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April 15, 2010

Via EDGAR

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

Re:

ConocoPhillips
Form 10-K for the Fiscal Year Ended December 31, 2009
File No. 001-32395

Dear Mr. Schwall:

Our responses to the comments raised in your letter dated April 1, 2010, are set forth below. The Staff’s comments are shown in bold followed by our responses.

Form 10-K for Fiscal Year Ended December 31, 2009

General

We note that your Form 10-K no longer includes disclosure about your crude oil purchases from Syria or Lukoil’s activities in Iran. Please advise. In this respect, we note as discussed below substantial activities by Lukoil in Iran and information in a recent New York Times article that a Company spokesman confirmed that you profit from Lukoil’s Iran-related business.

Response: Please see the response to Comment 3 below.

We note a March 2010 New York Times article discussing companies that do business with both the U.S. government and Iran. We note that the Company is on the list because of Lukoil doing business with Iran, having a contract with an Iranian oil company to develop an oil project in Uzbekistan and selling gasoline to Iran. We also note a public March 2010 letter to the President from several Congressmen stating that companies including Lukoil are likely in violation of the Iran Sanctions Act. We also note recent news articles reporting Lukoil Iranian contracts including agreements with Iran’s National Iranian Oil Co. to

U.S. Securities and Exchange Commission
April 15, 2010
Page 2

		develop oil fields, an agreement with an Iranian company for oil exploration in Uzbekistan, and Iran-based subsidiary. We also note news articles relating to Lukoil selling gas to the Syrian state oil company, Sytrol, and considering using a Cuban refiner to process crude from Russia. Finally, we note a recent article that states that you and Lukoil make purchases from a Syrian refinery.

		Please describe to us the nature and extent of your contacts with Iran, Syria and Cuba, whether through Lukoil, subsidiaries, resellers, distributors or other direct or indirect arrangements. Your response should describe any services or products you have provided to those countries directly or indirectly, and any agreements, commercial arrangements, or other direct or indirect contacts you have had with the governments of those countries or entities controlled by those governments.

		Response: Please see the response to Comment 3 below.

3.		Please discuss the materiality of any contacts with Iran, Syria or Cuba described in response to the foregoing comment and whether those contacts constitute a material investment risk for your security holders. You should address materiality in quantitative terms, including the approximate dollar amounts of any associated revenues, assets, and liabilities for the last three fiscal years. Also, address materiality in terms of qualitative factors that a reasonable investor would deem important in making an investment decision, including the potential impact of corporate activities upon a company’s reputation and share value. As you may be aware, various state and municipal governments, universities, and other investors have proposed or adopted divestment or similar initiatives regarding investment in companies that do business with U.S.-designated state sponsors of terrorism. Your materiality analysis should address the potential impact of the investor sentiment evidenced by such actions directed toward companies that have operations associated with Iran, Syria or Cuba, and should address specifically the recent publicity the company has received because of Lukoil’s contacts with these countries.

		Response: ConocoPhillips is committed to complying with all laws to which we are subject, including U.S. economic sanctions. As more fully described below, we have analyzed and continue to monitor our own activities, as well as LUKOIL’s public disclosures, and we believe the matters raised by the Staff do not rise to a level which would constitute a material investment risk to ConocoPhillips’ shareholders, on either a quantitative or qualitative basis. Given the quantitative and qualitative immateriality to ConocoPhillips of the matters as described herein, we do not believe ConocoPhillips will become subject to negative investor sentiment as evidenced by divestment or similar initiatives as a result of such matters.

		Below we discuss our analysis with respect to ConocoPhillips and our LUKOIL Investment segment:

		*ConocoPhillips*

		As part of our global crude oil supply and trading operations, ConocoPhillips has purchased, and may continue to purchase, immaterial amounts of Syrian crude oil and blendstocks as feedstock for our global refining operations. These purchases are made in full compliance with U.S. economic sanctions and export laws and regulations.

