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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-K

(Mark One)



|x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ------------------------------------------------------------------------------------

For the fiscal year ended December 31, 2006

OR



| ̈ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------

For the transition period from                     
to

Commission File Number 001-03196



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CONSOLIDATED NATURAL GAS COMPANY

(Exact name of registrant as specified in its charter)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 54-1966737                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)
|                                                               | 
|120 Tredegar Street Richmond, Virginia                         |  | 23219                               
|(Address of principal executive offices)                       |  | (Zip Code)                          

(804) 819-2000

(Registrants telephone number)



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Securities registered pursuant to Section 12(b) of the Act:



|                                         |  |                                          
|---------------------------------------- |  | -----------------------------------------
|Title of Each Class                      |  | Name of Each Exchange on Which Registered
|7.8% Trust Preferred Securities, $25 Par |  | New York Stock Exchange                  

Securities registered pursuant to Section 12(g) of the Act:

None



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Indicate by check mark whether the registrant is a well-known seasoned issuer as defined in Rule 405 of the Securities
Act.    Yes ̈No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange
Act.    Yes ̈No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days.    Yes  x    No ̈

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrants knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x

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.

Large accelerated
filer ̈Accelerated filer ̈Non-accelerated filer  x

Indicate by
check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ̈No  x

The aggregate market value of the voting stock held by
non-affiliates of the registrant as of the last business day of the registrants most recently completed second fiscal quarter was zero.

As of February 1, 2007, there were issued and outstanding 100 shares of the registrants common stock, without par value, all of which were held, beneficially and of record, by Dominion Resources, Inc.

THE REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION I.(1)(a) AND (b) OF FORM 10-K AND IS FILING THIS FORM 10-K UNDER THE REDUCED
DISCLOSURE FORMAT.

DOCUMENTS INCORPORATED BY REFERENCE

None



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CONSOLIDATED NATURAL GAS COMPANY



|            |  |                                                                                                                  |  |           
|----------- |  | ---------------------------------------------------------------------------------------------------------------- |  | ----------
|Item Number |  |                                                                                                                  |  | PageNumber
|Part I      |  |                                                                                                                 
|1.          |  | Business                                                                                                         |  | 1         
|1A.         |  | Risk Factors                                                                                                     |  | 7         
|1B.         |  | Unresolved Staff Comments                                                                                        |  | 8         
|2.          |  | Properties                                                                                                       |  | 8         
|3.          |  | Legal Proceedings                                                                                                |  | 9         
|4.          |  | Submission of Matters to a Vote of Security Holders                                                              |  | 10        
|            | 
|Part II     |  |                                                                                                                 
|5.          |  | Market for the Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 11        
|6.          |  | Selected Financial Data                                                                                          |  | 11        
|7.          |  | Managements Discussion and Analysis of Results of Operations                                                    |  | 11        
|7A.         |  | Quantitative and Qualitative Disclosures About Market Risk                                                       |  | 18        
|8.          |  | Financial Statements and Supplementary Data                                                                      |  | 20        
|9.          |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                             |  | 55        
|9A.         |  | Controls and Procedures                                                                                          |  | 55        
|9B.         |  | Other Information                                                                                                |  | 55        
|            | 
|Part III    |  |                                                                                                                 
|10.         |  | Directors and Executive Officers of the Registrant                                                               |  | 56        
|11.         |  | Executive Compensation                                                                                           |  | 56        
|12.         |  | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters                   |  | 56        
|13.         |  | Certain Relationships and Related Transactions                                                                   |  | 56        
|14.         |  | Principal Accountant Fees and Services                                                                           |  | 56        
|            | 
|Part IV     |  |                                                                                                                 
|15.         |  | Exhibits and Financial Statement Schedules                                                                       |  | 57        



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PART I



ITEM 1. BUSINESS THE COMPANY Consolidated
Natural Gas Company (CNG) operates in all phases of the natural gas business, explores for and produces gas and oil, and provides a variety of energy marketing services. In addition, CNG is a transporter, distributor and retail marketer of natural
gas serving customers in Pennsylvania, Ohio, West Virginia and other states. CNG also operates a liquefied natural gas (LNG) import and storage facility in Maryland. CNG is a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion), a fully
integrated gas and electric holding company headquartered in Richmond, Virginia. 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, CNG, one of CNGs consolidated subsidiaries or operating segments or the
entirety of CNG and its consolidated subsidiaries. As of December 31, 2006, we had approximately 4,700 full-time employees.
Approximately 2,500 employees are subject to collective bargaining agreements. We were incorporated in Delaware in 1999. Our principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and our telephone number is
(804) 819-2000. OPERATING SEGMENTS 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. While we manage our daily operations through our operating segments,
our assets remain wholly owned by our legal subsidiaries. For additional financial information on business segments and geographic areas, see Notes 1 and 25 to our Consolidated Financial Statements. For additional information on operating revenue
related to our principal products and services, see Note 6 to our Consolidated Financial Statements. Delivery Delivery includes our regulated gas distribution and customer service operations as well as our nonregulated retail energy marketing operations. Gas distribution
operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Nonregulated retail energy marketing operations include the marketing of gas, electricity and related products
and services to residential, industrial and small commercial customers in the Northeast, Mid-Atlantic and Midwest. In March 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 end of the second quarter of 2007, subject to
state regulatory approvals in Pennsylvania and West Virginia as well as approval under the Hart-Scott-Rodino Act.


COMPETITION Retail competition for gas supply exists to varying degrees in the three states in which our gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small
commercial customers. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, we have offered an Energy Choice program to customers in cooperation with the Public
Utilities Commission of Ohio (Ohio Commission). West Virginia does not require customer choice in its retail natural gas markets at this time. See RegulationState Regulations for additional information. REGULATION Our gas distribution service, including the rates we may charge to
customers, is regulated by the Ohio Commission, the Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission). See RegulationState Regulations for
additional information. PROPERTIES Deliverys gas distribution
network is located in the states of Ohio, Pennsylvania and West Virginia. This network includes approximately 27,700 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines
have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on
publicly owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate. Delivery also operates 10 underground gas storage fields
located in Ohio and Pennsylvania, with more than 800 storage wells and approximately 121,000 acres of operated leaseholds. The total
designed capacity of the underground storage fields operated by Delivery is approximately 200 billion cubic feet (bcf). The Delivery segment has about 40 compressor stations with approximately 65,000 horsepower of installed compression. SOURCES OF ENERGY SUPPLY Delivery is engaged in the sale and storage of natural gas
through its operating subsidiaries. Deliverys natural gas supply for its operations is obtained from various sources including purchases from: major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the
Appalachian area, and gas marketers. SEASONALITY Deliverys
business varies seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Energy Energy includes our regulated interstate natural gas transmission pipeline and storage business and the Cove Point LNG import and
storage facility. It also includes gathering and extraction activities, plus certain Appalachian natural gas production. The Energy segment also includes producer services, which consist of




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aggregation of gas supply and related wholesale activities. The gas transmission pipeline and storage business serves our gas distribution businesses and
other customers in the Northeast, Mid-Atlantic and Midwest. COMPETITION The Energy segments gas transmission operations compete with domestic and Canadian pipeline companies. We also compete with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy
sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on
certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along our own pipeline system enable us to tailor our services to meet the needs of individual customers.


REGULATION Energys natural gas transmission, storage and LNG operations are subject to regulation by the Federal Energy Regulatory
Commission (FERC). See RegulationFederal Regulations for additional information. PROPERTIES Energy has approximately 7,800 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and
West Virginia. Energy operates 17 underground gas storage fields located in New York, Pennsylvania and West Virginia, with more than 1,500 storage wells and approximately 252,000 acres of operated leaseholds. The total designed capacity of the underground storage fields is approximately 776 bcf. Six storage fields are jointly-owned and operated by Energy. The
capacity of those six fields owned by our partners totals about 242 bcf. Energy also has about 8 bcf of above-ground storage capacity at its Cove Point LNG facility. Energy has about 90 compressor stations with approximately 630,000 installed
compressor horsepower.




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The following map
illustrates Energys gas transmission pipelines, storage facilities and LNG facility.

LOGO



SOURCES OF ENERGY SUPPLY Our large underground natural gas storage network and the
location of our pipeline system provide a significant link between the countrys major interstate gas pipelines and large markets in the Northeast and Mid-Atlantic regions. Our pipelines are part of an interconnected gas transmission system,
which provides access to supplies nationwide for local distribution companies, marketers, power generators and commercial and industrial customers. Our underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, Mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in
the effective management of both gas supply and pipeline transport capacity. SEASONALITY The Energy segments nonregulated businesses are affected by seasonal changes in the prices of commodities that they transport, store and actively market.


E&P E&P includes our gas and oil exploration, development and production operations. These 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, West Texas, Mid-Continent, the Rockies and Appalachia. In November 2006, Dominion announced its decision to pursue the sale of all of our natural gas and oil E&P operations and assets, with the exception
of those located in the Appalachian Basin. As of December 31, 2006, our natural gas and oil assets  excluding the Appalachian Basin  included about 4.7 trillion cubic feet of proved reserves. The Appalachian assets that we would
retain constitute approximately 17% of our total proved reserves as of December 31, 2006. Proceeds from any sale are expected to be
used to reduce debt, acquire assets related to our remaining core businesses and for other corporate purposes, including the payment of dividends to Dominion. Dominion expects to initiate a formal sales process in early 2007. Closing of any sale or
sales is targeted for mid-2007. In February 2006, we completed the acquisition of Pablo Energy, LLC (Pablo) for approximately $92 million
in cash. Pablo holds producing and other properties located in the Texas Panhandle area. Also in 2006, we received approximately $360 million of proceeds from sales of gas and oil properties, primarily resulting from the fourth quarter sale of
certain properties located in Texas and New Mexico.




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COMPETITION E&Ps competitors range from major international oil
companies to smaller independent producers. E&P faces significant competition in bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. As the operator of production properties, E&P also faces
competition in securing drilling equipment and supplies for exploration and development. E&P sells most of its deliverable natural gas
and oil into short and intermediate-term markets. E&P faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, E&P owns a large and
diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions which strengthens its knowledge of the marketplace and delivery options. REGULATION Our E&P operations are subject to regulation by numerous federal and
state authorities. The pipeline transportation of our natural gas production is regulated by FERC; pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands Act, which requires services to be
offered on an open-access, non-discriminatory basis. Our production operations in the Gulf of Mexico and most of our operations in the western United States are located on property subject to federal gas and oil leases that are administered by the
Minerals Management Service (MMS) or the Bureau of Land Manage-


ment. These leases are issued through a competitive bidding process and require us to comply with stringent regulations. Offshore production facilities must
comply with MMS regulations relating to engineering, construction, operations and the plugging and abandonment of wells. Our production operations are also subject to environmental regulations including regulations relating to oil spills into
navigable waters of the United States. See RegulationFederal Regulations and RegulationEnvironmental Regulationsfor additional information. PROPERTIES E&P owns 5.6 trillion cubic feet of proved equivalent natural gas and oil reserves and produces approximately 1.1 bcfe of natural
gas per day from its leasehold acreage and facility investments. Either alone or with partners, we hold interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. E&P also owns or
holds rights to seismic data and other tools used in exploration and development drilling activities. E&Ps share of developed leasehold totals 2.5 million acres, with another 1.5 million acres held for future exploration and development
drilling opportunities. See also Item 2. Properties for additional information on E&Ps properties. SEASONALITY E&Ps business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for our unhedged natural gas and oil
production, can be impacted by seasonal weather changes and by the effects of weather on operations.


LOGO

| |  | Note: Includes the E&P segment and the production activity of Dominion Transmission, Inc., which is included in the Energy segment.
| |  | -----------------------------------------------------------------------------------------------------------------------------------

| |  | Bcfe = billion cubic feet equivalent
| |  | ------------------------------------

| |  | Mmcfe = million cubic feet equivalent
| |  | -------------------------------------

| |  | Tcfe = trillion cubic feet equivalent
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Corporate We also have a Corporate segment which includes the cost
of our corporate and other functions, including the net impact of the discontinued operations of our power generating facility and other minor subsidiaries. It also includes specific items attributable to our operating segments that have been
excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. See Notes 1 and 25 to our Consolidated Financial Statements. In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell Armstrong, our
625-megawatt natural gas-fired merchant generation peaking facility in Shelocta, Pennsylvania, along with two other facilities owned by Dominion. Total expected proceeds for the three facilities is approximately $256 million, of which about $117
million will be allocated to Armstrong. The sale is expected to close by the end of the first quarter of 2007, pending regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. No state regulatory approvals are
required. We offered the facility for sale following a review of our portfolio of assets. On February 27, 2007, an affiliate acquired from Armstrong, a majority equity interest in exchange for a reduction in net amounts owed to the affiliate of
approximately $207 million. Immediately following this transaction, we sold our remaining minority interest in Armstrong to the affiliate. REGULATION We are subject to regulation by the Securities and Exchange Commission (SEC), FERC, the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Army
Corps of Engineers, the Ohio Commission, the Pennsylvania Commission, the West Virginia Commission and other federal, state and local authorities. State
Regulations Our gas distribution services are regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission. STATUS OF COMPETITIVE RETAIL GAS SERVICES Each of the three states in
which we have gas distribution operations has enacted or considered legislation regarding a competitive deregulation of natural gas sales at the retail level. OhioOhio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, we have offered retail choice to
residential and commercial customers. At December 31, 2006, approximately 814,000 of our 1.2 million Ohio customers were participating in this Energy Choice program. Large industrial customers in Ohio also source their own natural gas
supplies. In May 2006, the Ohio Commission approved a two-year pilot program to improve and expand our Energy Choice Program. Under the previous structure, non-Energy Choice customers purchased gas directly from us at a monthly gas cost recovery
rate that included true-up adjustments that could change significantly from one quarter to the next. In August 2006, the Ohio Commission approved an auction that enabled us to enter into gas purchase contracts with selected suppliers at a fixed
price above the New York Mercantile Exchange (NYMEX) month-end settlement. This pricing mechanism, implemented in October 2006, replaces the traditional gas cost recovery rate with a monthly market price that eliminates the true-up adjustment,
making it easier for customers to compare


and switch to competitive suppliers by the end of the transition period. Subject to Ohio Commission approval, we plan to exit the gas merchant function in
Ohio entirely and have all customers select an alternate gas supplier. We will continue to be the provider of last resort in the event of default by a supplier. PennsylvaniaIn Pennsylvania, supplier choice is available for all residential and small commercial customers. At December 31, 2006, approximately 99,000 residential and small commercial customers had
opted for Energy Choice in our Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers. West VirginiaAt this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. However, the West Virginia Commission has issued regulations to govern
pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia. RATES Our gas distribution subsidiaries are subject to regulation of rates and other
aspects of their businesses by the states in which they operatePennsylvania, Ohio and West Virginia. When necessary, our gas distribution subsidiaries seek general base rate increases on a timely basis to recover increased operating costs. In
addition to general rate increases, our gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are subject to rate
recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover
prospective one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses. MINIMUM SERVICE STANDARDS In January 2006, the Ohio Commission issued an Order
adopting rules establishing minimum service standards for natural gas companies. The Ohio Commission issued a second Entry on Rehearing in July 2006 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 December 2006, Dominion East Ohio (DEO) submitted to Ohio Commission
staff for review a meter reading plan to achieve compliance with the related standard. DEO also submitted to the Ohio Commission the following: (1) an application requesting approval for waivers of specified service standards to allow time for
programming and other changes required to implement those new standards, (2) an application requesting approval for a plan to install automated meter reading (AMR) devices system wide over a five-year period as part of DEOs meter reading plan
and for recovery of related costs, and (3) tariffs revisions necessary for compliance with the new standards. Updated estimates for implementing the new standards indicate that meter reading operations and maintenance costs could increase $7 million
to $9 million per year if the waiver regarding remote reading devices is not approved. Call center expenses are expected to increase by $2 million per year to reach the required average speed of answer. Related information technology costs are
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$1 million. DEO estimates the cost of system-wide AMR deployment to be between $100 million and $110 million. Federal Regulations PUBLIC UTILITY HOLDING COMPANY ACT OF 2005 The Energy Policy Act of 2005 provided for the repeal of the Public Utility Holding Company Act of 1935 (1935 Act) in February 2006. The 1935 Act and related regulations
issued by the SEC governed our activities with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in businesses activities not directly related to the
utility or energy business and other matters. Since the effective date of repeal of the 1935 Act, we are considered a holding company under the Public Utility Holding Company Act of 2005 (PUHCA 2005), the rules and regulations of which are
administered by FERC. PUHCA 2005 is more limited in scope than the 1935 Act and relates primarily to certain record-keeping requirements and transactions involving public utilities and their affiliates. FEDERAL ENERGY REGULATORY COMMISSION FERC regulates the transportation and sale for
resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by our interstate
natural gas company subsidiaries, including Dominion Transmission, Inc. (DTI), Dominion Cove Point LNG, LP (DCP) and Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import
facilities and interstate natural gas pipeline facilities. Our interstate gas transportation and storage activities are conducted on an
open access basis, in accordance with certificates, tariffs and service agreements on file with FERC. We are also subject to
the Pipeline Safety Act of 2002 (2002 Act), which mandates inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. We have evaluated our natural gas
transmission and storage properties as required by the Department of Transportation regulations under the 2002 Act, and have implemented a program of identification, testing and potential remediation activities. These activities are ongoing. We are also subject to FERCs Standards of Conduct that govern conduct between interstate gas providers and their marketing function
or their energy related affiliates. The rules define the scope of the affiliates covered by the standards and are designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences. In May 2005, FERC approved a comprehensive rate settlement with our subsidiary, DTI, and its customers and interested state commissions. The settlement,
which became effective July 1, 2005, revised our natural gas transportation rates and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium until 2010. In June 2006, we filed a general rate proceeding for DCP. The rates to be established in this case will take effect as of January 1, 2007.
This rate proceeding will enable DCP to update the cost of service underlying its rates, including recovery of costs associated with the 2002 to 2003 reactivation of the LNG import terminal. Resolution of the case is expected during the first half
of 2007. We implemented various other rate filings, tariff changes and negotiated rate service agreements for our FERC-regulated businesses
during 2006. In all material respects, these filings were


approved by FERC in the form requested by us and were subject to only minor modifications. FEDERAL OFFSHORE OIL AND GAS LEASE LEGISLATION A bill passed by the U.S. House of Representatives on January 16, 2007, but not yet
enacted into law, addresses certain federal offshore oil and gas leases issued in 1998 and 1999 that do not include a provision requiring royalties to be paid on specified royalty suspension volumes when oil and gas commodity futures closing prices
exceed specified threshold levels (as is the case under current market conditions). The bill imposes a conservation of resources fee of $1.25 per MMbtu of gas and $9.00 per barrel oil (2005 dollars) produced from such leases on and after October 1,
2006 in calendar years when the average oil or gas (as applicable) commodity futures monthly closing prices on the NYMEX exceed $4.34 per MMbtu for gas or $34.73 for oil (2005 dollars). In addition, commencing on and after October 1, 2006, in
calendar years when the average NYMEX monthly closing prices exceed the foregoing thresholds, a conservation of resources fee of $3.75 per acre per lease per year is imposed on such leases that are non-producing. The bill permits lessees to avoid
payment of the foregoing fee by agreeing to lease amendments that provide that royalties are payable with respect to royalty suspension volumes on and after October 1, 2006 when the foregoing threshold conditions are met. Finally, the bill imposes
sanctions on lessees, including disqualification from future offshore lease sales, for those who do not enter into such lease amendments and fail to pay the fee. The Senate is considering similar legislation. Environmental Regulations Each of our operating segments face substantial
regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, see Item 3. Legal Proceedings and Note 20 to our Consolidated Financial Statements. From time to time we may be identified as a potentially responsible party (PRP) in relation to a Superfund site. The EPA (or a state) can either
(a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held
jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, we may be responsible for the costs of remedial
investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. We do not believe that any currently identified sites will result in significant liabilities. In 1997, the U.S. signed an International Protocol (Protocol) to limit man-made greenhouse emissions under the United Nations Framework Convention on
Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the
nations greenhouse gas emission intensity by 18% over the period 2002-2012. Several legislative proposals in the U.S. Congress have in the past and are likely in the future to include provisions seeking to target the reductions of greenhouse
gas emissions. The cost of compliance with the Protocol or other programs seeking greenhouse gas reductions could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue,
we cannot predict the financial impact of future climate change actions on our operations at this time.




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We have applied for or obtained the necessary environmental permits for the operation of our regulated facilities. Many of these permits are subject to
re-issuance and continuing review. ITEM 1A. RISK FACTORS 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 factors below. 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 Item 7. Managements Discussion and Analysis of Results of Operations (MD&A). Our operations are weather sensitive.Our results of operations can be affected by changes in the weather. Weather
conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing production delays and property
damage that require us to incur additional expenses. We are subject to complex
governmental regulation that could adversely affect our operations.Our operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates
from various governmental agencies. We must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for our existing operations and that our business is conducted in
accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, may require us to incur additional expenses. Costs of environmental compliance, liabilities and litigation could exceed our estimates, which
could adversely affect our results ofoperations.Compliance with federal, state and local
environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, we may be a responsible party for environmental clean-up at a site
identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility
that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties. The use of derivative instruments could result in financial losses and liquidity
constraints.We use derivative instruments, including futures, forwards, options and swaps, to manage our commodity and financial market risks. We could recognize financial losses on these contracts
as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of
these contracts involves managements judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. In addition, we use derivatives to hedge future sales of our gas and oil production, which may limit the benefit we would otherwise receive from increases
in commodity prices. These hedge arrangements generally include collateral requirements that


require us to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit
limits. When commodity prices rise to levels substantially higher than the levels where we have hedged future sales, we may be required to use a material portion of our available liquidity and obtain additional liquidity to cover these collateral
requirements. In some circumstances, this could have a compounding effect on our financial liquidity and results. Derivatives designated
under hedge accounting to the extent not fully offset by the hedged transaction can result in ineffectiveness losses. These losses primarily result from differences in the location and specifications of the derivative hedging instrument and the
hedged item and could adversely affect our results of operations. For additional information concerning derivatives and commodity-based
contracts, see Market Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 8 to our Consolidated Financial Statements. Our E&P business is affected by 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, but are not limited to: 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, our ability to acquire additional land
positions in competitive lease areas, operational risks that could disrupt production and geological and other uncertainties inherent in the estimate of gas and oil reserves. 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 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. 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. 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




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of our E&P assets would reduce our future earnings. While Dominion believes it would be able to execute any sale or 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. We may also 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. An inability to access financial markets could affect the execution of our business
plan.We rely on access to short-term money markets, longer-term capital markets and banks as significant sources of liquidity for capital requirements and collateral requirements related to hedges of
future gas and oil production not satisfied by the cash flows from our operations. Management believes that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of our
control may increase our cost of borrowing or restrict our ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to our credit


ratings. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled. Changing rating agency requirements could negatively affect our growth and business
strategy.As of February 1, 2007, our senior unsecured debt is rated BBB, positive outlook, by Standard & Poors Ratings Services (Standard & Poors); A3, under review
for possible downgrade, by Moodys Investors Service (Moodys); and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary
to take steps or change our business plans in ways that may adversely affect our growth and earnings. A reduction in our credit ratings by Standard & Poors, Moodys or Fitch could increase our borrowing costs and adversely affect
operating results and could require us to post additional collateral in connection with some of our price risk management activities. Potential changes in accounting practices may adversely affect our financial results.We cannot predict the impact that future changes in
accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities.
These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities. Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations.Our
business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future
operating results.




ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We share our principal office in Richmond, Virginia, which is owned by our parent company, Dominion. We lease offices in other cities in which our subsidiaries operate. Our assets consist primarily of investments in
our subsidiaries, the principal properties of which are described below and in Item 1. Business.


The following information detailing our gas and oil operations includes the activities of the E&P segment and the production activity of DTI, which is
included in the Energy segment:




COMPANY-OWNED PROVED GAS AND OIL
RESERVES

Estimated net quantities of proved gas and oil reserves at December 31 of each of the last three years were as follows:



|                                         |  |                 |  |             |  |                 |  |             |  |                 |  |            
|---------------------------------------- |  | --------------- |  | ----------- |  | --------------- |  | ----------- |  | --------------- |  | -----------
|                                         |  | 2006            |  | 2005        |  | 2004           
|                                         |  | ProvedDeveloped |  | TotalProved |  | ProvedDeveloped |  | TotalProved |  | ProvedDeveloped |  | TotalProved
|Proved gas reserves (bcf)                |  | 2,898           |  | 4,328       |  | 3,059           |  | 4,219       |  | 3,049           |  | 4,202      
|Proved oil reserves (000 barrel)         |  | 172,505         |  | 215,636     |  | 144,417         |  | 197,284     |  | 100,780         |  | 142,635    
|Total proved gas and oil reserves (bcfe) |  | 3,933           |  | 5,621       |  | 3,925           |  | 5,403       |  | 3,654           |  | 5,058      



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Certain of our subsidiaries file Form EIA-23 with the DOE, which reports gross proved reserves, including the working interest shares of other owners, for
properties operated by such subsidiaries. The proved reserves reported in the table above represent our share of proved reserves for all properties, based on our ownership interest in each property. For properties we operate, the difference between
the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2006 are based upon a
study for each of our properties prepared by our staff engineers and audited by Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance
with SEC guidelines. QUANTITIES OF GAS AND OIL PRODUCED Quantities of
gas and oil produced during each of the last three years follow:  2006

2005

2004Gas production (bcf)

272

242

264Oil production (000 barrel)

23,773

14,543

11,117Total gas and oil production (bcfe)

415

329

331 The average realized price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other
Company operations at market prices) during the years 2006, 2005 and 2004 was $4.64, $5.08 and $4.45, respectively. The respective average realized prices without hedging results per mcf of gas produced were $6.77, $8.13 and $6.01, respectively. The
respective average realized prices for oil with hedging results were $32.80, $29.92 and $25.28 per barrel and the respective average realized prices without hedging results were $54.88, $50.23 and $39.96 per barrel. The average production (lifting)
cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2006, 2005 and 2004 was $1.07, $1.03 and $0.78, respectively. ACREAGE Gross and net developed and undeveloped acreage at December 31, 2006 was:  Developed Acreage

Undeveloped AcreageGross

Net

Gross

Net(thousands)Acreage

3,836

2,488

2,698

1,455 NET WELLS DRILLED IN THE CALENDAR YEAR The number of net wells completed during each of the last three years follows:  2006

2005

2004Exploratory:Productive

6

6

7Dry

3

6

7Total Exploratory

9

12

14Development:Productive

1,034

817

830Dry

33

34

17Total Development

1,067

851

847Total wells drilled (net)

1,076

863

861


As of December 31, 2006, 143 gross (89 net) wells were in the process of being drilled, including wells temporarily suspended. PRODUCTIVE WELLS The number of productive gas and oil wells in which we had an
interest at December 31, 2006, follows:  Gross

NetTotal gas wells

18,690

14,060Total oil wells

1,804

593 The number of productive wells includes 201 gross (147 net) multiple completion gas wells and 17
gross (11 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes. ITEM 3. LEGAL PROCEEDINGS 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. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position,
liquidity or results of operations. See Regulation in Item 1. Business and Note 20 to our Consolidated Financial Statements for
additional information on various environmental, rate matters and other regulatory proceedings to which we are a party. In March 2006,
Peoples and Equitable Resources, Inc. (Equitable) filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by Equitable of all of the stock of Peoples and Hope. In April 2006, Hope and Equitable filed a joint petition
seeking West Virginia Commission approval of the purchase by Equitable of all of the stock of Hope. In February 2007, the administrative law judge for the Pennsylvania Commission entered an initial decision approving a proposed joint settlement and
recommending approval of the sale in Pennsylvania. Before being acquired by us in 2001, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was
one of numerous defendants in a lawsuit consolidated and pending in the 93rd Judicial Court in Hidalgo County, Texas. The lawsuit alleged that gas wells and related pipeline facilities operated by Louis Dreyfus and other facilities operated by other
defendants caused an underground hydrocarbon plume in McAllen, Texas. In April 2006, we entered into a settlement agreement with the plaintiffs resolving all of their claims against us. In May 2006, the plaintiffs non-suited Dominion with prejudice,
resulting in the dismissal of the case. We remain subject, however, to a cross-claim and an indemnity claim with certain of the other defendants that were not a party to our settlement with the plaintiffs. Neither claim is material and we do not
expect the resolution of these remaining claims or the settlement to have a material adverse effect on the results of operations or financial condition. In July 1997, Jack Grynberg brought suit against CNG Producing Company, predecessor to Dominion Exploration & Production, Inc. (DEPI), and several of its affiliates (there are 73 defendants in this case). The
suit seeks damages for alleged




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fraudulent mis-measurement of gas volumes and underreporting of gas royalties from gas production from federal leases. The suit was consolidated with
approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynbergs claims were dismissed on the basis that they overlapped with Mr. Wrights claims, which are noted below.
Mr. Grynberg has filed an appeal. In October 2006, Judge Downes issued an order dismissing all claims against DEPI and its affiliates on the jurisdictional grounds that Mr. Grynberg has failed to meet his burden to prove he is the
original source of the claims being asserted under the False Claims Act. It is expected that Mr. Grynberg will appeal this order. In April 1998, Harrold E. (Gene) Wright filed suit against DEPI (formerly known as CNG Producing Company), a subsidiary of CNG, and numerous other companies under the False Claims Act. Mr. Wright alleged various fraudulent valuation
practices in the payment of royalties due under federal oil and gas leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim
against us was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied our motion to dismiss on jurisdictional grounds in January 2005. Discovery in this matter is
currently underway. In September 2006, DTI 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.


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Omitted pursuant to General Instruction I.(2)(c).




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PART II



ITEM 5. MARKET FOR THE REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Dominion Resources, Inc. owns all of our common stock. Restrictions on our payment of dividends are discussed in Note 18 to our Consolidated Financial Statements. We paid quarterly cash dividends on our common stock as follows (in
millions):  Quarter

First

Second

Third

Fourth

Total2006

$
191

$
99

$
96

$
289

$
6752005


214


110


92


159


575 ITEM 6. SELECTED FINANCIAL DATA Omitted pursuant to General Instruction I.(2)(a). ITEM 7. MANAGEMENTS DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS Managements Discussion and Analysis of
Results of Operations (MD&A) discusses our results of operations. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms Company, we, our and us are used
throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Consolidated Natural Gas Company (CNG); one of CNGs consolidated subsidiaries or operating segments, or the entirety of CNG
and its consolidated subsidiaries. CONTENTS OF MD&A Our MD&A
consists of the following information: n


Forward-Looking Statements n


Introduction n


Accounting Matters n


Results of Operations n


Segment Results of Operations n


Credit Risk 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, target 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: n


Unusual weather conditions and their effect on energy sales to customers and energy commodity prices; n


Extreme weather events, including hurricanes and winter storms, that can cause outages, production delays and property damage to our facilities; n


State and federal legislative and regulatory developments, including deregulation and changes in environmental and other laws and regulations to which we are
subject; n


Cost of environmental compliance; n


Fluctuations in energy-related commodity prices and the effect they could have on our earnings, liquidity position and the underlying value of our assets; n


Counterparty credit risk; n


Capital market conditions, including price risk due to marketable securities held as investments in benefit plan trusts; n


Fluctuations in interest rates; n


Change in rating agency requirements or credit ratings and their effect on availability and cost of capital; n


Changes in financial or regulatory accounting principles or policies imposed by governing bodies; n


Employee workforce factors including collective bargaining agreements and labor negotiations with union employees; n


The risks of operating businesses in regulated industries that are subject to changing regulatory structures; n


Changes in our ability to recover investments made under traditional regulation through rates; n


Receipt of approvals for and timing of closing dates for acquisitions and divestitures, including our divestiture of The Peoples Natural Gas Company (Peoples) and
Hope Gas, Inc. (Hope), and any divestiture of our exploration and production (E&P) business; n


Risks associated with any realignment of our operating assets, including a reduction to future earnings, costs associated with any sale of our E&P business and
the costs and reinvestment risks related to the deployment of proceeds from any sale; n


Political and economic conditions, including the threat of domestic terrorism, inflation and deflation; and n


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. 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.




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INTRODUCTION CNG operates in all phases of the natural gas business, explores for and
produces gas and oil, and provides a variety of energy marketing services. We are a wholly-owned subsidiary of Dominion Resources, Inc. (Dominion). We manage our operations through three primary operating segments: Delivery, Energy, and E&P. The contributions to net income by our primary operating segments are determined based on a measure of profit that we believe represents the
segments core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by management in assessing segment performance or allocating resources among the segments. Those specific
items are reported in the Corporate segment. Deliveryincludes our regulated gas distribution and customer service business, as well as nonregulated retail energy marketing operations and related products and services. Our three regulated gas distribution operations
serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Our nonregulated retail energy marketing operations market gas, electricity and related products and services to
residential, industrial and small commercial customers in the Northeast, Mid-Atlantic and Midwest. Revenue provided by our gas distribution
operations is based primarily on rates established by state regulatory authorities and state law. The profitability of this business is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable
return on our capital investments. Variability in earnings relates largely to changes in volumes, which are primarily weather sensitive, and changes in the cost of routine maintenance and repairs (including labor and benefits). Income from retail
energy marketing operations varies in connection with changes in weather and commodity prices, as well as the acquisition and loss of customers. In March 2006, we entered into an agreement with Equitable Resources, Inc. to sell two of our wholly-owned regulated gas distribution subsidiaries, Peoples and 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 end of the second quarter of 2007, subject to state regulatory
approvals in Pennsylvania and West Virginia, as well as approval under the Hart-Scott-Rodino Act. In February 2007, the administrative law judge for the Pennsylvania Commission entered an initial decision approving a proposed joint settlement and
recommending approval of the sale in Pennsylvania. Energyincludes our natural gas transmission pipeline and storage businesses and the Cove Point liquefied natural gas (LNG) import and storage facility. It also includes gathering and extraction activities, certain
Appalachian natural gas production, as well as producer services, which consist of aggregation of gas supply and related wholesale activities. The gas transmission pipeline and storage business serves our gas distribution businesses and other
customers in the Northeast, Mid-Atlantic and Midwest. Revenue provided by our regulated gas transmission operations and the LNG facility is
based primarily on rates established by the Federal Energy Regulatory Commission (FERC). The profitability of these businesses is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return
on our capital investments. Variability in earnings results primarily from changes in rates and the demand for services, which is primarily weather dependent.


Earnings from Energys nonregulated
businesses are subject to variability associated with changes in commodity prices. Energys nonregulated businesses use physical and financial arrangements to attempt to hedge this price risk. Certain hedging activities may require cash
deposits to satisfy collateral requirements. Variability in earnings also results from changes in operating and maintenance expenditures (including labor and benefits). E&Pincludes 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, West Texas, Mid-Continent, the Rockies and Appalachia. E&P generates income from the sale of natural gas and oil we produce from our reserves. Variability in earnings relates primarily to changes in
commodity prices, which are market-based, and production volumes, which are impacted by numerous factors including drilling success, timing of development projects and external factors such as storm-related damage caused by hurricanes. We attempt to
manage commodity price volatility by hedging a substantial portion of our expected production. These hedging activities may require cash deposits to satisfy collateral requirements. In November 2006, Dominion announced its decision to pursue the sale of all of our oil and natural gas E&P operations and assets, with the exception
of those located in the Appalachian Basin. As of December 31, 2006, our natural gas and oil assets  excluding the Appalachian Basin  included about 4.7 trillion cubic feet of proved reserves. The Appalachian assets that we would
retain constitute approximately 17% of our total reserves as of December 31, 2006. Corporateincludes our corporate functions, including the activities of CNG International (CNGI), the net impact of the discontinued operations of our Armstrong power generating
facility and other minor subsidiaries. It also includes specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or allocating
resources among segments. In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg
Pincus LLC to sell Armstrong, our 625-megawatt natural gas-fired merchant generation peaking facility in Shelocta, Pennsylvania, along with two other facilities owned by Dominion. Total expected proceeds for the three facilities is approximately
$256 million, of which about $117 million will be allocated to Armstrong. The sale is expected to close by the end of the first quarter of 2007, pending regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. No
state regulatory approvals are required. We offered the facility for sale following a review of our portfolio of assets. On February 27, 2007, an affiliate acquired from Armstrong, a majority equity interest in exchange for a reduction in net
amounts owed to the affiliate of approximately $207 million. Immediately following this transaction, we sold our remaining minority interest in Armstrong to the affiliate. ACCOUNTING MATTERS Critical Accounting Policies and Estimates We have identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could
result in material changes to our financial condition or results of oper
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ations under different conditions or using different assumptions. We have discussed the development, selection and disclosure of each of these policies with the Audit Committee of our Board of Directors. ACCOUNTING FOR
DERIVATIVE CONTRACTS AT FAIR VALUE We use derivative contracts such as forwards, futures, swaps and options to buy and sell energy-related commodities and
to manage our commodity and financial market risks. Derivative contracts, with certain exceptions, are subject to fair value accounting and are reported on our Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and
related hedging activities are complex and may be subject to further clarification by standard-setting bodies. Fair value is based on
actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources
is not available, we must estimate prices based on available historical and near-term future price information and use of statistical methods. For options and contracts with option-like characteristics where pricing information is not available from
external sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions. We use other option models under special circumstances, including a Spread
Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique
characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate under the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is
required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on a contracts estimated fair value. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of
occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains and/or losses on cash flow hedges
from accumulated other comprehensive income (loss) (AOCI) into earnings. USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING As of December 31, 2006, we reported $623 million of goodwill on our Consolidated Balance Sheet. The majority of this goodwill is allocated to the E&P reporting
unit, with the remainder allocated to the Energy reporting unit. In April of each year, we test our goodwill for potential impairment, and perform additional tests more frequently if impairment indicators are present. The 2006 annual test did not
result in the recognition of any goodwill impairment, as the estimated fair values of our reporting units exceeded their respective carrying amounts. We estimate the fair value of our reporting units by using a combination of discounted cash flow analyses, based on our internal five-year strategic plan, and other valuation techniques that use multiples of earnings
for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on subjective factors such as our estimate of future cash flows, the selection of appropriate discount and growth
rates, and the selection of peer group companies and recent transactions. These underlying assumptions


and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in our estimates of
future cash flows, could result in a future impairment of goodwill. Although we have consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows,
and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent annual
test had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING Impairment testing for an
individual or group of long-lived assets or intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an assets carrying amount exceeds the undiscounted estimated future cash flows
associated with the asset, the asset is considered impaired to the extent that the assets fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves our judgment in areas such as identifying
circumstances that indicate impairment; identifying and grouping affected assets; and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the
asset, including the selection of an appropriate discount rate. Although our cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may
vary significantly from actual results. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities
sold and consumed. In conjunction with the results of a review conducted to determine how specific assets are contributing to our return on
invested capital and shareholder value, the Armstrong facility, with a carrying amount of $203 million, was marketed for sale in the third quarter of 2006 and a decision was made in the fourth quarter of 2006 to no longer pursue the development of a
gas transmission pipeline project with capitalized construction costs of $28 million. The pipeline project was previously tested for impairment during 2005. The results of our analysis in 2005 indicated that the carrying amount was recoverable. An
impairment analysis performed in the third quarter of 2006 indicated that the carrying amount of the Armstrong facility was recoverable as the expected undiscounted cash flows, probability weighted to reflect both continued use and possible sale
scenarios, exceeded the carrying amount. In December 2006, we reached an agreement to sell the Armstrong facility and accordingly, we reduced its carrying amount to fair value less cost to sell and classified it as held for sale in our Consolidated
Balance Sheet. Impairment charges of $113 million ($72 million after-tax) were recorded in December 2006 related to the Armstrong facility and the transmission pipeline project. In 2004, we did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may
exist. EMPLOYEE BENEFIT PLANS We sponsor and also participate in
certain Dominion noncontributory defined benefit pension plans and other postretire
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ment benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan
assets. Assumptions about the future, including the expected rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in health care costs and participant compensation, also have a significant
impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in our Consolidated Statements of Income over the remaining average service
period of plan participants rather than immediately. The expected long-term rates of return on plan assets, discount rates and medical cost
trend rates are critical assumptions. We determine the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of: n


Historical return analysis to determine expected future risk premiums; n


Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices; n


Expected inflation and risk-free interest rate assumptions; and n


Investment allocation of plan assets. Effective September 1, 2006, the strategic target asset allocation for our pension fund is 34% U.S. equity securities,
12% non-U.S. equity securities, 22% debt securities, 7% real estate and 25% other, such as private equity investments. Prior to September 1, 2006, the strategic target asset allocation for our pension fund was 45% U.S. equity securities, 8%
non-U.S. equity securities, 22% debt securities and 25% other, such as real estate and private equity investments. Assisted by an independent actuary, we develop assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. We calculated our
pension cost using an expected return on plan assets assumption of 8.75% for 2006, 2005 and 2004. We calculated our 2006 and 2005 other postretirement benefit cost using an expected return on plan assets assumption of 8.00% compared to 7.79% for
2004. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets. We determine discount rates from analyses performed by a third-party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to
be made under our plans. The discount rates used to calculate 2006 pension cost and other postretirement benefit cost were 5.60% and 5.50%, respectively, compared to the 6.00% and 6.25% discount rates used to calculate 2005 and 2004 pension and
other postretirement benefit costs, respectively. Lower long-term bond yields were the primary reason for the decline in the discount rate from 2005 to 2006. We selected discount rates of 6.20% and 6.10% for determining our December 31, 2006
projected pension and postretirement benefit obligations, respectively. We establish the medical cost trend rate assumption based on
analyses performed by a third-party actuarial firm of various factors including the specific provisions of our medical plans, actual cost trends experienced and projected, and demographics of plan participants. Our medical cost trend rate assumption
as of


December 31, 2006 is 9.00% and is expected to gradually decrease to 5.00% in later years. ACCOUNTING FOR REGULATED OPERATIONS The accounting for our regulated gas operations differs from the accounting for nonregulated
operations in that we are required to reflect the effect of rate regulation in our Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to
accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, we defer these costs as
regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from
customers for expenditures that are not yet incurred. Regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the recovery period authorized by the regulator. We evaluate whether or not recovery of our regulatory assets through future rates is probable and make various assumptions in our analyses. The
expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than
probable, it will be written off in the period such assessment is made. In 2006, $162 million of our regulatory assets were written off as a result of the pending sale of Peoples and Hope since the recovery of those assets is no longer probable. We
currently believe the recovery of our remaining regulatory assets is probable. See Notes 2 and 12 to our Consolidated Financial Statements. ACCOUNTING FOR GAS AND
OIL OPERATIONS We follow the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities and Exchange
Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. The depletable base of costs includes
estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depletable base are subject to a ceiling test prescribed by the
SEC. The test limits capitalized amounts to a ceilingthe present value of estimated future net revenues to be derived from the production of proved gas and oil reserves, assuming period-end pricing adjusted for any cash flow hedges in place.
We perform the ceiling test quarterly and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized
unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Our estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to
develop the proved reserves, and estimates of future production from the proved reserves. Our estimated proved reserves as of December 31, 2006 are based upon studies for each of our properties prepared by our staff engineers and audited by
Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering




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methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Given the volatility of natural gas and oil prices, it is
possible that our estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near-term. The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of our estimates or
assumptions in the future and revisions to the value of our proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur.
See Notes 2 and 26 to our Consolidated Financial Statements. INCOME TAXES Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret them
differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material. Through December 31, 2006, we have established liabilities for tax-related contingencies in accordance with Statement of Financial Accounting
Standards (SFAS) No. 5, Accounting for Contingencies,and reviewed them in light of changing facts and circumstances. However, as discussed in Note 4 to our Consolidated Financial Statements, effective January 1, 2007, we adopted
Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), Accounting for Uncertainty in Income Taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, FIN
48 establishes standards for recognition and measurement, in financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the
financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets
and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be
implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. Accounting Standards During 2006, 2005 and 2004, we were required to adopt
several new accounting standards, the requirements of which are discussed in Note 3 to our Consolidated Financial Statements. Our adoption of SFAS No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement
Plans on December 31, 2006 affected the comparability of our Consolidated Balance Sheet at December 31, 2006 to prior periods. Under SFAS No. 158, our Consolidated Balance Sheet now reflects the overfunded or underfunded status of
our defined benefit plans as an asset or liability, respectively, with previously unrecognized net actuarial gains or losses, prior service costs or credits and transition obligations recognized as a component of either AOCI or regulatory assets or
liabilities. See Note 4 to our Consolidated


Financial Statements for a discussion of recently issued accounting standards that will be adopted in the future. RESULTS OF OPERATIONS Overview 2006 vs. 2005 Net income increased 40% to $773 million from $553 million in 2005.
Favorable drivers included an increase in gas and oil production as compared to 2005, when operations were significantly impacted by Hurricanes Katrina and Rita (2005 hurricanes), which struck the Gulf Coast area in late August and late September
2005, respectively, an increase in business interruption insurance revenue received in 2006 related to the 2005 hurricanes, the absence of a $272 million after-tax loss in 2005 related to the discontinuance of hedge accounting for certain gas and
oil hedges caused by the interruption in gas and oil production, the positive 2006 mark-to-market impact of certain gas and oil derivatives that were de-designated as hedges in 2005 and a higher contribution from our nonregulated retail energy
marketing operations. These favorable drivers were partially offset by the impact of milder weather on regulated gas sales and lower realized gas prices for our E&P operations. Analysis of Consolidated Operations Presented below are selected amounts related to our results of operations:  Year Ended December 31,

2006


2005

$ Change(millions)Operating Revenue(1)

$
7,642


$
8,033

(391
)Operating ExpensesPurchased gas(1)


2,862



3,782

(920
)Electric energy purchases(1)


227



319

(92
)Other energy-related commodity purchases (1)


413



363

50Other operations and maintenance(1)


1,219



1,547

(328
)Depreciation, depletion and amortization


906



663

243Other taxes


293



302

(9
)Other income


26



30

(4
)Interest and related charges(1)


278



215

63Income tax expense


638



317

321Loss from discontinued operations


(59
)




(59
)  (1)
Includes transactions with other Dominion subsidiaries related to Dominions enterprise-wide price risk management and other activities. See Note 23 to our Consolidated Financial
Statements for a description of transactions with affiliates. An analysis of our results of operations for 2006 compared to
2005 follows: Operating Revenuedecreased 5% to $7.6
billion, primarily reflecting: n


A $730 million decrease in our producer services business consisting of a decrease in both volumes ($627 million) and prices ($103 million) associated with gas
aggregation; n


A $363 million decrease from regulated gas distribution operations, primarily reflecting a $270 million decrease associated with milder weather and changes in
customer usage and a $219 million decrease resulting from the loss of customers related to Energy Choice programs, partially offset by a $122 million increase related to the recovery of higher gas prices; and




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n


A $102 million decrease in revenue from sales of gas purchased by E&P operations, due to reduced sales volumes associated with lower gas volumes purchased to
facilitate gas transportation and other contracts and the impact of netting sales and purchases of gas under buy/sell arrangements associated with the implementation of Emerging Issues Task Force (EITF) Issue No. 04-13, Accounting for
Purchases and Sales of Inventory with the Same Counterparty. These decreases were partially offset by: n


A $191 million increase in sales of gas and oil production, primarily due to higher volumes ($379 million), partially offset by lower prices ($188 million); n


A $184 million increase in gas sales by our nonregulated retail energy marketing operations primarily resulting from increased customer counts ($141 million) and
higher contracted sales prices ($43 million); n


A $161 million increase in sales of extracted products, primarily due to increased prices and a contractual change for a portion of our gas production processed by
third parties. We now take title to and market the extracted products from this gas; n


An increase of $95 million resulting from higher business interruption insurance revenue received in 2006, related to the 2005 hurricanes ($274 million) versus
business interruption insurance revenue received in 2005 ($179 million) related to Hurricane Ivan; n


An $88 million increase due to a sale of gas inventory by our East Ohio Gas subsidiary related to the implementation of the Standard Service Offer (SSO) pilot
program as approved by the Ohio Commission. The SSO was initiated to encourage and assist other suppliers to enter the gas procurement market. By the end of the transition period, we plan to exit the gas merchant function in Ohio and have all
customers select an alternate gas supplier. This increase is offset by a comparable increase in Purchased gas expense; and n


A $46 million increase in sales of purchased oil by E&P operations. This increase in sales of purchased oil was largely offset by a corresponding increase in
Other energy-related commodity purchases expense. Operating Expenses Purchased gas expensedecreased 24% to $2.9
billion, primarily resulting from: n


A $721 million decrease associated with our producer services business, due to lower volumes ($618 million) and prices ($103 million); n


A $192 million decrease related to regulated gas distribution operations, due to a $252 million decrease associated with milder weather and fewer Energy Choice
customers and a $222 million decrease due to lower average gas prices, partially offset by a $282 million increase related to the recovery of gas costs; and n


A $123 million decrease related to E&P operations, as a result of lower volumes purchased to facilitate gas transportation and other contracts and the impact of
netting sales and purchases of gas under buy/sell arrangements following the implementation of EITF 04-13, as discussed in Operating Revenue; partially offset by n


A $139 million increase associated with nonregulated retail energy marketing operations, primarily due to increased volumes.


