April 14, 2008

Via EDGAR

Mail Stop 7010

Mr. H. Roger Schwall
Assistant Director
Division of Corporation Finance
U.S. Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010

Re:

ConocoPhillips Form 10-K for the fiscal year ended December 31, 2007 File No. 001-32395

Dear Mr. Schwall:

Our responses to the comments raised in your letter dated March 31, 2008, are set forth below. The Staff’s comments are shown in bold followed by our responses.

Pursuant to Rule 83 of the Freedom of Information Act, a request for confidential treatment by the Staff has been submitted concurrently with this letter to the Office of Freedom of Information. Accordingly, this letter is filed via EDGAR in a redacted version, with redactions indicated by the notation <redact>, and is provided to the Staff (Mr. Karl Hiller, Branch Chief), in paper format in its entirety, pursuant to Rule 101(c)(1)(i) of Regulation S-T.

Form 10-K for the Fiscal Year Ended December 31, 2007

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 48

Business Environment and Executive Overview, page 48

1.

We note you identify three primary ways that you add to your proved reserve base and that, for the three years ending December 31, 2007, your reserve replacement ratio was 186 percent. We believe the following additional information would assist readers in understanding the relevance of the measure you disclose:

a)

An explanation of how the ratio is calculated; and if the information used to calculate this ratio is not derived directly from the line items disclosed in your reconciliations of beginning and ending proved reserve quantities on pages 176-179, a tabulation showing your computation with a reconciliation of the various components utilized to the amounts in your SFAS 69 disclosures.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 2

	b)		The extent to which the proved reserves that have been added are either proved developed or proved undeveloped; also indicating the portion attributable to entities accounted for using the equity method (i.e., to reserves which you are prohibited from tabulating jointly under paragraph 14(c) of SFAS 69).
	c)		A disaggregation of your reserve replacement ratio for you and the consolidated entities together, and separately for equity method investees, showing the extent to which it is attributable to revisions, improved recovery, purchases, and extensions and discoveries for each year in the three-year period, and in the aggregate.
	d)		The nature of any material uncertainties pertaining to undeveloped or newly discovered reserves which may impact the time horizon over which the reserve additions are expected to be developed and produced.
	e)		An indication of how management uses this measure, and any limitations.

		Please submit the information outlined above.
		Response: We believe the information contained in our proved reserves tables on pages 176 through 179, along with the additional information provided in Management’s Discussion and Analysis (MD&A) on pages 79, 87 and 88 of our 2007 Form 10-K present the information necessary for investors to calculate the reserve replacement ratio, the extent to which reserve additions are due to proved developed or proved undeveloped reserves, the reserve replacement ratio for our consolidated entities and our equity affiliates for each year in the three-year period and in the aggregate, and the extent to which each category of change in reserves impacted the reserve replacement ratio.
		(a) We calculate the Company’s reserve replacement ratio by dividing the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries, and sales) for the most recent three years by the sum of our production (including that used for fuel gas) for the same time period, all taken directly from the proved reserves tables included in the supplemental oil and gas disclosures prepared under the guidance of SFAS 69 on pages 176 through 179. In view of the Staff’s comment, in future Form 10-K filings we will add an explanation of how we calculate the reserve replacement ratio.
		(b) Our proved reserves tables show consolidated operations and equity affiliate information separately, and do not tabulate jointly as prohibited per SFAS 69. However, management believes the information about our proportionate share of equity affiliates is necessary for a full understanding of our operations because equity affiliate operations are an integral part of the overall success of our oil and gas operations. As such, in MD&A, where we disclose our reserve replacement ratio, we do so on a combined basis. Also, in MD&A under the caption “Proved Undeveloped Reserves” in the Capital Resources and Liquidity section on page 79, we disclose the percentage split of our net additions of proved undeveloped reserves for each of the three years ending December 31, 2007, on a combined basis. Using this information in conjunction with the reserves tables on pages 176 through 179, an investor can calculate the split of the net additions of proved developed and proved undeveloped reserves for each year and in the aggregate.
		(c) Our reserve replacement ratio for our consolidated operations was 166 percent for the three years ending December 31, 2007, and 60 percent, 301 percent and 124 percent for the one-year periods ending in 2007, 2006 and 2005, respectively. Our reserve replacement ratio for our equity affiliate operations was 260 percent for the three years ending December 31, 2007, and negative 80 percent, 319 percent and 656 percent for the one-year periods ending in 2007, 2006 and 2005, respectively.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 3

