August 22, 2008

Mr. H. Christopher Owings

Assistant Director

Division of Corporation Finance

U.S. Securities and Exchange Commission

100 F Street NE

Washington, DC 20549

RE:            Dominion Resources, Inc.

Annual Report on Form 10-K for the Year Ended December 31, 2007

Filed February 28, 2008

Definitive Proxy Statement on Schedule 14A

Filed April 4, 2008

File No. 1-08489

Dear Mr. Owings:

Dominion Resources, Inc. (the Company) received the Staff's letter dated August 8, 2008, which provided comments on the above-referenced documents.  References to "Dominion" in the letter refer to Dominion Resources, Inc. and its consolidated subsidiaries. This response letter has been filed on EDGAR, and a copy has been sent by facsimile.

As requested by the Staff, the Company hereby acknowledges the following:

· The Company is responsible for the adequacy and accuracy of the disclosures in its filings with the SEC;

· Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking action with respect to the filings; and

· The Company may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

For your convenience, the Staff's comments are set forth below and are followed by the Company's responses.

Annual Report on Form 10-K for the Year Ended December 31, 2007

Item 7. Management’s Discussion and Analysis of Financial Condition, page 21

Staff Comments:

1. In future filings, please expand this section to discuss known material trends, demands, commitments, events, or uncertainties that will have, or are reasonably likely to have, a material impact on your financial condition, operating performance, revenues, or income, or result in your liquidity decreasing or increasing in any material way.  See Item 303 of Regulation S-K and SEC Release No. 33-8350.  For example, on page 24 of your document, you state that you have strong growth in your electric transmission and distribution operations, particularly in the major metropolitan areas of Virginia, due to higher energy use and efficient operations and maintenance spending.  However, you fail to discuss the reasons that there has been higher energy use in the major metropolitan areas and how you have made your operations and maintenance spending more efficient.  As another example, throughout this section, you state that much of your operations are dependent on certain weather conditions.  However, you do not discuss the type of weather conditions that positively and negatively affect your operations.  As a further example, we note that you have not discussed in great detail how, if at all, the recent escalation in certain commodity prices affects you.  In future filings, please discuss in greater detail the trends and factors, such as these, that contribute to your overall financial position and affect your operations.

Response

We are committed to providing investors with information that establishes a basis for understanding the key drivers of our business and, to discussing known trends, demands, commitments, events or uncertainties that are likely to materially impact our results of operations and/or financial condition.  We have included most of our disclosures of this nature under the heading Outlook on page 34 and in the Future Issues and Other Matters section beginning on page 43 of our Annual Report on Form 10-K.  For example, we have discussed the issues associated with fuel cost recovery in Virginia under the heading Virginia Fuel Expenses on page 44.  We have also discussed weather effects on our business in terms of year-over-year changes in heating and cooling degree days in our consolidated and segment operations discussions on pages 29-36.  In years when storms materially affect us, we also discuss them.  In addition, we highlight the issue of extreme weather events under the heading Forward-Looking Statements on page 23 and in Item 1A. Risk Factors.

Each reporting period, we consider how to best present our MD&A to readers, and will take your comments regarding the inclusion of additional details on material trends into account as we work on future filings.

Critical Accounting Policies and Estimates, page 25

Staff Comments:

2. We note your disclosure on pages 26 and 62 that the use of different valuation models or assumptions could have a material effect on a contract’s estimated fair value.  In future filings, please revise the critical accounting policy disclosure to provide an overview of the contracts which are subject to internal fair value estimation, for example the amount or amounts of any long-dated commodity contracts, the specific numerical inputs used to estimate fair value, and a comprehensive sensitivity analysis that allows the reader to estimate possible future impacts to net income.  See Item 303 of Regulation S-K as well as section five of the Commission’s Interpretive Release on Management’s Discussion and Analysis of Financial Condition and Results of Operation which is located on our website at http://www.sec.gov/rules/interp/33-8350.htm.

