| Notes payable to affiliates | 206 | -- | 1,099 | (1,099) | 206 |
| Deferred credits and other liabilities | 246 | 1,231 | 5,004 | (686) | 5,795 |
| Common shareholder’s equity | 4,291 | 1,096 | 2,588 | (3,684) | 4,291 |
| Total liabilities and shareholder’s equity | $8,277 | $5,173 | $18,667 | $(10,215) | $21,902 |
Condensed Consolidating Statement of Cash Flow Information
| Nine Months Ended September 30, 2006 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | |
| Net cash provided by operating activities | $415 | $ 56 | $1,781 | $(346) | $1,906 |
| Net cash provided by (used in) investing activities | 75 | (685) | (1,136) | 50 | (1,696) |
| Net cash provided by (used in) financing activities | (490) | 626 | (664) | 296 | (232) |
| Nine Months Ended September 30, 2005 | CNG (Parent Company) | DOTEPI | Other Subsidiaries | Adjustments & Eliminations | Consolidated |
| (millions) | |
| | |
| Net cash provided by operating activities | $444 | $ 271 | $995 | $(410) | $1,300 |
| Net cash provided by (used in) investing activities | 72 | (483) | (817) | (128) | (1,356) |
| Net cash provided by (used in) financing activities | (373) | 212 | (168) | 396 | 67 |
Note 18. Operating Segments
Our Company is organized primarily on the basis of products and services sold in the United States. We manage our operations through the following segments:
Delivery includes our regulated gas distribution and customer service businesses which are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. It also includes our nonregulated retail energy marketing operations.
Energy includes our tariff-based natural gas transmission pipeline and underground natural gas storage businesses and an LNG facility which are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71. It also includes gathering and extraction facilities, certain natural gas production operations and producer services, which consist of aggregation of gas supply and related wholesale activities.
E&P includes our gas and oil exploration, development and production operations. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico.
Corporate includes our corporate functions, including the activities of CNG International (CNGI), our power generating facility and other minor subsidiaries. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents our segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments and are instead reported in the Corporate segment. In the nine months ended September 30, 2006 and 2005, we reported net expenses of $125 million and $359 million, respectively, in the Corporate segment attributable to our operating segments. The net expenses in 2006 primarily relate to a $163 million ($100 million after-tax) charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, attributable to the Delivery segment and a $10 million ($6 million after-tax) impairment charge related to an equity-method investment, attributable to the E&P segment. The net expenses in 2005 primarily reflect a $556 million ($357 million after-tax) loss related to the discontinuance of hedge accounting for certain gas and oil hedges, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by Hurricanes Katrina and Rita, and subsequent changes in the fair value of those hedges, attributable to the E&P segment.
Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.
The following table presents segment information pertaining to our operations:
| | Delivery | Energy | E&P | Corporate | Adjustments & Eliminations | Consolidated Total |
| (millions) | |
| | |
Three Months ended September 30, 2006 | | | | | | |
| Operating revenue: | | | | | | |
| External customers | $327 | $282 | $797 | $ -- | $ -- | $1,406 |
| Affiliated customers | -- | 97 | 2 | 9 | -- | 108 |
| Intersegment | 1 | 59 | 43 | -- | (103) | -- |
| Total operating revenue | 328 | 438 | 842 | 9 | (103) | 1,514 |
| Net income (loss) | (9) | 61 | 290 | (2) | -- | 340 |
| | | | | | | |
| Three Months ended September 30, 2005 | | | | | | |
| Operating revenue: | | | | | | |
| External customers | $330 | $312 | $512 | $ (1) | $ -- | $1,153 |
| Affiliated customers | -- | 303 | 3 | 18 | -- | 324 |
| Intersegment | 1 | 71 | 51 | -- | (123) | -- |
| Total operating revenue | 331 | 686 | 566 | 17 | (123) | 1,477 |
| Net income (loss) | (6) | 44 | 20 | (356) | -- | (298) |
| | | | | | | |
Nine Months Ended September 30, 2006 | | | | | | |
| Operating revenue: | | | | | | |
| External customers | $2,164 | $992 | $2,314 | $ -- | $ -- | $5,470 |
| Affiliated customers | 1 | 392 | 7 | 17 | -- | 417 |
| Intersegment | 2 | 213 | 139 | -- | (354) | -- |
| Total operating revenue | 2,167 | 1,597 | 2,460 | 17 | (354) | 5,887 |
| Net income (loss) | 91�� | 201 | 585 | (186) | -- | 691 |
| | | | | | | |
| Nine Months Ended September 30, 2005 | | | | | | |
| Operating revenue: | | | | | | |
| External customers | $2,000 | $894 | $1,736 | $ -- | $ -- | $4,630 |
| Affiliated customers | 1 | 759 | 14 | 27 | -- | 801 |
| Intersegment | 24 | 186 | 123 | -- | (333) | -- |
| Total operating revenue | 2,025 | 1,839 | 1,873 | 27 | (333) | 5,431 |
| Net income (loss) | 114 | 173 | 309 | (356) | -- | 240 |
CONSOLIDATED NATURAL GAS COMPANY
RESULTS OF OPERATIONS
Management’s Discussion and Analysis of Results of Operations (MD&A) discusses the results of operations and general financial condition of Consolidated Natural Gas Company. MD&A should be read in conjunction with the Consolidated Financial Statements. The terms “Company,” “we,” “our” and “us”are used throughout MD&A and, depending on the context of their use, may represent any of the following: the legal entity, Consolidated Natural Gas Company, one of Consolidated Natural Gas Company’s consolidated subsidiaries or operating segments or the entirety of Consolidated Natural Gas Company and its consolidated subsidiaries. We are a wholly-owned subsidiary of Dominion.