		The approximate dollar amounts paid to the Syrian Petroleum Company for crude oil feedstock purchases totaled $300 million in 2007, $335 million in 2008, and $240 million in 2009. The

U.S. Securities and Exchange Commission
April 15, 2010
Page 3

		approximate dollar amounts of purchases of Syrian-origin crude oil and other feedstocks from entities not affiliated with Syria totaled $115 million in 2007, $125 million in 2008, and $60 million in 2009.

		To put these purchases in context, during each of 2007, 2008 and 2009, ConocoPhillips’ global refining and marketing segment had purchase costs of approximately $105 billion, $140 billion and $90 billion, respectively. Thus our aggregate purchases of Syrian-origin crude oil and other feedstocks and crude oil feedstocks from the Syrian Petroleum Company referred to above represented well less than 1 percent of our global purchases during these same periods and were a small part of our global refinery feedstock supply processes, which secure products from competitive sources while complying with the spirit and intent of the laws and policies of the United States and the other countries in which we operate.

		Accordingly, we have determined this activity to be quantitatively and qualitatively immaterial to ConocoPhillips. Based on this determination, we did not include disclosure of this immaterial activity in our 2008 and 2009 Form 10-K’s.

		Neither ConocoPhillips nor any of its consolidated subsidiaries have contacts or business activities with Iran or Cuba.

		*LUKOIL Investment*

		ConocoPhillips initiated its strategic equity investment in LUKOIL in 2004 to gain exposure to Russia’s oil and natural gas resource potential, where LUKOIL has significant positions in proved oil and natural gas reserves and production. This investment allowed us to increase our proved oil and natural gas reserves at an attractive acquisition price, and positioned ConocoPhillips to benefit from direct participation with LUKOIL in large oil projects in the northern Timan-Pechora province of Russia. In March 2010, we announced our intention to reduce our stake in LUKOIL by 50 percent, to a 10 percent shareholder interest.

		ConocoPhillips has notified LUKOIL of our commitment to compliance with U.S. economic sanctions and export laws and regulations. While our contractual arrangements with LUKOIL provide us with certain rights, including the right to appoint Board representatives (we currently appoint one of eleven LUKOIL directors), we do not exercise control over the day-to-day operations of LUKOIL. Since we do not control the day-to-day business affairs of LUKOIL, ConocoPhillips cannot preclude LUKOIL from engaging in business activities, including those noted by the Staff in the referenced articles.

		A review of LUKOIL’s audited consolidated financial statements and its accompanying management’s discussion and analysis of financial condition and results of operations, do not indicate that the transactions described in the SEC’s comments from third-party news articles, assuming such third-party reports are accurate, are material to LUKOIL’s financial condition or results of operations. We would note in this context over 90 percent of LUKOIL’s proved reserves at year-end 2009 were located in Russia, and LUKOIL’s recent announcement of their withdrawal from the Anaran project in Iran and the associated $63 million impairment recorded in their consolidated financial statements for the year ending December 31, 2009.

		We believe the limited scope of LUKOIL’s activity in the countries referenced in the Staff’s comments, the size of our LUKOIL investment relative to our overall portfolio, and our lack of control over the day-to-day business affairs of LUKOIL make any such activity quantitatively and qualitatively immaterial to ConocoPhillips. Accordingly, we did not include disclosure of this activity in our 2008 or 2009 Form 10-K’s.

U.S. Securities and Exchange Commission
April 15, 2010
Page 4

Business and Properties

Segment and Geographic Information

Alaska, page 3

4.		We note your disclosure which indicates that you are engaged in enhanced recovery activities. Please tell us and disclose if material, your accounting policy relative to enhanced recovery activities, including your accounting for such costs during each stage of a projects development. Provide us with a summary of your accounting conventions by type of injected material such as CO2, nitrogen, water, etc. Clarify the stage of a project’s lifecycle that your accounting for injected materials may change.