		(d) We believe the disclosures in MD&A under the caption “Proved Undeveloped Reserves” in the Capital Resources and Liquidity section on page 79 appropriately discuss the information requested by the Staff in this request (d), including our historical percentages of net reserve additions that were attributable to proved undeveloped reserves, a historical and forward-looking disclosure of the percentage of undeveloped reserves converted to developed reserves, and a listing of major projects associated with the majority of our proved undeveloped reserves. In addition, in MD&A under the caption “Proved Oil and Gas Reserves and Canadian Syncrude Reserves” in the Critical Accounting Estimates section on pages 87 and 88, we provide the nature of any material uncertainties pertaining to undeveloped or newly discovered reserves.
		(e) As discussed in MD&A on page 71, to maintain or grow production volumes, we must continue to add to our proved reserves base. The reserve replacement ratio is used by management and the industry to measure how successful a company has been in adding to its proved reserves base. A limitation of the measure is that in any given year, a large reserve addition due to a business acquisition or large field discovery may mask longer-term trends in replacing reserves. Accordingly, in our Form 10-K, we reference a three-year average to help mitigate this limitation.

Results of Operations, page 53

General

2.		In this section, you often refer to two or more factors that contributed to material changes over the reported periods. Please confirm that in future filings you will quantify the amount of the changes contributed by each of the factors or events that you identify as they relate to revenues, operating expenses and other income or expenses. Instead of simply using the terms “primarily” or “partially” to describe changes, quantify the amount of the change that is attributable to the source you identify. See section III.D of SEC Release 33-6835 (May 18, 1989).
		Response: We confirm that in future filings we will continue to quantify, where material to an understanding of the variance, individual factors discussed in the variance explanation of changes over reported periods. Some examples of this practice in our 2007 Form 10-K include quantifying the following items in the Results of Operations section:

	•		The amount of the complete impairment of our Venezuelan oil interests, on pages 53, 54, and 59.
	•		The negative earnings impact on our E&P segment of United Kingdom increased income tax rates, on page 61.
	•		Our net share of a gain from the sale of DCP Midstream’s interest in TEPPCO, on page 62.
	•		The benefit from the liquidation of prior year layers under the LIFO method, on page 64.
	•		A deferred tax benefit related to tax legislation in Germany, on page 64.
	•		The cumulative effect of adopting FIN 47, on page 65.
	•		The recognition of a net business interruption insurance benefit, on page 65.
	•		A capital-loss tax benefit, on page 67.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 4

		An important aspect to consider in this regard is our layered approach to disclosures in this section of MD&A. We are more likely to quantify individual items in our segment variance explanations, than in our consolidated results, as the materiality determinations will be at a lower quantitative threshold at the segment level, than at the consolidated level.
		In addition, we believe that in many cases, use of the terms “primarily” or “partially offset by” appropriately serve to convey the causes of material changes from period to period, in accordance with Instruction 4 to Regulation S-K Item 303(a). The absence of a quantification of individual named items covered by the terms “primarily” or “partially offset by” conveys the concept that no individual item need be quantified to assist the reader in understanding a variance between the two periods. Stated differently, we would not rely solely on the term “primarily” if quantification were required to convey material information. However, in light of the Staff’s comment, we will look for further opportunities to quantify material factors in our variance explanations in future filings.

Commercial Paper and Credit Facilities, page 72

3.		It does not appear that you have filed the agreement underlying your $7.5 billion revolving credit facility. Tell us why you do not believe that it should be filed as an exhibit pursuant to Item 601(b)(10) of Regulation S-K.
		Response: Based upon a quantitative and qualitative analysis of the agreement underlying our $7.5 billion revolving credit facility, we do not believe this agreement to be material to the Company at this time. Our ongoing analysis in this regard considers not only the size of the commitment and current debt levels, but also the fact that we currently do not have any outstanding borrowings under the facility. Likewise, the facility does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The primary use of the credit facility is as support for the Company’s commercial paper program. We continue to monitor the facility in light of the Company’s liquidity position and expected borrowings, if any, and, at this time, do not consider the agreement to be material.