Electric energy purchases expensedecreased 29% to $227 million, resulting from a decrease in purchases by our nonregulated retail energy marketing operations primarily due to
customer attrition. Other energy-related commodity purchases expenseincreased 14% to $413 million, primarily attributable to higher market prices ($63 million), partially offset by lower volumes ($16 million) due to 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 expensedecreased 21% to $1.2 billion, primarily resulting from: n


The absence of a $423 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; n


A $62 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; n


The absence of a $59 million loss related to the discontinuance of hedge accounting in March 2005, for certain oil hedges primarily resulting from a delay in
reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those hedges; and n


An $83 million decrease in hedge ineffectiveness expense associated with E&P operations, primarily due to the increased use of basis swaps. These decreases were partially offset by: n


A $162 million charge from the write-off of certain regulatory assets related to the pending sale of Peoples and Hope; n


A $91 million increase attributable to higher production handling, transportation and operating costs related to E&P operations; n


A $64 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; n


A $31 million increase resulting from price risk management activities associated with our nonregulated retail energy marketing operations; and n


A $27 million charge resulting from the cancellation of a pipeline project. Depreciation, depletion and amortization expenseincreased 37% to $906 million, due to the impact of increased gas and oil production and higher E&P finding and development costs. Interest and related chargesincreased 29% to $278 million, primarily due to the impact of additional borrowings from Dominions
money pool and higher interest rates on those borrowings. Income tax
expenseincreased to $638 million primarily due to increased income from operations and the recognition of $105 million of deferred taxes related to the pending sale of Peoples and Hope. Loss from discontinued operationsincreased to
$59 million reflecting a $56 million after-tax impairment charge related to the pending sale of the Armstrong generation peaking facility, whose operating losses were reclassified to discontinued operations in December 2006.




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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:  Year Ended December 31,

2006


2005


$ Change(millions)Delivery

$
157


$
157


$
Energy


263



234



29E&P


608



529



79Primary operating segments


1,028



920



108Corporate


(255
)


(367
)


112Consolidated

$
773


$
553


$
220 Delivery Presented below
are operating statistics related to our Delivery operations:  Year Ended December 31,

2006

2005

% ChangeGas throughput (bcf):Gas sales

94

131

(28
)Gas transportation

240

241

Heating degree days (gas service area)(1)

5,190

5,899

(12
)Average gas delivery customer accounts(2):Gas sales

858

1,030

(17
)Gas transportation

830

661

26Average nonregulated retail energy marketing customer accounts

1,354

1,162

17 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)
Thirteen-month average, in thousands. Presented below, on an after-tax basis, are
the key factors impacting Deliverys net income contribution: 2006 VS. 2005  Increase(Decrease)(millions)Nonregulated retail energy marketing operations(1)

$
39Regulated operations:Depreciation, depletion and amortization expense


12Weather


(26
)Interest expense


(17
)Other margins(2)


(10
)Other


2Change in net income contribution

$
  (1)
Higher average margins for electric and gas sales due to higher contracted sales rates, increased natural gas customers and lower commodity costs. (2)
Reflects reduced customer usage at our regulated gas distribution operations, due in part to price sensitivity. Energy Presented below are operating statistics related to our Energy operations:  Year Ended December 31,

2006

2005

% ChangeGas transportation throughput (bcf)

650

794

(18
)


Presented below, on an after-tax basis, are the key factors impacting Energys net income contribution: 2006 VS. 2005  Increase(Decrease)(millions)Gas transmission:Other margins(1)

$
43Rate settlement(2)


(13
)Producer services(3)


10Other


(11
)Change in net income contribution

$
29 (1)
Higher margins primarily from extracted products and short-term transportation and storage opportunities. (2)
Represents lower natural gas transportation and storage revenue as a result of a rate settlement between Dominion Transmission, Inc., and its customers, effective July 1, 2005. (3)
Higher income resulting from the impact of favorable price changes on natural gas marketing and aggregation activities associated with certain transportation and storage contracts. E&P Presented below are operating statistics
related to our E&P operations:  Year Ended December 31,

2006

2005

% ChangeGas production (bcf)


263


232

13Oil production (million bbls)


24


14

71Average realized prices without hedging results:Gas (per mcf)(1)

$
6.73

$
8.11

(17
)Oil (per bbl)


55.06


50.30

9Average realized prices with hedging results:Gas (per mcf)(1)


4.51


5.03

(10
)Oil (per bbl)


32.75


29.65

10DD&A (unit of production rate per mcfe)

$
1.78

$
1.50

19Average production (lifting) cost (per mcfe)


1.08


1.04

4 bbl = barrel mcf = thousand cubic feet mcfe = thousand cubic feet equivalent (1)
Excludes $160 million and $227 million of revenue recognized in 2006 and 2005, respectively, under the volumetric production payment agreements described in Note 10 in our Consolidated
Financial Statements. Presented below, on an after-tax basis, are the key factors impacting E&Ps net income
contribution: 2006 VS. 2005  Increase(Decrease)(millions)Gas and oilproduction(1)

$
411Business interruption insurance


62Operations and maintenance(2)


45Gas and oilprices


(213
)Depreciation, depletion and amortization


(166
)Interest expense


(42
)Income tax adjustments(3)


(23
)Other


5Change in net income contribution

$
79  (1)
Represents an increase primarily in Gulf of Mexico deepwater and shelf gas and oil production and Rocky Mountain gas production.




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(2)
Reflects 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 expense. (3)
Reflects the enactment of the Texas margins tax 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
December 31, 2006 by applicable time period:  Natural Gas

OilYear

Hedgedproduction(bcf)

Averagehedgeprice(per mcf)

Hedgedproduction(millionbbls)

Averagehedgeprice(per bbl)2007

195.5

$
5.91

10.0

$
33.412008

151.2


8.26

5.0


49.362009

25.5


8.09

0.3


75.36 Corporate Presented
below are the Corporate segments after-tax results:  Year Ended December 31,

2006


2005(millions)Specific items attributable to operating segments

$
(146
)

$
(373
)Armstrong discontinued operations


(59
)


Other corporate operations


(50
)


6Total net expense

$
(255
)

$
(367
) Specific Items Attributable to Operating Segments Corporate includes specific items attributable to our primary operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or allocating
resources among segments. See Note 25 to our Consolidated Financial Statements for a discussion of these items. Armstrong Discontinued Operations In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell Armstrong, our natural gas-fired
merchant generation peaking facility. The sale is expected to close by the end of the first quarter of 2007, pending regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. Due to the pending sale of this facility,
we recorded a $92 million ($59 million after-tax) loss from the discontinued operations of this facility, which included: n


$86 million ($56 million after-tax) associated with the impairment of the merchant generation facility; and n


$6 million ($3 million after-tax) of operating losses from the normal course of business. On February 27, 2007, an affiliate acquired from Armstrong, a majority equity interest in exchange for a reduction in net amounts owed to the affiliate of
approximately $207 million. Immediately following this transaction, we sold our remaining minority interest in Armstrong to the affiliate. Other Corporate
Operations The net expenses associated with other corporate operations for 2006 increased by $56 million as compared to 2005, primarily reflecting tax
adjustments associated with the pending sale of Peoples and Hope as discussed in Note 7 to our Consolidated Financial Statements.


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 December 31, 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.  GrossCreditExposure

CreditCollateral

NetCreditExposure(millions)Investment grade(1)

$
368

$
4

$
364Non-investment grade(2)


45





45No external ratings:Internally ratedinvestment grade(3)


29





29Internally ratednon-investment grade(4)


134





134Total

$
576

$
4

$
572  (1)
Designations as investment grade are based on minimum credit ratings assigned by Moodys Investors Service (Moodys) and Standard & Poors Ratings Services
(Standard & Poors). The five largest counterparty exposures, combined, for this category represented approximately 34% of the total net credit exposure. (2)
The five largest counterparty exposures, combined, for this category represented approximately 4% of the total net credit exposure. (3)
The five largest counterparty exposures, combined, for this category represented approximately 4% of the total net credit exposure. (4)
The five largest counterparty exposures, combined, for this category represented approximately 7% of the total net credit exposure. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The matters discussed in this Item may contain
forward-looking statements as described in the introductory paragraphs under Item 7. MD&A of this Form 10-K. The readers attention is directed to those paragraphs and Item 1A. Risk Factors, for discussion of various
risks and uncertainties that may affect our future. MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT Our financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices and
interest rates as described below. Commodity price risk is present in our gas and oil production and procurement operations and energy marketing operations due to the exposure to market shifts in prices received and paid for natural gas, oil,
electricity and other commodities. We use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk generally is related to our outstanding debt. The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected
time period due to a 10% unfavorable change in commodity prices and interest rates.




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Commodity Price Risk We manage the price risk associated with purchases and
sales of natural gas, oil, electricity and other commodities using commodity-based financial derivative instruments, including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of our commodity-based financial
derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and
volatility are principally determined based on actively-quoted market prices. A hypothetical 10% unfavorable change in commodity prices
would have resulted in a decrease of approximately $383 million and $519 million in the fair value of our commodity-based financial derivative instruments as of December 31, 2006 and 2005, respectively. The impact of a change in energy commodity prices on our commodity-based financial derivative instruments at a point in time is not necessarily
representative of the results that will be realized when such contracts are ultimately settled. Net losses from derivative commodity instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged
transaction, such as revenue from sales. Interest Rate Risk We
manage our interest rate risk exposure predominantly by maintaining a balance of fixed and variable-rate debt. We also enter into interest rate sensitive derivatives, including interest rate swap agreements and interest rate lock agreements. For
financial instruments outstanding at December 31, 2006, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $12 million. A hypothetical 10% increase in market interest
rates, as determined at December 31, 2005, would have resulted in a decrease in annual earnings of approximately $8 million.


Investment Price Risk We sponsor employee pension and other postretirement benefit plans and participate in plans sponsored by Dominion that hold investments in trusts to fund benefit
payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in our recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed by
us to the employee benefit plans. Risk Management Policies We
have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk
management policies of all subsidiaries, including the Company. Dominion maintains credit policies that include the evaluation of a prospective counterpartys financial condition, collateral requirements where deemed necessary, and the use of
standardized agreements which facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on Dominions credit
policies and our December 31, 2006 provision for credit losses, management believes that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of counterparty
nonperformance.




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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



INDEX



|                                                                                                                                                 |  |         
|------------------------------------------------------------------------------------------------------------------------------------------------ |  | --------
|                                                                                                                                                 |  | Page No.
|Report of Managements Responsibilities                                                                                                          |  | 21      
|Report of Independent Registered Public Accounting Firm                                                                                          |  | 22      
|Consolidated Statements of Income for the years ended December 31, 2006, 2005 and 2004                                                           |  | 23      
|Consolidated Balance Sheets at December 31, 2006 and 2005                                                                                        |  | 24      
|Consolidated Statements of Common Shareholders Equity and Comprehensive Income at December 31, 2006, 2005 and 2004 and for the years then ended |  | 26      
|Consolidated Statements of Cash Flows for the years ended December 31, 2006, 2005 and 2004                                                       |  | 27      
|Notes to Consolidated Financial Statements                                                                                                       |  | 28      



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REPORT OF MANAGEMENTS RESPONSIBILITIES



Because
we are not an accelerated filer as defined in Exchange Act Rule 12b-2, we are not required to comply with Securities and Exchange Commission rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 until December 31, 2007.

Our management is responsible for all information and representations contained in the Consolidated Financial Statements and other sections
of our annual report on Form 10-K. Our Consolidated Financial Statements, which include amounts based on estimates and judgments of management, have been prepared in conformity with accounting principles generally accepted in the United States of
America. Other financial information in the Form 10-K is consistent with that in our Consolidated Financial Statements.

Management
maintains a system of internal controls designed to provide reasonable assurance, at a reasonable cost, that our assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance
with established procedures. Management recognizes the inherent limitations of any system of internal control and, therefore, cannot provide absolute assurance that the objectives of the established internal controls will be met. This system
includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel, and internal audits. Management believes that during 2006 the system of
internal control was adequate to accomplish the intended objectives.

Our Consolidated Financial Statements have been audited by
Deloitte & Touche LLP, independent registered public accounting firm, who have been engaged by Dominions Audit Committee which is composed entirely of independent directors. Deloitte & Touche LLPs audit was conducted in
accordance with the standards of the Public Company Accounting Oversight Board (United States).

The Board of Directors also serves as our
Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal accounting control and financial reporting matters and to ensure that each is properly
discharging its responsibilities.

Management recognizes its responsibility for fostering a strong ethical climate so that our affairs are
conducted according to the highest standards of personal corporate conduct. This responsibility is characterized and reflected in our code of ethics, which addresses potential conflicts of interest, compliance with all domestic and foreign laws, the
confidentiality of proprietary information and full disclosure of public information.

February 28, 2007



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Shareholder of

Consolidated Natural Gas Company

Richmond, Virginia

We have audited the accompanying consolidated balance sheets of Consolidated Natural Gas Company (a
wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (the Company) as of December 31, 2006 and 2005, and the related consolidated statements of income, common shareholders equity and comprehensive income, and
of cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based
on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Companys internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Consolidated
Natural Gas Company and subsidiaries as of December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles
generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, the Company changed
its methods of accounting to adopt new accounting standards for pension and other postretirement benefit plans and purchases and sales of inventory with the same counterparty in 2006, and for conditional asset retirement obligations in 2005.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 28, 2007



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CONSOLIDATED STATEMENTS OF INCOME



|                                                                                             |  |      |       |   |      |   |       |      |  |   |      
|-------------------------------------------------------------------------------------------- |  | ---- | ----- | - | ---- | - | ----- | ---- |  | - | -----
|Year Ended December 31,                                                                      |  | 2006 |       |   | 2005 |   |       | 2004
|(millions)                                                                                   |  |      |       |   |      |   |       |     
|Operating Revenue                                                                            |  |      |       |   |      |   |       |      |  |   |      
|External customers                                                                           |  | $    | 7,125 |   |      | $ | 6,871 |      |  | $ | 5,489
|Affiliated customers                                                                         |  |      | 517   |   |      |   | 1,162 |      |  |   | 1,049
|Total operating revenue                                                                      |  |      | 7,642 |   |      |   | 8,033 |      |  |   | 6,538
|Operating Expenses                                                                           |  |      |       |   |      |   |       |      |  |   |      
|Purchased gas:                                                                               |  |      |       |   |      |   |       |      |  |   |      
|External suppliers                                                                           |  |      | 2,218 |   |      |   | 3,104 |      |  |   | 2,283
|Affiliated suppliers                                                                         |  |      | 644   |   |      |   | 678   |      |  |   | 527  
|Electric energy purchases:                                                                   |  |      |       |   |      |   |       |      |  |   |      
|External suppliers                                                                           |  |      | 126   |   |      |   | 132   |      |  |   | 153  
|Affiliated suppliers                                                                         |  |      | 101   |   |      |   | 187   |      |  |   | 171  
|Other energy-related commodity purchases                                                     |  |      | 413   |   |      |   | 363   |      |  |   | 273  
|Other operations and maintenance:                                                            |  |      |       |   |      |   |       |      |  |   |      
|External suppliers                                                                           |  |      | 1,007 |   |      |   | 1,405 |      |  |   | 619  
|Affiliated suppliers                                                                         |  |      | 212   |   |      |   | 142   |      |  |   | 161  
|Depreciation, depletion and amortization                                                     |  |      | 906   |   |      |   | 663   |      |  |   | 620  
|Other taxes                                                                                  |  |      | 293   |   |      |   | 302   |      |  |   | 270  
|Total operating expenses                                                                     |  |      | 5,920 |   |      |   | 6,976 |      |  |   | 5,077
|Income from operations                                                                       |  |      | 1,722 |   |      |   | 1,057 |      |  |   | 1,461
|Other income                                                                                 |  |      | 26    |   |      |   | 30    |      |  |   | 55   
|Interest and related charges:                                                                |  |      |       |   |      |   |       |      |  |   |      
|Interest expense                                                                             |  |      | 262   |   |      |   | 199   |      |  |   | 151  
|Interest expensejunior subordinated notes payable to affiliated trust                       |  |      | 16    |   |      |   | 16    |      |  |   | 16   
|Total interest and related charges                                                           |  |      | 278   |   |      |   | 215   |      |  |   | 167  
|Income from continuing operations before income tax expense                                  |  |      | 1,470 |   |      |   | 872   |      |  |   | 1,349
|Income tax expense                                                                           |  |      | 638   |   |      |   | 317   |      |  |   | 482  
|Income from continuing operations before cumulative effect of change in accounting principle |  |      | 832   |   |      |   | 555   |      |  |   | 867  
|Loss from discontinued operations (net of income tax benefit of $33)                         |  |      | (59   | ) |      |   |      |      |  |   |     
|Cumulative effect of change in accounting principle (net of income tax benefit of $1)        |  |      |      |   |      |   | (2    | )    |  |   |     
|Net Income                                                                                   |  | $    | 773   |   |      | $ | 553   |      |  | $ | 867  

The accompanying notes are an integral part of our Consolidated Financial Statements.



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CONSOLIDATED BALANCE SHEETS



|                                                                           |  |      |        |   |      |   |        |  
|-------------------------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | -
|At December 31,                                                            |  | 2006 |        |   | 2005 |  
|(millions)                                                                 |  |      |        |   |      |  
|                                                                           |  |     
|ASSETS                                                                     |  |      |        |   |      |   |        |  
|Current Assets                                                             |  |      |        |   |      |   |        |  
|Cash and cash equivalents                                                  |  | $    | 28     |   |      | $ | 44     |  
|Customer receivables (less allowance for doubtful accounts of $17 and $27) |  |      | 1,096  |   |      |   | 1,502  |  
|Affiliated receivables                                                     |  |      | 127    |   |      |   | 214    |  
|Other receivables                                                          |  |      | 130    |   |      |   | 110    |  
|Inventories:                                                               |  |      |        |   |      |   |        |  
|Materials and supplies                                                     |  |      | 26     |   |      |   | 29     |  
|Gas stored                                                                 |  |      | 222    |   |      |   | 337    |  
|Derivative assets                                                          |  |      | 714    |   |      |   | 1,991  |  
|Assets held for sale                                                       |  |      | 1,236  |   |      |   | 2      |  
|Deferred income taxes                                                      |  |      | 225    |   |      |   | 510    |  
|Prepayments                                                                |  |      | 77     |   |      |   | 122    |  
|Other                                                                      |  |      | 269    |   |      |   | 567    |  
|Total current assets                                                       |  |      | 4,150  |   |      |   | 5,428  |  
|Investments                                                                |  |      |        |   |      |   |        |  
|Investments in affiliates                                                  |  |      | 161    |   |      |   | 208    |  
|Other                                                                      |  |      | 106    |   |      |   | 97     |  
|Total investments                                                          |  |      | 267    |   |      |   | 305    |  
|Property, Plant and Equipment                                              |  |      |        |   |      |   |        |  
|Property, plant and equipment                                              |  |      | 20,146 |   |      |   | 19,126 |  
|Accumulated depreciation, depletion and amortization                       |  |      | (7,420 | ) |      |   | (6,780 | )
|Total property, plant and equipment, net                                   |  |      | 12,726 |   |      |   | 12,346 |  
|Deferred Charges and Other Assets                                          |  |      |        |   |      |   |        |  
|Goodwill                                                                   |  |      | 623    |   |      |   | 623    |  
|Pension and other postretirement benefit assets                            |  |      | 1,317  |   |      |   | 1,086  |  
|Derivative assets                                                          |  |      | 309    |   |      |   | 1,403  |  
|Intangible assets                                                          |  |      | 125    |   |      |   | 130    |  
|Regulatory assets                                                          |  |      | 147    |   |      |   | 403    |  
|Other                                                                      |  |      | 139    |   |      |   | 178    |  
|Total deferred charges and other assets                                    |  |      | 2,660  |   |      |   | 3,823  |  
|Total assets                                                               |  | $    | 19,803 |   |      | $ | 21,902 |  

The accompanying notes are an integral part of our Consolidated Financial Statements.