		Response: The use of enhanced recovery methods is typically capital-intensive and there can be an extended period of time between the first investment in enhanced recovery and the additional production resulting from those activities. Costs associated with enhanced recovery facilities, equipment and injection wells are expected to provide a future benefit and are therefore capitalized as development costs and then amortized on a unit-of-production basis.

		Typically, the cost of the injected material (injectants) recurs over the property’s productive life and is not recoverable, or has no value other than as an injectant, and therefore is expensed as incurred. However, we do use some hydrocarbon miscible injectants (e.g., natural gas and natural gas liquids) that are partially recoverable. In this situation, if the recoverable portion of hydrocarbon miscible injectants can be reliably determined, and is significant, we record the recoverable portion as a long-term deferred charge. The deferred charges are recorded on a weighted-average cost method. At the end of each reporting period, an assessment is made to determine the volume of hydrocarbon injectants that ultimately will be recovered. If that volume estimate increased from the last reporting period, the increment to the deferred charge account is costed at the average purchase/production cost of the hydrocarbon injectants for the period. If the recoverable volume estimate has decreased since the last reporting period, the decrement to the deferred charge account will be costed using the weighted average cost of the account at the beginning of the reporting period. The cost of injecting the injectants into the reservoir is treated as a current period expense. Also note that production statistics and reserves exclude volumes of recovered purchased injectants whether sold or reinjected.

		We do not believe the amounts associated with the above described activity are material enough to warrant revisions to our existing accounting policy disclosures.

Legal Proceedings, page 26

We note your description of the compliance issues related to Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants requirements at your Trainer, Pennsylvania and Borger, Texas, facilities. You state that the U.S. Department of Justice made an initial penalty demand as part of confidential settlement negotiations. Please disclose the amount of the penalty demand or explain your basis for omitting it.

U.S. Securities and Exchange Commission
April 15, 2010
Page 5

Response: With respect to the compliance issues related to the Benzene Waste Operations National Emission Standard for Hazardous Air Pollutants at our facilities in Trainer, Pennsylvania, and Borger, Texas, the proposed penalties in question are currently part of ongoing settlement negotiations and thus strictly confidential under the Federal Rule of Evidence 408. However, we do not anticipate the settlement of either demand to be material. When the final penalty amounts are determined, we will disclose those amounts in Legal Proceedings in a future filing.

Critical Accounting Estimates

Oil and Gas Accounting, page 62

6.		We note your disclosure that the acquisition of geological and geophysical seismic information prior to the discovery of proved reserves is expensed as incurred. Please explain to us and disclose your accounting convention for seismic costs, subsequent to the determination of proved reserves and the reason you believe your policy is appropriate. Please refer to ASC 932-720-25-1 for guidance.

		Response: The guidance in ASC 932-720-25-1 originated from SFAS No. 19 and at that time geological and geophysical activities were commonly aligned with exploration activities covering undeveloped areas with no proved reserves. However, as enhanced recovery methods have advanced over the past thirty years, it has become common to use seismic surveys to optimize the placement of development wells and injection wells within a proved area. For example, four-dimensional seismic provides subsurface analysis on proved acreage to better understand changes in the reservoir over time and this information is used to increase total recoverability. Such activities are aligned with development activities and it is standard industry practice to capitalize such costs, as they enhance a future benefit by optimizing the recoverability of a proved area. All seismic expenses that are not development in nature are expensed as incurred. Any seismic survey costs related to both unproved and proved acreage are allocated between exploration expense and development capital based on the surface areas.

		We do not believe the amounts associated with the above described activity are material enough to warrant revisions to our existing accounting policy disclosures.

Financial Statements

Note 6 — Investments, Loans and Long-Term Receivables

Lukoil, page 89

We note your disclosure that indicates you have estimated amounts of your equity in earnings from your investment in Lukoil. We also note your responses dated April 14, 2008 and June 20, 2008 to comment number four in our letter dated March 31, 2008. Please update us as to the quantitative impact of your estimate to actual true-up related to your equity in earnings of Lukoil for each quarterly and annual period since the first quarter of fiscal 2008 through the first quarter of fiscal 2010. Additionally, please tell us how you considered specifically disclosing the quantitative impact of the estimate to actual adjustment process on your fiscal 2009 results.