Financial Statements and Supplementary Data, page 98

Note 10—Investments, Loans and Long-Term Receivables, page 122

LUKOIL, page 124

4.

We note your disclosure explaining that because LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occur subsequent to your reporting deadline, the amount of equity income you record is estimated, based on current market indicators and other publicly-available information; and that you reflect any adjustment necessary to record actual results in the next quarterly period. Tell us how you concluded that this equity investment earnings adjustment should be characterized as a change in estimate, rather than a correction of error, following the guidance in SFAS 154, if that is your view. Conversely, if you believe it is a non-material error, further disclosure may be necessary to comply with the guidance in SAB Topic 1:N. Please submit a schedule showing

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 5

		the impact of these adjustments for each quarterly period; and any disclosures that you propose to further clarify the nature of the adjustments.
		Response: SFAS 154, “Accounting Changes and Error Corrections,” defines a change in accounting estimate as: “a change that has the effect of adjusting the carrying amount of an existing asset or liability or altering the subsequent accounting for existing or future assets or liabilities. A change in accounting estimate is a necessary consequence of the assessment, in conjunction with periodic presentation of financial statements, of the present status and expected future benefits and obligations associated with assets and liabilities. Changes in accounting estimates result from new information.” An error is defined as: “an error in recognition, measurement, presentation, or disclosure in financial statements, resulting from mathematical mistakes, mistakes in the application of GAAP, or oversight or misuse of facts that existed at the time the financial statements were prepared.”
		A change in an accounting estimate is the result of new events, changing conditions, more experience, or additional information, any of which requires previous estimates to be revised. Although distinguishing between a change in estimate and correction of an error may sometimes be confusing, they differ in that a change in estimate is based on new information that was previously unavailable.
		Because LUKOIL’s current period U.S. GAAP financial results are not available to us at the time we prepare and file our financial statements, we consider the inherent adjustment resulting from this new information to be a change in estimate. We acknowledge any adjustments to our LUKOIL segment earnings resulting from the error factors noted above are subject to the guidance in SAB Topic 1:N.
		We believe the differences between estimated and actual LUKOIL results have been adequately disclosed (see page 66 of our 2007 Form 10-K) and therefore no additional disclosures are required in future filings.

Note 13—Impairments, page 131

5.		We understand that the Nationalization Decree issued by the president of Venezuela mandated the termination of the then-existing structures related to your heavy-oil ventures and oil production risk contracts, and the transfer of your rights to Venezuelan-controlled joint ventures, in which you would continue to hold an interest.
		We also note that you have been unable to reach agreement with respect to the migration of these activities mandated by the Nationalization Decree, and concluded that complete impairment was required in the second quarter of 2007, even though you are engaged in negotiations with the Venezuelan authorities concerning appropriate compensation, and believe you preserved all of your rights under the contracts, as stated on page 91.
		Tell us how you determined that you could reasonably estimate the amount of loss without regard to the amount of consideration to which you would be entitled, given your ongoing negotiations, preservation of rights, and seeing that other industry participants had reached agreement and concluded that full impairment of their interests had not occurred. It should be clear how you determined that the guidance of FIN 14, and paragraphs 8(b) and 32 of SFAS 5 did not apply to you, under the circumstances.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 6