Contents of MD&A
Our MD&A consists of the following information:
· Forward-Looking Statements
· Accounting Matters
· Results of Operations
· Segment Results of Operations
· Credit Risk
· Other Matters
Forward-Looking Statements
This report contains statements concerning our expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may” or other similar words.
We make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include, but are not limited to:
· Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;
· Extreme weather events, including hurricanes and winter storms, that can cause outages, production delays and property damage to our facilities;
· State and federal legislative and regulatory developments, including deregulation and changes in environmental and other laws and regulations to which we are subject;
· Cost of environmental compliance;
· Fluctuations in energy-related commodity prices and the effect these could have on our earnings, liquidity position and the underlying value of our assets;
· Counterparty credit risk;
· Capital market conditions, including price risk due to marketable securities held as investments in benefit plan trusts;
· Fluctuations in interest rates;
· Change in rating agency requirements or credit ratings and the effect on availability and cost of capital;
· Changes in financial or regulatory accounting principles or policies imposed by governing bodies;
· Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;
· The risks of operating businesses in regulated industries that are subject to changing regulatory structures;
· Changes in our ability to recover investments made under traditional regulation through rates;
· Receipt of approvals for and timing of closing dates for acquisitions and divestitures;
· Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; and
· Additional risk exposure associated with the termination of business interruption and offshore property damage insurance related to our E&P operations and our inability to replace such insurance on commercially reasonable terms.
Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors in this report and in our Annual Report on Form 10-K for the year ended December 31, 2005 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
Accounting Matters
Critical Accounting Policies and Estimates
As of September 30, 2006, there have been no significant changes with regard to critical accounting policies and estimates as disclosed in MD&A in our Annual Report on Form 10-K for the year ended December 31, 2005. The policies disclosed included the accounting for derivative contracts at fair value, goodwill impairment testing, employee benefit plans, regulated operations, gas and oil operations and income taxes.
Other
SFAS No. 158
In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans. SFAS No. 158 requires an employer to recognize the overfunded or underfunded status of their benefit plans as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur as a component of other comprehensive income. The funded status is measured as the difference between the fair value of the plan’s assets and its benefit obligation. In addition, SFAS No. 158 requires an employer to measure benefit plan assets and obligations that determine the funded status of a plan as of the end of its fiscal year, which we already do. The prospective requirement to recognize the funded status of a benefit plan and to provide the required disclosures will become effective for us on December 31, 2006. The adoption of SFAS No. 158 will have no impact on our results of operations or cash flows. We are currently evaluating the impact that SFAS No. 158 will have on our financial condition.
FIN 48
In July 2006, the FASB issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. FIN 48 establishes standards for measurement and recognition in financial statements of positions taken by an entity in its income tax returns. In addition, FIN 48 requires new disclosures about positions taken by an entity in its tax returns that are not recognized in its financial statements, information about potential significant changes in estimates related to tax positions and descriptions of open tax years by major jurisdiction. The provisions of FIN 48 will become effective for us beginning January 1, 2007, with the cumulative effect of the change in accounting principle recorded as an adjustment to retained earnings. We are currently evaluating the impact that FIN 48 will have on our results of operations and financial condition.
SFAS No. 157
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 clarifies that fair value should be based on assumptions that market participants would use when pricing an asset or liability and establishes a fair value hierarchy of three levels that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data. SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy. The provisions of SFAS No. 157 will become effective for us beginning January 1, 2008. Generally, the provisions of this statement are to be applied prospectively. Certain situations, however, require retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application is required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses under EITF Issue 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. We are currently evaluating the impact that SFAS No. 157 will have on our results of operations and financial condition.
Results of Operations
Presented below is a summary of our consolidated results for the third quarter and year-to-date periods ended September 30, 2006 and 2005:
| (millions) | 2006 | 2005 | $ Change |
Third Quarter | |
| Net income (loss) | $340 | $(298) | $638 |
Year-To-Date | | | |
| Net income | $691 | $240 | $451 |
Overview
Third Quarter 2006 vs. 2005
Net income increased by $638 million to $340 million. Favorable drivers include business interruption insurance revenue related to hurricanes, an increase in gas and oil production, the absence of a $357 million after-tax loss in 2005 related to the discontinuance of hedge accounting for certain gas and oil hedges resulting from a hurricane-related interruption of gas and oil production in the Gulf of Mexico and the positive 2006 mark-to-market impact of certain gas and oil derivatives that were de-designated as hedges in 2005.