U.S. Securities and Exchange Commission
April 15, 2010
Page 6

Response: The table below indicates the estimate-to-actual adjustment for each quarterly and annual period since the first quarter of 2008. Other than the fourth quarter amounts, which are not applicable to periods reported in Forms 10-Q and 10-K, all estimate-to-actual adjustments shown below have been disclosed in Form 10-Q or Form 10-K filings.


	ConocoPhillips’						Percent of
	Consolidated			Estimate-to-			Consolidated
Reporting	Net Income			Actual			Net Income
Period	(Loss)*			Adjustment			(Loss)**
	($ Millions)			($ Millions)
1 Q 2008	$	4,139		$	(16	)	<1		%
2 Q 2008	$	5,439		$	(120	)		2	%
3 Q 2008	$	5,188		$	(101	)		2	%
4 Q 2008	$	(31,764	)	$	101		<1		%
Yr 2008***	$	(16,998	)	$	(16	)	<1		%
1 Q 2009	$	840		$	-0-			—
2 Q 2009	$	1,298		$	192			15	%
3 Q 2009	$	1,503		$	33			2	%
4 Q 2009	$	1,217		$	(54	)		4	%
Yr 2009***	$	4,858		$	-0-			—


*		Net income attributable to ConocoPhillips.

**		Based on absolute amounts.

***		Reflects true-up for fourth quarter of prior year recorded in first quarter of current year.

		Due to the write-down of our LUKOIL investment to market value as of December 31, 2008, there was no required true-up of fourth-quarter 2008 results in the first quarter of 2009. Accordingly, there was no true-up impact on fiscal year 2009 results, and thus no disclosure was needed in our 2009 Form 10-K.

		As we publicly disclosed at our analyst meeting on March 24, 2010, we intend to change the method used to record our share of LUKOIL’s earnings under equity-method accounting, effective January 1, 2010. In the past, and as noted above, we estimated LUKOIL’s current quarter earnings. This earnings estimation process was necessary because, historically, LUKOIL’s accounting cycle close and preparation of U.S. GAAP financial statements occurred subsequent to our reporting deadline, and for certain periods this timing gap exceeded 93 days. LUKOIL has now demonstrated the ability to furnish financial information for all periods within 93 days of ConocoPhillips’ quarter-end, and thus we will begin recording LUKOIL’s actual earnings on a one-quarter lag basis. This change in accounting principle is preferable as it improves reporting reliability, while maintaining an acceptable degree of relevance. Implementation of this accounting change is subject to the receipt of a preferability letter from our independent registered public accounting firm. Under the guidance in FASB ASC Topic 250, “Accounting Changes and Error Corrections,” we intend to implement this change through retrospective application. Thus the estimate-to-actual adjustments detailed above will be eliminated when prior periods are recast to reflect this change in accounting principle, and there will no longer be an estimate-to-actual adjustment in the first quarter of 2010 or any future periods.

U.S. Securities and Exchange Commission
April 15, 2010
Page 7

8.		Please tell us how you have considered the requirements to provide audited financial statements under Rule 3-09 of Regulation S-X relative to your investment in Lukoil. Please note that we believe that the significance tests required by Rule 3-09(a) of Regulation S-X should be performed for each year presented in your financial statements. Additionally, if significance is met for any year presented, then financial statements for all three years required by Rules 3-01 and 3-02 of Regulation S-X must be presented, but only those years that are significant need be audited. If financial statements are necessary, please tell us and provide disclosure of when you anticipate filing an amended 10-K that will include such financial statements.