		Provide us with a schedule showing the extent to which your interests would have been conveyed in order for PDVSA to secure the 60% level of control, which we understand was the objective of the Nationalization Decree. Advise us of the terms of compensation offered for your interests and any changes arising during the negotiations, specifying the corresponding dates of the initial offer and subsequent discussions.
		Response: On June 26, 2007, we announced we had rejected Venezuela’s demand that we relinquish our existing rights in the Petrozuata, Hamaca and Corocoro ventures. Our decision resulted in the expropriation by the Venezuelan government of our participation in the oil interests subject to the Nationalization Decree, and resulted in a different fact pattern and different applicable accounting guidance than those companies that reached agreement to migrate to an empresa mixta structure.
		Based on statements by the Venezuelan government that the expropriation of our oil interests in Venezuela occurred on June 26, 2007, from an accounting perspective, we viewed this as an involuntary disposition of our equity investments and oil interests to the Venezuelan government as of that date. Since we effectively no longer had title to these assets as of June 26, 2007, it was necessary to reflect this involuntary conversion event by fully writing off the carrying values of the net assets that were expropriated. We believe paragraph 8(b) of SFAS 5 requires an evaluation of the loss before any potential recoveries. Accordingly, since we were deprived of the use of the oil interests in Venezuela, the loss was reasonably estimable — it was the carrying value of the assets, plus allocable goodwill. We believe this represents the best estimate of the loss pursuant to FIN 14.
		In addressing the Staff’s specific references to SFAS 5, it is important to note paragraph 32 of SFAS 5 deals with the threat of expropriation, not accounting for situations where an expropriation has already occurred and is no longer a contingent event. We agree that, prior to June 26, 2007, paragraph 32 was appropriate guidance to our accounting situation, and our disclosures in Note 13—Contingencies and Commitments on pages 15 and 16 of our Form 10-Q for the quarterly period ended March 31, 2007, were based on its guidance. On June 26, 2007, the expropriation event occurred and it was no longer a contingent threat. Instead, expropriation was a past transaction that required accounting recognition.
		Following the loss of our oil interests, the key accounting issue was what, if any, potential compensation was appropriate to recognize. To answer that question, we then looked to the gain contingency accounting literature to determine the appropriate accounting for any future compensation we should receive for the expropriated assets. Paragraph 17(a) of SFAS 5 states, “Contingencies that might result in gains usually are not reflected in the accounts since to do so might be to recognize revenue prior to its realization.” Thus SFAS 5 cautions a conservative view should be taken in regards to recording any potential future compensation prior to its realization. Paragraph 3 of FIN 30, “Accounting for Involuntary Conversions of Nonmonetary Assets to Monetary Assets,” states that when a nonmonetary asset is destroyed in one period, and the amount of monetary assets to be received is not determinable until a subsequent period, the gain or loss should be recognized in accordance with SFAS 5. This expropriation is similar to condemnation of property in an eminent domain proceeding as discussed in FIN 30.
		Additionally, we gave great weight to the guidance in paragraph .140 of SOP 96-1, “Environmental Remediation Liabilities,” that states, “If the claim is the subject of litigation, a rebuttable presumption exists that realization of the claim is not probable.” Although SOP 96-1 deals with environmental remediation claims, we believe the fact pattern is analogous to an