Year-To-Date 2006 vs. 2005
Net income increased 188% to $691 million. Favorable drivers include higher business interruption insurance revenue in 2006 versus 2005, an increase in gas and oil production, higher realized prices for gas and oil, the absence of a $357 million after-tax loss in 2005 related to the discontinuance of hedge accounting for certain gas and oil hedges resulting from a hurricane-related interruption of gas and oil production in the Gulf of Mexico and the positive 2006 mark-to-market impact of certain gas and oil derivatives that were de-designated as hedges in 2005. Unfavorable drivers include charges associated with the pending sale of Peoples and Hope.
Analysis of Consolidated Operations
Presented below are selected amounts related to our results of operations:
| | Third Quarter | Year-To-Date |
| (millions) | 2006 | 2005 | $ Change | 2006 | 2005 | $ Change |
| Operating Revenue | $1,514 | $1,477 | $37 | $5,887 | $5,431 | $456 |
| Operating Expenses: | | | | | | |
| Purchased gas | 324 | 601 | (277) | 2,102 | 2,324 | (222) |
| Electric fuel and energy purchases | 63 | 115 | (52) | 184 | 254 | (70) |
| Other energy-related commodity purchases | 1 | 122 | (121) | 413 | 290 | 123 |
| Other operations and maintenance | 220 | 820 | (600) | 857 | 1,322 | (465) |
| Depreciation, depletion and amortization | 229 | 163 | 66 | 672 | 498 | 174 |
| Other taxes | 59 | 60 | (1) | 217 | 210 | 7 |
| Other income (loss) | (4) | 8 | (12) | 12 | 20 | (8) |
| Interest and related charges | 77 | 62 | 15 | 221 | 167 | 54 |
| Income tax expense (benefit) | 197 | (160) | 357 | 542 | 146 | 396 |
An analysis of our results of operations for the third quarter and year-to-date period of 2006 compared to the third quarter and year-to-date period of 2005 follows:
Third Quarter 2006 vs. 2005
Operating Revenue increased 3% to $1.5 billion, primarily reflecting:
| · | $269 million of business interruption insurance revenue received in 2006, associated with the 2005 hurricanes; |
| · | A $122 million increase in sales of gas and oil production due to higher volumes ($216 million) partially offset by lower prices ($94 million); and |
| · | A $55 million increase in sales of extracted products, primarily due to increased volumes ($42 million) and increased prices ($13 million); partially offset by |
| · | A $228 million decrease in gas sales primarily due to a decrease of $250 million resulting from our producer services operations reflecting lower prices and volumes and a $32 million decrease in revenue from sales of gas purchased by E&P operations to facilitate gas transportation and other contracts primarily due to lower volumes and the implementation of EITF 04-13, partially offset by a $41 million increase in sales by nonregulated retail energy marketing activities primarily due to higher volumes |
| · | A $125 million decrease as a result of the impact of netting sales and purchases of oil under buy/sell arrangements that were entered into or modified by E&P operations subsequent to April 1, 2006, in accordance with EITF 04-13. The effect of this decrease was largely offset by a corresponding decrease in Other energy-related commodity purchases expense; |
| · | A $41 million decrease in electric sales primarily due to decreased volumes, partially offset by higher customer contract sales rates for electric commodities at our nonregulated retail energy marketing operations; and |
| · | A $26 million decrease from regulated gas distribution operations primarily reflecting a $21 million decrease resulting from the loss of customers related to Energy Choice programs and a $5 million decrease associated with milder weather and changes in customer usage and other factors. |
Operating Expenses and Other Items
Purchased gas expense decreased 46% to $324 million, primarily resulting from a $249 million decrease related to our producer services operations due to lower volumes and prices and a $37 million decrease related to E&P operations primarily due to the implementation of EITF 04-13, partially offset by a $44 million increase from nonregulated retail energy marketing activities due to higher volumes. The decrease also reflects a $22 million decrease related to lower volumes attributable to regulated gas distribution operations and a $16 million decrease related to lower system gas costs for gas transmission operations.
Electric fuel and energy purchases expense decreased 45% to $63 million, resulting from a decrease in purchases by our nonregulated retail energy marketing operations due to customer attrition and lower prices.
Other energy-related commodity purchases expense decreased 99% to $1 million as a result of the impact of netting sales and purchases of oil under buy/sell arrangements in accordance with EITF 04-13, as discussed in Operating Revenue.
Other operations and maintenance expense decreased 73% to $220 million, primarily reflecting the following:
| · | The absence of a $556 million loss recognized in 2005 related to the discontinuance of hedge accounting for certain gas and oil hedges, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by the 2005 hurricanes, and subsequent changes in the fair value of those hedges; |
| · | A $51 million benefit resulting from favorable price changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes; and |
| · | A $27 million decrease in hedge ineffectiveness expense associated with our E&P operations, primarily due to a decrease in the fair value differential between the delivery location and commodity specifications of derivative contracts held by us as compared to our forecasted gas and oil sales and the increased use of basis swaps. |
These decreases were partially offset by:
| · | A $29 million increase attributable to higher production handling, transportation and operating costs related to E&P operations; and |
| · | A $13 million increase resulting from price risk management activities associated with our nonregulated retail energy marketing operations. |
Depreciation, depletion and amortization expense (DD&A) increased 40% to $229 million, largely due to the impact of increased gas and oil production, as well as higher E&P finding and development costs.