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|                                                            |  |      |        |   |      |   |        |  
|----------------------------------------------------------- |  | ---- | ------ | - | ---- | - | ------ | -
|At December 31,                                             |  | 2006 |        |   | 2005 |  
|(millions)                                                  |  |      |        |   |      |  
|                                                            |  |     
|LIABILITIES AND SHAREHOLDERS EQUITY                        |  |      |        |   |      |   |        |  
|Current Liabilities                                         |  |      |        |   |      |   |        |  
|Securities due within one year                              |  | $    | 199    |   |      | $ | 734    |  
|Short-term debt                                             |  |      | 752    |   |      |   | 187    |  
|Accounts payable                                            |  |      | 1,175  |   |      |   | 1,438  |  
|Payables to affiliates                                      |  |      | 151    |   |      |   | 151    |  
|Affiliated current borrowings                               |  |      | 2,473  |   |      |   | 1,922  |  
|Accrued interest, payroll and taxes                         |  |      | 256    |   |      |   | 250    |  
|Derivative liabilities                                      |  |      | 1,296  |   |      |   | 3,731  |  
|Liabilities held for sale                                   |  |      | 480    |   |      |   |       |  
|Other                                                       |  |      | 332    |   |      |   | 489    |  
|Total current liabilities                                   |  |      | 7,114  |   |      |   | 8,902  |  
|Long-Term Debt                                              |  |      |        |   |      |   |        |  
|Long-term debt                                              |  |      | 2,506  |   |      |   | 2,708  |  
|Junior subordinated notes payable to affiliated trust       |  |      | 206    |   |      |   | 206    |  
|Total long-term debt                                        |  |      | 2,712  |   |      |   | 2,914  |  
|Deferred Credits and Other Liabilities                      |  |      |        |   |      |   |        |  
|Deferred income taxes and investment tax credits            |  |      | 3,049  |   |      |   | 2,321  |  
|Asset retirement obligations                                |  |      | 399    |   |      |   | 392    |  
|Derivative liabilities                                      |  |      | 357    |   |      |   | 2,706  |  
|Regulatory liabilities                                      |  |      | 137    |   |      |   | 147    |  
|Other                                                       |  |      | 170    |   |      |   | 229    |  
|Total deferred credits and other liabilities                |  |      | 4,112  |   |      |   | 5,795  |  
|Total liabilities                                           |  |      | 13,938 |   |      |   | 17,611 |  
|Commitments and Contingencies (see Note 20)                 |  |      |        |   |      |   |        |  
|Common Shareholders Equity                                 |  |      |        |   |      |   |        |  
|Common stock, no par, 100 shares authorized and outstanding |  |      | 1,816  |   |      |   | 1,816  |  
|Other paid-in capital                                       |  |      | 3,274  |   |      |   | 3,273  |  
|Retained earnings                                           |  |      | 1,069  |   |      |   | 971    |  
|Accumulated other comprehensive loss                        |  |      | (294   | ) |      |   | (1,769 | )
|Total common shareholders equity                           |  |      | 5,865  |   |      |   | 4,291  |  
|Total liabilities and shareholders equity                  |  | $    | 19,803 |   |      | $ | 21,902 |  



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CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS EQUITY AND COMPREHENSIVE INCOME



|                                                                             |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|---------------------------------------------------------------------------- |  | ------------ |  | ------------------- | ----- | ---------------- | - | ----- | ------------------------------------------ | - | ----- | ----- |  | - | ------ | - |  | - | ------ | -
|                                                                             |  | Common Stock |  | OtherPaid-InCapital |       | RetainedEarnings |   |       | AccumulatedOtherComprehensiveIncome (Loss) |   |       | Total | 
|                                                                             |  | Shares       |  | Amount              |       |                  |   |      
|(millions, except for shares)                                                |  |              |  |                     |       |                  |   |       |                                           
|Balance at December 31, 2003                                                 |  | 100          |  | $                   | 1,816 |                  | $ | 2,478 |                                            | $ | 608   |       |  | $ | (537   | ) |  | $ | 4,365  |  
|Comprehensive income:                                                        |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net income                                                                   |  |              |  |                     |       |                  |   |       |                                            |   | 867   |       |  |   |        |   |  |   | 867    |  
|Foreign currency translation adjustments                                     |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 11     |   |  |   | 11     |  
|Net deferred derivative losseshedging activities, net of $431 tax benefit   |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | (744   | ) |  |   | (744   | )
|Amounts reclassified to net income:                                          |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net derivative losseshedging activities, net of $269 tax benefit            |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 465    |   |  |   | 465    |  
|Foreign currency translation adjustments(1)                                  |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | (44    | ) |  |   | (44    | )
|Total comprehensive income                                                   |  |              |  |                     |       |                  |   |       |                                            |   | 867   |       |  |   | (312   | ) |  |   | 555    |  
|Equity contribution by parent                                                |  |              |  |                     |       |                  |   | 41    |                                            |   |       |       |  |   |        |   |  |   | 41     |  
|Tax benefit from stock awards and stock options exercised                    |  |              |  |                     |       |                  |   | 1     |                                            |   |       |       |  |   |        |   |  |   | 1      |  
|Dividends                                                                    |  |              |  |                     |       |                  |   |       |                                            |   | (482  | )     |  |   |        |   |  |   | (482   | )
|Balance at December 31, 2004                                                 |  | 100          |  |                     | 1,816 |                  |   | 2,520 |                                            |   | 993   |       |  |   | (849   | ) |  |   | 4,480  |  
|Comprehensive income:                                                        |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net income                                                                   |  |              |  |                     |       |                  |   |       |                                            |   | 553   |       |  |   |        |   |  |   | 553    |  
|Net deferred derivative losseshedging activities, net of $1,053 tax benefit |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | (1,842 | ) |  |   | (1,842 | )
|Amounts reclassified to net income:                                          |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net derivative losseshedging activities, net of $529 tax benefit            |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 922    |   |  |   | 922    |  
|Total comprehensive income (loss)                                            |  |              |  |                     |       |                  |   |       |                                            |   | 553   |       |  |   | (920   | ) |  |   | (367   | )
|Equity contribution by parent                                                |  |              |  |                     |       |                  |   | 750   |                                            |   |       |       |  |   |        |   |  |   | 750    |  
|Tax benefit from stock awards and stock options exercised                    |  |              |  |                     |       |                  |   | 3     |                                            |   |       |       |  |   |        |   |  |   | 3      |  
|Dividends                                                                    |  |              |  |                     |       |                  |   |       |                                            |   | (575  | )     |  |   |        |   |  |   | (575   | )
|Balance at December 31, 2005                                                 |  | 100          |  |                     | 1,816 |                  |   | 3,273 |                                            |   | 971   |       |  |   | (1,769 | ) |  |   | 4,291  |  
|Comprehensive income:                                                        |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net income                                                                   |  |              |  |                     |       |                  |   |       |                                            |   | 773   |       |  |   |        |   |  |   | 773    |  
|Net deferred derivative gainshedging activities, net of $364 tax expense    |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 641    |   |  |   | 641    |  
|Amounts reclassified to net income:                                          |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   |        |   |  |   |        |  
|Net derivative losseshedging activities, net of $440 tax benefit            |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 762    |   |  |   | 762    |  
|Total comprehensive income                                                   |  |              |  |                     |       |                  |   |       |                                            |   | 773   |       |  |   | 1,403  |   |  |   | 2,176  |  
|Tax benefit from stock awards and stock options exercised                    |  |              |  |                     |       |                  |   | 1     |                                            |   |       |       |  |   |        |   |  |   | 1      |  
|Adjustment to initially adopt SFAS No. 158, net of $42 tax expense           |  |              |  |                     |       |                  |   |       |                                            |   |       |       |  |   | 72     |   |  |   | 72     |  
|Dividends                                                                    |  |              |  |                     |       |                  |   |       |                                            |   | (675  | )     |  |   |        |   |  |   | (675   | )
|Balance at December 31, 2006                                                 |  | 100          |  | $                   | 1,816 |                  | $ | 3,274 |                                            | $ | 1,069 |       |  | $ | (294   | ) |  | $ | 5,865  |  



|(1) | Reclassified to earnings due to the sale of CNG International investments.
|--- | --------------------------------------------------------------------------

The accompanying
notes are an integral part of our Consolidated Financial Statements.



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CONSOLIDATED STATEMENTS OF CASH FLOWS



|                                                                                                 |  |      |        |   |      |   |        |      |  |   |        |  
|------------------------------------------------------------------------------------------------ |  | ---- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|Year Ended December 31,                                                                          |  | 2006 |        |   | 2005 |   |        | 2004 | 
|(millions)                                                                                       |  |      |        |   |      |   |        |      | 
|Operating Activities                                                                             |  |      |        |   |      |   |        |      |  |   |        |  
|Net income                                                                                       |  | $    | 773    |   |      | $ | 553    |      |  | $ | 867    |  
|Adjustments to reconcile net income to net cash from operating activities:                       |  |      |        |   |      |   |        |      |  |   |        |  
|Depreciation, depletion and amortization                                                         |  |      | 906    |   |      |   | 670    |      |  |   | 627    |  
|Deferred income taxes and investment tax credits, net                                            |  |      | 387    |   |      |   | 295    |      |  |   | 398    |  
|Net realized and unrealized derivative (gains)/losses                                            |  |      | (204   | ) |      |   | 162    |      |  |   | (133   | )
|Charges related to pending sale of gas distribution subsidiaries                                 |  |      | 183    |   |      |   |       |      |  |   |       |  
|Impairment of merchant generation peaking facility                                               |  |      | 86     |   |      |   |       |      |  |   |       |  
|Other adjustments to net income                                                                  |  |      | (11    | ) |      |   | (7     | )    |  |   | (52    | )
|Changes in :                                                                                     |  |      |        |   |      |   |        |      |  |   |        |  
|Accounts receivable                                                                              |  |      | 234    |   |      |   | (487   | )    |  |   | (265   | )
|Affiliated accounts receivable and payable                                                       |  |      | 127    |   |      |   | (49    | )    |  |   | 208    |  
|Inventories                                                                                      |  |      | 63     |   |      |   | (144   | )    |  |   | 16     |  
|Deferred purchased gas costs, net                                                                |  |      | 140    |   |      |   | (133   | )    |  |   | 2      |  
|Pension and other postretirement benefit assets                                                  |  |      | (109   | ) |      |   | (102   | )    |  |   | (112   | )
|Accounts payable                                                                                 |  |      | (228   | ) |      |   | 419    |      |  |   | 294    |  
|Accrued interest, payroll and taxes                                                              |  |      | 36     |   |      |   | 24     |      |  |   | 57     |  
|Deferred revenue                                                                                 |  |      | (160   | ) |      |   | (227   | )    |  |   | (223   | )
|Margin deposit assets and liabilities                                                            |  |      | (49    | ) |      |   | 194    |      |  |   | (29    | )
|Other operating assets and liabilities                                                           |  |      | 69     |   |      |   | (188   | )    |  |   | (37    | )
|Net cash provided by operating activities                                                        |  |      | 2,243  |   |      |   | 980    |      |  |   | 1,618  |  
|Investing Activities                                                                             |  |      |        |   |      |   |        |      |  |   |        |  
|Additions to gas and oil properties, including acquisitions                                      |  |      | (1,874 | ) |      |   | (1,508 | )    |  |   | (1,168 | )
|Plant construction and other property additions                                                  |  |      | (435   | ) |      |   | (423   | )    |  |   | (378   | )
|Proceeds from sales of gas and oil properties                                                    |  |      | 360    |   |      |   | 93     |      |  |   | 413    |  
|Acquisition of business, net of cash acquired                                                    |  |      | (91    | ) |      |   | (43    | )    |  |   |       |  
|Other                                                                                            |  |      | 74     |   |      |   | (19    | )    |  |   | 47     |  
|Net cash used in investing activities                                                            |  |      | (1,966 | ) |      |   | (1,900 | )    |  |   | (1,086 | )
|Financing Activities                                                                             |  |      |        |   |      |   |        |      |  |   |        |  
|Issuance of long-term debt                                                                       |  |      |       |   |      |   |       |      |  |   | 400    |  
|Repayment of long-term debt                                                                      |  |      | (500   | ) |      |   | (150   | )    |  |   | (489   | )
|Issuance of short-term borrowings from affiliates, net                                           |  |      | 317    |   |      |   | 1,477  |      |  |   | 168    |  
|Issuance (repayment) of short-term debt, net                                                     |  |      | 565    |   |      |   | 187    |      |  |   | (151   | )
|Common dividend payments                                                                         |  |      | (675   | ) |      |   | (575   | )    |  |   | (482   | )
|Other                                                                                            |  |      | 4      |   |      |   | 6      |      |  |   | 2      |  
|Net cash provided by (used in) financing activities                                              |  |      | (289   | ) |      |   | 945    |      |  |   | (552   | )
|Increase (decrease) in cash and cash equivalents                                                 |  |      | (12    | ) |      |   | 25     |      |  |   | (20    | )
|Cash and cash equivalents at beginning of year                                                   |  |      | 44     |   |      |   | 19     |      |  |   | 39     |  
|Cash and cash equivalents at end of year(1)                                                      |  | $    | 32     |   |      | $ | 44     |      |  | $ | 19     |  
|Supplemental Cash Flow Information                                                               |  |      |        |   |      |   |        |      |  |   |        |  
|Cash paid during the year for:                                                                   |  |      |        |   |      |   |        |      |  |   |        |  
|Interest and related charges, excluding capitalized amounts                                      |  | $    | 300    |   |      | $ | 229    |      |  | $ | 191    |  
|Income taxes                                                                                     |  |      | 131    |   |      |   | 153    |      |  |   | 14     |  
|Noncash investing and financing activities:                                                      |  |      |        |   |      |   |        |      |  |   |        |  
|Issuance of affiliated short-term note payable in exchange for repayment oflong-term debt        |  |      | 234    |   |      |   |       |      |  |   |       |  
|Accrued capital expenditures                                                                     |  |      | 208    |   |      |   | 156    |      |  |   | 86     |  
|Conversion of short-term borrowings and other amounts payable to parent to other paid-in capital |  |      |       |   |      |   | 750    |      |  |   | 41     |  



|(1) | 2006 amount includes $4 million of cash classified as held for sale in our Consolidated Balance Sheet
|--- | -----------------------------------------------------------------------------------------------------

The accompanying notes are an integral part of our Consolidated Financial Statements.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



NOTE 1. NATURE OF OPERATIONS Consolidated Natural Gas Company (CNG) 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 December 31, 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 1.5 million residential and commercial gas and electric customer accounts in the Northeast, Mid-Atlantic and Midwest regions of the United States (U.S.). We operate an
interstate gas transmission pipeline system, underground natural gas storage system and gathering and extraction facilities in the Northeast, Mid-Atlantic and Midwest 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. Corporate also includes specific items attributable to our operating segments that are excluded from the profit measures evaluated by management in
assessing segment performance or allocating resources among segments. Our assets remain wholly owned by our legal subsidiaries. TheDeliverysegment includes our regulated gas distribution subsidiaries, The East Ohio Gas Company (East Ohio), The Peoples Natural Gas Company
(Peoples) and Hope Gas, Inc. (Hope), as well as our nonregulated marketing subsidiaries, Dominion Retail, Inc. and Dominion Products and Services, Inc. Our regulated gas distribution subsidiaries are subject to price regulation by their respective
state utility commissions. Our nonregulated marketing subsidiaries pursue opportunities arising from the deregulation of the energy industry at the retail level. TheEnergysegment includes Dominion Transmission, Inc. (DTI), Dominion Cove Point LNG, LP (DCP) and Dominion
Field Services, Inc. (DFS). DTI operates a regional interstate pipeline and storage system and is regulated by the Federal Energy Regulatory Commission (FERC). DCP operates an LNG import and storage facility and is also regulated by FERC. DFS is a
nonregulated subsidiary engaged in the aggregation of gas supply and related wholesale activities. TheE&Psegment includes Dominion Exploration & Production, Inc. (DEPI) and Dominion Oklahoma Texas Exploration & Production, Inc. (DOTEPI). These subsidiaries
explore for, develop and produce gas and oil. 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, CNG, one of CNGs consolidated subsidiaries or operating segments, or the entirety of CNG and its consolidated
subsidiaries.


NOTE 2. SIGNIFICANT ACCOUNTING POLICIES General We make certain estimates and assumptions in preparing our Consolidated Financial Statements in accordance with accounting principles generally accepted in the United
States of America (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 revenues and
expenses for the periods presented. Actual results may differ from those estimates. Our 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. Certain amounts in the 2005 and 2004 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2006 presentation. Operating Revenue Operating revenue is recorded on the basis of
services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. Our customer receivables at December 31, 2006 and 2005 included $34 million and $133 million, respectively, of accrued unbilled
revenue based on estimated amounts of natural gas delivered but not yet billed to our utility customers. We estimate unbilled utility revenue based on historical usage, applicable customer rates and weather factors. The primary types of sales and service activities reported as operating revenue include: n


Regulated gas salesconsist primarily of state-regulated
retail natural gas sales and related distribution services; n


Nonregulated gas salesconsist primarily of sales of natural
gas at market-based rates and contracted fixed prices, sales of gas purchased from third parties and other gas marketing activities and sales activity related to agreements used to facilitate the marketing of gas production (buy/sell arrangements)
described in Note 3; n


Nonregulated electric salesconsist primarily of sales of
electricity to residential and commercial customers at contracted fixed prices and market-based rates; n


Other energy related-commodity salesconsist primarily of
sales of extracted products and sales activity related to agreements used to facilitate the marketing of oil production (buy/sell arrangements) described in Note 3; n


Gas transportation and storageconsists primarily of
regulated sales of gathering, transmission, distribution and storage services. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; n


Gas and oil productionrevenue is recognized based on actual
volumes of gas and oil sold to purchasers. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed. Gas and oil production revenue includes sales of Company produced gas, oil,
condensate and the recognition of revenue previously deferred in connection with the volumetric production payment (VPP) transactions described in Note 10. Gas and oil production revenue is reported net of royalties. The Company uses the sales
method of accounting for gas imbalances. An imbalance


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is created when Company volumes of gas sold pertaining to a property do not equate to the volumes the Company is entitled to based on its interest in the
property. A liability is recognized when the Companys excess sales over entitled volumes exceeds the Companys net remaining property reserves; and n


Other revenueconsists primarily of miscellaneous service
revenue from gas distribution operations; gas and oil processing and handling revenue; and business interruption insurance revenue associated with delayed gas and oil production caused by hurricanes. Purchased GasDeferred Costs Where permitted by regulatory authorities,
the differences between actual purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period recovery is
recognized as a regulatory asset, while the recovery in excess of current period expenses is recognized as a regulatory liability. Income Taxes We file a consolidated federal income tax return and participate in an intercompany tax allocation agreement with Dominion and its subsidiaries. Our current income taxes
are based on our taxable income or loss, determined on a separate company basis. However, prior to the repeal, effective in 2006, of the Public Utility Holding Company Act of 1935 (the 1935 Act), cash payments to Dominion were limited. Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, requires an asset and liability approach to accounting
for income taxes. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Where permitted by
regulatory authorities, the treatment of temporary differences may differ from the requirements of SFAS No. 109. Accordingly, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax
liabilities. We establish a valuation allowance when it is more likely than not that all or a portion of a deferred tax asset will not be realized. Deferred investment tax credits are amortized over the service lives of the properties giving rise to
the credits. At December 31, 2006, our Consolidated Balance Sheet included $18 million of prepaid federal income taxes (recorded in
prepayments), $8 million of federal income taxes receivable from Dominion (recorded in deferred charges and other assets) and $19 million of state income taxes payable to Dominion (recorded in accrued interest, payroll and taxes). At December 31,
2005, our Consolidated Balance Sheet included $52 million of prepaid federal income taxes (recorded in prepayments), $30 million of federal income taxes receivable from Dominion (recorded in deferred charges and other assets) and $9 million of state
income taxes payable to Dominion (recorded in accrued interest, payroll and taxes). Cash and Cash Equivalents Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2006 and 2005, accounts payable
included $70 million and $85 million, respectively, of checks outstanding but not yet presented for payment. For purposes of our Consolidated Statements of Cash Flows, we consider cash and cash equivalents to include cash on hand, cash in banks and
temporary investments purchased with an original maturity of three months or less.


Inventories Materials and supplies inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in local gas distribution operations is valued
using the last-in-first-out (LIFO) method. Under the LIFO method, those inventories were valued at $8 million at December 31, 2006 and $128 million at December 31, 2005. The decrease in inventory from 2005 to 2006 reflects the sale of gas
storage inventory at East Ohio and the reclassification of the inventory of Peoples and Hope to assets held for sale. Based on the average price of gas purchased during 2006, the cost of replacing the current portion of stored gas inventory exceeded
the amount stated on a LIFO basis by approximately $211 million. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method. Gas Imbalances Natural gas imbalances occur when the physical amount of natural gas delivered from or received by a pipeline
system or storage facility differs from the contractual amount of natural gas delivered or received. We value these imbalances due to or from shippers and operators at an appropriate index price at period-end, subject to the terms of our tariff for
regulated entities. Imbalances are primarily settled in-kind. Imbalances due to us from other parties are reported in other current assets and imbalances that we owe to other parties are reported in other current liabilities on our Consolidated
Balance Sheets. Derivative Instruments We use derivative
instruments such as futures, swaps, forwards and options to manage the commodity and financial market risks of our business operations. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, requires all derivatives, except those for which an exception applies, to be reported on our Consolidated Balance Sheets at fair value. Derivative
contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair
value accountingnormal purchases and normal salesmay be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from
deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance. We hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent we do not hold offsetting positions for such derivatives, we believe these
instruments represent economic hedges that mitigate our exposure to fluctuations in commodity prices and interest rates. Statement of
Income Presentation: n


Financially-Settled DerivativesNot Held for Trading
Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements are presented in other operations and maintenance expense on a net basis. n


Physically-Settled DerivativesNot Held for Trading
Purposes and Not Designated as Hedging Instruments: All unrealized changes in fair value and settlements for physical derivative sales contracts are presented in revenues, while all


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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



unrealized changes in fair value and settlements for physical derivative purchase contracts are reported in expenses. We recognize revenue or expense from all non-derivative energy-related contracts on a gross basis at the time of contract performance, settlement or
termination. DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS We designate a substantial portion of our derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, we formally document the relationship between the hedging
instrument and the hedged item as well as the risk management objective and strategy for using the hedging instrument. We assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in
cash flows or fair values, both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is
recognized currently in earnings. Also, we may elect to exclude certain gains or losses on hedging instruments from the measurement of hedge effectiveness, such as gains or losses attributable to changes in the time value of options, thus requiring
that such changes be recorded currently in earnings. We discontinue hedge accounting prospectively for derivatives that cease to be highly effective hedges. Cash Flow HedgesA significant portion of our hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of natural gas, oil, electricity and other
energy-related products. We also use interest rate swaps to hedge our exposure to variable interest rates on long-term debt. For transactions in which we are hedging the variability of cash flows, changes in the fair value of the derivative are
reported in accumulated other comprehensive income (loss) (AOCI), to the extent effective at offsetting changes in the hedged item, until earnings are affected by the hedged item. For cash flow hedge transactions, we discontinue hedge accounting if
the occurrence of the forecasted transaction is determined to be no longer probable. We reclassify any derivative gains or losses reported in AOCI to earnings when the forecasted item is included in earnings, if it should occur, or earlier, if it
becomes probable that the forecasted transaction will not occur. Fair Value HedgesWe also use fair value hedges to mitigate
the fixed price exposure inherent in certain firm commodity commitments. In addition, we have designated interest rate swaps as fair value hedges to manage our interest rate exposure on certain fixed rate long-term debt. For fair value hedge
transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged items fair value. Statement of Income PresentationGains and losses on derivatives designated as hedges, when recognized, are included in operating revenue, operating expenses or interest and related charges in our
Consolidated Statements of Income. Specific line item classification is determined based on the nature of the risk underlying individual hedge strategies. The portion of gains or losses on hedging instruments determined to be ineffective and the
portion of gains or losses on hedging instruments excluded from the measurement of the hedging relationships effectiveness,


such as gains or losses attributable to changes in the time value of options, are included in other operations and maintenance expense. VALUATION METHODS Fair value is based on actively-quoted market prices, if available.
In the absence of actively-quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices
based on available historical and near-term future price information and certain statistical methods, including regression analysis. For options and contracts with option-like characteristics where pricing information is not available from external
sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. We use other option models under special circumstances,
including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts
with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment
is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contracts estimated fair value. Property, Plant and Equipment Property, plant and equipment, including
additions and replacements, is recorded at original cost, including labor, materials, asset retirement costs and other direct and indirect costs including capitalized interest. The cost of repairs and maintenance, including minor additions and
replacements, is charged to expense as incurred. In 2006, 2005 and 2004, we capitalized interest costs of $68 million, $57 million and $56 million, respectively. For gas utility and transmission property subject to cost-of-service rate regulation, the depreciable cost of such property, less salvage value, is charged to accumulated depreciation at retirement. Cost of removal
collections from utility customers and expenditures not representing asset retirement obligations (AROs) are recorded as regulatory liabilities or regulatory assets. We record gains and losses upon retirement of nonutility property based on the
difference between proceeds received, if any, and the propertys net book value at the retirement date. Depreciation of property,
plant and equipment is computed on the straight-line method based on projected service lives or in the case of gas and oil producing properties, the units-of-production method. Our depreciation rates on utility property, plant and equipment are as
follows:  2006

