FOIA Confidential Treatment Requested by ConocoPhillips pursuant to 17 C.F.R. § 200.83

Pursuant to 17 C.F.R. § 200.83 (“Rule 83”), ConocoPhillips has requested confidential treatment under the Freedom of Information Act of portions of this letter. This letter omits confidential information included in the unredacted version of this letter that was delivered to the Division of Corporation Finance. The notes below denote such omissions.

June 12, 2014

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, 2013

Filed February 25, 2014

Form 10-Q for the Quarterly Period Ended March 31, 2014

Filed May 6, 2014

File No. 1-32395

Dear Mr. Schwall:

Our responses to the comments raised in your letter dated May 22, 2014, are set forth below. The Staff’s comments are shown in bold followed by our responses.

Form 10-K for the Fiscal Year Ended December 31, 2013

Business and Properties, page 1

Segment and Geographic Information, page 2

Facilities, page 9

U.S. Securities and Exchange Commission

June 12, 2014

Page 2

Golden Pass LNG Terminal

1. Disclosure under this section indicates that, due to current market conditions, your near-to-mid-term utilization of the Golden Pass terminal is expected to be limited. In view of this, explain to us whether you have tested this property for impairment. If not, explain your basis for concluding that no impairment testing was necessary. Otherwise, describe for us, in reasonable detail, the methodology, assumptions and results of your impairment test. As part of your response, address the following:

• Explain the operational history of the terminal since it became commercially operational in May 2011;

• Explain the nature and extent of the “limited” utilization that you expect for the near-to-mid-term; and,

• Describe your future plans and actions that you intend to take or are considering taking with respect to the terminal.

Response:

In 2003, ConocoPhillips and Qatar Petroleum (QP) signed a Heads of Agreement (HoA) for the development of an integrated project consisting of facilities and activities to produce natural gas from Qatar’s North Field, construction of a new liquefied natural gas (LNG) train in Qatar to manufacture LNG and associated products, and shipment and sale of LNG to markets, primarily in the United States. Key points of the HoA were:

a) ConocoPhillips and QP would form a joint venture company known as Qatargas 3 (QG3);

[Note 1: Rule 83 Confidential Treatment Request Made by ConocoPhillips;

Request Number 1]

QG3 is an entity majority-owned by QP, with ConocoPhillips owning 30 percent. QG3 owns and operates the upstream natural gas production facilities and LNG facility as part of the integrated project described above.

As a condition of investing in the QG3 upstream venture, ConocoPhillips was required to buy a 12.4 percent equity interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline in the United States. The other owners of the terminal and pipeline are QP and ExxonMobil. ConocoPhillips accounts for these three investments separately under the equity method of accounting.

Golden Pass LNG became commercially operational in May 2011. Since that time, market conditions have favored the flow of LNG to European and Asian markets. From the beginning, QG3, Golden Pass Terminal and Golden Pass Pipeline have been viewed on an integrated basis to maximize the overall value of the natural resource across the entire value chain. The downstream transportation, regasification, pipeline and commercial arrangements are all necessary components in the value

U.S. Securities and Exchange Commission

June 12, 2014

Page 3

chain, which ensures QG3 a consistent cash flow stream that is required by both the QG3 shareholders and the QG3 debt holders. While each of the three legal entity’s cash flows are discrete, they are not largely independent of one another, as a result of the interdependency caused by the structure of the governing agreements. This interdependency is demonstrated through the following contractual linkages:

[Note 2: Rule 83 Confidential Treatment Request Made by ConocoPhillips;

Request Number 2]

Due to the above factors, ConocoPhillips has viewed the investment decision on a holistic basis since inception. The form of the project, the creation of three separate legal entities (QG3, Golden Pass Terminal and Golden Pass Pipeline), resulted from legal and tax jurisdiction requirements; however, the economics, project financing and governance indicate in substance there is only one business. Since the three legal entities together are viewed as a single project and their cash flows are contractually linked, our equity method investment in the three entities is tested for impairment in the aggregate.

Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic No. 323, “Investments – Equity Method and Joint Ventures” does not discuss aggregation of equity method investments when testing for impairment. Accordingly, we believe it is appropriate to analogize the aggregation criteria required pursuant to ASC 360, “Property, Plant, and Equipment.” ASC 360-10-35-23 states, “For purposes of recognition and measurement of an impairment loss, a long-lived asset or assets shall be grouped with other assets and liabilities at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities.” Aggregation of the three legal entities for impairment testing is further supported by the guidance contained in ASC 820-10-35-12 which states, “The fair value of an asset in-use is determined based on the use of the asset together with other assets as a group (consistent with its highest and best use from the perspective of market participants), even if the asset that is the subject of the measurement is aggregated (or disaggregated) at a different level for purposes of applying other guidance.” Therefore, the correct unit of valuation for determining the fair value of QG3 and the Golden Pass entities is on a combined basis.