Other income decreased $12 million to a net loss of $4 million, primarily due to a $10 million impairment charge associated with an equity-method investment.
Interest and related charges increased 24% to $77 million, primarily due to the impact of additional borrowings from Dominion’s money pool and higher interest rates on those borrowings.
Year-To-Date 2006 vs. 2005
Operating Revenue increased 8% to $5.9 billion, primarily reflecting:
| · | A $317 million increase in sales of gas and oil production, primarily due to higher volumes ($331 million) partially offset by lower prices ($14 million); |
| · | A $130 million increase in sales of extracted products, primarily due to increased volumes ($89 million) and increased prices ($41 million); |
| · | A $121 million increase in sales of purchased oil under buy/sell arrangements by E&P operations resulting from higher market prices ($68 million) and increased sales volumes ($53 million); and |
| · | An increase of $90 million resulting from business interruption insurance revenue of $269 million received in 2006, associated with the 2005 hurricanes, versus insurance revenue of $179 million received in 2005, associated with Hurricane Ivan; partially offset by |
| · | A $173 million decrease in gas sales primarily due to a decrease of $309 million resulting from our producer services operations reflecting lower volumes, partially offset by higher prices and a $60 million decrease in revenue from sales of gas purchased by E&P operations to facilitate gas transportation and other contracts primarily due to the implementation of EITF 04-13, partially offset by a $187 million increase in sales by nonregulated retail energy marketing activities primarily due to higher prices ($128 million) and increased volumes ($59 million); and |
| · | A $46 million decrease from regulated gas distribution operations primarily reflecting a $103 million decrease resulting from the loss of customers related to Energy Choice programs and a $162 million decrease associated with milder weather and changes in customer usage and other factors, partially offset by a $219 million increase related to the recovery of higher gas prices. |
Operating Expenses and Other Items
Purchased gas expense decreased 10% to $2.1 billion, resulting from a $312 million decrease related to our producer services operations due to lower volumes, partially offset by higher prices and a $66 million decrease related to E&P operations primarily due to lower volumes and the implementation of EITF 04-13, partially offset by a $200 million increase attributable to nonregulated retail energy marketing activities due to higher prices ($147 million) and increased volumes ($53 million).
Electric fuel and energy purchases expense decreased 28% to $184 million, resulting from a decrease in purchases by our nonregulated retail energy marketing operations due to customer attrition and lower prices.
Other energy-related commodity purchases expense increased 42% to $413 million primarily attributable to higher market prices ($69 million) and increased volumes of oil purchases under buy/sell arrangements by E&P operations ($51 million).
Other operations and maintenance expense decreased 35% to $857 million, primarily resulting from:
| · | The absence of a $556 million loss recognized in 2005 related to the discontinuance of hedge accounting for certain gas and oil hedges, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by the 2005 hurricanes, and subsequent changes in the fair value of those hedges; |
| · | A $189 million benefit resulting from favorable price changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes; |
| · | A $60 million decrease in hedge ineffectiveness expense associated with our E&P operations, primarily due to a decrease in the fair value differential between the delivery location and commodity specifications of derivative contracts held by us as compared to our forecasted gas and oil sales and the increased use of basis swaps; and |
| · | The absence of a $59 million loss related to the discontinuance of hedge accounting in March 2005, for certain oil derivatives primarily resulting from a delay in reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those derivatives. |
These decreases were partially offset by:
| · | A $163 million charge from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope; |
| · | An $82 million increase attributable to higher production handling, transportation and operating costs related to E&P operations; |
| · | A $42 million increase in bad debt expense primarily reflecting expenses for regulated gas operations related to low income home energy assistance programs. These expenditures are recovered through rates and do not impact our net income; |
| · | A $25 million increase resulting from price risk management activities associated with our nonregulated retail energy marketing operations; |
| · | An $18 million increase in insurance costs for E&P operations due to higher insurance premiums incurred following the 2005 hurricanes; and |
| · | An $18 million increase resulting primarily from higher salaries, wages and benefits. |
Depreciation, depletion and amortization expense increased 35% to $672 million, largely due to the impact of increased gas and oil production, as well as higher E&P finding and development costs.
Other income decreased 40% to $12 million primarily due to a $10 million impairment charge associated with an equity-method investment.
Interest and related charges increased 32% to $221 million, primarily due to the impact of additional borrowings from Dominion’s money pool and higher interest rates on those borrowings.