2005

2004(percent)Transmission

2.58

2.49

2.42Distribution

2.43

2.37

2.37Storage

3.10

3.15

3.04Gas gathering and processing

2.05

2.21

2.31General and other

6.84

6.89

6.85




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Our nonutility property, plant and equipment, excluding E&P properties, is depreciated using the straight-line method over estimated useful lives of 5 to
25 years. We follow the full cost method of accounting for gas and oil exploration and production activities prescribed by the Securities
and Exchange Commission (SEC). Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These 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 pricing adjusted for cash flow hedges in place. If net
capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. The ceiling test is performed separately for each cost center, with cost centers established
on a country-by-country basis. Approximately 8% 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 December 31, 2006. Future cash flows associated with settling AROs that have been accrued on our Consolidated Balance
Sheets pursuant to SFAS No.143, Accounting for Asset Retirement Obligations, are excluded from our calculations under the full cost ceiling test. Depletion of gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be
incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties, including associated exploration-related costs, are initially
excluded from the depletable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over terms of underlying leases. Once
a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would
significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost center. Goodwill and Intangible
Assets We evaluate goodwill for impairment annually, as of April 1, and whenever an event occurs or circumstances change in the interim that would more
likely than not reduce the fair value of a reporting unit below its carrying amount. Intangible assets with finite lives are amortized over their estimated useful lives or as consumed. Impairment of Long-Lived and Intangible Assets We perform an evaluation for impairment whenever events or changes in
circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to


fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount. Regulatory Assets and Liabilities For utility operations subject to federal or
state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of
current costs through future rates charged to customers, we defer these costs as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize regulatory liabilities when it is probable that regulators will
require customer refunds through future rates and when revenue is collected from customers for expenditures that are not yet incurred. Regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the
recovery period authorized by the regulator. Asset Retirement Obligations We recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities. These amounts are capitalized as costs of the related
tangible long-lived assets. Since relevant market information is not available, we estimate fair value using discounted cash flow analyses. We report the accretion of the AROs due to the passage of time in other operations and maintenance expense on
our Consolidated Statements of Income. Amortization of Debt Issuance Costs We defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. NOTE 3. NEWLY ADOPTED ACCOUNTING STANDARDS 2006 SFAS NO.158 Effective December 31, 2006, we adopted 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 its defined benefit pension and other postretirement benefit
plans as an asset or liability, respectively, in its balance sheet and to recognize changes in the funded status as a component of other comprehensive income in the year in which the changes occur. The funded status is measured as the difference
between the fair value of a plans assets and the 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 the
employers fiscal year, which we already do. Our adoption of SFAS No. 158 had no impact on our results of operations or cash
flows and it will not affect our operating results or cash flows in future periods.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



The following table illustrates the incremental effect of adopting the provisions of SFAS No. 158 in our Consolidated Balance Sheet at December 31, 2006:  Prior toAdoptingSFASNo. 158


Effect ofAdoptingSFASNo.
158

As
ReportedatDecember 31,2006(millions)Assets:Pension and other postretirement benefit assets

$
1,195


$
122

$
1,317Regulatory assets


131



16


147Liabilities:Deferred income taxes and investment tax credits


3,007



42


3,049Regulatory liabilities


124



13


137Other deferred credits and other liabilities


159



11


170Shareholders Equity:Accumulated other comprehensive loss


(366
)


72


(294
) Upon adoption, we recorded regulatory assets (liabilities), rather than an adjustment to AOCI, for
previously unrecognized pension and other postretirement benefit costs (credits) expected to be recovered (refunded) through future rates by certain of our rate-regulated subsidiaries. The adjustments to AOCI, regulatory assets and regulatory
liabilities at adoption of SFAS No. 158 represent the net unrecognized actuarial gains (losses), unrecognized prior service cost (credit) and unrecognized transition obligation remaining from our initial adoption of SFAS No. 106, Employers
Accounting for Postretirement Benefits Other Than Pensions, all of which were previously netted against the funded status of our plans in our Consolidated Balance Sheet. The amounts in AOCI, regulatory assets and regulatory liabilities will be
subsequently recognized as a component of net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Further, actuarial gains and losses that arise in subsequent periods and are not recognized as net periodic
benefit cost (credit) in the same periods will be recognized as a component of other comprehensive income (loss) or regulatory assets or regulatory liabilities as appropriate. Those amounts will be subsequently recognized as a component of net
periodic benefit cost (credit) on the same basis as the amounts recognized in AOCI, regulatory assets and regulatory liabilities at adoption of SFAS No. 158. 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. Our adoption of SAB 108 on December 31, 2006, had no impact on our Consolidated Financial Statements.


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 onshore marketing
locations 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 and modifications or renewals of existing arrangements made 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 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:  2006

2005

2004Sale activity included in operating revenue

$
577

$
633

$
437Purchase activity included in operating expenses(1)


579


655


440  (1)
Included in other energy-related commodity purchases expense and purchased gas expense on our Consolidated Statements of Income. 2005 FIN 47 We adopted FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47) on December 31, 2005. FIN 47 clarifies that an entity is required to recognize a liability for
the fair value of a conditional asset retirement obligation when the obligation is incurredgenerally upon acquisition, construction, or development and/or through the normal operation of the asset, if the fair value of the liability can be
reasonably estimated. A conditional asset retirement obligation is a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control
of the entity. Uncertainty about the timing and/or method of settlement is required to be factored into the measurement of the liability when sufficient information exists. Our adoption of FIN 47 resulted in the recognition of an after-tax charge of
$2 million, representing the cumulative effect of the change in accounting principle. Presented below are our pro forma net income as if we
had applied the provisions of FIN 47 as of January 1, 2004:  Year Ended December 31

2005

2004(millions)Net incomeas reported

$
553

$
867Net incomepro forma


555


866 If we had applied the provisions of FIN 47 as of January 1, 2004, our asset retirement
obligations would have increased by $122 million and $130 million as of January 1, 2004 and December 31, 2004, respectively.




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NOTE 4. RECENTLY ISSUED ACCOUNTING STANDARDS FIN 48 In July 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). Taking into consideration the uncertainty and
judgement involved in the determination and filing of income taxes, FIN 48 establishes standards for recognition and measurement, in the financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns.
Positions taken by an entity in its income tax returns that are recognized in its financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge
of all relevant information. Beginning in 2007, FIN 48 requires disclosures about positions taken by an entity in its tax returns that are
not recognized in its financial statements, descriptions of open tax years by major jurisdiction and reasonably possible significant changes in the amount of unrecognized tax benefits that could occur in the next twelve months. With the adoption of FIN 48, we estimate that the cumulative effect of the change in accounting principle will not have a material impact on the beginning
balance of our retained earnings as of January 1, 2007. 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 No. 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.


SFAS NO. 159 In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities.SFAS No. 159 provides an entity with the option, at specified election dates, to
measure certain financial assets and liabilities and other items at fair value, with changes in fair value recognized in earnings as those changes occur. SFAS No. 159 also establishes presentation and disclosure requirements that include displaying
the fair value of those assets and liabilities for which the entity elected the fair value option on the face of the balance sheet and providing managements reasons for electing the fair value option for each eligible item. The provisions of
SFAS No. 159 will become effective for us beginning January 1, 2008. Early adoption is permitted provided that an election is also made to apply the provisions of SFAS No. 157. We are currently evaluating the impact that SFAS No. 159 may have on our
results of operations and financial condition. NOTE 5. ACQUISITION Pablo
Energy, LLC In February 2006, we completed the acquisition of Pablo Energy, LLC for approximately $92 million in cash. Pablo holds producing and other
properties located in the Texas Panhandle area. The operations of Pablo are included in our E&P operating segment. Craton Energy Corp. In July 2005, we completed the acquisition of Craton Energy Corp. for approximately $45 million in cash. Cratons operations are focused on oil and gas property
acquisition and development in the eastern Texas region. The operations of Craton are included in our E&P operating segment. NOTE 6. OPERATING REVENUE Our operating revenue consists of the following:  Year Ended December 31,

2006

2005

2004(millions)Gas sales:Regulated

$
1,400

$
1,763

$
1,422Nonregulated:External customers


1,631


1,533


959Affiliated customers


494


1,129


1,027Nonregulated electric sales


304


334


357Other energy-related commodity sales


804


598


457Gas transportation and storage


953


923


819Gas and oil production


1,659


1,468


1,297Other


397


285


200Total operating revenue

$
7,642

$
8,033

$
6,538




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



NOTE 7. INCOME TAXES Details of income tax expense for continuing operations were as follows:  Year Ended December 31,

2006


2005


2004(millions)Current expense:Federal

$
175


$
12


$
72State


52



9



12Total current


227



21



84Deferred expense:Federal


365



267



395State


47



30



4Total deferred(1)


412



297



399Amortization of deferred investment tax credits


(1
)


(1
)


(1
)Total income tax expense

$
638


$
317


$
482  (1)
2006 includes a decrease of $34 million in federal and state valuation allowances and a net $16 million increase resulting from the enactment of the Texas margins tax. The statutory U.S. federal income tax rate reconciles to our effective income tax rate as follows:  Year Ended December 31,

2006


2005


2004U.S. statutory rate

35.0
%

35.0
%

35.0
%Recognition of deferred taxesstock of subsidiaries held for sale

7.1





State taxes, net of federal benefit

4.0


3.5


0.2Valuation allowance

(2.3
)

(0.6
)

2.2Employee benefits

(0.4
)

(1.5
)

(0.8
)Amortization of investment tax credits

(0.1
)

(0.2
)

(0.1
)Other, net

0.1


0.1


(0.7
)Effective tax rate

43.4
%

36.3
%

35.8
% In connection with the pending sale of two of our regulated gas distribution subsidiaries, we established $105
million of deferred taxliabilities in our Consolidated Balance Sheet in accordance with EITF Issue No. 93-17, Recognition of Deferred Tax Assets for a ParentCompanys Excess Tax Basis in the Stock of a Subsidiary that
is Accounted for as a Discontinued Operation (EITF 93-17). Although these subsidiaries are not classified as discontinued operations, 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 a charge since the financial reporting basis of our investment exceeds our tax basis in
the subsidiaries. This difference and related deferred taxes will reverse and will partially offset current tax expense that will be recognized upon closing of the sale. In addition, for the year ended December 31, 2006, we partially reduced previously recorded valuation allowances to reflect the expected utilization of federal and state capital loss carryforwards to offset capital
gain income that will be generated from the pending sale of the two subsidiaries.


Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Our net deferred income taxes consist of the following:  At December 31,

2006


2005(millions)Deferred income taxes:Total deferred income tax assets

$
611


$
1,578Total deferred income tax liabilities


3,432



3,379Total net deferred income tax liabilities

$
2,821


$
1,801Total deferred income taxes:Gas and oil exploration and production related differences

$
2,121


$
1,907Depreciation method and plant basis differences


478



613Pension benefits


435



381Deferred state income taxes


246



291Recognition of deferred taxesstock of subsidiaries held for sale


105



Partnership basis differences


24



58Valuation allowances


11



38Derivative losses


(246
)


(1,148
)Loss and credit carryforwards


(235
)


(317
)Other


(118
)


(22
)Total net deferred income tax liabilities

$
2,821


$
1,801 At December 31, 2006, we had the following loss and credit carryforwards: n


Federal loss carryforwards of $105 million that expire if unutilized during the period 2007 through 2009; n


State loss carryforwards of $906 million that expire if unutilized during the period 2007 through 2026. A valuation allowance on $139 million of these carryforwards
has been established due to the uncertainty of realizing these future deductions; and n


Federal minimum tax credits of $139 million that do not expire. We are routinely audited by federal and state tax authorities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret them differently. We establish liabilities for tax-related
contingencies in accordance with SFAS No. 5, Accounting for Contingencies, and review them in light of changing facts and circumstances. Ultimate resolution of income tax matters may result in favorable or unfavorable adjustments that could
be material. At December 31, 2006 and 2005, our Consolidated Balance Sheets included no significant income tax-related contingent liabilities. American Jobs
Creation Act of 2004 (the Jobs Act) The Act has several provisions for energy companies, including a deduction related to taxable income derived from
qualified production activities. Our oil and gas extraction activities qualify as production activities under the Act. The Act limits the deduction to the lesser of taxable income derived from qualified production activities or our consolidated
federal taxable income. Our qualified production activities deduction for 2006 is minimal.




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NOTE 8. 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. Selected information about our hedge accounting activities follows:  Year Ended December 31,

2006


2005


2004(millions)Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:Fair value hedges

$
(4
)

$
2


$
(2
)Cash flow hedges(1)


25



(57
)


(1
)Net ineffectiveness

$
21


$
(55
)

$
(3
)Portion of gains (losses) on hedging instruments excluded from measurement of effectiveness and included in net income:Fair value hedges

$
1


$
(1
)

$
1Cash flow hedges(2)


(2
)


(1
)


103Total

$
(1
)

$
(2
)

$
104  (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. (2)
Amounts relate to changes in options time value. Due to
interruptions in the Gulf of Mexico oil production caused by Hurricane Ivan, we discontinued hedge accounting for certain cash flow hedges in September 2004, since it became probable that the forecasted sales of oil would not occur. In connection
with the discontinuance of hedge accounting for these contracts, we reclassified $71 million ($45 million after-tax) of losses from AOCI to earnings in September 2004. 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 AOCI to earnings in March 2005. Additionally, due to interruptions in the Gulf of Mexico and southern 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. Losses related to the discontinuance of hedge accounting are reported in other operations and maintenance expense in our
Consolidated Statements of Income.


The following table presents selected information related to cash flow hedges included in AOCI in our Consolidated Balance Sheet at December 31, 2006:  AOCI AfterTax


Portion Expectedto be Reclassifiedto Earningsduring the Next12 Months After Tax


MaximumTerm(millions)Commodities:Gas

$
(110
)

$
(151
)

51 monthsOil


(254
)


(198
)

36 monthsElectricity


(1
)


(1
)

5 monthsInterest rate


(1
)





95 monthsTotal

$
(366
)

$
(350
) 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.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



NOTE 9. DISPOSITIONS Sale of Merchant Generation Facility In December 2006, we
reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell Armstrong, our 625-megawatt natural gas-fired merchant generation peaking facility in Shelocta, Pennsylvania, along with two other
facilities owned by Dominion. Total expected proceeds for the three facilities is approximately $256 million, of which about $117 million will be allocated to Armstrong. The sale is expected to close by the end of the first quarter of 2007, pending
regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. No state regulatory approvals are required. We
offered the facility for sale following a review of our portfolio of assets. We classified this asset as held for sale during the fourth quarter of 2006 and adjusted its carrying amount to fair value less cost to sell, resulting in an impairment
charge of $86 million ($56 million after-tax). The carrying amounts of the major classes of assets and liabilities classified as held for
sale in our Consolidated Balance Sheet are comprised of property, plant and equipment, net ($115 million), inventory ($4 million) and accounts payable ($2 million). On February 27, 2007, an affiliate acquired from Armstrong, a majority equity
interest in exchange for a reduction in net amounts owed to the affiliate of approximately $207 million. Immediately following this transaction, we sold our remaining minority interest in Armstrong to the affiliate. The following table presents selected information regarding the results of operations of Armstrong, which is reported as discontinued operations on our
Consolidated Statements of Income:  At December 31,

2006


2005

2004(millions)Operating Revenue

$
21


$
40

$
44Income (loss) before income taxes


(92
)





1 Armstrongs operating revenues were related to sales to other Dominion affiliates. In
addition, Armstrong purchased $6 million, $22 million and $25 million of electric fuel from affiliates in 2006, 2005 and 2004, respectively.


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, Peoples and
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 end of the second 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:  At December 31,

2006(millions)ASSETSCurrent AssetsCash

$
4Customer accounts receivable


144Unrecovered gas costs


31Other


90Total current assets


269Investments


2Property, Plant and EquipmentProperty, plant and equipment


1,108Accumulated depreciation, depletion and amortization


(370
)Total property, plant and equipment, net


738Deferred Charges and Other AssetsRegulatory assets


106Other


2Total deferred charges and other assets


108Assets held for sale

$
1,117LIABILITIESCurrent LiabilitiesAccounts payable

$
90Payables to affiliates


40Accrued taxes


23Deferred income taxes


9Other


74Total current liabilities


236Deferred Credits and Other LiabilitiesAsset retirement obligations


38Deferred income taxes and investment tax credits


187Regulatory liabilities


10Other


7Total deferred credits and other liabilities


242Liabilities held for sale

$
478 The following table presents selected information regarding the results of operations of Peoples
and Hope:  At December 31,

2006


2005

2004(millions)Operating Revenue

$
699


$
742

$
617Income (loss) before income taxes


(112
)


54


71 During 2006, we recognized a $162 million ($102 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




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of Peoples and Hope, since the recovery of those assets is no longer probable. We also established $105 million of deferred tax liabilities in our
Consolidated Balance Sheet in accordance with EITF 93-17. EITF Issue No. 03-13, Applying the Conditions of Paragraph 42 of FASB
Statement No.144 in Determining Whether to Report Discontinued Operations(EITF 03-13), 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 Appalachian E&P operations, as well as natural gas transportation and storage services provided to them by our gas 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 10. PROPERTY, PLANT AND EQUIPMENT Major classes of property, plant and equipment and their respective balances are:  At December 31,

2006

2005(millions)Utility:Transmission

$
1,850

$
1,899Distribution


1,331


2,070Storage


1,109


947Gas gathering and processing


433


433General and other


143


185Plant under construction


349


317Total utility


5,215


5,851Nonutility:Exploration and production properties being amortized:Proved


12,574


10,855Unproved


1,269


1,121Unproved exploration and production properties not being amortized


994


956Otherincluding plant under construction


94


343Total nonutility


14,931


13,275Total property, plant and equipment

$
20,146

$
19,126


Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2006 and the
years in which the excluded costs were incurred, are as follows:  Total

2006

2005

2004

YearsPrior(millions)Property acquisition costs

$
531

$
124

$
51

$
15

$
341Exploration costs


309


169


68


29


43Capitalized interest


154


36


28


23


67Total

$
994

$
329

$
147

$
67

$
451 There were no significant properties under development, as defined by the SEC, excluded from
amortization at December 31, 2006. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization
calculation. Amortization rates for capitalized costs under the full cost method of accounting in thousand cubic feet (mcf) equivalent were
$1.74, $1.46 and $1.35 for 2006, 2005 and 2004, respectively. Volumetric Production Payment Transactions In 2005, the Company and Dominion Energy, Inc. (DEI), a wholly-owned subsidiary of Dominion, received $86 million and $338 million, respectively, for the sale of
fixed-term overriding royalty interests in certain natural gas reserves for the period March 2005 through February 2009. The sale reduced the proved natural gas reserves of the Company and DEI by approximately 15 billion cubic feet (bcf) and 61 bcf,
respectively. While the Company and DEI are obligated under the agreement to deliver to the purchaser its portion of future natural gas production from the properties, the Company and DEI retain control of the properties and rights to future
development drilling. If total production from the properties subject to the sale is inadequate to deliver the approximately 76 bcf of natural gas scheduled for delivery to the purchaser, the Company and DEI have no obligation to make up the
shortfall. A production shortfall against scheduled production for one group of properties subject to the sale, however, may be required to be made up in whole or in part from additional production in excess of scheduled production quantities from
other properties subject to the sale. We recorded our portion of the cash proceeds received from this VPP transaction as deferred revenue. We recognize revenue as natural gas is produced and delivered to the purchaser. We previously entered into VPP
transactions in 2004 and 2003 for approximately 83 bcf for the period May 2004 through April 2008 and 66 bcf for the period August 2003 through July 2007, respectively. The remaining deferred revenue balance at December 31, 2006 and 2005 was $107
million and $267 million, respectively.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



Sale of E&P Properties In 2006, we received approximately $360
million of proceeds from sales of gas and oil properties, primarily resulting from the fourth quarter sale of certain properties located in Texas and New Mexico. The proceeds were credited to our U.S. full cost pool. NOTE 11. GOODWILL AND INTANGIBLE ASSETS There was no impairment of or material change
to the carrying amount or segment allocation of goodwill in 2006 or 2005. All of our intangible assets, other than goodwill, are subject to
amortization. Amortization expense for intangible assets was $37 million, $22 million and $22 million for 2006, 2005 and 2004, respectively. There were no material acquisitions of intangible assets in 2006. The components of our intangible assets
are as follows:  At December 31,

2006

2005Gross Carrying Amount

Accumulated Amortization

Gross Carrying Amount

Accumulated Amortization(millions)Software and software licenses

$
259

$
147

$
234

$
116Other


29


16


26


14Total

$
288

$
163

$
260

$
130 Annual amortization expense for intangible assets is estimated to be $28 million for 2007, $25
million for 2008, $22 million for 2009, $17 million for 2010 and $9 million for 2011. NOTE 12. REGULATORY ASSETS AND LIABILITIES Our regulatory assets and liabilities include the following:  At December 31,

2006

2005(millions)Regulatory assets:Unrecovered gas costs

$
11

$
179Regulatory assetscurrent(1)


11


179Customer bad debts(2)


85


70Other postretirement benefit costs(3)


37


45Income taxes recoverable through future rates(4)





213Other


25


75Regulatory assetsnon-current


147


403Total regulatory assets

$
158

$
582Regulatory liabilities:Amounts payable to customers

$
2

$
5Estimated rate contingencies and refunds(5)


5


4Regulatory liabilitiescurrent(6)


7


9Provision for future cost of removal(7)


121


128Other


16


19Regulatory liabilitiesnon-current


137


147Total regulatory liabilities

$
144

$
156  (1)
Reported in other current assets. (2)
Instead of recovering bad debt costs through our base rates, the Public Utilities Commission of Ohio (Ohio Commission) allows us to recover all eligible bad debt expenses through a bad debt
tracker. Annually, we assess the need to adjust the tracker based on the preceding years unrecovered deferred bad


debt expense. The Ohio Commission also has authorized the collection of previously deferred costs associated with certain uncollectible customer accounts from 2001
over five years through the tracker rider. Remaining costs to be recovered totaled $25 million at December 31, 2006. (3)
Pending the recognition in rates of costs recognized under SFAS No. 106, Employers Accounting for Postretirement Benefits Other Than Pensions, our rate-regulated
subsidiaries deferred the differences between SFAS No. 106 costs and amounts included in rates. (4)
Income taxes recoverable through future rates resulting from the recognition of additional deferred income taxes not recognized under ratemaking practices. (5)
Estimated rate contingencies and refunds are associated with certain increases in prices by our rate regulated utilities and other ratemaking issues that are subject to final modification in
regulatory proceedings. (6)
Reported in other current liabilities. (7)
Rates charged to customers by our regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement. At December 31, 2006, approximately $101 million of our regulatory assets represented past expenditures on which we do
not earn a return. These expenditures consist primarily of unrecovered gas costs and customer bad debts. Unrecovered gas costs and the ongoing portion of bad debts are recovered within two years. The previously deferred bad debts will also be
recovered over a 2-year period. NOTE 13. ASSET RETIREMENT OBLIGATIONS Our AROs are primarily associated with dismantlement and removal of gas and oil wells and platforms, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components and the retirement of certain
nonutility offshore natural gas pipelines. We also have AROs related to the retirement of the approximately 2,300 gas storage wells in our
underground natural gas storage network and our LNG processing and storage facilities. We currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets. Thus, AROs for these assets
will not be reflected in our Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. Generally, this will occur when the expected
retirement or abandonment dates are determined by our operational planning. The changes to our AROs during 2006 were as follows:  Amount(millions)Asset retirement obligations at December 31, 2005(1)