		Response: We are aware of the Staff’s view on the required duration of presenting separate financial statements under Rule 3-09 of Regulation S-X. Although our LUKOIL investment did not meet the significance thresholds in 2009 under Rule 3-09, we will continue to include LUKOIL’s separate financial statements within our Form 10-K until the year of significance (2008) is no longer included in the comparative income statement. Accordingly, in our 2009 Form 10-K filed on February 25, 2010, we made the following disclosure in Item 15(c) of Part IV on page 173:

		“Financial statements of OAO LUKOIL will be filed by amendment to this Annual Report on Form 10-K no later than June 30, 2010, in accordance with Rule 3-09 of Regulation S-X.”

		We filed the amended 2009 Form 10-K on April 1, 2010. We also expect to amend our 2010 Form 10-K next year to include LUKOIL’s separate financial statements. We file LUKOIL’s financial statements by amendment because they are not available prior to the due date of our original Form 10-K filing, as allowed under Rule 3-09(b)(1).

Engineering Comments

Notes to Consolidated Financial Statements

Oil and Gas Operations, page 137

9.		We note your statement, “Our estimated year-end 2009 reserves related to our equity investment in LUKOIL are based on LUKOIL’s year-end 2009 reserve estimates and include adjustments to conform them to ConocoPhillips’ reserves policy.” LUKOIL’s February 19, 2010 press release presents its January 1, 2010 proved reserves as 17.5 billion barrels of oil equivalent. Application of your 20 percent share in LUKOIL (page 1) results in 3.5 billion BOE net to your ownership. This appears inconsistent with your year-end 2009 Russian proved reserves of 2.055 billion BOE. Please reconcile this difference for us.

		Response: ConocoPhillips’ reported proved reserves attributable to our equity investment in LUKOIL are based on LUKOIL’s initial reserve technical assessments. In order to align the reserve technical assessments prepared by LUKOIL with ConocoPhillips’ internal reserves governance policies, we reduced the reserves attributable to our equity ownership. These reductions were based on our judgmental assessment of reserve classification criteria related to reserves to be produced beyond the end of current production license terms, natural gas volumes to be produced beyond the term of gas sales contracts, volumes associated with projects for which certain elements of our authority-for-development criteria have not yet been met, and joint-

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April 15, 2010
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		venture fields in which we have an engineering presence and can therefore estimate the reserve quantities ourselves.

		LUKOIL also applies reductions to their initial reserve technical assessments based on their own internal judgmental methodologies to arrive at their reported proved reserve quantities, and these methodologies are not necessarily the same as ConocoPhillips’, thus resulting in the different proved reserves amounts reported. This difference reflects each company’s judgmental conclusions under this deliberative process.

10.		We note your disclosure that you have applied the 12 month average price for determination of economic producibility of reserves. Please explain the procedures you used to arrive at these reserve determination average prices. Include illustrations with figures that correspond to those you used for proved reserves attributed to the Bayu-Undan Field and to the Lobo Trend in South Texas. Please explain whether you treat transportation costs as a lease operating expense or a price reduction.

		Response: We use benchmark daily prices (e.g., Platts) to determine the first-day-of-the-month price, unless prices are fixed by contract terms. Other publicly available benchmarks, such as Argus, are used if specified in sales contracts. Benchmarks are also used to determine the monthly average prices used to calculate adjustment factors related to hydrocarbon quality, location differentials and other differences necessary to convert the benchmark prices into prices realized at the property level. If the first day of the month falls on a non-trading day, the previous trading day’s price is used. Assets under long-term contract pricing use the average contract price for the 12-month period of the current year, and these prices are only escalated in the future if a fixed and determinable escalation provision is included in the contractual terms.