Response

In future filings, the Company will revise its critical accounting policy disclosure to provide the requested information related to contracts subject to significant internal fair value estimation. For Dominion, these contracts are now disclosed in more detail in the “Fair Value Measurement” footnote in our quarterly 10-Q filings. We will also include a reference in MD&A critical accounting policies to the footnote to the financial statements that provides information related to contracts subject to significant internal fair value estimation. Furthermore, we will provide information about the types and sources of inputs used to estimate fair value for these contracts. Finally, we will provide a sensitivity analysis for contracts subject to significant internal fair value estimation, which will estimate future impacts to net income under certain potential market scenarios.

Results of Operations, page 29

Liquidity and Capital Resources, page 37

Staff comments:

3. In future filings, please expand your liquidity discussion to address the cash flow effects regarding the discontinued operations discussed in note 6, such as the Canadian E&P operations, Gichner and Dallastown, and the Peaker facilities.  Prospectively, please revise to disclose the following information:

· Describe how cash flows from discontinued operations are reported in the cash flow statement;

· Quantify the cash flows from discontinued operations by operating, investing, and financing herein; and

· Describe how the absence of cash flows, or negative cash flows, from discontinued operations is expected to affect future liquidity and capital resources.

Response

Dominion will expand its liquidity discussion in future filings to discuss the cash flow effects of its discontinued operations.

Contractual Obligations, page 41

Staff comments:

4. Please reconcile for us other long term liabilities on the balance sheet of $1,072 million to the table of contractual obligations.  Prospectively, please ensure that your table of contractual obligations includes other long term cash liabilities reflected on balance sheet.  See Item 303(a)(5) of Regulation S-K.

Response

We believe that all other long-term liabilities that meet the disclosure requirements of Regulation S-K, Item 303(a)(5) are properly included in our table of contractual obligations.

Please see the following table for a reconciliation of the amounts reported in Other long-term liabilities on the Consolidated Balance Sheet to the amounts reported in our contractual obligations table, including a brief description of why we believe these items were appropriately excluded from the contractual obligations table.

Reconciliation of Other liabilities per Balance Sheet to Contractual Obligations table
As of December 31, 2007
(in millions)
Other long-term liabilities per Balance Sheet	$1,072
Less:  Items excluded from Other long-term liabilities per Contractual Obligations table	1,019	A
Other long-term liabilities per Contractual Obligations table	$     53

A. Items included in other long-term liabilities in the Consolidated Balance Sheet but excluded from the other long-term liabilities section of the Contractual Obligations table consist of employee benefit obligations ($695 million), the long-term portion of taxes payable ($149 million), including those related to unrecognized income tax benefits, and other individually insignificant miscellaneous non-current liabilities which were excluded from the contractual obligations table since these items will either not require cash payment upon settlement or the timing of payment is uncertain.

As discussed in footnote 6 to our contractual obligations table, the amounts exclude employee benefit obligations since they are not contractually fixed as to timing and amount.  Footnote 6 also indicates that certain amounts related to taxes payable are excluded from the table due to the uncertainty about the timing and amounts that will ultimately be paid to settle these items.  We also include a reference to Notes 9 and 23 to the Consolidated Financial Statements, where these items are discussed.  We believe these items are appropriately excluded from the contractual obligations table since Item 303(a)(5) indicates that the tabular disclosure of contractual obligations should contain “pertinent data to the extent necessary for an understanding of the timing and amount of the registrant’s specified contractual obligations.”

Note 2. Significant Accounting Policies, page 58

Staff comments:

5. We read your disclosure regarding the reapplication of SFAS no. 71 to the Virginia jurisdiction of the company’s utility generation operations.  Please address the following points with regard to this issue:

· Please provide to us your accounting analysis with regard to the reapplication of Statement no. 71.  Please explain how the company met all the criteria of paragraph 5 of SFAS no. 71.  In this regard, we read your disclosure on page 25 that the Virginia General Assembly enacted legislation in April 2007 to return the Virginia jurisdiction of your utility generation operations to a modified cost-of-service rate model.

· We also read your disclosure on page 43 that indicated after the end of capped rates, the Virginia State Corporation Commission (Virginia Commission) will set base rates under a modified cost-of-service model, although you disclose that capped rates end on December 31, 2008.  In this regard, please explain to us why April 2007 was the appropriate point in time to reapply Statement no. 71.