$
398Obligations incurred during the period


8Obligations settled during the period


(11
)Accretion


20Revisions in estimated cash flows


21Other(2)


(35
)Asset retirement obligations at December 31, 2006(1)

$
401  (1)
Includes $6 million and $2 million reported in other current liabilities at December 31, 2005 and 2006, respectively. (2)
Primarily reflects reclassification of Peoples and Hope AROs that are reported in liabilities held for sale. NOTE 14. VARIABLE INTEREST ENTITIES FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest
Entities (FIN 46R), addresses the consolidation of VIEs. An entity is considered a VIE under FIN




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46R if it does not have sufficient equity to finance its activities without assistance from variable interest holders or if its equity investors lack any of
the following characteristics of a controlling financial interest: n


control through voting rights, n


the obligation to absorb expected losses, or n


the right to receive expected residual returns. FIN 46R requires the primary beneficiary of a VIE to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that
receives the majority of a VIEs expected losses, expected residual returns, or both. In 2006, we, along with three other gas and oil
exploration companies, entered into a long-term contract with an unrelated limited liability company (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 December 31, 2006 we have not made any payments to the LLC. In accordance with FIN 46R, we
consolidated a variable interest lessor entity through which we financed and leased the Armstrong generation facility. Our Consolidated Balance Sheet as of December 31, 2005 reflected net property, plant and equipment of $207 million and debt
of $234 million related to this entity. The debt was non-recourse to us and was secured by the entitys property, plant and equipment. In November 2006, the lease under which we operated the power generation facility terminated and we took
legal title to the facility through an affiliates repayment of the lessors related debt in exchange for a short-term borrowing from the affiliate. NOTE
15. SHORT-TERM DEBT AND CREDIT AGREEMENTS Joint Credit Facility 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. Short-term financing is supported by a $3.0 billion five-year joint revolving credit facility dated February 2006 with Dominion and Virginia Electric and Power
Company (Virginia Power), a wholly-owned subsidiary of Dominion, that 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 the Company and other general corporate purposes. This credit facility can also be used to support up to $1.5
billion of letters of credit. At December 31, 2006, total outstanding commercial paper supported by the joint credit facility was
$1.76 billion, of which our borrowings were $252 million, with a weighted average interest rate of 5.42%. At December 31, 2005, total outstanding commercial paper supported by the previous joint credit facility was $1.4 billion, none of which
was issued on our behalf. At December 31, 2006 and 2005, total outstanding letters of credit supported by joint credit facilities were
$236 million and $892 million, respectively, none of which were issued on our behalf. At December 31, 2006, capacity available under
the joint credit facility was $1.0 billion. Other Credit Facilities Our short-term financing is also supported by an amended and restated $1.7 billion five-year revolving credit facility, dated February 2006, which is scheduled to terminate in August 2010 and a $1.05 billion 364-day credit facility dated
February 2006, which terminated in February 2007, and was not renewed (CNG facilities). These credit facilities support our issuance of commercial paper and letters of credit to provide collateral required by counterparties on derivative financial
contracts used in our risk management strategies for our gas and oil production. At December 31, 2006, there was no outstanding
commercial paper supported by the CNG facilities. At December 31, 2005, total outstanding commercial paper supported by the previous credit agreement was $187 million, with a weighed average interest rate of 4.53%. At December 31, 2006 and 2005, outstanding letters of credit under the CNG facilities totaled $484 million and $1.23 billion, respectively. At December 31, 2006, outstanding borrowings from the CNG facilities totaled $500 million. The funds borrowed were used to repay our
$500 million 2001 Series B 5.375% Senior Notes which matured on November 1, 2006. We expect to repay the outstanding loan with proceeds received from pending asset sales. At December 31, 2006 capacity available under the CNG facilities was $1.77 billion. We have also entered into several bilateral credit facilities in addition to the facilities above in order to provide collateral required on derivative
contracts used in our price risk management strategies for gas and oil production operations. At December 31, 2006, we had the following letter of credit facilities:  FacilityLimit

OutstandingLetters ofCredit

FacilityCapacityRemaining

Facility Inception Date

Facility Maturity Date(millions)$100

$
25

$
75

June 2004

June 2007100


100




August 2004

August 2009200(1)





200

December 2005

December 2010$400

$
125

$
275  (1)
This facility can also be used to support commercial paper borrowings




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



NOTE 16. LONG-TERM DEBT  At December 31,

2006WeightedAverageCoupon(1)


2006


2005(millions, except percentages)Secured Bank Debt, Variable rate, due 2006(2)









234Unsecured Debentures and Senior Notes:5.375% to 6.875%, due 2006 to 2011

6.54
%

$
1,500


$
2,0005.0% to 6.875%, due 2013 to 2027

5.89
%


1,200



1,200Unsecured Junior Subordinated Notes Payable to Affiliated Trust 7.8%, due 2041





206



2062,906



3,640Fair value hedge valuation(3)





11



11Amount due within one year(4)

6.88
%


(199
)


(734
)Unamortized discount and premium, net





(6
)


(3
)Total long-term debt




$
2,712


$
2,914  (1)
Represents weighted-average coupon rate for debt outstanding as of December 31, 2006 (2)
Represents debt associated with a special purpose lessor entity consolidated in accordance with FIN 46R. The debt was nonrecourse to us and was secured by the entitys property, plant
and equipment, which totaled $207 million at December 31, 2005. (3)
Represents the valuation of certain fair value hedges associated with our fixed-rate debt. (4)
Includes $2 million of net unamortized premium, offset by a $3 million fair value hedge valuation. Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2006 were as follows:  2007

2008

2009

2010

2011

Thereafter

Total(millions)$200

$
150



$
200

$
950

$
1,406

$
2,906 Our short-term credit facilities and long-term debt agreements contain customary covenants and
default provisions. As of December 31, 2006, there were no events of default under our covenants. Junior Subordinated Notes Payable to Affiliated Trust In 2001, we established a subsidiary capital trust, Dominion CNG Capital Trust I (trust), a finance subsidiary of which we hold 100% of the voting
interests. The trust sold 8 million 7.8% trust preferred securities for $200 million, representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trust. In exchange for the $200 million realized from the
sale of the trust preferred securities and $6 million of common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trust, we issued $206 million of our 2001 7.8% junior subordinated notes
(junior subordinated notes) due October 31, 2041. The junior subordinated notes constitute 100% of the trusts assets. The trust must redeem its trust preferred securities when the junior subordinated notes are repaid or if redeemed prior
to maturity. Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the
Company when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the trust preferred secu


rities to the extent that the trust has funds legally and immediately available to make distributions. The trusts ability to pay amounts when they are
due on the trust preferred securities is dependent solely upon our payment of amounts when they are due on the junior subordinated notes. If the payment on the junior subordinated notes is deferred, we may not make distributions related to our
capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, we may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment
with, or subordinated to, the junior subordinated notes. NOTE 17. SHAREHOLDERS EQUITY At December 31, 2006 and 2005, our AOCI was $294 million and $1.8 billion, respectively. In 2005, we received a $750 million equity contribution in exchange for a reduction in our outstanding Dominion money pool
borrowings. Presented in the table below is a summary of AOCI by component:  At December 31,

2006


2005(millions)Net unrealized losses on derivatives-hedging activities, net of tax

$
(366
)

$
(1,769
)Net unrecognized pension and other postretirement benefit credits, net of tax


72



Total accumulated other comprehensive loss

$
(294
)

$
(1,769
) NOTE 18. DIVIDEND RESTRICTIONS Certain agreements associated with our joint credit facility with Dominion and Virginia Power contain restrictions on the ratio of our debt to total capitalization. These limitations did not restrict our ability to pay dividends to Dominion
at December 31, 2006. See Note 16 for a description of potential restrictions on our dividend payments in connection with the deferral
of distribution payments on trust preferred securities.




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NOTE 19. EMPLOYEE BENEFIT PLANS We provide certain benefits to eligible active
employees, retirees and qualifying dependents. Under the terms of our benefit plans, we reserve the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced
benefits. Pension benefits, for our employees not represented by recognized bargaining units, are covered by Dominions pension plan,
which provides benefits to multiple Dominion subsidiaries. We sponsor qualified pension plans that cover employee groups represented by collective bargaining units. Retirement benefits payable under all plans are based primarily on years-of-service,
age and the employees compensation. Our contributions to the plans are generally determined in accordance with the provisions of the Employment Retirement Income Security Act of 1974. Retiree health care and life insurance benefits, for our employees not represented by recognized bargaining units, are covered by Dominions other
postretirement benefit plans. We sponsor other postretirement benefit plans that cover employee groups represented by collective bargaining units. Annual employee premiums are based on several factors such as age, retirement date and years of
service. On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was signed
into law. The Medicare Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to
Medicare Part D. Based on an analysis performed by a third-party actuary, we have determined that the prescription drug benefit offered under our other postretirement benefit plans is at least actuarially equivalent to Medicare Part D and therefore
we expect to receive the federal subsidy offered under the Medicare Act. The measurement date for our employee benefit plans is
December 31. We use a market-related value of pension plan assets to determine the expected return on pension plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line
basis over a four-year period. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses.


The following table summarizes information for
our pension and other postretirement benefit plans for employees represented by collective bargaining units, including the changes in the pension and other postretirement benefit plan obligations and plan assets and includes a statement of the
plans funded status:  Pension Benefits


Other Postretirement BenefitsYear Ended December 31,

2006


2005


2006


2005Change in benefit obligation:Benefit obligation at beginning of year

$
569


$
527


$
445


$
402Service cost


14



12



17



14Interest cost


31



31



24



23Plan amendments










(11
)


(23
)Actuarial (gain) loss


(10
)


29



(112
)


52Benefits paid


(37
)


(30
)


(25
)


(23
)Curtailments(1)










(17
)


Benefit obligation at end of year

$
567


$
569


$
321


$
445Change in plan assets:Fair value of plan assets at beginning of year

$
1,291


$
1,200


$
225


$
204Actual return on plan assets


161



121



21



13Employer contributions










37



29Benefits paid from plan assets


(37
)


(30
)


(24
)


(21
)Fair value of plan assets at end of year

$
1,415


$
1,291


$
259


$
225Funded status

$
848


$
722


$
(62
)

$
(220
)Unrecognized net transition obligation














27Unrecognized net actuarial (gain) loss






(70
)






155Unrecognized prior service cost (credit)






16







(14
)Net asset (liability) recognized

$
848


$
668


$
(62
)

$
(52
)Amounts recognized in the Consolidated Balance Sheets at December 31(2):Noncurrent pension and other postretirement benefit assets

$
848


$
668


$
4


$
Noncurrent other postretirement benefit liabilities










(66
)


(52
)Net amount recognized

$
848


$
668


$
(62
)

$
(52
)  (1)
Relates to the pending sale of Peoples and Hope. (2)
Amounts relate to benefit plans for employees represented by collective bargaining units, and do not include benefit plans covering multiple Dominion subsidiaries.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



The following table summarizes the overfunded and underfunded status of our benefit plans for employees recognized by collective bargaining units recognized in our Consolidated Balance Sheet at December 31, 2006:  Pension Benefits

OtherPostretirementBenefitsFunded status of overfunded plans



$
848



$
4Funded status of underfunded plans









(66
)Funded status



$
848



$
(62
) The accumulated benefit obligation for defined benefit pension plans for employees represented by
collective bargaining units was $538 million and $527 million at December 31, 2006 and 2005, respectively. Under our funding policies, we evaluate plan funding requirements annually, usually in the fourth quarter after receiving updated plan
information from our actuary. Based on the funded status of each plan and other factors, we determine the amount of contributions for the current year, if any, at that time. We do not expect any pension or postretirement benefit plan assets to be returned to the Company during 2007. The following table reflects after-tax amounts in AOCI in our Consolidated Balance Sheet at December 31, 2006 that have not yet been recognized as
components of net periodic benefit cost:  PensionBenefits


OtherPostretirementBenefits(millions)Unrecognized net transition obligation

$



$
(1
)Unrecognized net actuarial gain (loss)


82



(1
)Unrecognized prior service (cost) credit


(9
)


1Net amount recognized

$
73


$
(1
) Of the above amounts included in AOCI, we expect to recognize $1 million of after-tax prior service
cost and less than $1 million of unrecognized net transition obligation and net actuarial gain (loss) in net periodic benefit cost during the year ended December 31, 2007.


The following benefit payments, which reflect
expected future service, as appropriate, are expected to be paid for employees represented by collective bargaining units:  PensionBenefits

OtherPostretirementBenefits(millions)2007

$
34

$
252008


36


272009


37


292010


39


302011


40


312012-2016


223


161 The above benefit payments for other postretirement benefit plans are expected to be offset by
Medicare Part D subsidies of approximately $1 million annually for the years 2007 through 2011 and approximately $7 million during the period 2012 through 2016.


Our overall objective for investing pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate
with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocation for our pension funds is 34% U.S. equity securities, 12% non-U.S.
equity securities, 22% debt securities, 7% real estate and 25% other, such as private equity investments. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities. Our asset allocations for pension
plans and other postretirement benefit plans for employees represented by collective bargaining units follow:



|                   |  |               |       |                            |     |            |   |            |  |            |  |            |     |            |     |            |   |     |  |    
|------------------ |  | ------------- | ----- | -------------------------- | --- | ---------- | - | ---------- |  | ---------- |  | ---------- | --- | ---------- | --- | ---------- | - | --- |  | ---
|                   |  | Pension Plans |       | Other Postretirement Plans
|At December 31,    |  | 2006          |       | 2005                       |     | 2006       |   | 2005      
|                   |  | FairValue     |       | % ofTotal                  |     | Fair Value |   | % of Total |  | Fair Value |  | % of Total |     | Fair Value |     | % of Total
|(millions)         |  |               |       |                            |     |           
|                   |  |               |       |                            |     |            |   |           
|Equity securities: |  |               |       |                            |     |            |   |            |  |            |  |            |     |            |     |            |   |     |  |    
|U.S.               |  | $             | 440   |                            | 31  |            | $ | 521        |  | 40         |  | $          | 110 |            | 43  |            | $ | 95  |  | 42 
|International      |  |               | 222   |                            | 16  |            |   | 180        |  | 14         |  |            | 27  |            | 10  |            |   | 23  |  | 11 
|Debt securities    |  |               | 400   |                            | 28  |            |   | 289        |  | 22         |  |            | 103 |            | 40  |            |   | 90  |  | 40 
|Real estate        |  |               | 111   |                            | 8   |            |   | 101        |  | 8          |  |            | 3   |            | 1   |            |   | 3   |  | 1  
|Other              |  |               | 242   |                            | 17  |            |   | 200        |  | 16         |  |            | 16  |            | 6   |            |   | 14  |  | 6  
|Total              |  | $             | 1,415 |                            | 100 |            | $ | 1,291      |  | 100        |  | $          | 259 |            | 100 |            | $ | 225 |  | 100



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The components of the provision for net periodic benefit cost for employees represented by collective bargaining units were as follows:



|                                           |  |                  |      |   |                               |   |      |      |  |   |      |   |  |      |     |   |      |   |     |   |  |   |     |  
|------------------------------------------ |  | ---------------- | ---- | - | ----------------------------- | - | ---- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | - |  | - | --- | -
|                                           |  | Pension Benefits |      |   | Other Postretirement Benefits |  
|Year Ended December 31,                    |  | 2006             |      |   | 2005                          |   |      | 2004 |  |   | 2006 |   |  | 2005 |     |   | 2004 |  
|(millions)                                 |  |                  |      |   |                               |   |      |      | 
|                                           |  |                  |      |   |                               |  
|Service cost                               |  | $                | 14   |   |                               | $ | 12   |      |  | $ | 11   |   |  | $    | 17  |   |      | $ | 14  |   |  | $ | 17  |  
|Interest cost                              |  |                  | 31   |   |                               |   | 31   |      |  |   | 30   |   |  |      | 24  |   |      |   | 23  |   |  |   | 26  |  
|Expected return on assets                  |  |                  | (108 | ) |                               |   | (103 | )    |  |   | (100 | ) |  |      | (17 | ) |      |   | (16 | ) |  |   | (13 | )
|Prior service cost amortization            |  |                  | 1    |   |                               |   | 2    |      |  |   | 1    |   |  |      | (2  | ) |      |   |    |   |  |   |    |  
|Transition (asset) obligation amortization |  |                  |     |   |                               |   |     |      |  |   | (3   | ) |  |      | 4   |   |      |   | 6   |   |  |   | 6   |  
|Amortization of net (gain) loss            |  |                  |     |   |                               |   |     |      |  |   | (1   | ) |  |      | 13  |   |      |   | 6   |   |  |   | 10  |  
|Curtailments(1)                            |  |                  |     |   |                               |   |     |      |  |   |     |   |  |      | 3   |   |      |   |    |   |  |   |    |  
|Net periodic benefit (credit) cost         |  | $                | (62  | ) |                               | $ | (58  | )    |  | $ | (62  | ) |  | $    | 42  |   |      | $ | 33  |   |  | $ | 46  |  



|(1) | Relates to the pending sale of Peoples and Hope.
|--- | ------------------------------------------------

Pension benefits,
for our employees not represented by collective bargaining units, are covered by Dominions pension plan, which provides benefits to multiple Dominion subsidiaries. Benefits payable under the plan are based primarily on years of service, age
and the employees compensation. As a participating employer, we are subject to Dominions funding policy, which is to generally contribute annually an amount that is in accordance with the provisions of the Employment Retirement Income
Security Act of 1974. We recognized $47 million, $44 million and $50 million of net periodic pension credits in 2006, 2005 and 2004, respectively, related to the plan. We did not contribute to the pension plan in 2006, 2005 or 2004.

Significant assumptions used in determining the net periodic cost for our pension and other postretirement benefit plans for employees represented by
collective bargaining units recognized in our Consolidated Statements of Income were as follows, on a weighted-average basis:



|                                  |  |                  |   |  |                               |   |  |      |   |  |      |   |  |      |   |  |      |  
|--------------------------------- |  | ---------------- | - |  | ----------------------------- | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|                                  |  | Pension Benefits |   |  | Other Postretirement Benefits |  
|Year Ended December 31,           |  | 2006             |   |  | 2005                          |   |  | 2004 |   |  | 2006 |   |  | 2005 |   |  | 2004 |  
|Discount rate                     |  | 5.60             | % |  | 6.00                          | % |  | 6.25 | % |  | 5.50 | % |  | 6.00 | % |  | 6.25 | %
|Expected return on plan assets    |  | 8.75             | % |  | 8.75                          | % |  | 8.75 | % |  | 8.00 | % |  | 8.00 | % |  | 8.00 | %
|Rate of increase for compensation |  | 4.00             | % |  | 4.00                          | % |  | 4.00 | % |  | 4.00 | % |  | 4.00 | % |  | 4.00 | %
|Medical cost trend rate(1)        |  |                  |   |  |                               |   |  |      |   |  | 9.00 | % |  | 9.00 | % |  | 9.00 | %



|(1) | The medical cost trend rate for 2006 is assumed to gradually decrease to 5.00% by 2010 and continues at that rate for years thereafter.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------

Significant assumptions used in determining the projected benefit obligations for our pension and other postretirement benefit plans for employees
represented by collective bargaining units recognized in our Consolidated Balance Sheets were as follows, on a weighted-average basis:



|                                  |  |                  |   |  |                               |   |  |      |   |  |      |  
|--------------------------------- |  | ---------------- | - |  | ----------------------------- | - |  | ---- | - |  | ---- | -
|                                  |  | Pension Benefits |   |  | Other Postretirement Benefits |  
|At December 31,                   |  | 2006             |   |  | 2005                          |   |  | 2006 |   |  | 2005 |  
|Discount rate                     |  | 6.20             | % |  | 5.60                          | % |  | 6.10 | % |  | 5.50 | %
|Rate of increase for compensation |  | 4.40             | % |  | 4.00                          | % |  | 4.00 | % |  | 4.00 | %



We determine the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of: n


Historical return analysis to determine expected future risk premiums; n


Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices; n


Expected inflation and risk-free interest rate assumptions, and n


The types of investments expected to be held by the plans. Assisted by an independent actuary, we develop assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final
assumptions. Discount rates are determined from analyses performed by a third-party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under our plans. Assumed health care cost trend rates have a significant effect on the amounts reported for our retiree health care plans. A


one-percentage-point change in the assumed health care cost trend rate would have had the following effects on postretirement benefit plans for employees
represented by collective bargaining units:  Other Postretirement BenefitsOne Percentage Point Increase

One Percentage Point Decrease(millions)Effect on total service and interest cost components for 2006

$
7

$
(5
)Effect on postretirement benefit obligation at December 31, 2006


31


(24
) Retiree health care and life insurance benefits, for our employees not represented by recognized
bargaining units, are covered by Dominions other postretirement benefit plans. Annual employee premiums are based on several factors such as age, retirement date and years of service. Our net periodic benefit cost related to these plans was
$14 million, $15 million and $17 million in 2006, 2005 and 2004, respectively.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits in excess of benefits actually paid during the
year must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of our subsidiaries fund postretirement benefit costs through Voluntary Employees Beneficiary Associations (VEBAs). Our
remaining subsidiaries do not prefund postretirement benefit costs but instead pay claims as presented. Our contributions to the CNG VEBAs were $8 million, $11 million and $11 million in 2006, 2005 and 2004, respectively. We expect to contribute $18
million to the CNG VEBAs in 2007. We also participate in Dominion-sponsored employee savings plans that cover substantially all employees.
Employer matching contributions of $9 million, $9 million and $8 million were incurred in 2006, 2005 and 2004, respectively. NOTE 20. COMMITMENTS AND CONTINGENCIES As the result of issues generated in the ordinary course of business, we are involved in legal, tax and regulatory proceedings before various courts,
regulatory commissions and governmental agencies, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings will not have a material effect on our financial position, liquidity or results of
operations. Long-Term Purchase Agreements At December 31,
2006, we had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:  2007

2008

2009

2010

2011

Later Years

Total(millions)Production handling for gas and oil production operations(1)

$
54

$
43

$
26

$
15

$
11

$
5

$
154  (1)
Payments under this contract, which ends in 2012, totaled $56 million, $52 million and $22 million for 2006, 2005 and 2004, respectively. Lease Commitments We lease various facilities, onshore and offshore drilling
rigs, vehicles and equipment primarily under operating leases. The lease agreements expire on various dates and certain of the leases are renewable and contain options to purchase the leased property. Payments under certain leases are escalated
based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2006 are as follows:  2007