Segment Results of Operations
Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit and loss. Presented below is a summary of contributions by our operating segments to net income for the third quarter and year-to-date periods of 2006 and 2005:
Third Quarter | 2006 | 2005 | $ Change |
| (millions) | | | |
| Delivery | $ (9) | $ (6) | $ (3) |
| Energy | 61 | 44 | 17 |
| E&P | 290 | 20 | 270 |
| Primary operating segments | 342 | 58 | 284 |
| Corporate | (2) | (356) | 354 |
| Consolidated | $340 | $(298) | $638 |
| | | | |
Year-To-Date | | | |
| (millions) | | | |
| Delivery | $ 91 | $114 | $(23) |
| Energy | 201 | 173 | 28 |
| E&P | 585 | 309 | 276 |
| Primary operating segments | 877 | 596 | 281 |
| Corporate | (186) | (356) | 170 |
| Consolidated | $691 | $240 | $451 |
Delivery
Delivery includes our regulated gas distribution and customer service business, as well as nonregulated retail energy marketing operations and related products and services. Presented below are operating statistics related to our Delivery operations:
| Third Quarter | Year-To-Date |
| | 2006 | 2005 | % Change | 2006 | 2005 | % Change |
| Gas throughput (bcf): | | | | | | |
| Gas sales | 6 | 8 | (25)% | 68 | 90 | (24)% |
| Gas transportation | 37 | 35 | 6 | 167 | 172 | (3) |
Heating degree days (gas service area)(1) | 111 | 24 | 363 | 3,347 | 3,794 | (12) |
Average gas delivery customer accounts(2): | | | | | | |
| Gas sales | 780 | 1,000 | (22) | 881 | 1,037 | (15) |
| Gas transportation | 893 | 674 | 32 | 807 | 653 | 24 |
Average nonregulated retail energy marketing customer accounts(2) | 1,398 | 1,175 | 19 | 1,308 | 1,153 | 13 |
bcf = billion cubic feet
(1) Heating degree days (HDDs) are units measuring the extent to which the average daily temperature is less than 65 degrees. HDDs are calculated as the difference between the average temperature for each day and 65 degrees.
(2) In thousands.
Presented below, on an after-tax basis, are the key factors impacting Delivery’s net income contribution:
| | Third Quarter 2006 vs. 2005 Increase (Decrease) | Year-To-Date 2006 vs. 2005 Increase (Decrease) |
| (millions) | |
| Interest expense | $ (5) | $ (17) |
Nonregulated retail energy marketing operations(1) | (2) | 7 |
| Weather | 1 | (13) |
Other margins(2) | -- | (11) |
| Other | 3 | 11 |
| Change in net income contribution | $ (3) | $ (23) |
(1) Third quarter results reflect the impact of unfavorable price changes related to certain commodity derivative contracts partially offset by higher average margins for electric and gas sales due to higher contracted sales rates, increase in customers and lower electricity costs. Year-to-date results reflect higher average margins for electric and gas sales due to higher contracted sales rates, an increase in customers and lower electricity costs.
(2) Reflects reduced customer usage in the year-to-date period due in part to sensitivity to high gas prices.
Energy
Energy includes our tariff-based natural gas transmission pipeline and storage businesses and an LNG import and storage facility. It also includes gathering and extraction facilities, certain natural gas production operations and producer services, which consist of aggregation of gas supply and related wholesale activities. Presented below are operating statistics related to our Energy operations:
| | Third Quarter | Year-To-Date |
| 2006 | 2005 | % Change | 2006 | 2005 | % Change |
| | | | | | | |
| Gas transportation throughput (bcf) | 128 | 131 | (2)% | 484 | 565 | (14)% |
Presented below, on an after-tax basis, are the key factors impacting Energy’s net income contribution:
| | Third Quarter 2006 vs. 2005 Increase (Decrease) | Year-To-Date 2006 vs. 2005 Increase (Decrease) |
| (millions) | |
| Gas transmission: | | |
Other margins(1) | $ 18 | $ 39 |
Rate settlement(2) | -- | (13) |
Producer services(3) | 2 | 13 |
| Other | (3) | (11) |
| Change in net income contribution | $ 17 | $ 28 |
(1) Higher margins primarily from extracted products, natural gas production and market center service opportunities.
(2) Represents lower natural gas transportation and storage revenues in the year-to-date period as a result of a rate settlement effective July 2005.
| (3) | Higher income in the year-to-date period resulting from the impact of favorable price changes on gas marketing activities associated with certain contractual assets. |
E&P
E&P includes our gas and oil exploration, development and production business. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico. Presented below are operating statistics related to our E&P operations:
| | Third Quarter | Year-To-Date |
| 2006 | 2005 | % Change | 2006 | 2005 | % Change |
| | | | | | | |
| Gas production (bcf) | 68.3 | 56.5 | 21% | 196.7 | 175.5 | 12% |
| Oil production (million bbls) | 6.0 | 3.0 | 100 | 17.8 | 10.5 | 70 |
| Average realized prices without hedging results: | | | | | | |
Gas (per mcf)(1) | $6.42 | $8.12 | (21) | $6.94 | $7.07 | (2) |
| Oil (per bbl) | $58.84 | $55.81 | 5 | $57.42 | $49.11 | 17 |
| Average realized prices with hedging results: | | | | | | |
Gas (per mcf)(1) | $4.44 | $4.58 | (3) | $4.67 | $4.45 | 5 |
| Oil (per bbl) | $32.86 | $22.76 | 44 | $35.35 | $26.01 | 36 |
| DD&A (unit of production rate per mcfe) | $1.74 | $1.53 | 14 | $1.74 | $1.49 | 17 |
| |
bbl(s) = barrel(s)
mcf = thousand cubic feet
mcfe = thousand cubic feet equivalent
(1) Excludes $37 million and $52 million of revenue recognized in the third quarter of 2006 and 2005, respectively, and $125 million and $178 million of revenue recognized in the year-to-date period of 2006 and 2005, respectively, under the volumetric production payment agreements described in Note 10 to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2005.