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 7

		expropriation claim, and thus it was appropriate to apply paragraph .140’s guidance to our situation. At the date of our impairment on June 26, 2007, we could not conclude that it was probable we would reach a negotiated settlement prior to filing for arbitration, and this decision was verified by our international arbitration filing on November 2, 2007. Thus our claim for compensation was expected to, and in actuality did, become the subject of litigation. As such, we believe we could not, in light of paragraph .140 of SOP 96-1, take a position that realization of compensation was probable. In response to the Staff’s request to be advised of the terms of compensation offered, note that Venezuela never made a formal, fully-termed compensation offer to ConocoPhillips for expropriation of its Venezuelan oil interests.
		This accounting position is also supported by analogy to Example 8 in EITF 01-10. In that example, which deals with business interruption insurance recoveries, the EITF’s view was that a company should not recognize a gain on the potential insurance recovery because contingencies with respect to the validity of the claim remained unresolved, and a gain should not be recognized until those contingencies were resolved.
		Accordingly, based on the gain contingency guidance in SFAS 5, SOP 96-1 and EITF 01-10, any compensation for our expropriated assets is not yet considered recognizable since to do so would result in the recognition of compensation for a gain contingency prior to its realization. This conclusion was disclosed on page 12 in our Form 10-Q for the quarter ended June 30, 2007.
		Although it is now hypothetical and not relevant, to address the Staff’s inquiry on the extent to which our interests would have been conveyed for PDVSA to secure 60 percent control, we direct the Staff to the disclosure in our Form 10-Q for the quarterly period ended March 31, 2007, on page 56: “...and assuming PDVSA takes a 60 percent interest under the terms of the Nationalization Decree and our ownership interest is reduced pro rata, our ownership interests in Petrozuata, Hamaca and Corocoro would decrease from 50.1 percent, 40.0 percent and 32.2 percent to 40.0 percent, 22.9 percent and 19.8 percent, respectively.”
6.		We note you indicate that you classified the proved reserves related to your Petrozuata, Hamaca and Corocoro ventures in Venezuela as a “sale” in your subsequent reserves disclosures. Please tell us why you concluded that these reserves should be characterized as a sale, rather than something more descriptive as to the actual nature of and reason for their removal from your reserves, and indicate the portion of these reserves you would have retained had you opted to participate in the joint ventures with PDVSA.
		Response: In order to facilitate comparisons of our reserves disclosures to our peer companies, we prefer to report changes in our reserve quantities using the standard six disclosure categories required in paragraph 11 of SFAS 69. Expropriations are not one of the standard six categories required by SFAS 69. However, as a matter of international law, the expropriation event in Venezuela was an involuntary and forced sale, albeit one for which compensation, as of yet, has not yet been agreed upon. Therefore, we included the Venezuela expropriation impact in the category to which it is most closely related, “Sales.” On page 177 of our 2007 Form 10-K, we disclosed in an explanatory note to the crude oil proved reserves table that sales for our equity affiliates were primarily due to the expropriation of our oil interests in Venezuela. It is our understanding that presenting expropriation impacts as “Sales” in the reserves tables is consistent with how other companies have reported expropriation impacts in their filings.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 8

With regard to the Staff’s question about the portion of these reserves we would have retained had we agreed to participate in the migration to empresa mixta structures — answering that question would require the development of a hypothetical fact pattern of the final terms and conditions that would have ultimately been mandated by the Venezuelan government, an exercise we do not believe is relevant at this time as we made the decision not to agree to relinquish our existing rights in the Petrozuata, Hamaca and Corocoro ventures.

Note 14—Asset Retirement Obligations and Accrued Environmental Costs, page 133

7.		We see from your disclosure that you continue to exclude “market-risk premium” from your measurement of asset retirement obligations, stating that no examples exist of credit-worthy parties willing to assume such risk. We also note that, in your recent acquisition of Burlington Resources, you assumed certain asset retirement obligations, determining a fair value for such obligations as part of your purchase price allocation. Accordingly, considering your recent acquisition and corresponding valuation determination of the assumed asset retirement obligations, please tell us how you determined that excluding a market-risk premium from your periodic measurements is consistent with the guidance in paragraphs B22 and B23 of FIN 47, if that is your view.
		Response: The issue of whether the oil and gas industry has observable or determinable examples of “market-risk premiums” for asset retirement obligations (ARO) was debated in our industry during the implementation of SFAS 143 in 2002, and was discussed with the SEC Staff at that time by the large accounting firms. The following is Ernst & Young’s current interpretive guidance in their Accounting Manual on this issue:

			“I1.4.4.2 Market Risk Premium
			According to the FASB, the market risk premium is intended to reflect what a contractor would hypothetically demand for bearing the uncertainty of a fixed price today for performing many years in the future when dismantling will occur. The FASB has provided no additional guidance regarding the estimate of an appropriate market risk premium. This estimate will be particularly difficult in circumstances in which the retirement activities will be performed many years in the future, and the company has little information about how much a contractor would charge in addition to a normal price to assume the risk that the actual costs to perform the retirement activities will change in the future. The single example provided in Statement 143 that describes the component cash flows of the ARO estimates the market risk premium as 5% of the ARO cash flows before consideration of the market risk premium (the period until retirement of that example asset was estimated to be 10 years). However, estimating the appropriate market risk premium is a matter of judgment that depends on all the facts and circumstances.
			Paragraph 62 of Concepts Statement 7 discusses instances in which a reliable estimate of the market risk premium is not obtainable (or would represent an arbitrary adjustment for risk) or the amount may be small relative to potential measurement error in the estimated cash flows. In such instances, the market risk premium may be excluded from the estimate of the fair value of an ARO. If a reliable estimate of the market premium risk cannot be made and is thus excluded in

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 9

estimating the fair value of an ARO liability, the SEC staff believes that fact and the reasons therefore should be disclosed.”