2008

2009

2010

2011

Thereafter

Total(millions)$117

$
95

$
86

$
61

$
53

$
187

$
599 Rental expense totaled $61 million, $54 million, and $50 million for 2006, 2005 and 2004,
respectively, the majority of which is reflected in other operations and maintenance expense. Lease


payments associated with our onshore and offshore drilling rig commitments are capitalized under the full cost method of accounting for gas and oil E&P
activities. Environmental Matters We are subject to costs
resulting from a steadily increasing number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations and can result in increased
capital, operating and other costs as a result of our compliance, remediation, containment and monitoring obligations. We may sometimes seek recovery of environmental-related expenditures through regulatory proceedings. Before being acquired by us in 2001, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and pending
in the 93rd Judicial Court in Hidalgo County, Texas. The lawsuit alleged that gas wells and related pipeline facilities operated by Louis Dreyfus and other facilities operated by other defendants caused an underground hydrocarbon plume in McAllen,
Texas. In April 2006, we entered into a settlement agreement with the plaintiffs resolving all of their claims against us. In May 2006, the plaintiffs non-suited Dominion with prejudice, resulting in the dismissal of the case. We remain subject,
however, to a cross-claim and an indemnity claim with certain of the other defendants that were not a party to our settlement with the plaintiffs. Neither claim is material and we do not expect the resolution of these remaining claims or the
settlement to have a material adverse effect on the results of operations or financial condition. We have determined that we are associated
with 16 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 16 former sites with
which we are associated is under investigation by any state or federal environmental agency, and no investigation or action is currently anticipated. At this time, it is not known to what degree these sites may contain environmental contamination.
We are not able to estimate the cost, if any, that may be required for the possible remediation of these sites. Litigation In 2006, Gary P. Jones and others filed suit against DTI, DEPI and Dominion Resources Services, Inc. (DRS). The plaintiffs are royalty owners, seeking to recover damages
as a result of the Dominion defendants allegedly underpaying royalties by improperly deducting post-production costs and not paying fair market value for the gas produced from their leases. The plaintiffs seek class action status on behalf of all
West Virginia residents and others who are parties to or beneficiaries of oil and gas leases with the Dominion defendants. DRS is erroneously named as a defendant as the parent company of DTI and DEPI. We do not believe that the final resolution of
this matter will have a material adverse effect on our results of operations or financial condition. Insurance for E&P Operations In the past, we 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




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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 under our current policy. 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. Guarantees, Surety Bonds and Letters of Credit 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 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 believe is improbable. We have not recognized any significant liabilities related to this guarantee arrangement. In 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. 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. The agreements require that we pay a
demand charge of approximately $63 million over five years starting on the day after the mechanical completion of 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 it is improbable that we would be required to perform under this guarantee and have not recognized any significant liabilities for this arrangement. The
agreements also require the payment of production processing fees including a minimum processing fee if yearly production processing fees are below specified amounts. Our maximum obligation for the minimum processing fee would be approximately $3
million per year. Our obligation for the payment of these processing fees will terminate upon the cessation of our production. 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 December 31, 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 December 31, 2006, we had issued the following subsidiary guarantees:  StatedLimit

Value(1)(millions)Subsidiary debt(2)

$
201

$
201Offshore drilling commitments(3)





493Commodity transactions(4)


1,130


480Miscellaneous


354


264Total subsidiary obligations

$
1,685

$
1,438  (1)
Represents the estimated portion of the guarantees stated limit that is utilized as of December 31, 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 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. Additionally, as of December 31, 2006, we had purchased $48 million of surety bonds and
authorized the issuance of standby letters of credit by financial institutions of $609 million to facilitate commercial transactions by our subsidiaries with third parties. Indemnifications As part of commercial contract negotiations in the normal course of business, we may sometimes agree to make payments to
compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in
tax law or interpretation of the tax law. We are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate us have not yet occurred or, if any such event has occurred,
we have not been notified of its occurrence. However, at December 31, 2006, we believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on our results of operations,
cash flows or financial position. We have entered into other types of contracts that require indemnifications, such as purchase and sale
agreements and financing agreements. These agreements may include, but are not limited to, indemnifications around certain title, tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the
sale price and is typically limited in duration depending on the nature of the indemnified




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



matter. Since January 1, 2004, we have entered into sale agreements with maximum exposure related to the collective purchase prices of approximately $1.6
billion . We believe that it is improbable that we would be required to perform under these indemnifications and have not recognized any significant liabilities related to these arrangements. NOTE 21. FAIR VALUE OF FINANCIAL INSTRUMENTS Substantially all of our financial
instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Fair values have been determined using available market information and valuation methodologies considered
appropriate by management. The financial instruments carrying amounts and fair values are as follows:  At December 31,

2006

2005Carrying Amount

Estimated Fair Value(1)

Carrying Amount

Estimated Fair Value(1)(millions)Long-term debt(2)

$
2,705

$
2,776

$
3,442

$
3,572Junior subordinated notes payable to affiliated trust


206


209


206


210  (1)
Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and remaining maturities. The carrying amount of
debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value. (2)
Includes securities due within one year. NOTE 22. CREDIT RISK Credit risk is our risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, Dominion and its
subsidiaries, including us, maintain credit policies, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single
counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction. We maintain a provision for credit losses based on factors surrounding the credit risk of our customers, historical trends and other information. We
believe, based on our credit policies and our December 31, 2006 provision for credit losses, that it is unlikely that a material adverse effect on our financial position, results of operations or cash flows would occur as a result of
counterparty nonperformance. We sell natural gas and provide distribution services to residential, commercial and industrial customers and
provide trans


mission 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, including natural gas and oil. Except for our E&P business activities, these transactions principally occur in the Northeast, Mid-Atlantic and Midwest regions of the U.S. We do not believe that this
geographic concentration contributes significantly to our overall exposure to credit risk. In addition, as a result of our large and diverse customer base, we are not exposed to a significant concentration of credit risk for receivables arising from
gas utility operations, including transmission services and retail energy sales. Our exposure to credit risk is concentrated primarily
within our sales of gas and oil production and energy marketing, including our hedging activities, as we transact with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile
commodity prices. 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 December 31, 2006, our gross credit exposure totaled $576 million. After the application of collateral, our credit exposure is reduced to $572 million. Of this amount, investment grade counterparties
represented 69% and no single counterparty exceeded 13%. NOTE 23. RELATED-PARTY TRANSACTIONS We engage in related party transactions primarily with affiliates (Dominion subsidiaries). Our 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 financial 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. DRS provides accounting, legal and certain administrative and technical services to us.




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Presented below are significant affiliated transactions, including net realized gains and losses on affiliated commodity derivative contracts, recorded in
operating revenue and operating expenses:  Year Ended December 31,

2006

2005

2004(millions)Sales of natural gas

$
494

$
1,129

$
1,027Purchases of natural gas


644


678


527Purchases of electric energy


101


187


171Services provided by DRS


203


188


168 At December 31, 2006 and 2005, our Consolidated Balance Sheets include derivative assets with
affiliates of $188 million and $431 million, respectively, and derivative liabilities with affiliates of $215 million and $120 million, respectively. Unrealized gains or losses, representing the effective portion of the changes in fair value of
those derivative contracts that had been designated as cash flow hedges, are included in AOCI on our Consolidated Balance Sheets. In 2006 and 2005, we also recognized a benefit of $19 million and $38 million, respectively, related to
financially-settled derivative contracts entered into with affiliates in other operations and maintenance expense. We have borrowed funds
from Dominion under short-term borrowing arrangements. At December 31, 2006 and 2005, our outstanding borrowings, net of repayments, under the Dominion money pool totaled $2.3 billion and $1.9 billion, respectively. We incurred interest charges
related to these borrowings of $124 million, $58 million and $15 million in 2006, 2005 and 2004, respectively. In November 2006, we issued
a $234 million short-term note payable to one of our affiliates in connection with their repayment of long-term debt associated with our Armstrong facility. Other
Related-Party Transactions Upon adoption of FIN 46R for our interests in special purpose entities on December 31, 2003, we ceased to consolidate
the


Dominion CNG Capital Trust I, a finance subsidiary of the Company. The junior subordinated notes issued by us and held by the trust are reported as long-term
debt. We reported $16 million each year for interest expense on the junior subordinated notes payable to affiliated trust in 2006, 2005 and 2004. Equity Method
Investments At December 31, 2006 and 2005, our equity method investments totaled $161 million and $210 million, respectively and equity earnings
on these investments totaled $17 million in 2006, $16 million in 2005 and $14 million in 2004. Our equity method investments are reported in investments in affiliates, with the exception of the international investments discussed below, which are
classified as part of assets held for sale in other current assets in our Consolidated Balance Sheets. We received dividend income from these investments of $3 million, $12 million and $9 million in 2006, 2005, and 2004, respectively. Equity
earnings on these investments are reported in other income (loss) in our Consolidated Statements of Income. Also during 2006, we sold two
of our equity method investments, resulting in a net loss of $3 million. International Investments CNG International Corporation (CNGI) was engaged in energy-related activities outside of the continental United States, primarily through equity investments in Australia
and Argentina. After Dominion completed the CNG acquisition in 2000, its management committed to a plan to dispose of the entire CNGI operation consistent with its strategy to focus on core businesses. In 2004, we received cash proceeds of $52 million and recognized a benefit in other income of $31 million related to the sale of a portion of our
investment in an Australian pipeline business. At December 31, 2005, our remaining CNGI investment was accounted for at its fair value of $2 million. During 2006, we wrote off our remaining investment.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



NOTE 24. 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 and are reflected in current liabilities at December 31, 2006. 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

(millions)



|                                                                  |  |                     |     |   |        |   |                    |  |   |                           |   |  |              |      |   |  |   |       |  
|----------------------------------------------------------------- |  | ------------------- | --- | - | ------ | - | ------------------ |  | - | ------------------------- | - |  | ------------ | ---- | - |  | - | ----- | -
|Year Ended December 31,                                           |  | CNG (ParentCompany) |     |   | DOTEPI |   | Other Subsidiaries |  |   | Adjustments &Eliminations |   |  | Consolidated |     
|2006                                                              |  |                     |     |   |        |   |                    |  |   |                           |   |  |              |      |   |  |   |       |  
|Operating revenue                                                 |  | $                   |    |   |        | $ | 786                |  | $ | 7,516                     |   |  | $            | (660 | ) |  | $ | 7,642 |  
|Operating expenses                                                |  |                     | 11  |   |        |   | 518                |  |   | 6,031                     |   |  |              | (640 | ) |  |   | 5,920 |  
|Income (loss) from operations                                     |  |                     | (11 | ) |        |   | 268                |  |   | 1,485                     |   |  |              | (20  | ) |  |   | 1,722 |  
|Other income                                                      |  |                     | 241 |   |        |   |                   |  |   | 37                        |   |  |              | (252 | ) |  |   | 26    |  
|Interest and related charges                                      |  |                     | 213 |   |        |   | 84                 |  |   | 233                       |   |  |              | (252 | ) |  |   | 278   |  
|Income from continuing operations before income tax expense       |  |                     | 17  |   |        |   | 184                |  |   | 1,289                     |   |  |              | (20  | ) |  |   | 1,470 |  
|Income tax expense                                                |  |                     | 107 |   |        |   | 83                 |  |   | 456                       |   |  |              | (8   | ) |  |   | 638   |  
|Equity in earnings of subsidiaries                                |  |                     | 863 |   |        |   |                   |  |   |                          |   |  |              | (863 | ) |  |   |      |  
|Loss from discontinued operations                                 |  |                     |    |   |        |   |                   |  |   | (59                       | ) |  |              |     |   |  |   | (59   | )
|Net income                                                        |  | $                   | 773 |   |        | $ | 101                |  | $ | 774                       |   |  | $            | (875 | ) |  | $ | 773   |  
|2005                                                              |  |                     |     |   |        |   |                    |  |   |                           |   |  |              |      |   |  |   |       |  
|Operating revenue                                                 |  | $                   |    |   |        | $ | 724                |  | $ | 7,945                     |   |  | $            | (636 | ) |  | $ | 8,033 |  
|Operating expenses                                                |  |                     | 3   |   |        |   | 448                |  |   | 7,128                     |   |  |              | (603 | ) |  |   | 6,976 |  
|Income (loss) from operations                                     |  |                     | (3  | ) |        |   | 276                |  |   | 817                       |   |  |              | (33  | ) |  |   | 1,057 |  
|Other income                                                      |  |                     | 209 |   |        |   |                   |  |   | 32                        |   |  |              | (211 | ) |  |   | 30    |  
|Interest and related charges                                      |  |                     | 203 |   |        |   | 62                 |  |   | 161                       |   |  |              | (211 | ) |  |   | 215   |  
|Income before income tax expense                                  |  |                     | 3   |   |        |   | 214                |  |   | 688                       |   |  |              | (33  | ) |  |   | 872   |  
|Income tax expense (benefit)                                      |  |                     | (2  | ) |        |   | 75                 |  |   | 256                       |   |  |              | (12  | ) |  |   | 317   |  
|Income before cumulative effect of change in accounting principle |  |                     | 5   |   |        |   | 139                |  |   | 432                       |   |  |              | (21  | ) |  |   | 555   |  
|Equity in earnings of subsidiaries                                |  |                     | 548 |   |        |   |                   |  |   |                          |   |  |              | (548 | ) |  |   |      |  
|Cumulative effect of change in accounting principle               |  |                     |    |   |        |   |                   |  |   | (2                        | ) |  |              |     |   |  |   | (2    | )
|Net income                                                        |  | $                   | 553 |   |        | $ | 139                |  | $ | 430                       |   |  | $            | (569 | ) |  | $ | 553   |  
|2004                                                              |  |                     |     |   |        |   |                    |  |   |                           |   |  |              |      |   |  |   |       |  
|Operating revenue                                                 |  | $                   |    |   |        | $ | 642                |  | $ | 6,395                     |   |  | $            | (499 | ) |  | $ | 6,538 |  
|Operating expenses                                                |  |                     | 1   |   |        |   | 362                |  |   | 5,188                     |   |  |              | (474 | ) |  |   | 5,077 |  
|Income (loss) from operations                                     |  |                     | (1  | ) |        |   | 280                |  |   | 1,207                     |   |  |              | (25  | ) |  |   | 1,461 |  
|Other income                                                      |  |                     | 187 |   |        |   |                   |  |   | 51                        |   |  |              | (183 | ) |  |   | 55    |  
|Interest and related charges                                      |  |                     | 197 |   |        |   | 42                 |  |   | 112                       |   |  |              | (184 | ) |  |   | 167   |  
|Income (loss) before income tax expense                           |  |                     | (11 | ) |        |   | 238                |  |   | 1,146                     |   |  |              | (24  | ) |  |   | 1,349 |  
|Income tax expense (benefit)                                      |  |                     | (5  | ) |        |   | 72                 |  |   | 425                       |   |  |              | (10  | ) |  |   | 482   |  
|Equity in earnings of subsidiaries                                |  |                     | 873 |   |        |   |                   |  |   |                          |   |  |              | (873 | ) |  |   |      |  
|Net income                                                        |  | $                   | 867 |   |        | $ | 166                |  | $ | 721                       |   |  | $            | (887 | ) |  | $ | 867   |  



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Condensed Consolidating Balance Sheet Information

(millions)



|                                           |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|------------------------------------------ |  | ------------------- | ----- | ------ | - | ----------------- |  | ------------------------- | ------ |  | ------------ | ------- | - |  | - | ------
|At December 31,                            |  | CNG (ParentCompany) |       | DOTEPI |   | OtherSubsidiaries |  | Adjustments &Eliminations |        |  | Consolidated
|2006                                       |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|Assets                                     |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|Current assets                             |  | $                   | 2,143 |        | $ | 266               |  | $                         | 3,993  |  | $            | (2,252  | ) |  | $ | 4,150 
|Investment in affiliates                   |  |                     | 5,707 |        |   |                  |  |                           | 98     |  |              | (5,644  | ) |  |   | 161   
|Other investments                          |  |                     | 105   |        |   |                  |  |                           | 3      |  |              | (2      | ) |  |   | 106   
|Loans to affiliates                        |  |                     | 1,562 |        |   |                  |  |                           |       |  |              | (1,562  | ) |  |   |      
|Property, plant, and equipment, net        |  |                     |      |        |   | 4,585             |  |                           | 8,964  |  |              | (823    | ) |  |   | 12,726
|Deferred charges and other assets          |  |                     | 21    |        |   | 571               |  |                           | 2,218  |  |              | (150    | ) |  |   | 2,660 
|Total assets                               |  |                     | 9,538 |        |   | 5,422             |  |                           | 15,276 |  |              | (10,433 | ) |  |   | 19,803
|Liabilities & Shareholders Equity         |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|Current liabilities                        |  |                     | 953   |        |   | 2,522             |  |                           | 6,468  |  |              | (2,829  | ) |  |   | 7,114 
|Long-term debt                             |  |                     | 2,506 |        |   |                  |  |                           |       |  |              |        |   |  |   | 2,506 
|Notes payable to affiliates                |  |                     | 206   |        |   |                  |  |                           | 1,562  |  |              | (1,562  | ) |  |   | 206   
|Deferred credits and other liabilities     |  |                     | 8     |        |   | 1,163             |  |                           | 3,279  |  |              | (338    | ) |  |   | 4,112 
|Common shareholders equity                |  |                     | 5,865 |        |   | 1,737             |  |                           | 3,967  |  |              | (5,704  | ) |  |   | 5,865 
|Total liabilities and shareholders equity |  | $                   | 9,538 |        | $ | 5,422             |  | $                         | 15,276 |  | $            | (10,433 | ) |  | $ | 19,803
|2005                                       |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|Assets                                     |  |                     |       |        |   |                   |  |                           |        |  |              |         |   |  |   |       
|Current assets                             |  | $                   | 2,019 |        | $ | 539               |  | $                         | 6,529  |  | $            | (3,659  | ) |  | $ | 5,428 
|Investment in affiliates                   |  |                     | 3,697 |        |   |                  |  |                           | 145    |  |              | (3,634  | ) |  |   | 208   
|Other investments                          |  |                     | 94    |        |   |                  |  |                           | 3      |  |              |        |   |  |   | 97    
|Loans to affiliates                        |  |                     | 2,188 |        |   |                  |  |                           |       |  |              | (2,188  | ) |  |   |      
|Property, plant, and equipment, net        |  |                     |      |        |   | 4,079             |  |                           | 8,370  |  |              | (103    | ) |  |   | 12,346
|Deferred charges and other assets          |  |                     | 279   |        |   | 555               |  |                           | 3,620  |  |              | (631    | ) |  |   | 3,823 
|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

(millions)



|                                                    |  |                     |      |   |        |   |      |                   |  |   |                           |   |  |              |      |   |  |   |        |  
|--------------------------------------------------- |  | ------------------- | ---- | - | ------ | - | ---- | ----------------- |  | - | ------------------------- | - |  | ------------ | ---- | - |  | - | ------ | -
|Year Ended December 31,                             |  | CNG (ParentCompany) |      |   | DOTEPI |   |      | OtherSubsidiaries |  |   | Adjustments &Eliminations |   |  | Consolidated |     
|2006                                                |  |                     |      |   |        |   |      |                   |  |   |                           |   |  |              |      |   |  |   |        |  
|Net cash provided by operating activities           |  | $                   | 654  |   |        | $ | 317  |                   |  | $ | 1,948                     |   |  | $            | (676 | ) |  | $ | 2,243  |  
|Net cash used in investing activities               |  |                     | (48  | ) |        |   | (698 | )                 |  |   | (1,477                    | ) |  |              | 257  |   |  |   | (1,966 | )
|Net cash provided by (used in) financing activities |  |                     | (606 | ) |        |   | 381  |                   |  |   | (483                      | ) |  |              | 419  |   |  |   | (289   | )
|2005                                                |  |                     |      |   |        |   |      |                   |  |   |                           |   |  |              |      |   |  |   |        |  
|Net cash provided by operating activities           |  | $                   | 575  |   |        | $ | 467  |                   |  | $ | 737                       |   |  | $            | (799 | ) |  | $ | 980    |  
|Net cash used in investing activities               |  |                     | (37  | ) |        |   | (655 | )                 |  |   | (1,254                    | ) |  |              | 46   |   |  |   | (1,900 | )
|Net cash provided by (used in) financing activities |  |                     | (538 | ) |        |   | 193  |                   |  |   | 537                       |   |  |              | 753  |   |  |   | 945    |  
|2004                                                |  |                     |      |   |        |   |      |                   |  |   |                           |   |  |              |      |   |  |   |        |  
|Net cash provided by operating activities           |  | $                   | 448  |   |        | $ | 175  |                   |  | $ | 1,476                     |   |  | $            | (481 | ) |  | $ | 1,618  |  
|Net cash provided by (used in) investing activities |  |                     | 188  |   |        |   | (374 | )                 |  |   | (829                      | ) |  |              | (71  | ) |  |   | (1,086 | )
|Net cash provided by (used in) financing activities |  |                     | (636 | ) |        |   | 192  |                   |  |   | (660                      | ) |  |              | 552  |   |  |   | (552   | )



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



NOTE 25. OPERATING SEGMENTS We are organized primarily on the basis of products and services sold in the United States. We manage our operations through the following segments: Deliveryincludes 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. Energyincludes our tariff-based natural gas transmission pipeline and underground natural gas storage businesses and an LNG facility that are subject to cost-of-service rate regulation and accordingly, apply SFAS No. 71. It also includes gathering
and extraction facilities, certain Appalachian natural gas production and producer services, which consist of aggregation of gas supply and related wholesale activities. E&Pincludes 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, West Texas, Mid-Continent, the Rockies and Appalachia. Corporateincludes our corporate functions,
including the activities of CNGI, the net impact of the discontinued operations of our Armstrong 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 2006, the Corporate segment included $146
million of net expenses attributable to our operating segments. The net expenses in 2006 primarily related to the impact of the following: n


A $162 million ($102 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; n


A $27 million ($17 million after-tax) charge resulting from the cancellation of a pipeline project, attributable to the Energy segment; and n


A $17 million ($11 million after-tax) loss related to incremental operations and maintenance expenses and severance costs associated with Hurricanes Katrina and
Rita, attributable to the E&P segment. In 2005, the Corporate segment included $373 million of net expenses
attributable to our operating segments. The net expenses in 2005 primarily related to the impact of the following: n


A $556 million ($357 million after-tax) loss related to the discontinuance of hedge accounting in August and September 2005, 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 during the third quarter, attributable to the E&P segment; and n


A $21 million ($13 million after-tax) loss related to incremental operations and maintenance expenses and severance costs associated with Hurricanes Katrina and
Rita, attributable to the E&P segment. In 2004, the Corporate segment included $61 million of net expenses
attributable to our operating segments. The net expenses in 2004 resulted from a $96 million loss ($61 million after-tax) related to the discontinuance of hedge accounting in September 2004 for certain oil hedges resulting from an interruption of
oil production in the Gulf of Mexico caused by Hurricane Ivan and subsequent changes in the fair value of those hedges during the third quarter, 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.