Response:

Dominion’s wholly-owned electric utility subsidiary, Virginia Electric and Power Company (Virginia Power), is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina.  Comprehensive electric industry restructuring legislation was enacted in Virginia on March 25, 1999 through the Virginia Electric Utility Restructuring Act (the "1999 Virginia Restructuring Act").  The 1999 Virginia Restructuring Act provided a detailed timeline for the transition from a cost-based environment to a competitive market for electric generation in Virginia.  It addressed, among other things: capped base rates, RTO participation, retail choice, the recovery of stranded costs, and the functional separation of a utility's electric generation from its electric transmission and distribution.  Under the 1999 Virginia Restructuring Act, as amended in 2004 and 2006, Virginia Power’s base rates were capped until December 31, 2010 and fuel factor provisions were locked in until July 1, 2007.

Effective with the enactment of the 1999 Virginia Restructuring Act, which was designed to move from a regulatory environment and promote  competitive market forces for electric generation, Virginia Power’s generation operations discontinued application of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71) in accordance with the EITF’s consensus on Issue 1 in Issue No. 97-4, Deregulation of the Pricing of Electricity—Issues Related to the Application of FASB Statements No. 71 and 101 (EITF 97-4). In EITF 97-4 the EITF concluded “. . . that when deregulatory legislation is passed or when a rate order (whichever is necessary to effect change in the jurisdiction) that contains sufficient detail for the enterprise to reasonably determine how the transition plan will affect the separable portion of its business whose pricing is being deregulated is issued, the enterprise should stop applying [SFAS No. 71] to that separable portion of its business.”  

On April 4, 2007, the Virginia General Assembly passed legislation (the 2007 legislation) that amended the 1999 Virginia Restructuring Act to return the Virginia jurisdiction of Virginia Power’s utility generation operations to a modified cost-of-service rate model, subject to rate caps in effect through December 31, 2008.  In addition to providing for traditional recovery of base cost of service,the Virginia model has been modified to provide for the following additional rate-making enhancements:

· authorize stand-alone rate increases for recovery of certain costs, including qualified new generation projects, major generation unit modifications, environmental compliance projects, FERC-approved costs for transmission service, and energy efficiency, conservation, and renewable energy programs;

· provide an enhanced return on common equity on new capital expenditures as a financial incentive for construction of certain major generation projects and for various other achievements such as generating plant performance and operating efficiency; and

· establish a return on common equity no lower than that reported by at least a majority of a group of  electric utilities within the southeastern U.S., with certain limitations, as described in the 2007 legislation.

The 2007 legislation also reinstated annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs beginning July 1, 2007.

With the enactment of legislation on April 4, 2007 re-regulating utility generation, the circumstances that gave rise to deregulation as assessed under EITF 97-4 were no longer present and accordingly, Dominion reassessed whether it met the three criteria in paragraph 5 to apply SFAS No. 71 to Virginia Power’s generation operations.  Paragraph 5 of SFAS No. 71, lists three criteria that an enterprise with regulated operations must satisfy in order to apply the provisions of the standard:

Criterion 5.a. The enterprise’s rates for regulated services or products provided to its customers are established by or are subject to approval by an independent, third-party regulator or by its own governing board empowered by statute or contract to establish rates that bind customers.

In connection with the discontinuance of SFAS No. 71 for the generation portion of Virginia Power’s business in 1999, emphasis was placed on the following provisions of the 1999 Virginia Restructuring Act:

Section §56-577 Schedule for transition to retail competition; Commission authority, which stated in part:

A.3. On and after January 1, 2002, the generation of electric energy shall no longer be subject to regulation under this title, except as specified in this chapter.

Section §56-582.B provided that the Virginia State Corporation Commission (Virginia Commission) could adjust capped rates only in connection with (i) the Company’s recovery of fuel costs, (ii) any changes in taxation of electric utility revenues by the Commonwealth of Virginia, and (iii) any financial distress of the utility beyond its control.  Except for these circumstances, the Company was precluded from requesting rate increases and the Virginia Commission could not initiate proceedings to change the Company’s rates.