Our Company makes no accounting policy distinction on this issue between a newly-incurred ARO on an asset development project versus an ARO acquired in a business combination. As we disclosed in Note 14—Asset Retirement Obligations and Accrued Environmental Costs of our 2007 Form 10-K on page 133, we believe the oil and gas industry has no examples of credit-worthy third parties who are willing to assume this type of risk, for a determinable price, on major oil and gas production facilities and pipelines. While our Company did absorb the uncertainty risk on the AROs of Burlington Resources, we have no credible way of quantifying the fair value of that market risk premium we absorbed, and thus excluded that risk when measuring the AROs acquired in that business combination. This treatment is consistent with our accounting practices since the adoption of SFAS 143 in 2002 and, we believe, consistent with the prevalent oil and gas industry interpretation of SFAS 143 and SFAS 141 on this issue. Paragraphs B22 and B23 of FIN 47 are not relevant since our Company does not have any internal estimate of the market risk premium we absorbed on the acquisition of the AROs of Burlington Resources.

Note 16—Joint Venture Acquisition Obligation, page 138

8.		You disclose that you are obligated to contribute $7.5 billion, plus accrued interest, to a portion of the business venture that was formed with EnCana Corporation. We understand from other corresponding disclosures in your filing, that your joint venture partner is responsible for a similar corresponding obligation. However, you also state that 50% of your interest payments are reflected as an additional capital contribution, and classified as an investing activity in your statement of cash flows. Please tell us why you believe that 50% of your interest expense associated with your required funding should be characterized as additional capital contribution, rather than being reflected entirely as interest expense.
		Response: On January 3, 2007, we closed on a business venture with EnCana Corporation to create an integrated North American heavy-oil business, consisting of two 50/50 business ventures. Each 50/50 business venture has an interest bearing, long-term commitment from either ConocoPhillips or EnCana to fund future developments and expansions. Accordingly, we contribute quarterly principal and interest payments of $237 million on this obligation to the upstream venture. These long-term funding commitments are legally binding and unavoidable.
		Since the quarterly interest payment, to the extent of our 50% ownership interest, is inherently intercompany in nature, we had to make an accounting judgment on the most appropriate presentation of this intercompany transaction with an equity affiliate. When making this judgmental determination, we found the following insight in Interpretation No. 1 to APB Opinion No. 18 helpful:

“The elimination of intercompany profit might be reflected in the investor’s balance sheet in various ways. The income statement and balance sheet presentations will depend upon what is the most meaningful in the circumstances.”

When deciding what presentation in our financial statements would be “the most meaningful” in our specific circumstances, we considered the impact of alternative presentations on our reported

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 10

“total revenues and other income” and the follow-on impacts in our cash flow statement. We considered two possible presentation approaches to our specific situation:

			(1) report 100 percent of the interest paid to the business venture as interest expense on our income statement, and allow our 50 percent share of the related interest income recorded by the business venture to flow back into our “total revenue and other income” section as equity method earnings, or
			(2) eliminate 50 percent of the interest expense we pay to the business venture against our reported equity method earnings from the venture, which would remove our 50% share of the related interest income from our reported equity method earnings.