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The following tables present
segment information pertaining to our operations:



|                                                                |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|--------------------------------------------------------------- |  | -------- | ----- | ------ | - | ----- |  | - | --------- | - |  | ------------------------- | ----- | - | ------------------ | - | ------ | - |  | - | ------ | -
|Year Ended December 31,                                         |  | Delivery |       | Energy |   | E&P   |  |   | Corporate |   |  | Adjustments &Eliminations |       |   | Consolidated Total |  
|(millions)                                                      |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |  
|                                                                |  |          |       |        |   |      
|2006                                                            |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|Operating revenue:                                              |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|External customers                                              |  | $        | 3,051 |        | $ | 1,317 |  | $ | 2,757     |   |  | $                         |      |   |                    | $ |       |   |  | $ | 7,125  |  
|Affiliated customers                                            |  |          | 3     |        |   | 504   |  |   | 10        |   |  |                           |      |   |                    |   |       |   |  |   | 517    |  
|Intersegment revenue                                            |  |          | 7     |        |   | 286   |  |   | 179       |   |  |                           |      |   |                    |   | (472   | ) |  |   |       |  
|Total operating revenue                                         |  |          | 3,061 |        |   | 2,107 |  |   | 2,946     |   |  |                           |      |   |                    |   | (472   | ) |  |   | 7,642  |  
|Depreciation, depletion and amortization                        |  |          | 63    |        |   | 92    |  |   | 751       |   |  |                           |      |   |                    |   |       |   |  |   | 906    |  
|Equity in earnings of equity method investees                   |  |          | 2     |        |   | 13    |  |   | 2         |   |  |                           |      |   |                    |   |       |   |  |   | 17     |  
|Interest income                                                 |  |          | 19    |        |   | 9     |  |   | 2         |   |  |                           | 237   |   |                    |   | (252   | ) |  |   | 15     |  
|Interest and related charges                                    |  |          | 97    |        |   | 41    |  |   | 179       |   |  |                           | 213   |   |                    |   | (252   | ) |  |   | 278    |  
|Income tax expense (benefit)                                    |  |          | 76    |        |   | 185   |  |   | 383       |   |  |                           | (6    | ) |                    |   |       |   |  |   | 638    |  
|Loss from discontinued operations, net of tax                   |  |          |      |        |   |      |  |   |          |   |  |                           | (59   | ) |                    |   |       |   |  |   | (59    | )
|Net income (loss)                                               |  |          | 157   |        |   | 263   |  |   | 608       |   |  |                           | (255  | ) |                    |   |       |   |  |   | 773    |  
|Investment in equity method investees                           |  |          |      |        |   | 98    |  |   |          |   |  |                           | 63    |   |                    |   |       |   |  |   | 161    |  
|Capital expenditures                                            |  |          | 124   |        |   | 289   |  |   | 1,895     |   |  |                           |      |   |                    |   |       |   |  |   | 2,308  |  
|Total assets                                                    |  |          | 4,744 |        |   | 3,739 |  |   | 11,848    |   |  |                           | 4,197 |   |                    |   | (4,725 | ) |  |   | 19,803 |  
|2005                                                            |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|Operating revenue:                                              |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|External customers                                              |  | $        | 3,121 |        | $ | 1,371 |  | $ | 2,379     |   |  | $                         |      |   |                    | $ |       |   |  | $ | 6,871  |  
|Affiliated customers                                            |  |          | 2     |        |   | 1,141 |  |   | 19        |   |  |                           |      |   |                    |   |       |   |  |   | 1,162  |  
|Intersegment revenue                                            |  |          | 30    |        |   | 287   |  |   | 207       |   |  |                           |      |   |                    |   | (524   | ) |  |   |       |  
|Total operating revenue                                         |  |          | 3,153 |        |   | 2,799 |  |   | 2,605     |   |  |                           |      |   |                    |   | (524   | ) |  |   | 8,033  |  
|Depreciation, depletion and amortization                        |  |          | 82    |        |   | 86    |  |   | 495       |   |  |                           |      |   |                    |   |       |   |  |   | 663    |  
|Equity in earnings (losses) of equity method investees          |  |          | 1     |        |   | 13    |  |   | 2         |   |  |                           |      |   |                    |   |       |   |  |   | 16     |  
|Interest income                                                 |  |          | 11    |        |   | 2     |  |   | 5         |   |  |                           | 206   |   |                    |   | (211   | ) |  |   | 13     |  
|Interest and related charges                                    |  |          | 68    |        |   | 36    |  |   | 119       |   |  |                           | 203   |   |                    |   | (211   | ) |  |   | 215    |  
|Income tax expense (benefit)                                    |  |          | 75    |        |   | 160   |  |   | 289       |   |  |                           | (207  | ) |                    |   |       |   |  |   | 317    |  
|Cumulative effect of change in accounting principle, net of tax |  |          |      |        |   |      |  |   |          |   |  |                           | (2    | ) |                    |   |       |   |  |   | (2     | )
|Net income (loss)                                               |  |          | 157   |        |   | 234   |  |   | 529       |   |  |                           | (367  | ) |                    |   |       |   |  |   | 553    |  
|Investment in equity method investees                           |  |          | 14    |        |   | 95    |  |   | 36        |   |  |                           | 65    |   |                    |   |       |   |  |   | 210    |  
|Capital expenditures                                            |  |          | 142   |        |   | 267   |  |   | 1,522     |   |  |                           |      |   |                    |   |       |   |  |   | 1,931  |  
|Total assets                                                    |  |          | 5,000 |        |   | 3,515 |  |   | 13,846    |   |  |                           | 5,062 |   |                    |   | (5,521 | ) |  |   | 21,902 |  
|2004                                                            |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|Operating revenue:                                              |  |          |       |        |   |       |  |   |           |   |  |                           |       |   |                    |   |        |   |  |   |        |  
|External customers                                              |  | $        | 2,627 |        | $ | 949   |  | $ | 1,913     |   |  | $                         |      |   |                    | $ |       |   |  | $ | 5,489  |  
|Affiliated customers                                            |  |          | 2     |        |   | 1,047 |  |   |          |   |  |                           |      |   |                    |   |       |   |  |   | 1,049  |  
|Intersegment revenue                                            |  |          | 63    |        |   | 213   |  |   | 132       |   |  |                           |      |   |                    |   | (408   | ) |  |   |       |  
|Total operating revenue                                         |  |          | 2,692 |        |   | 2,209 |  |   | 2,045     |   |  |                           |      |   |                    |   | (408   | ) |  |   | 6,538  |  
|Depreciation, depletion and amortization                        |  |          | 82    |        |   | 79    |  |   | 459       |   |  |                           |      |   |                    |   |       |   |  |   | 620    |  
|Equity in earnings (losses) of equity method investees          |  |          | 3     |        |   | 12    |  |   | (2        | ) |  |                           | 1     |   |                    |   |       |   |  |   | 14     |  
|Interest income                                                 |  |          | 7     |        |   | 1     |  |   | 2         |   |  |                           | 181   |   |                    |   | (183   | ) |  |   | 8      |  
|Interest and related charges                                    |  |          | 46    |        |   | 31    |  |   | 76        |   |  |                           | 197   |   |                    |   | (183   | ) |  |   | 167    |  
|Income tax expense (benefit)                                    |  |          | 84    |        |   | 143   |  |   | 263       |   |  |                           | (8    | ) |                    |   |       |   |  |   | 482    |  
|Net income (loss)                                               |  |          | 184   |        |   | 228   |  |   | 520       |   |  |                           | (65   | ) |                    |   |       |   |  |   | 867    |  



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



As of
December 31, 2006 and 2005, less than 1% of our total long-lived assets were associated with international operations. For the years ended December 31, 2006, 2005 and 2004, less than 1% of our operating revenues were associated with
international operations. NOTE 26. GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED) Capitalized Costs The aggregate amounts of costs capitalized for gas and oil producing activities and related aggregate amounts of
accumulated depletion follow:  At December 31,

2006

2005(millions)Capitalized costs:Proved properties

$
12,574

$
10,855Unproved properties


2,263


2,07714,837


12,932Accumulated depletion:Proved properties


5,311


4,367Unproved properties


326


2915,637


4,658Net capitalized costs

$
9,200

$
8,274 Total Costs Incurred The
following costs were incurred in gas and oil producing activities:  Year Ended December 31,

2006

2005

2004(millions)Property acquisition costs:Proved properties

$
82

$
87

$
19Unproved properties


154


126


101236


213


120Exploration costs


382


231


197Development costs(1)


1,305


1,090


811Total

$
1,923

$
1,534

$
1,128  (1)
Development costs incurred for proved undeveloped reserves were $295 million, $281 million and $162 million for 2006, 2005 and 2004, respectively. Results of Operations We caution that the following standardized disclosures
required by the FASB do not represent the results of operations based on our historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and
corporate overhead.  Year Ended December 31,

2006

2005

2004(millions)Revenue (net of royalties) from:Sales to nonaffiliated companies

$
1,741

$
1,352

$
1,169Transfers to other operations


220


234


167Total


1,961


1,586


1,336Less:Production (lifting) costs


446


339


259Depreciation, depletion and amortization


734


492


457Income tax expense


285


281


243Results of operations

$
496

$
474

$
377


Company-Owned Reserves Estimated net quantities of proved gas and oil
(including condensate) reserves in the United States at December 31, 2006, 2005 and 2004, and changes in the reserves during those years, are shown in the two schedules that follow:  2006


2005


2004(billion cubic feet)Proved developed and undeveloped reservesGasAt January 1

4,219


4,202


4,039Changes in reserves:Extensions, discoveries and other additions

380


224


325Revisions of previous estimates

44


21


177Production

(272
)

(242
)

(264
)Purchases of gas in place

48


36


10Sales of gas in place

(91
)

(22
)

(85
)At December 31

4,328


4,219


4,202Proved developed reservesGasAt January 1

3,059


3,049


2,902At December 31

2,898


3,059


3,049Proved developed and undeveloped reservesOil(thousands of barrels)At January 1

197,284


142,635


147,954Changes in reserves:Extensions, discoveries and other additions

10,678


5,400


7,699Revisions of previous estimates(1)

40,584


65,146


(1,749
)Production

(23,773
)

(14,543
)

(11,117
)Purchases of oil in place

615


69


666Sales of oil in place

(9,752
)

(1,423
)

(818
)At December 31(2)

215,636


197,284


142,635Proved developed reservesOilAt January 1

144,417


100,780


53,776At December 31

172,505


144,417


100,780  (1)
The2006 revision is comprised of approximately 27.6 million barrels of natural gas liquids and 13 million barrels of oil/condensate. Natural gas liquids revisions were primarily the
result of additional contractual changes with third-party gas processors in which we now take title to our processed natural gas liquids, and residue gas and liquids reserve amounts recognized under such contracts. Oil/condensate revisions were
primarily the result of positive performance revisions at Gulf of Mexico deepwater locations. The 2005 revision is primarily due to an increase in plant liquids that resulted from a contractual change for a portion of our gas processed by third
parties. We now take title to and market the natural gas liquids extracted from this gas. (2)
Ending reserves for 2006, 2005 and 2004 included 99.2, 108.6 and 128.7 million barrels of oil/condensate, respectively, and 116.4, 88.7 and 13.9 million barrels of natural gas liquids,
respectively.




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Standardized Measure of Discounted Future Net Cash Flows and Changes Therein The following tabulation has been prepared in accordance with the FASBs rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities that we own:  2006

2005

2004(millions)Future cash inflows(1)

$
33,235

$
54,510

$
32,115Less:Future development costs(2)


2,933


1,795


1,436Future production costs


5,734


6,534


4,676Future income tax expense


8,100


16,559


8,856Future net cash flows


16,468


29,622


17,147Less: annual discount (10% a year)


9,359


16,573


9,286Standardized measure of discounted future net cash flows

$
7,109

$
13,049

$
7,861  (1)
Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at year-end. (2)
Estimated future development costs, excluding abandonment, for proved undeveloped reserves are estimated to be $690 million, $458 million and $329 million for 2007, 2008 and 2009,
respectively. In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual
arrangements or market prices at year-end. Future costs of developing and producing the proved gas and oil reserves reported at the end of each year shown were based on costs determined at each such year-end, assuming the continuation of existing
economic conditions. Future income taxes were computed by applying the appropriate year-end or future statutory tax rate to future pre-tax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions,
permanent differences and tax credits. It is not intended that the FASBs standardized measure of discounted future net cash flows
represent the fair market value of our proved reserves. We caution that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10%
discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.


The following tabulation is a summary of changes
between the total standardized measure of discounted future net cash flows at the beginning and end of each year:  2006


2005


2004(millions)Standardized measure of discounted future net cash flows at January 1

$
13,049


$
7,861


$
7,279Changes in the year resulting from:Sales and transfers of gas and oil produced during the year, less production costs


(2,596
)


(2,244
)


(1,647
)Prices and production and development costs related to future production


(10,054
)


7,459



1,327Extensions, discoveries and other additions, less production and development costs


621



1,090



948Previously estimated development costs incurred during the year


295



281



162Revisions of previous quantity estimates


316



26



(102
)Accretion of discount


2,025



1,187



1,075Income taxes


3,729



(3,189
)


(551
)Other purchases and sales of proved reserves in place, net


(314
)


71



(386
)Other (principally timing of production)


38



507



(244
)Standardized measure of discounted future net cash flows at December 31

$
7,109


$
13,049


$
7,861 NOTE 27. QUARTERLY FINANCIAL DATA (UNAUDITED) A summary of our quarterly results of operations for the years ended December 31, 2006 and 2005 follows. Amounts shown reflect all adjustments necessary in the opinion of management for a fair statement of the
results for the interim periods. Because a major portion of the gas sold or transported by our distribution operations is ultimately used for space heating, both revenue and earnings are subject to seasonal fluctuations. Seasonal fluctuations may be
further influenced by the timing of rate relief granted under regulation to compensate for the increased cost of providing service to customers. As described in Note 9, we reported the operations of the Armstrong facility as discontinued operations
beginning in the fourth quarter of 2006. Prior quarters for 2006 and 2005 have been recast to conform to this presentation. All differences between amounts presented below and those previously reported in our Quarterly Reports on Forms 10-Q during
2006 and 2005 are a result of reporting the results of operations of Armstrong as discontinued operations.




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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, CONTINUED



FirstQuarter


SecondQuarter


ThirdQuarter


FourthQuarter


Full Year(millions)2006Operating revenue

$
2,821


$
1,544


$
1,505


$
1,772


$
7,642Income from operations


517



304



615



286



1,722Income from continuing operations


202



152



341



137



832Loss from discontinued operations


(1
)


(2
)


(1
)


(55
)


(59
)Net income


201



150



340



82



7732005Operating revenue

$
2,372


$
1,573


$
1,460


$
2,628


$
8,033Income (loss) from operations


500



434



(407
)


530



1,057Income (loss) from continuing operations before cumulative effect of change in accounting principle


288



251



(298
)


314



555Income (loss) from discontinued operations


(1
)










1



Cumulative effect of change in accounting principle














(2
)


(2
)Net income (loss)


287



251



(298
)


313



553 Our 2006 results include the impact of the following significant items: n


First quarter results include a $94 million after-tax charge resulting from the write-off of certain regulatory assets related to the pending sale of Peoples and
Hope and the establishment of $107 million of deferred tax liabilities associated with the excess of our financial reporting basis over the tax basis in the stock of Peoples and Hope. The recognition of these deferred tax liabilities was partially
offset by a $25 million tax benefit


from the partial reversal of previously recorded valuation allowances on certain federal and state tax loss carryforwards, since the carryforwards are
expected to be utilized to offset capital gain income that will be generated from the sale of Peoples and Hope. We also recognized a $76 million after-tax benefit resulting from favorable changes in the fair value of certain gas and oil derivatives
that were de-designated as hedges following the 2005 hurricanes. n


Third quarter results include a $171 million after-tax benefit from business interruption insurance revenue related to Hurricanes Katrina and Rita (2005
hurricanes). n


Fourth quarter results include a $55 million after-tax loss associated with the discontinued operations of our Armstrong power generating facility as a result of
its pending sale and a $17 million after-tax impairment charge resulting from the cancellation of a pipeline project. Our 2005 results
include the impact of the following significant items: n


First quarter results include $31 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges, resulting from a delay in
reaching anticipated production levels in the Gulf of Mexico, and subsequent changes in the fair value of those hedges and a $28 million after-tax benefit due to the recognition of business interruption insurance revenue associated with the recovery
of delayed gas and oil production due to Hurricane Ivan. n


Second quarter results include an $86 million after-tax benefit due to the final settlement of business interruption insurance claims associated with Hurricane
Ivan. n


Third quarter results include a $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. n


Fourth quarter results include a $77 million after-tax benefit reflecting the impact of a decrease in gas and oil prices on hedges that were de-designated following
Hurricanes Katrina and Rita.




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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.


ITEM 9A. CONTROLS AND PROCEDURES Senior management, including our Chief Executive Officer and Chief Financial Officer,
evaluated the effectiveness of our Companys disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, our Chief Executive Officer and Chief Financial Officer have concluded that
our Companys disclosure controls and procedures are effective. There were no changes in our Companys internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably
likely to materially affect, our Companys internal control over financial reporting. ITEM 9B. OTHER INFORMATION None.




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PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Omitted pursuant to General Instruction I.(2)(c). We have adopted a Code of Ethics that applies to our principal executive, financial and accounting officers as well as our employees. This Code of Ethics
is available at the corporate governance section of Dominions website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning us at: Corporate Secretary, 120 Tredegar Street, Richmond,
Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to our Code of Ethics will be posted on the Dominion website. ITEM 11. EXECUTIVE COMPENSATION Omitted pursuant to General Instruction I.(2)(c). ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS Omitted pursuant to
General Instruction I.(2)(c).


ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE Omitted pursuant to General Instruction
I.(2)(c). ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The following table presents fees paid to Deloitte & Touche LLP for
the fiscal year ended December 31, 2006 and 2005:  Type of Fees

2006

2005(millions)Audit fees

$
2.30

$
1.51Audit-related


0.37


0.40Tax fees





0.02All other fees





$
2.67

$
1.93 Audit Fees are for the audit and review of our financial statements in accordance with
generally accepted auditing standards, including comfort letters, statutory and regulatory audits, consents and services related to Securities and Exchange Commission matters. Audit-Related Fees are for assurance and related services that are related to the audit or review of our financial statements, including employee
benefit plan audits, due diligence services and financial accounting and reporting consultation. Tax Fees are for tax compliance
services. In 2003, the Board adopted a pre-approval policy for Deloitte & Touche LLP services and fees. Attached to the policy is
a schedule that details the services to be provided and an estimated range of fees to be charged for such services. In December 2006, Dominions Audit Committee approved the services and fees for 2007.




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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Certain documents are filed as part of this Form 10-K and are
incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 20.

All schedules are omitted because they
are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

2. 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|    | 
|4.1 |  | Indenture, dated as of May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and
Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012, incorporated by reference); Fifteenth Supplemental Indenture dated as of October 1, 1989 (Exhibit (5) to Certificate of Notification at
Commission File No. 70-7651, incorporated by reference); Seventeenth Supplemental Indenture dated as of August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Eighteenth Supplemental
Indenture dated as of December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167, incorporated by reference); Nineteenth Supplemental Indenture dated as of January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the
fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Twentieth Supplemental Indenture dated as of March 19, 2001 (Exhibit 4, Form 10-Q for the quarter ended September 30, 2003, File No. 1-3196, incorporated by
reference).                                                                                                                                                                                                                                                                                                                                                                                                                            
|    | 
|4.2 |  | Indenture, dated as of April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to United States Trust Company of New York) (Exhibit (4) to
Certificate of Notification at Commission File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4 A)(ii), Form 10-K for the fiscal year ended December 31, 1999, File No. 1-3196, incorporated by reference); Securities
Resolution No. 1 effective as of April 12, 1995 (Exhibit 2 to Form 8-A filed April 21, 1995 under File No. 1-3196 and relating to the 73/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2 to Form 8-A filed October 18, 1996 under file No. 1-3196 and relating to the 67/8% Debentures Due October 15, 2026); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2 to
Form 8-A filed December 12, 1996 under file No. 1-3196 and relating to the 65/8% Debentures Due December 1,
2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2 to Form 8-A filed December 12, 1997 under file No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October
20, 1998 (Exhibit 2 to Form 8-A filed October 22, 1998 under file No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended
December 31, 1999, File No. 1-3196, and relating to the 71/4% Notes Due October 1, 2004, incorporated by
reference).
|    | 
|4.3 |  | Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form
S-3 File No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K, File dated April 12, 2001, File No. 1-3196
incorporated by reference); Second Supplemental Indenture, dated October 25, 2001 (Exhibit 4.1, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Third Supplemental Indenture, dated October 25, 2001
(Exhibit 4.3, Form 8-K, dated October 23, 2001, File No. 1-3196, incorporated by reference); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K, dated May 22, 2002, Form 1-3196, incorporated by reference); Form of
Fifth Supplemental Indenture (Exhibit 4.2, Form 8-K, filed November 25, 2003, Form 1-3196, incorporated by reference); Form of Sixth Supplemental Indenture (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196, incorporated by
reference).                                                                                                                                                                                                                                                                                                                                                                                                                                                                            
|    | 
|4.4 |  | Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to Bank One Trust Company,
National Association) (Exhibit 4.2, Form S-3 Registration No. 333-52602, as filed on December 22, 2000, incorporated by reference); as supplemented by the First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K, dated October 16,
2001, File No. 1-3196, incorporated by reference).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          



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|     |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|---- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|4.5  |  | Indenture, dated as of December 11, 1997, between Louis Dreyfus Natural Gas Corp., Dominion Oklahoma Texas Exploration & Production, Inc., and La Salle Bank National Association (formerly
LaSalle National Bank) (Exhibit 4.6, Form 10-K for the fiscal year ended December 31, 2001, File No. 1-8489, incorporated by reference); as supplemented by the First Supplemental Indenture, dated as of November 1, 2001 (Exhibit 4.9, Form 10-Q for
the quarter ended September 30, 2001, incorporated by reference).
|     | 
|10.1 |  | $3.0 billion Five-Year Credit Agreement dated February 28, 2006 among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company, JPMorgan Chase Bank, N.A.,
as Administrative Agent, Citibank, N.A., as Syndication Agent and Barclays Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents and other lenders named therein. (Exhibit 10.1, Form 8-K filed March 3,
2006, File No. 1-3196, incorporated by reference).       
|     | 
|10.2 |  | $1.70 billion Amended and Restated Five-Year Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and
KeyBank National Association, as Syndication Agents and SunTrust Bank, The Bank of Nova Scotia and ABN AMRO Bank N.V., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No. 1-3196,
incorporated by reference).                                     
|     | 
|10.3 |  | $1.05 billion 364-Day Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclays Bank PLC, as Administrative Agent, Barclays Bank PLC and Key Bank National
Association, as Syndication Agents, The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch and Mizuho Corporate Bank, Ltd., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.3, Form 8-K, filed March
3, 2006, File No. 1-3196, incorporated by reference).          
|     | 
|12   |  | Ratio of earnings to fixed charges (filed herewith).                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|     | 
|23.1 |  | Consent of Deloitte & Touche LLP (filed herewith).                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|     | 
|23.2 |  | Consent of Ryder Scott Company, L.P. (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
(furnished herewith).                                                                                                                                                                                                                                                                                                     



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Signatures

Pursuant to the requirements of Section 13 or 15(d) 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 COMPANYBy:

/S/    THOMAS F. FARRELL,
II(Thomas F. Farrell, II,Chairman of the Board of Directors, Presidentand Chief Executive Officer)


Date: February 28, 2007

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February,
2007.



|                                                   |  |                                                                                  
|-------------------------------------------------- |  | ---------------------------------------------------------------------------------
|Signature                                          |  | Title                                                                            
|                                                   | 
|/S/    THOMAS F. FARRELL,
II Thomas F. Farrell, II |  | Chairman of the Board of Directors, President and Chief Executive Officer        
|                                                   | 
|/S/    THOMAS N.
CHEWNING Thomas N. Chewning       |  | Director, Executive Vice President and Chief Financial Officer                   
|                                                   | 
|/S/    STEVEN A.
ROGERS Steven A. Rogers           |  | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)



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