Visit us online at: Dominion’s common stock trades under ticker D:NYSE Investor Meetings December 2006 New Dominion

2 This presentation contains certain forward-looking statements including our projected future long-term operating earnings growth rates, projected future earnings mix, projected future trading multiples and projected use of proceeds that are subject to various risks and uncertainties. Factors that could cause actual results to differ materially from management's projections, forecasts, estimates and expectations may include factors that are beyond the company's ability to control or estimate precisely, such as fluctuations in energy-related commodity prices, including changes in the cost of fuel for our regulated electric business, the timing of the closing dates of acquisitions or divestitures (including any divestiture of our natural gas and oil assets), risks associated with the realignment of our operating assets (including costs associated with any sale of our exploration and production business and the costs and reinvestment risks related to the redeployment of proceeds from any sales), realization of and timing of the receipt of expected business interruption insurance proceeds, additional risk exposure associated with the termination of business interruption and offshore property damage related to our exploration and production operations and our inability to replace such insurance on commercially reasonable terms, estimates of future market conditions, estimates of proved and unproved reserves, the company’s ability to meet its natural gas and oil production forecasts, the behavior of other market participants, and the effects of hurricanes on our operations, gas and oil production and realized prices. Other factors include, but are not limited to, weather conditions, governmental regulations, economic conditions in the company's service area, risks of operating businesses in regulated industries that are subject to changing regulatory structures, changes to regulated gas and electric rates collected by Dominion, risks associated with the realignment of our operating assets (including the potential dilutive effect on earnings in the near term, costs associated with any sale of our exploration and production business and the redeployment of proceeds from any sales), changes to rating agency requirements and ratings, changing financial accounting standards, trading counter-party credit risks, risks related to energy trading and marketing, and other uncertainties. Other risk factors are detailed from time to time in Dominion’s most recent quarterly report on Form 10-Q or annual report on Form 10-K filed with the Securities & Exchange Commission. Important Notes to Investors

3 New Dominion Asset Mix (Focus Area = East of Mississippi)

4 New Dominion Earnings Mix 2006 E&P Generation Energy Delivery Energy Generation Appalachia 36%* <5%* E&P Generation Energy Delivery 40%* Status Quo 2008 New Dominion *Excludes earnings from gas and oil production from Dominion Transmission properties included in Dominion Energy.

New Dominion: How We Got There

6 A Changing Earnings Mix 1997 to Present 2006E 1997 E&P Generation Energy Delivery VP DCI DEI- Gen DEI- E&P UK 36%* 3% *Excludes earnings from gas and oil production from Dominion Transmission properties included in Dominion Energy.

7 The Symptom: P/E Discount 2008 P/E 23% Discount To Utility Peers Multiples based on 20-day average ended Oct.31.

8 The Symptom: P/E Discount 2008 P/E 15% Discount To Commodity Sensitive Peers Multiples based on 20-day average ended Oct.31.

9 The Symptom: P/E Discount 2008 P/E And Only A Little Better Than E&P “Peers” Multiples based on 20-day average ended Oct.31.

10  D viewed as a conglomerate, thus, CONGLOMERATE DISCOUNT  E&P Concerns Have Drawn Attention Away from Dominion’s Other Businesses  Commodity Price Sensitivity = Heavy Discounting of Forward Earnings Estimates  General Business Risk of E&P Adds to Equity Risk Premium  Split Shareholder Base  E&P Investors Don’t Want to Invest in Utility  Utility Investors Don’t Want to Invest in E&P  So... Who Wants To Invest in a Combination Utility/E&P? Reasons for the P/E Discount

11 Potential Cure: The IPO/Spin Option  Advantages:  Avoid tax leakage  Keep company together for employees  Disadvantages:  Public market discount relative to asset value  30% discount offsets tax leakage of 25-28%  Possible large equity issuance at D needed to pay down debt  Results from limited debt capacity of stand-alone E&P  IPO discount  15-20% discount  Longer timeline  Adds additional operational, financial and market risk to equation for Dominion shareholders due to length of time to execute  Tax free benefits of IPO limited by Dominion’s tax basis in SpinCo assets  Loss of cash flow coverage to maintain/grow dividend at remaining Dominion

+ Dominion Generation, Energy, Delivery + Dominion Appalachia - Sell E&P = THE VALUE EQUATION

13 Two Categories of Consideration  The Obvious  The Not So Obvious

14 Obvious Modeling Assumptions  Use a comparable transaction analysis to estimate gross sales price  Use tax basis, tax rate and tax shields provided to estimate net proceeds  Assume net proceeds are used to pay down debt and buy back stock  Assume D trades at peer multiple post divestiture

15 The Not So Obvious  Quality, size and potential of E&P reserves being sold should command a premium to comparable transactions  Buyer tax basis step up enhances asset value vs. public market value  Dominion has a number of opportunities to enhance net cash proceeds Monetize underperforming assets to yield investable cash and enhance ROIC/EPS  Use of proceeds to strengthen credit metrics should provide financial benefits beyond immediate EPS Lower cost of capital should enhance ability to add accretive assets to portfolio at higher earnings and cash flow  New Dominion’s asset mix should command a premium multiple to peers Result - lower equity cost of capital