		We believe approach (1) is a less meaningful presentation, since it would have the effect of grossing up our reported revenues and expenses for an item (our 50 percent share of the interest) which is inherently intercompany in nature and for which there never will be a follow-on transaction with an unrelated third party.
		Therefore, we concluded approach (2) above was most meaningful, as it results in an equity earnings amount that best reflects our 50% share of the underlying upstream venture’s operations, without grossing it up for interest income that we are, in essence, paying to ourselves.
		In making the judgmental assessment of the most meaningful presentation, we also considered paragraph 6 of ARB 51, which provides that, in the presentation of consolidated financial statements, intercompany interest transactions should be eliminated. Although this guidance in ARB 51 is not directly relevant to equity-method accounting, APB 18 does support the concept that equity-method accounting is an extension of the consolidation concept. We further looked at the guidance in paragraph 21 of SFAS 58, which states: “in situations involving intercompany interest there should be little effect because capitalized intercompany interest should be eliminated in accordance with Opinion 18 and ARB 51.” Again, our fact pattern is different from this guidance, but it reiterates the concept that intercompany interest should be carefully examined to determine if elimination of intercompany profits are warranted.
		Once we had decided on what we believed was the most meaningful income statement presentation, the classification of the interest payment in the cash flow statement mirrored those decisions. The half of the interest payment that was not eliminated was classified as a reduction in cash from operating activities. The half of the interest payment that was eliminated was judged to be most analogous to an investment purchase (and thus classified as an investing cash outflow) since the difference between the gross interest payment and the after-elimination amount results in an increase in our investment balance in the upstream venture.
		Due to the judgmental nature of these accounting decisions, we transparently disclosed the amounts and financial statement classifications of these intercompany interest transactions in Note 16—Joint Venture Acquisition Obligation of the financial statements included in our 2007 Form 10-K on page 138.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 11

Note 18—Contingencies and Commitments, page 140

9.		You state that for “all known non-income tax related contingencies,” you do not reduce accrued contingent liabilities for potential insurance or third-party recoveries. However, in regard to acquisition-related indemnifications, you state that you have not recorded accruals for any potential contingent liabilities, the payment of which you would expect to recover from prior owners under such indemnifications. While we see that you use the term “potential” when referring to liabilities for which you may be indemnified, we presume the point of your disclosure is to address the accounting for liabilities of this type otherwise assessed as probable. Tell us how you concluded that each of these types of third-party recoveries should be accounted for differently under SFAS 5.
		Response: The first disclosure in our 2007 Form 10-K noted by the Staff above refers to contingent liability situations where we are viewed as the primary obligor in the eyes of the claimant. In those cases, FIN 39 does not allow us to present, on the balance sheet, the accrued contingent obligation net of any probable recoveries from third parties, such as insurers, since we typically have no legal “right of setoff” for such liabilities and receivables. In those cases, we present the liabilities and receivables separately (i.e., gross) on the balance sheet.
		The second disclosure noted by the Staff is in our environmental remediation disclosure section on page 141:

“As a result of various acquisitions in the past, we assumed certain environmental obligations. Some of these environmental obligations are mitigated by indemnifications made by others for our benefit and some of the indemnifications are subject to dollar limits and time limits. We have not recorded accruals for any potential contingent liabilities that we expect to be funded by the prior owners under these indemnifications.”

The use of the word “potential” in this second disclosure is intended to communicate to the reader that, for these environmental exposures, the Company is only secondarily liable for the remediation exposure, to the extent there is a third-party indemnification agreement. Based on the indemnification agreements with us, the previous owners of these assets retained their status as the primary obligor for the environmental remediation work and, as such, the previous owner is considered a “potentially responsible party” (PRP) for the remediation work. These previous owners are not disputing such PRP status, and the allocation of the remediation costs between the various PRPs, including ourselves, is reasonably estimable. Under these conditions, paragraphs .133 through .139 of SOP 96-1, “Environmental Remediation Liabilities,” indicate that our Company should only record an environmental remediation obligation for our share of the remediation effort that we believe we will be funding beyond the third-party indemnification agreement. As indicated by paragraph .140 of SOP 96-1, these environmental indemnification situations are more appropriately considered to be an allocation of costs subject to joint and several liability among a group of primary obligors, not a potential recovery from third party insurers or state reimbursement funds for funds that we expect to expend in the future under some type of primary obligor status.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 12

Engineering Comments

General

10.		Please provide us with a copy of your reserve report as of December 31, 2007. Please provide this on electronic media, such as CD-ROM, if possible. If you would like this information to be returned to you, please follow the guidelines in Rule 12b-4 under the Exchange Act of 1934. See also Rule 83 under the Freedom of Information Act if you wish to request confidential treatment of that information. Please send the report to James Murphy at mail stop 7010.
		Response: ConocoPhillips’ reserves, as of December 31, 2007, are set out on pages 174 through 179 of our 2007 Form 10-K, and include a disaggregation by geographic location, presented separately for our consolidated operations and equity affiliates.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 48