Per the original legislation, customer choice began on January 1, 2002, and generation pricing was to be based on competitive market pricing after July 2007.  The Virginia Commission’s authority to regulate and adjust Virginia Power generation’s base rates as required by criterion (a) was taken away effective January 1, 2002; therefore, criterion (a) was no longer met as of that date.

The 2007 legislation amended §56-577 Schedule for transition to retail competition; Commission authority of the Restructuring Act so that it now reads:

A.2. The generation of electric energy shall be subject to regulation as specified in this chapter.

The amendments made to the 1999 Virginia Restructuring Act pursuant to the 2007 legislation reinstated the Virginia Commission’s authority over electric utility generation as of the date the legislation was enacted. Accordingly, criterion 5.a. of SFAS No. 71 was met on April 4, 2007.

Criterion 5.b. The regulated rates are designed to recover the specific enterprise’s costs of providing the regulated services or products.

The Virginia Commission sets Virginia Power’s base (non-fuel) rates based on cost-of-service studies specific to Virginia Power’s costs.  Virginia Power’s base rates during the capped-rate period were established as part of the 1998 settlement of Virginia Power’s then current Virginia rate proceeding.  In that proceeding, Virginia Power had filed a cost-of-service study which supported maintaining the base rates in effect as of March 1, 1997.  The negotiated settlement included a one-time refund and other rate reductions during 1998 and 1999.

An important characteristic of base rates is that they are reset only as needed.  Although the individual components of the base cost of service change over time, a change in rates may not be necessary for several reasons.  Some individual specific costs may increase over a period of time while others decrease over the same period.  Alternatively, increased costs may result in an increased revenue requirement, but growth in customer sales may provide sufficient revenue to provide recovery of such cost increases, as well as continue to provide a return on common shareholder’s equity.  Accordingly, specificity of the individual components of the cost of service underlying the regulated rates is not required to meet criterion 5.b of SFAS No. 71.  While SFAS No. 71 does not explicitly make such a statement in regards to criterion 5.b., the FASB does address criterion 5.b. in paragraph 65, which states:

The second criterion is that the regulated rates are designed to recover the specific enterprise's costs of providing the regulated services or products. If rates are based on industry costs or some other measure that is not directly related to the specific enterprise's costs, there is no cause-and-effect relationship between the enterprise's costs and its revenues. In that case, costs would not be expected to result in revenues approximately equal to the costs; thus, the basis for the accounting specified in this Statement is not present under that type of regulation. That criterion is intended to be applied to the substance of the regulation, rather than its form.

From a practical perspective, if the FASB had intended cost specificity as a requirement for meeting criterion 5.b., it would have focused its guidance in paragraph 65 on the meaning of “specific costs” rather than “specific enterprise.”  The portion of the capped rates that were attributable to the generation portion of Virginia Power’s business (Virginia Power generation) were based on the specific enterprise’s (in this case, Virginia Power generation’s) base costs.  Certain individual specific costs for Virginia Power’s generation operations have increased and some have decreased during the capped rate period but, in addition to these changes, Virginia Power generation has also experienced growth in customer sales over the same period.

The cause-and-effect relationship of costs and revenues in the rate-regulated environment discussed in SFAS No. 71 is particularly relevant in periods of rising costs.  If there is not sufficient growth in customer sales or a mechanism for an entity’s rates to increase in tandem with its costs, it will not recover its allowable costs and thus will not be able to meet criterion 5.b.  The capped rates provided by the 1999 Virginia Restructuring Act were intended to compensate Virginia Power for continuing to provide generation services and to allow Virginia Power to incur costs to restructure such operations during the transition period to deregulation. Although the Virginia Commission has continually monitored Virginia Power’s financial results during the capped rate period via Annual Informational Filings, the 1999 Virginia Restructuring Act did not provide an opportunity for the Virginia Commission to reduce base rates during the transition period to deregulation if Virginia Power “over-earned.”  While certain costs have increased since the 1999 Virginia Restructuring Act was enacted, Virginia Power generation has taken steps to lower its cost structure and has also experienced customer growth. As a result, management expected at April 4, 2007 and continues to believe that existing capped rates will result in recovery of the costs of providing service as well as a return on common equity through the termination of capped rates on December 31, 2008.