In accordance with ASC 323 and as stated in Note 1 – Accounting Policies in the Notes to Consolidated Financial Statements included in our 2013 Form 10-K, we review investments in nonconsolidated entities accounted for under the equity method for impairment when there is evidence of a loss in value and at least annually. Although the Golden Pass Terminal and Golden Pass Pipeline entities are expected to have limited utilization in the near-to-mid-term, the fair value of all three entities in the aggregate exceeds the combined carrying value. Fair value is based on expected future cash flows using estimated future production volumes, prices and costs, consistent with those we believe would be utilized by market participants.

[Note 3: Rule 83 Confidential Treatment Request Made by ConocoPhillips;

Request Number 3]

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 35

Income Statement Analysis, page 44

U.S. Securities and Exchange Commission

June 12, 2014

Page 4

2. Throughout this section, you refer to multiple factors when explaining the change between years in reported amounts without indicating the amount attributable to each factor. For example, you indicate that the decrease in sales and other operating revenues in 2013 was due to lower natural gas volumes and lower crude oil prices, partly offset by higher natural gas prices, without indicating the amount attributable to each factor. To the extent that two or more factors contribute to a material change in reported amounts, revise the disclosure throughout your MD&A to indicate the amount attributable to each factor. See FRC 501.04.

Response:

Where material to an understanding of the variance, we have quantified individual factors discussed in the variance explanation of changes over reported periods.

Below we note several examples in the Results of Operations section of our 2013 Form 10-K where we have quantified individual factors:

• The amount of gain from disposition of our Clyden undeveloped oil sands leasehold and the negative earnings impact due to impairments in western Canada and for the Mackenzie Gas Project, on page 49.

• The amount of gains from asset dispositions in Europe, as well as the negative earnings impact from additional income tax expense recognized as a result of newly enacted U.K. tax legislation, on pages 50 and 51.

• The amount of gain from the disposition of our interest in Naryanmarneftegaz (NMNG) and the negative earnings impacts from the impairments of NMNG and the N Block, on page 54.

• The amount of premium on early debt retirement and pension settlement expense, on pages 55 and 56.

In addition, we believe 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. We also include statistical information for sales prices and volumes, which we believe further assist the reader in understanding the components of certain variances.

We acknowledge the Staff’s comment but respectfully submit the disclosures in our 2013 Form 10-K are compliant with applicable SEC rules and interpretations, including FRC 501.04. However, in light of the Staff’s comment, we will continue to look for further opportunities to quantify material factors in our variance explanations in future filings.

Financial Statements and Supplementary Data, page 75

Notes to Consolidated Financial Statements, page 84

Note 4 – Variable Interest Entities (VIEs), page 91

U.S. Securities and Exchange Commission

June 12, 2014

Page 5

3. You disclose that you expect to record an after-tax charge of approximately $540 million when the related agreement with Freeport LNG becomes effective. Explain to us, in reasonable detail, how the expected amount and timing of this charge has been determined. As part of your response, address the following:

• Provide a summary of the operating history, and your involvement in, the LNG receiving terminal.

• Clarify when you began making payments under the terminal use agreement, and explain how the payment amounts were determined;

• Explain what the prepaid balance of the terminal use agreement of $282 at December 31, 2013 represents, and explain your basis for concluding that this asset was recoverable as of that date;

• Explain the material terms of the termination agreement, including, but not limited to, any obligations that you have between the effective date and Jul 1, 2016;

• Explain how you determined that the charge should be recorded at the effective date of the agreement, and explain how you considered regarding part or all of the charge as of any earlier date; and,

• Identify the specific authoritative literature you relied on in determining the expected amount and timing of the charge.

Response:

In late 2003, ConocoPhillips acquired a 50 percent equity ownership interest in Freeport LNG-GP, Inc., which serves as the general partner and manager of Freeport LNG Development, L.P. (Freeport LNG). In July 2004, we entered into a long-term terminal use agreement (TUA) with Freeport LNG for approximately two-thirds of Freeport LNG’s 1.5-billion-cubic-feet-per-day (bcfd) import capacity at a facility to be constructed. In January 2005, Freeport LNG was awarded a permit by the Federal Energy Regulatory Commission to construct the terminal, and in December 2005, ConocoPhillips entered into a $775 million loan agreement with Freeport LNG to fund approximately two-thirds of the actual construction costs of the terminal with a first lien on the terminal assets.