		Prices used to compute proved reserves at Bayu-Undan are based on the terms of the actual sales contract. The calculation includes a 12-month average of the specific benchmark price converted to U.S. dollars per thousand cubic feet as required in the contract. Adjustments for transportation and processing to comply with the production sharing contract terms are then made to arrive at the price received at the sales point, which is the onshore inlet to our Darwin LNG plant for natural gas and offshore for liquids. These prices are used to determine our proved reserves at Bayu-Undan for natural gas and liquids, respectively. Transportation costs for natural gas from the offshore platform to the onshore LNG plant are also included in the economic limit test for these proved reserves. Specific contract pricing terms at Bayu-Undan are commercially confidential.

		We have approximately 400 leases in the Lobo Trend in south Texas. Prices at the lease level are used to compute proved reserves. The 12 month, first-day-of-month average Henry Hub natural gas benchmark in 2009 was $3.87 per million British thermal units (mmbtu). Adjustment factors for each lease are individually calculated to determine the price received at the lease based upon the benchmark price. This adjustment factor captures location and hydrocarbon quality differentials, as well as natural gas conversion from one million British thermal units to one thousand cubic feet. The benchmark price of $3.87 per mmbtu was adjusted by the actual adjustment factors for each lease to arrive at the prices used to calculate proved reserves.

		Transportation costs include costs to transport produced hydrocarbons to their first marketable point, as well as fees paid to treat and process natural gas. As disclosed in Note 1 — Accounting Policies on page 78 of our 2009 Form 10-K, these costs are treated as lease operating expenses and included in “Production and operating expenses” in our Consolidated Statement of

U.S. Securities and Exchange Commission
April 15, 2010
Page 9

Operations. Transportation costs are reported as a separate line item in our Results of Operations disclosure beginning on page 148 of our 2009 Form 10-K.

Proved Undeveloped Reserves, page 146

11.		We note your statement that the net additions of proved undeveloped reserves were 52%, 156% and 77% of your total net additions in 2009, 2008 and 2007, respectively. Please expand this to disclose also the actual figures for these PUD reserves additions. Include material changes in PUD reserves due to revisions, drilling, improved recovery and acquisitions/divestments.

		Response: Proved undeveloped (PUD) reserve net additions for 2009, 2008 and 2007 were 632 million barrels of oil equivalent (MMBOE), 402 MMBOE and 1,094 MMBOE, respectively. In future Form 10-K filings, in addition to indicating the percentage of net additions attributable to PUD reserves, we will also disclose the volume of PUD reserve additions.

		As required by Item 1203 of Regulation S-K, the material changes to PUD reserves are disclosed in our 2009 Form 10-K. We noted on page 146 of our 2009 Form 10-K that 370 MMBOE were converted from PUD reserves to proved developed reserves during 2009. The net PUD additions were primarily due to extensions and discoveries and revisions, and those net additions mainly included the sanctioning of the Surmont Phase II and the Christina Lake Phase 1D projects, both disclosed on pages 8 and 144 of the 2009 Form 10-K. We also disclose the major projects that hold the majority of our proved undeveloped reserves on pages 146 and 147.

Proved Undeveloped Reserves, page 147

12.		We note your statement that a material portion of the Athabascan SAGD oil sands proved reserves will remain undeveloped for more than 5 years. Please explain to us the factors that limit the pace of development of these projects. You may refer to the concepts presented in our Compliance and Disclosure Interpretations that are relevant to project development: Items 108.01 and 131.03 through 131.06. C&DI are available at www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

		Response: The proved undeveloped reserves in our Athabascan steam-assisted gravity drainage (SAGD) oil sands projects meet the definition of “undeveloped oil and gas reserves” in Regulation S-X 4-10(a)(31). Although a material portion will remain undeveloped for more than five years, the specific circumstances impacting the pace of development of SAGD operations justify a longer development period.