The legislation enacted on April 4, 2007 (1) reinstated the authority of the Virginia Commission to regulate rates charged by the generation portion of Virginia Power’s business and (2) provides for specific stand-alone rate increases, subject to the Virginia Commission’s jurisdiction, to recover the costs of qualified new generation projects, major generation unit modifications, environmental compliance projects, FERC-approved costs for transmission service, and energy efficiency, conservation, and renewable energy programs.

For this reason and the reasons stated above, the generation portion of Virginia Power’s business satisfied on April 4, 2007, and will continue to satisfy through the end of the capped rate period and beyond, criterion 5.b. of SFAS No. 71.

Criterion 5.c. In view of the demand for the regulated services or products and the level of competition, direct and indirect, it is reasonable to assume that rates set at levels that will recover the enterprise’s costs can be charged to and collected from customers.  This criterion requires consideration of anticipated changes in levels of demand or competition during the recovery period for any capitalized costs.

Demand for electricity has increased significantly in Virginia Power's service area, especially in northern Virginia where such demand has grown approximately forty percent over the last decade and is projected to grow by another eight percent by 2011.  The 1999 Virginia Restructuring Act made customer choice available for electric utility generation since January 1, 2002; however, to date, competition in Virginia has not developed to any significant extent.  The 2007 legislation officially ends retail choice at the end of 2008 for all but individual customers with a demand of more than 5 megawatts and non-residential retail customers who obtain Virginia Commission approval to aggregate their load to reach the 5 megawatt threshold.  Retail choice, however, effectively ended on the date the 2007 legislation was enacted, as it is highly unlikely that competitors would enter the marketplace after that date – thus eliminating the anticipated changes in the level of competition for Virginia Power’s generation services.  Therefore, on April 4, 2007 it became reasonable to assume, given the demand for Virginia Power’s generation services and the practical elimination of customer choice, that Virginia Power’s generation rates will be set at levels that will recover its costs and that those rates can be charged to and collected from customers.  Accordingly, criterion 5.c. of SFAS No. 71 was met on April 4, 2007 when the 2007 legislation was enacted.

For the reasons stated above, all three criteria of paragraph 5 of SFAS No. 71 were satisfied on April 4, 2007 when the 2007 legislation was enacted; therefore Dominion reapplied SFAS No. 71 to the Virginia jurisdiction of its utility generation operations on that date.

Staff comments:

· Please provide to us your regulatory assessment that supported the recorded regulatory assets and liabilities explaining in detail how the criteria in paragraphs 7 and 9 of Statement no. 71 were met.

· Please tell us and disclose in future filings the nature and amount of the principal items entering into the determination of the charge of $259 million.

Response:

Upon the reapplication of SFAS No. 71 to the Virginia jurisdiction of its utility generation operations, Dominion recognized the following significant regulatory assets and liabilities. The amounts were measured in accordance with paragraph 9, for regulatory assets, and paragraph 11, for regulatory liabilities.

Nuclear decommissioning trust – As discussed in Note 2 in Dominion’s Annual Report on Form 10-K for the year ended December 31, 2007, upon the reapplication of SFAS No. 71 to the Virginia jurisdiction of its utility generation operations, Dominion recorded a $259 million ($158 million after tax) extraordinary charge and reclassified $195 million ($119 million after tax) of unrealized gains from accumulated other comprehensive income in order to establish a $454 million long-term regulatory liability for amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of its utility nuclear generation stations, in excess of amounts recorded pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations.  Dominion’s management believes that upon re-regulation Virginia Power’s customers are financially responsible for the costs necessary to decommission its nuclear power stations.  Consequently Virginia Power is accountable to its customers for any excess amounts collected from Virginia jurisdictional customers, and earnings thereon, for the future decommissioning of its North Anna and Surry nuclear stations.  Likewise, any underrecoveries, should they occur, would be recoverable from customers.  According to Paragraph 11a of SFAS No. 71, “A regulator may require refunds to customers.   Refunds that meet the criteria of paragraph 8 (accrual of loss contingencies) of FASB Statement No. 5, Accounting for Contingencies, shall be recorded as liabilities and as reductions of revenue or as expenses of the regulated enterprise.”  Since the Company believes it is probable it would have to credit to its customers, upon completing decommissioning of its nuclear facilities, any excess nuclear decommissioning funds, the Company recorded pursuant to the aforementioned guidance in paragraph 11a, a regulatory liability for the excess of the nuclear decommissioning trust funds over the decommissioning liability calculated in accordance with SFAS No. 143.  Dominion will continue to disclose the nature and amount of the $259 million extraordinary charge recorded upon reapplication of SFAS No. 71 in future filings, as applicable.