16 New Dominion Financial Attributes  Lower cost of equity  Reduced risk profile/lower borrowing costs  Continued emphasis on improving ROIC  Secure dividend with more opportunity for future growth

New Dominion: Operational Excellence, Organic Growth, Investment Opportunities

18 New Dominion Long-Term Growth Rate Delivery ~20%2-3% Generation>55%5-6% Energy~20%5-6% Appalachia <5%2-3% Consolidated100%4-6%  High growth electric service territory  Dominion East Ohio infrastructure opportunities  Dominion Retail 10-15% growth  High quality, low-cost generation fleet  Merchant generation assets located in NE market  Uprates and other organic growth potential  Acquisition opportunities  Well situated mid-stream assets  High value service offerings  Organic infrastructure growth  Acquisition opportunities  High drilling success rate  High potential drilling prospects  Very low decline rate EPS Projected Growth Rate Key Attributes Approximate % of Total Operating Unit 2008 EPS

19 Electric Service Reliability Is Improving 8% Improvement Average Customer Minutes Out Excluding Major Storms On target for improvement over 2005 Minutes out YTD reflects performance through October 2006.

20 Virginia Service Territory Ranked “Tops” Sources: unemployment: U.S. Bureau of Labor Statistics Sept. 06; Top States Forbes.com August 2006; Tax-friendly The Tax Foundation, 2006; State growth , Source: VA Economic Development Partnership; Bond ratings: Moody's Investors Service, 2005 State Debt Medians; Bureau of Economic Analysis; High-tech growth: Cyberstates 2006 Report  Ranked #1 among “Top States for Business” by Forbes.com  #1 national leader in high-tech job growth  AAA bond rating (one of only 7 states)  Ranked as 10 th most tax-friendly state  Unemployment rate in Virginia of 3.1% below US rate of 4.4%  State growth rate of 6.9% above US rate of 5.3%  ~40,000 new customer accounts annually in service territory

21 Cleveland Akron Canton Cleveland Akron Canton Northern VA Central VA Tidewater Northern VA Central VA Tidewater New Service Installations 56,902 51,243 55,505 58,077 18,293 18,417 17,791 16, ,000 40,000 60,000 80, ElectricGas New Service Installations Drive Growth

22 Dominion Retail’s Performance Also a Driver *Projected

23 Excellent Operations Exist at Generation YTD reflects performance through September 2006.

24  Unit uprates  Millstone Unit 3 power uprate*  Potential coal turbine uprates  Ongoing initiatives to enhance margins  Salem Harbor alternative fuel co-firing  Ash disposal  Southwest Virginia Coal Plant  Potential site expansions  Possum Point  Kincaid  North Anna Power Station *Included in current plan Along with Expansion Possibilities

25 Planned Environmental Spending = Competitive Advantage  VA and WVA: pre-2000 controls ($400 million)  Scrubber at Mt. Storm  Monitors and NOx controls (system wide)  Clover scrubbers  U.S. EPA Agreement: since 2001 controls ($1.6 billion)  Scrubbers (Chesterfield, Mt. Storm)  SCRs (Chesterfield, Mt. Storm, Chesapeake)  SNCRs (Clover, Chesapeake, Yorktown)  Convert Possum Point 3 & 4 from coal to gas  Build gas-fired Possum Point 6  Current plan to meet:  VA and Merchant: New EPA Rules ($800 million)  Scrubbers  Additional SCRs  Mercury control equipment  New England: State specific regulations in ($500 million)  Scrubbers  Additional SCRs  Mercury control equipment

26 Excellence at Dominion Energy  No unscheduled Firm Gas Service interruptions - 5 years without incident  Set new electric system peak of 19,375 MW on August 3, 2006 with no operational issues  Electric Transmission Minutes Out: YTD on track to meet goal 2.5 YTD 06 vs 4.0 YTD 05 Electric Trans Minutes Out YTD reflects performance through October 2006.

27 A Solid Track Record of Growth Projects in Energy In-service Date 935.0*5,100$1,200Existing Gas Rate Base as of ,915 $2, Planned Gas Rate Base 12.81,750$1,020 Cove Point Expansion & DTI/Cove Point Auxiliaries $85Northeast Storage 35.03,815 $1,680 Planned Growth CapEx $100Cove Point East and 5 th Tank $75Mid-Atlantic 5.01,000$350Cove Point Purchase & Reactivation $50Capstone Storage (Bcf) Firm Transportation (MDt/d) CapEx (millions) Project * Operated by DTI; includes LDC Storage

28 As Well As Transmission Expansion Potential Lower basis value Rockies Supply Gulf Supply Canadian Supply Web Growth

29 Cove Point LNG Terminal 50 Miles Dominion Conventional Acreage Dominion E&P Offices Major Pipelines Dominion Storage Fields Appalachian Acreage Well-Positioned

30 With Impressive Drilling Characteristics *Unaudited estimated Appalachian proved reserves as of 9/30/06 ~1.1 Tcfe; proved reserves as of 12/31/05 ~1.0 Tcfe. Includes 183 Bcfe of proved reserves owned by Dominion Transmission and reported in Dominion Energy.  1.1 Tcfe proved reserves*  High drilling success rate and low cost  Low decline rate ~5%  300 wells drilled annually  Upper Devonian Sandstone  Conventional plays

31 And Steady Growth in Production Volumes reflect Net Revenue Interest for Dominion E&P and Dominion Transmission plus VPP Volumes produced in Appalachia. Natural Gas Liquid volumes first recorded in 2001.