In August 2008, the terminal became operational. ConocoPhillips began paying Freeport LNG monthly capacity payments under the TUA, while Freeport LNG began making principal and interest payments to ConocoPhillips pursuant to the loan agreement. The monthly TUA and loan payments are equal to each other, but under both agreements they are structured to be higher in the early years and are scheduled to end in 2026 when the loan matures. Our reserved terminal capacity is constant over the term of the TUA, which expires in 2033. Therefore, ConocoPhillips recognizes expense for its reserved terminal capacity under the TUA in equal monthly pro rata amounts of the total capacity payments over the 25-year term of the TUA. Since the payments made by ConocoPhillips for terminal capacity are accelerated, a prepaid asset has been recognized and continues to accumulate during the early years of the TUA for the excess of the cash payments over the equal pro rata expense recognized each month. This prepaid asset will be amortized in later years when payments are less than the recognized pro rata monthly expense amount, so the appropriate amount of periodic expense for terminal capacity is recognized each year during the entire term of the TUA.

U.S. Securities and Exchange Commission

June 12, 2014

Page 6

The TUA is an executory contract that is not a lease. U.S. GAAP interpretive guidance indicates a liability should not be recognized for expected losses on executory contracts except when an arrangement is within the scope of authoritative literature that specifically provides for the accrual of losses such as the following:

• A firm purchase commitment for goods or inventory subject to ASC 440-10-25-4.

• Contracts within the scope of ASC 605-35.

• An operating lease that is subleased subject to ASC 840, including ASC 840-20-25-15 and ASC 840-30-35-13 (related to fiscal funding clauses), or ASC 420.

• Certain other executory contracts subject to ASC 420.

• An insurance contract with a premium deficiency subject to ASC 944.

• Certain derivative contracts within the scope of ASC 815.

• Losses on arrangements pursuant to ASC 985-605.

Accordingly, we evaluated whether a loss should be recognized under ASC 420, “Exit or Disposal Cost Obligations” for the required future capacity payments. ASC 420-10-25-2 states, “An obligation becomes a present obligation when a transaction or event occurs that leaves an entity little or no discretion to avoid the future transfer or use of assets to settle the liability.” Expectations for future reduced utilization of the terminal, while still having the contractual rights to use the terminal, do not meet the criteria of ASC 420 to accelerate expense recognition of the future periodic TUA costs. This determination is supported by the principles outlined in ASC 420, which indicate the costs incurred to terminate an operating lease or other contract are not recognized until an entity terminates the underlying contract or ceases to use the rights conveyed by that contract.

The criteria of ASC 420 will be met when our TUA contractual rights are terminated. In July 2013, we reached an agreement with Freeport LNG to terminate the TUA, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility, as disclosed in our 2013 Form 10-K. Material terms of the termination agreement are as follows:

• ConocoPhillips relinquishes ownership and its board seat in Freeport LNG-GP;

• ConocoPhillips pays a capacity termination fee of approximately $600 million;

• ConocoPhillips TUA capacity is immediately reduced from 0.9 to 0.4 bcfd, which terminates our contractual right to 0.5 bcfd of capacity;

• On July 1, 2016, our capacity rights to the remaining 0.4 bcfd capacity terminate; and

• Freeport LNG repays the outstanding ConocoPhillips loan.

If the termination agreement conditions precedent are never met, the TUA terms and conditions remain in effect. Therefore, at the time the termination agreement conditions precedent are met, we expect to recognize, in accordance with ASC 420-10-25-12, expense consisting mainly of the capacity termination fee and write-off of the prepaid balance of the TUA. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years, as disclosed in our 2013 Form 10-K. We will continue to recognize as period expense a revised monthly capacity fee for the 0.4 bcfd capacity that we retain for the period between the effective date and the final exit date of July 1, 2016.

Supplementary Information, page 138

Oil and Gas Operations (Unaudited)

U.S. Securities and Exchange Commission

June 12, 2014

Page 7

Capitalized Costs, page 160

4. We note that net capitalized costs for your consolidated Canadian operations as of December 31, 2013 were approximately $11.1 billion. Per the standardized measure of discounted future net cash flows table on page 161, the undiscounted future net cash flows for your consolidated Canadian operations was $4.6 billion as of December 31, 2013. Given the significant difference between these amounts, please tell us the facts and circumstances that led you to conclude no impairment for your Canadian operations was necessary beyond the $216 million disclosed under Note 9 – Impairments. As part of your response, provide reasonably detailed summaries of any impairment tests you performed, including a description of all material assumptions made regarding prices and quantities.