Presented below, on an after-tax basis, are the key factors impacting E&P’s net income contribution:
| | Third Quarter 2006 vs. 2005 Increase (Decrease) | Year-To-Date 2006 vs. 2005 Increase (Decrease) |
| (millions) | |
| Business interruption insurance | $ 171 | $ 58 |
Gas and oil—production(1) | 146 | 270 |
Operations and maintenance expense(2) | 43 | 107 |
| Gas and oil—prices | (47) | 9 |
Depreciation, depletion and amortization expense(3) | (45) | (118) |
| Interest expense | (9) | (34) |
Income tax adjustments (4) | -- | (22) |
| Other | 11 | 6 |
| Change in net income contribution | $ 270 | $ 276 |
(1) Represents an increase in gas and oil production primarily resulting from deepwater Gulf of Mexico locations. Gas and oil production in the prior year was negatively impacted during the third quarter as a result of the 2005 hurricanes.
(2) Lower operations and maintenance expenses primarily reflecting the impact of favorable changes in the fair value of certain gas and oil derivatives that were de-designated as hedges following the 2005 hurricanes, partially offset by increased production costs and salaries, wages and benefits expenses.
(3) Higher depreciation, depletion and amortization expense primarily reflecting the impact of increased gas and oil production as well as higher industry finding and development costs. For the year-to-date period, the increase also reflects the impact of increased acquisition costs.
(4) Reflects the effect of revisions to the Texas franchise tax enacted in May 2006 and a revision to estimated state income tax apportionment percentages on accumulated deferred income taxes during the first quarter of 2006.
Included below are the volumes and weighted-average prices associated with hedges in place as of September 30, 2006 by applicable time period. Prior cash flow hedges for which hedge accounting was discontinued due to production interruptions caused by the 2005 hurricanes, and for which amounts were reclassified from AOCI to earnings upon the discontinuance of hedge accounting, are excluded from the following table:
| | Natural Gas | Oil |
| Year | Hedged Production (bcf) | Average Hedge Price (per mcf) | Hedged Production (million bbls) | Average Hedge Price (per bbl) |
| 2006 | 47.5 | $4.64 | 3.5 | $25.02 |
| 2007 | 195.5 | 5.91 | 10.0 | 33.41 |
| 2008 | 151.2 | 8.26 | 5.0 | 49.36 |
| 2009 | 25.5 | 8.09 | 0.3 | 75.36 |
Corporate
Corporate includes our corporate functions, including the activities of CNGI, our power generating facility and other minor subsidiaries. In addition, the contribution to net income by our primary operating segments is determined based on a measure of profit that executive management believes represents our segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by executive management in assessing the segment’s performance or allocating resources among the segments and are instead reported in the Corporate segment. Presented below are the Corporate segment’s after-tax results:
| | Third Quarter | Year-To-Date |
| | 2006 | 2005 | $ Change | 2006 | 2005 | $ Change |
| (millions) | | | | | | |
| Specific items attributable to operating segments | $ (10) | $(359) | $ 349 | $(125) | $(359) | $234 |
| Other corporate operations | 8 | 3 | 5 | (61) | 3 | (64) |
| Total net income (expense) | $ (2) | $(356) | $ 354 | $(186) | $(356) | $170 |
Specific Items Attributable to Operating Segments
Third Quarter 2006 vs. 2005
We reported net expenses of $10 million and $359 million in 2006 and 2005, respectively, in the Corporate segment attributable to our operating segments. The net expenses in 2006 primarily reflect a $10 million ($6 million after-tax) impairment charge related to an equity-method investment, attributable to the E&P segment. The net expenses in 2005 primarily reflect a $556 million ($357 million after-tax) loss related to the discontinuance of hedge accounting for certain gas and oil hedges, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by Hurricanes Katrina and Rita, and subsequent changes in the fair value of those hedges, attributable to the E&P segment.
Year-To-Date 2006 vs. 2005
We reported net expenses of $125 million and $359 million in 2006 and 2005, respectively, in the Corporate segment attributable to our operating segments. The net expenses in 2006 primarily reflect a $163 million ($100 million after-tax) charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope, attributable to the Delivery segment and a $10 million ($6 million after-tax) impairment charge related to an equity-method investment, attributable to the E&P segment. The net expenses in 2005 primarily reflect a $556 million ($357 million after-tax) loss related to the discontinuance of hedge accounting for certain gas and oil hedges, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by Hurricanes Katrina and Rita, and subsequent changes in the fair value of those hedges, attributable to the E&P segment.
Other Corporate Operations
Year-To-Date 2006 vs. 2005
We reported net expenses of $61 million in 2006 associated with other corporate operations, primarily reflecting tax adjustments associated with the pending sale of Peoples and Hope. We recognized $96 million of deferred tax liabilities, in accordance with EITF 93-17, that were partially offset by a $24 million tax benefit from the partial reduction of previously recorded valuation allowances on deferred tax assets, representing certain federal and state tax loss carryforwards, since these carryforwards are expected to be utilized to offset capital gain income generated from the sale.