		The primary reason portions of these proved reserves will remain undeveloped for more than five years is due to the nature of the bitumen recovery process with SAGD. SAGD production requires the construction of steam generation and other central processing facilities that service and support numerous SAGD well pairs. These central facilities have a substantially longer life than the SAGD well pairs. To build central facilities that would process the entire field simultaneously would be neither economic nor environmentally efficient. Greater economic value and environmental efficiency are achieved by building central facilities with optimal capacity that provides for a series of SAGD well pairs to be drilled and produced over the life of the central facility. As these well pairs achieve their ultimate bitumen recovery, new well pairs will effectively take their place in the central facilities’ capacity. Proved reserves are recorded for

U.S. Securities and Exchange Commission
April 15, 2010
Page 10

		the total quantity that will be ultimately recovered through the central facilities, although the timing of the conversion of those reserves from undeveloped to developed will depend on when the well pair targeting those reserves is scheduled during the life of the central facilities.

		In determining that the proved undeveloped reserves recorded for our SAGD oil sands operations met the exception guidelines outlined by the Compliance and Disclosure Interpretations (C&DI), particularly Question 131.03, we also considered the following factors:

	•		The long and proven track record regarding our significant and ongoing developments at the Surmont, Foster Creek and Christina Lake projects. These ongoing developments included the use of pilot programs, the drilling of hundreds of delineation wells and the significant capital commitment for facility expansion on additional phases in these oil sands operations.

	•		Our long and proven track record of completing development of Phase I at Surmont and the various phases of development at Foster Creek and Christina Lake. Our net share of bitumen production from these projects averaged 50,000 barrels per day in 2009, a significant ramp-up from an average net production level in 2008 of 36,000 barrels per day. These earlier phase projects continue to ramp up toward peak production, demonstrating our ongoing funding and support for these SAGD operations.

	•		The adopted development plans have remained consistent, and these development plans are being implemented and improved as the various phases of development continue to occur.

It is important to note we are not “slowly developing a field in order to extend its economic life to justify recognizing proved undeveloped reserves in the field beyond five years” as addressed in Question 131.05 in the C&DI. On the contrary, we are actively developing the fields as quickly as possible to maximize the net present value to the company and other stakeholders.

Acreage at December 31, 2009, page 156

13.		In part, paragraph (b) of Item 1208 of Regulation S-K requires the disclosure of the minimum remaining terms of leases and concessions for material acreage concentrations. With a view toward disclosure, please explain the steps you will take to comply with Item 1208.

		Response: Our 2009 Form 10-K disclosures are in compliance with Item 1208 of Regulation S-K. As a major global oil and gas company, our acreage holdings are spread throughout the world, with no material concentrations of acreage upon which our company substantially depends. Similarly, we have had no expiration of leases or concessions in the past three years that have had a material adverse impact on ConocoPhillips, and we do not expect any in the near term. We disclose noteworthy lease expirations in Items 1 and 2, “Business and Properties.” For example, on page 11 of the 2009 Form 10-K, we disclosed the lease expirations related to our Xijiang development in the South China Sea. We would expect to make similar disclosures in Business and Properties in future filings when appropriate.

U.S. Securities and Exchange Commission
April 15, 2010
Page 11

In response to your request, I hereby acknowledge each of the following:

	1.		The adequacy and accuracy of the disclosures in the above filing is ConocoPhillips’ responsibility.

	2.		The Staff’s comments or the changes to disclosure we make in response to the Staff’s comments do not foreclose the Commission from taking any action on the above filing.

	3.		ConocoPhillips may not assert the Staff’s comments as a defense in any proceedings initiated by the Commission or any person under the federal securities laws of the United States.

An electronic version of this letter has been filed via EDGAR. In addition, we have provided courtesy copies by mail.


	Very truly yours, CONOCOPHILLIPS
	/s/ Sigmund L. Cornelius
	Sigmund L. Cornelius
	Senior Vice President, Finance and Chief Financial Officer

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,
   General Counsel and Corporate Secretary
Ms. Glenda M. Schwarz
   Vice President and Controller
Mr. Andrew R. Brownstein, Esq.
   Wachtell, Lipton, Rosen & Katz
Mr. Timothy T. Griffy
   Ernst & Young LLP
Mr. R. Dale Nijoka
   Ernst & Young LLP