Unrecognized pension and other postretirement benefit costs – This regulatory asset represents unrecognized pension and other postretirement benefit costs that were previously recorded in accumulated other comprehensive income pursuant to SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans, that are expected to be recovered through future rates for the Virginia jurisdictional generation operations.  Previously, the Virginia Commission had permitted the Company to recover in rates those costs commensurate with expenses recognized under either SFAS No. 87, Employers’ Accounting for Pensions, or SFAS No. 106, Employer’s Accounting for Postretirement Benefits Other Than Pensions. At the reapplication date of SFAS No. 71 and the date of our filing, the Company was not aware of any regulatory actions or change in accounting practices that would indicate the Virginia Commission would not provide future recovery for these costs under historical premises. Accordingly, Dominion believes that future recovery of these costs is probable and satisfies the requirements of paragraph 9 of SFAS No. 71.

Staff comments:

· Please explain your basis for treating the charge of $259 million as an extraordinary item.

Response:

As noted in SFAS No. 101, Regulated Enterprises – Accounting for the Discontinuation of Application of FASB Statement No. 71 (SFAS No. 101), the FASB concluded that the accounting for the reapplication of SFAS No. 71 is beyond the scope of SFAS No. 101.  Absent direct accounting guidance, Dominion considered the guidance in APB No. 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions (APB No. 30), which requires that an extraordinary item is both unusual in nature and infrequent in occurrence.  APB No. 30 explains that the environment in which an entity operates, the nature and extent of government regulation and the probability of recurrence of a particular event or transaction in the foreseeable future should be considered in determining whether an item is both unusual and infrequent.

Virginia has historically regulated its electric utilities until its experiment with electric generation deregulation that began with the 1999 Virginia Restructuring Act.  After determining that electric deregulation did not create competition and would not benefit consumers, Virginia passed the 2007 legislation to re-regulate electric utilities in Virginia.  Dominion views Virginia’s return to regulation as both an unusual and infrequent event in Virginia and believes the recurrence of deregulation is remote in the foreseeable future.  Based on the guidance in APB No. 30 and by analogy to the guidance in SFAS No. 101 for discontinuing the application of SFAS No. 71, Dominion classified the impact of reapplying SFAS No. 71 as an extraordinary item.

Staff comments:

· Please tell us the updates you made to other assumptions that were not in conjunction with the reapplication of Statement no. 71 and quantify for us the related change expected to annual depreciation.

Response:

In Note 2 to Dominion’s annual report on Form 10-K for the year ended December 31, 2007, Dominion discloses:

In October 2007, we revised the depreciation rates for our utility generation assets to reflect the results of a new depreciation study, which incorporates the property, plant and equipment accounting policy changes that were made upon the reapplication of SFAS No. 71, as well as updates to other assumptions.  This change is expected to increase annual depreciation expense by approximately $54 million ($33 million after tax).

The expected annual increase in depreciation expense of approximately $54 million includes an annual increase of approximately $57 million due to changes as a result of the SFAS No. 71 reapplication, offset by an estimated annual decrease of $3 million as a result of certain property, plant and equipment life extensions outside of the scope of the reapplication of SFAS No. 71. The life extensions resulted from the reassessment of the appropriateness of the useful lives of the Company’s property, plant and equipment based on current data and its impact on assumptions about the future.

Definitive Proxy Statement on Schedule 14A

Item 1 – Election of Directors, page 10

Staff comments:

6. In future filings, please disclose the business experience of all of your directors during the past five years, including each person’s principal occupations and employment, the name and principal business of any corporation or other business association, and whether any of the business associations are your parent, subsidiary, or other affiliate.  See Item 401(e)(1) of Regulation S-K.