Credit Risk
Our exposure to potential credit risk results primarily from our sales of gas and oil production, extracted products and energy marketing, including our hedging activities. Presented below is a summary of our gross credit exposure as of September 30, 2006. Our gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral.
| | Gross Credit Exposure |
| (millions) | |
Investment grade(1) | $333 |
Non-investment grade(2) | 39 |
| No external ratings: | |
Internally rated—investment grade(3) | 30 |
Internally rated—non-investment grade(4) | 151 |
| Total | $553 |
| (1) | Designations as investment grade are based on minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Rating Services, (Standard & Poor’s). The five largest counterparty exposures, combined, for this category represented approximately 28% of the total gross credit exposure. |
| (2) | The five largest counterparty exposures, combined, for this category represented approximately 5% of the total gross credit exposure. |
| (3) | The five largest counterparty exposures, combined, for this category represented approximately 4% of the total gross credit exposure. |
| (4) | The five largest counterparty exposures, combined, for this category represented approximately 4% of the total gross credit exposure. |
Future Issues and Other Matters
Possible Sale of E&P Business
On November 1, Dominion announced its decision to pursue the sale of all of our oil and natural gas exploration and production operations and assets, with the exception of those located in the Appalachian Basin. Any disposition would allow it to focus on its core electric generating and energy distribution, transmission and storage businesses and realign its operations and risk profile more closely with its peer investment group of utilities.
As of December 31, 2005, our natural gas and oil assets -- excluding the Appalachian Basin -- included about 4.5 trillion cubic feet of proved reserves across major producing regions in the lower 48 states, including the deepwater Gulf of Mexico, West Texas, Mid-Continent and the Rockies. The Appalachian assets that we would retain constitute approximately 17% of our total reserves.
Proceeds from any sale are expected to be used to reduce debt, acquire assets related to our remaining core businesses and other corporate purposes, including dividends to Dominion.
Dominion expects to conduct a formal asset auction process in early 2007. Closing of any sale or sales is targeted for mid-2007.
Future Divestitures
In September 2006, we entered into agreements to sell certain gas and oil properties in Texas and New Mexico for approximately $351 million in cash. The properties are included in our E&P operating segment. The sales are expected to close in the fourth quarter of 2006.
We are evaluating the possible sale of our Armstrong merchant generation facility. Armstrong is a 625-megawatt natural gas-fired power station located in Shelocta, Pennsylvania. We currently operate this facility under a leasing arrangement that terminates in November 2006. We intend to take legal title to this generation facility through the repayment of the lessor’s related debt at the end of the lease term prior to any potential sale.
Minimum Service Standards
In January 2006, the Public Utilities Commission of Ohio (Ohio Commission) issued an Order adopting rules establishing minimum service standards for natural gas companies. We had estimated that, if implemented as written, these rules would result in increased expenditures in the range of $10 million to $15 million per year. In July 2006, the Ohio Commission issued a second Entry on Rehearing that modifies the adopted standards to allow for the Average Speed of Answer time requirement to be met over a 12-month period rather than monthly and to extend the effective date of the new rules to January 1, 2007 rather than the previously ordered date of October 1, 2006. In doing so, the Ohio Commission attempted to address the most significant concerns of the Ohio gas local distribution companies affected by the standards. The East Ohio Gas Company (Dominion East Ohio) is working with the Ohio Commission Staff to address the issues raised by its nearly 560,000 inside meters, which create significant meter reading access challenges. Dominion East Ohio expects to submit a meter reading compliance plan and file several related applications with the Ohio Commission in early December. These changes are expected to decrease the cost of compliance previously estimated; however, an updated cost estimate is not yet available.
Cove Point Expansion
In June 2006, the Federal Energy Regulatory Commission (FERC) approved our plans to expand our Cove Point LNG terminal including the installation of two LNG storage tanks, each capable of storing 160 thousand cubic meters of LNG, and expand the send-out capacity of our Cove Point pipeline to approximately 1.8 million dekatherms per day. FERC also approved our plans to expand our Dominion Transmission, Inc. facilities by building 81 miles of pipeline and two compressor stations in central Pennsylvania. Statoil ASA has committed to all of the incremental terminal, transportation and storage capacity of the expansion for a term of 20 years. Expansion construction started in August 2006, and is expected to be completed in the fourth quarter of 2008.
Offshore Oil and Gas Leases
Two bills passed by the U.S. House of Representatives -- but not yet enacted into law -- address certain federal offshore oil and gas leases issued by the United States in 1998 and 1999 and seek to impose varying sanctions on the holders of such leases. The leases, as issued, do not include a provision requiring royalties to be paid on specified royalty suspension volumes.
In response to these legislative initiatives, the U.S. Department of Interior's Minerals Management Service (MMS) has invited us and other companies holding such leases to enter into voluntary renegotiations of these leases so that royalties would be payable on the suspension volumes when oil and gas commodity futures closing prices exceed specified threshold levels (as is the case under current market conditions). Without prejudice to our legal right to challenge any such sanctions should they be ultimately enacted into law, we have had preliminary discussions with the MMS regarding renegotiation of these leases.