Results of Operations, page 53

Segment Results—E&P, page 57

11.		Please tell us if your reported average production costs include production taxes.
		Response: The average production costs per barrel of oil equivalent (BOE), as disclosed on page 57 of our 2007 Form 10-K, do not include production taxes. However, our Results of Operations (RESOP) disclosure in the supplemental oil and gas disclosures on pages 180 through 183 provides a line item, “Taxes Other than Income Taxes,” that includes production taxes, property taxes and other non-income taxes. The RESOP disclosure explanatory notes on page 182 include a description of the taxes included in this line item. In addition, the statistics reported in our supplemental oil and gas disclosures includes a separate statistic for Taxes Other than Income Tax per BOE on page 186. This statistic includes the taxes noted above.
		We believe this additional statistic provides investors with enhanced information related to these taxes for our oil and gas producing activities, particularly given the recent increases in production and other non-income taxes incurred in our worldwide oil and gas operations. In view of the Staff’s comment, in future Form 10-K filings we will add a footnote to the production costs per BOE table in MD&A directing the reader to the supplemental oil and gas disclosures for the taxes other than income taxes per BOE statistic.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 13

Critical Accounting Estimates, page 86

Oil and Gas Accounting, page 86

Proved Oil and Gas Reserves and Canadian Syncrude Reserves, page 87

12.		You state that regarding the LUKOIL reserves, the reserves you report are based on the estimates prepared by LUKOIL but then reviewed by you and adjusted to comply with your internal reserves governance policies. Tell us for each of the last three years how much you adjusted the LUKOIL reserves, in which direction, and for what reasons.
		Response: In order to align the proved reserve estimates prepared by LUKOIL with ConocoPhillips’ internal reserves governance policies, we <redact> the reserves attributable to our equity ownership interest in LUKOIL by <redact> million barrels of oil equivalent (MMBOE), <redact> MMBOE and <redact> MMBOE at year-end 2007, 2006 and 2005, respectively. These <redact> are related to <redact>.

Average Sales Price, page 185

13.		We note the disclosure that the average sales price of oil from Canada in 2007 was $61.77 per barrel, which we assume is for your conventional oil and gas operations. Please tell us what your average price of bitumen was in 2007 and where in the filing this was disclosed.
		Response: Our average sales price for bitumen in 2007 was $37.79 per barrel. This amount is included in the calculation of our average sales price for crude oil. The bitumen sales from our Surmont consolidated operations are included in the calculation of our Canadian operations consolidated crude oil price per barrel of $61.77, and the bitumen sales from our FCCL Oil Sands Partnership equity affiliate are included in the calculation of our Canadian equity affiliate price of $37.94 per barrel. In light of the Staff’s comment, in future Form 10-K filings, we will disclose the average sales prices for our Surmont and FCCL bitumen production in Items 1 and 2, Business and Properties.

Confidential Treatment Requested by ConocoPhillips

U.S. Securities and Exchange Commission
April 14, 2008
Page 14

In response to your request, the Company hereby acknowledges each of the following:

	•		The adequacy and accuracy of the disclosures in the above filing is ConocoPhillips’ responsibility.
	•		The Staff’s comments or the changes to disclosure the Company makes in response to the Staff’s comments do not foreclose the Commission from taking any action with respect to the above filing.
	•		ConocoPhillips may not assert the Staff’s comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

cc:		Mr. James E. Copeland, Jr.    Chairman of the Audit and    Finance Committee Mr. James J. Mulva    Chairman and Chief Executive Officer Ms. Janet Langford Kelly, Esq.    Senior Vice President, Legal, and    General Counsel and Corporate Secretary Mr. Rand C. Berney    Vice President and Controller Mr. Andrew R. Brownstein, Esq.    Wachtell, Lipton, Rosen & Katz Mr. R. Dale Nijoka    Ernst & Young LLP

Confidential Treatment Requested by ConocoPhillips