Response

The description for each director nominee included in the 2008 Proxy Statement does reflect the business experience of each director for at least the past five years as required by Item 401(e)(1) of Regulation S-K, including the principal occupation and employment, the name and principal business of any corporation or other business association, and if applicable, the identification of any business association that is a parent, subsidiary or other affiliated company.  In future filings, we will clarify that the business experience listed is the experience/position each director has held for the past five years, indicate the relevant time periods as appropriate and necessary, and address any business associations that are our parent, subsidiary or other affiliate.

Compensation Discussion and Analysis, page 14

Staff comments:

7. We note that you benchmark the components of base pay, annual incentive pay, long-term pay, and total compensation of each officer’s position against one or more appropriate job matches from certain surveys, based on primary job responsibilities and scope of the position, which is typically based on revenue or asset size, and in some circumstances, on number of employees.  In future filings, please provide greater detail regarding these benchmarks and identify their components pursuant to Item 402(b)(2)(xiv) of Regulation S-K.

Response

In the event we engage in any benchmarking of total compensation or any material element of compensation, in future filings we will provide greater detail regarding such benchmarks and will identify the benchmark components.

The Annual Incentive Program, page 17

Staff comments:

8. While you have disclosed the consolidated operating earnings and business unit targets, you have not provided a quantitative discussion of the terms of all of the necessary targets to be achieved for your named executive officers to earn the annual bonus.  For example, you have not disclosed the safety, emergency response, response to power outages, environmental, and other targets you have mentioned on page 19.  Please tell us whether you believe that disclosure of that information would result in competitive harm such that the information could be excluded under Instruction 4 to Item 402(b) of Regulation S-K.  If disclosure of the performance-related factors would cause competitive harm, in future filings, please discuss how difficult it will be for the executive or how likely it will be for you to achieve the target levels or other factors.

Response

As stated on page 18 of the 2008 Proxy Statement, the 2007 annual bonuses for the named executive officers were based solely on the consolidated earnings goal, with the CGN Committee having negative discretion to reduce final payouts for all the named executive officers to the extent appropriate based on any goal accomplishment that was less than 100% of the established corporate-wide Six Sigma Goal.  In addition, business unit financial goals and operating and stewardship goals (e.g. goals such as safety and other targets mentioned on page 19 of the 2008 Proxy Statement) were established for the named executive officers other than the CEO and CFO, but achievement of such goals was not necessary for these officers to earn their full annual bonus.  The goals applied only to the extent the CGN Committee deemed it appropriate to take these goals into consideration in its exercise of negative discretion to reduce final payouts for these named executive officers.  In other words, these goals could only have a potential negative impact on payouts if they were not achieved; they could not and did not have a positive impact.  Also, the decision to take one or more of those goals into consideration was discretionary for the CGN Committee.  For 2007 annual bonuses, the CGN Committee reduced the payout for all named executive officers for reasons unrelated to these goals.  The CGN Committee made an additional small reduction of 3.7%  in the bonus for one named executive officer primarily due to performance in relation to one of these goals.

Because these goals were discretionary goals by which the CGN Committee could reduce payouts, rather than necessary targets to be achieved to earn a full payout, we did not deem them material and therefore did not provide a quantitative discussion of the terms of each operating and stewardship target.  Additionally, none of the operating and stewardship goals on an individual basis had more than a 3.75% potential negative impact on the payout to a named executive officer.

Whether or not disclosure of material operating and stewardship goals for named executive officers would result in competitive harm will depend each year on the specific targets established for that year.  In future filings, if we determine disclosure would not result in competitive harm, we will provide a quantitative discussion of any material operating and stewardship targets for the named executive officers, including targets applicable to the exercise of negative discretion.  If we determine that such disclosure would cause competitive harm, we will discuss factors that impact achievement of the targets and the difficulty for the executive or likelihood of the Company achieving the target.

If you have any questions or require further information, please call Ash Sawhney at (804) 771-3962 or fax him at (804) 771-6519 or call me at (804) 819-2450 or fax me at (804) 819-2638.

Sincerely,

/s/ Thomas P. Wohlfarth

Thomas P. Wohlfarth

Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)