32 As Well As Promising Initiatives  Unconventional Gas Resources  Tight Gas Sands  Devonian Shale  Coalbed Methane (CBM)  Cutting Edge Technology  Horizontal Drilling  State of the Art IT Applications  Geoscience  Land (GIS - Property Management) Engineering

33 In Summary, A Full Pipeline of Opportunities 2H  Potential SW VA Coal Plant in service  E&P Auction begins  LDC Sale close  Cove Point construction began  SCC Hearing on SW VA Coal Plant  New England FCM goes into effect  Millstone uprate  July 1 Fuel Factor Reset, Pass-Through Begins  Market- based rates in VA  DTI Storage and Transmission Expansion  Cove Point expansion in service

34 Supports An Achievable Long-Term Growth Rate  One of the strongest electric utility franchise areas  One of the premier gas LDC’s in nation  Successful, growing retail program  Diverse, merchant electric generation portfolio  One of the nation’s most active LNG facilities  One of the world’s largest natural gas storage systems  Natural gas pipeline among the most efficient and profitable in industry  Low risk gas and oil operation with ~9,000 producing wells and 7,000 prospective drilling sites 4-6% Long Term EPS Growth* *Projected

Appendix

36 New Dominion Key Modeling Considerations  Proved E&P reserves estimate as of 9/30/06 (excluding Appalachia): 5.5 Tcfe*  Book value of E&P (excluding Appalachia): $10.5 billion  Comparable transaction values  Suggested source: J. S. Herold financial database  Tax basis of E&P assets (excluding Appalachia): $3.8 billion  Tax rate: 37%  Average cost of debt: ~6.5% (Pre-tax)  Credit objective: maintain existing credit metric targets Adjusted Debt to Capitalization <= 50% Adjusted FFO to Interest >= 4.2x  Estimated E&P earnings mix in 2008 (as % of operating earnings)  Status Quo E&P: ~40% of total status quo earnings  Appalachian Only: <5% of total New Dominion earnings  Annual Appalachian CapEx: $ million  New ongoing Dominion operating earnings projected growth rate: 4-6% *As of 9/30/06, total unaudited estimated proved reserves ~6.6 Tcfe; Non-Appalachian reserves ~5.5 Tcfe; Appalachian reserves ~ 1.1 Tcfe

37 E&P Reserve Locations Proved reserves (Bcfe) as of December 31, 2005:6,268 Daily Production (Mmcfe/day) YTD December 31, 2005:1,050 1 Canada Proved Reserves (Bcfe):220 Daily Production (Mmcfe/day):55 2 Gulf Coast Proved Reserves (Bcfe):475 Daily Production (Mmcfe/day):158 3 Gulf of Mexico Proved Reserves (Bcfe):986 Daily Production (Mmcfe/day):331 4 Appalachia* Proved Reserves (Bcfe):1,005 Daily Production (Mmcfe/day):106 5 Mid-Continent Proved Reserves (Bcfe):703 Daily Production (Mmcfe/day):108 6 Permian Proved Reserves (Bcfe):2,096 Daily Production (Mmcfe/day):168 7 Rocky Mountain/Other Proved Reserves (Bcfe):533 Daily Production (Mmcfe/day):100 = 100 BCFe Major Producing Areas Non- Appalachia Appalachia 8 Michigan Proved Reserves (Bcfe):250 Daily Production (Mmcfe/day):24 * Includes 183 Bcfe of proved reserves owned by Dominion Transmission and reported in Dominion Energy. Total unaudited estimated proved reserves as of 9/30/06 ~6.6 Tcfe Appalachia unaudited estimated proved reserves as of 9/30/06 ~1.1 Tcfe Non-Appalachia unaudited estimated proved reserves as of 9/30/06 ~5.5 Tcfe

38 Reserve characteristics

39 Reserve Detail

40 Daily Production

41 Appalachia Hedge Position Hedges as of 11/1/06

42 Non-Appalachia Hedge Position Hedges as of 11/1/06

43 Total Hedge Position Hedges as of 11/1/06

44 Average North American Oil & Gas Reserve Replacement ( ) (includes acquisitions) Source: John S. Herold, Inc. Financial Database (8/06)

45 Average North American Reserve Replacement Cost ( ) $/mcfe (includes acquisitions) Source: John S. Herold, Inc. Financial Database (8/06)

46 Average North American Operating Expense ( ) $/mcfe Source: John S. Herold, Inc. Financial Database (8/06)

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