ITEM 4. CONTROLS AND PROCEDURES
Senior management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, the Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures are effective. There were no changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
In accordance with FIN 46R, we have included in our Consolidated Financial Statements a VIE through which we have financed and leased a power generation project. Our Consolidated Balance Sheet as of September 30, 2006 reflects $203 million of net property, plant and equipment and deferred charges and $234 million of related debt attributable to the VIE. As this VIE is owned by unrelated parties, we do not have the authority to dictate or modify, and therefore cannot assess, the disclosure controls and procedures or internal control over financial reporting in place at this entity.
CONSOLIDATED NATURAL GAS COMPANY
PART II. OTHER INFORMATION
From time to time, we are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by us, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, we are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations.
Dominion Transmission Inc. (DTI) has signed a Consent Order and Agreement (COA) with the Pennsylvania Department of Environmental Protection (PADEP) which supersedes a 1990 COA between the parties and has paid a penalty of $850,000. This COA was entered into as part of the settlement of an enforcement action with the PADEP and resolution of lease breaches with the Department of Conservation and Natural Resources.
See Other Matters in MD&A for discussion on various regulatory proceedings to which we are a party.
Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these risk factors in our Annual Report on Form 10-K for the year ended December 31, 2005 and our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006, which should be taken into consideration when reviewing the information contained in this report. With the exception of the risk factors below, which reflect recent developments relating to our E&P operations, there have been no other material changes with regard to the risk factors previously disclosed in our most recent Forms 10-K and 10-Q. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in MD&A.
Dominion’s decision to pursue a sale of most of our E&P assets is expected to be dilutive to earnings, could have an adverse impact on our results of operations and may not yield the benefits expected. On November 1, 2006, Dominion announced its decision to pursue a sale of all of our E&P assets, excluding those assets located in the Appalachian Basin. Management expects that a sale of our E&P assets would reduce our future earnings. While Dominion believes it would be able to execute any sales by mid-2007, it may not be able to sell our E&P assets within the expected time frame. If Dominion sells our E&P assets, it cannot be certain of the price it would receive or the impact that such a sale and the use of proceeds from any sale would have on our results of operations. Additionally, we may incur significant costs or be required to record certain charges in connection with any sale and in connection with transactions related to the deployment of the proceeds from any sale.
Additionally, uncertainty about the effect of the proposed disposition may have an adverse effect on the Company, particularly our E&P business. Although we have taken steps to reduce any adverse effects, including providing retention agreements for employees, these uncertainties may impair our ability to attract, retain and motivate key personnel and could cause partners, customers, suppliers and others that deal with our E&P business to seek to change future business relationships. Our E&P business could be harmed if, despite our retention efforts, key employees depart as a result of the proposed disposition.
Our exploration and production business is dependent on factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of our assets. Factors that may affect our financial results include damage to or suspension of operations caused by weather, fire, explosion or other events at our or third-party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and our ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.
CONSOLIDATED NATURAL GAS COMPANY
PART II. OTHER INFORMATION
(Continued)
Short-term market declines in the prices of natural gas and oil could adversely affect our financial results by causing a permanent write-down of our natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.
In the past, we have maintained business interruption, property damage and other insurance for our E&P operations. However, the recent increased level of hurricane activity in the Gulf of Mexico led our insurers to terminate certain coverages for our E&P operations; specifically, our Operator’s Extra Expense (OEE), offshore property damage and offshore business interruption coverage was terminated. All onshore property coverage (with the exception of OEE) and liability coverage commensurate with past coverage remained in place for our E&P operations. Recently our OEE coverage for both onshore and offshore E&P operations was reinstated under a new policy. However, efforts to replace the terminated insurance for our E&P operations for offshore property damage and offshore business interruption with similar insurance on commercially reasonable terms were unsuccessful. This lack of insurance could adversely affect our results of operations.
CONSOLIDATED NATURAL GAS COMPANY
PART II. OTHER INFORMATION
(Continued)
(a) Exhibits: |
| |
| | 3.1 | Certificate of Incorporation of Consolidated Natural Gas Company (Exhibit (3A)(i) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference). |
| | 3.2 | Certificate of Amendment of Certificate of Incorporation, dated January 28, 2000 (Exhibit (3A)(ii) to Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference). |
| | 3.3 | Bylaws as in effect on December 15, 2000 (Exhibit 3B to Form 10-K for the fiscal year ended December 31, 2000, File No. 1-3196, incorporated by reference). |
| | 4 | Consolidated Natural Gas Company agrees to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of its total consolidated assets. |
| | 12 | Ratio of earnings to fixed charges (filed herewith). |
| | 31.1 | Certification by Registrant’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
| | 31.2 | Certification by Registrant’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
| | 32 | Certification to the Securities and Exchange Commission by Registrant’s Chief Executive Officer and Chief Financial Officer, as required by Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith). |
| | 99 | Condensed consolidated earnings statements (unaudited) (filed herewith). |
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | CONSOLIDATED NATURAL GAS COMPANY Registrant |
| | |
| November 1, 2006 | /s/ Steven A. Rogers |
| | Steven A. Rogers Senior Vice President and Controller (Principal Accounting Officer) |
| | |