Response:

In accordance with ASC 360 and as stated in Note 1 – Accounting Policies in the Notes to Consolidated Financial Statements included in our 2013 Form 10-K, ConocoPhillips conducts impairment tests of long-lived assets having proved reserves at the lowest asset group level for which identifiable cash flows are largely independent of the cash flows of other assets, generally on a field-by-field basis. Oil and gas volumes used for the ASC 360 impairment tests are based on assumptions that would be used by market participants, which include cash flows from proved reserves, and may include an appropriate risk-adjusted amount of probable reserves when such reserves exist. Price assumptions used for impairment tests are based on publicly available future strip prices and/or third party pricing services for available periods, which generally show prices increasing over time. For expected production in time periods beyond those available from third party sources, we apply an estimated inflation factor consistent with those we believe would be applied by market participants.

We assess properties, plants and equipment (PP&E) for impairment whenever changes in facts and circumstances indicate a possible significant deterioration of future cash flows expected to be generated by an asset group and at least annually. The 2013 annual impairment test was concluded in the fourth quarter, and no additional impairments were indicated beyond the amounts disclosed in Note 9 – Impairments in the Notes to Consolidated Financial Statements included in our 2013 Form 10-K.

A number of factors make comparisons difficult between the capitalized cost schedules, the standardized measure of discounted future net cash flows tables, and impairment test conclusions under ASC 360. For example:

• The net capitalized costs of our Canadian operations include unproved properties of approximately $1.2 billion, which are excluded from the standardized measure of discounted cash flows tables. These properties are tested separately under ASC 932, “Extractive Activities – Oil and Gas,” and potential production from these properties is not included in the impairment tests of PP&E under ASC 360.

• The standardized measure of discounted future net cash flows tables reflect prices and quantities in accordance with ASC 932 and Rule 4-10 of Regulation S-X. Prices are based on the unweighted arithmetic average of the first-day-of-the-month price within the 12-month period prior to the end of the reporting period and are not escalated for future periods unless prices are defined by contractual arrangements. Production volumes are based exclusively on year-end estimates of proved reserves. In contrast, prices and volumes used for our ASC 360 impairment tests are based on assumptions that would be used by market participants, as described above.

U.S. Securities and Exchange Commission

June 12, 2014

Page 8

• Future cash outlays for dismantlement activities are a reduction to future net cash flows in the standardized measure of discounted future net cash flows tables, but are excluded from the undiscounted cash flows used for impairment tests in accordance with ASC 360-10-35-18(a).

Form 10-Q for the Quarterly Period Ended March 31, 2014

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 28

Capital Resources and Liquidity, page 42

Significant Sources of Capital, page 42

5. You explain that the increase in cash flow from operating activities for the quarter ended March 31, 2014 is primarily due to the $1.3 billion distribution from FCCL. Please expand this disclosure to explain the circumstances surrounding the increase in the distribution including, but not limited to, the reason for the distribution, and whether you believe this increased distribution represents a trend. See Item 303(b) of Regulation S-K, including Instruction 3 thereto.

Response:

We respectfully refer the Staff to the following disclosure included in the Capital Requirements section on pages 59-60 of our 2013 Form 10-K: “We were obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to our 50 percent owned FCCL Partnership. In December 2013, we paid the remaining balance of the obligation, which totaled $2,810 million. This $2,810 million prepayment substantially increases the FCCL Partnership’s ability to make distributions to its partners or fund future capital requirements without contributions from the partners.”

We believe the disclosure in our 2014 first quarter Form 10-Q, when read in conjunction with the related disclosures provided in our 2013 Form 10-K as described above, complies with Item 303(b) of Regulation S-K, including applicable instructions. Such disclosure provides the discussion and analysis necessary to enable the reader to assess the material change in our financial condition caused by the $1.3 billion distribution, as well as information relevant for an understanding of the extent to which such distribution is indicative of future changes in our financial condition.

U.S. Securities and Exchange Commission

June 12, 2014

Page 9

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 with respect to 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/ Jeff W. Sheets

Jeff W. Sheets

Executive Vice President, Finance and

Chief Financial Officer

cc: Mr. James E. Copeland, Jr.

Chairman of the Audit and

Finance Committee

Mr. Ryan M. Lance

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. Timothy T. Griffy

Ernst & Young LLP