UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2017

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from              to             

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware	01-0562944
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

600 North Dairy Ashford, Houston, TX 77079

(Address of principal executive offices) (Zip Code)

281-293-1000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

The registrant had 1,237,103,953 shares of common stock, $.01 par value, outstanding at March 31, 2017.

CONOCOPHILLIPS

TABLE OF CONTENTS

	Page
Part I—Financial Information
Item 1. Financial Statements
Consolidated Income Statement		1
Consolidated Statement of Comprehensive Income		2
Consolidated Balance Sheet		3
Consolidated Statement of Cash Flows		4
Notes to Consolidated Financial Statements		5
Supplementary Information—Condensed Consolidating Financial Information		25
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3. Quantitative and Qualitative Disclosures About Market Risk		49
Item 4. Controls and Procedures		49
Part II—Other Information
Item 1. Legal Proceedings		50
Item 1A. Risk Factors		50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		51
Item 6. Exhibits		52
Signature		53

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Revenues and Other Income
Sales and other operating revenues	$	7,518			5,121
Equity in earnings (losses) of affiliates		200			(149	)
Gain on dispositions		22			23
Other income		31			20
Total Revenues and Other Income		7,771			5,015
Costs and Expenses
Purchased commodities		3,192			2,225
Production and operating expenses		1,298			1,354
Selling, general and administrative expenses		157			186
Exploration expenses		551			505
Depreciation, depletion and amortization		1,979			2,247
Impairments		175			136
Taxes other than income taxes		231			180
Accretion on discounted liabilities		95			109
Interest and debt expense		315			281
Foreign currency transaction losses		10			16
Total Costs and Expenses		8,003			7,239
Loss before income taxes		(232	)		(2,224	)
Income tax benefit		(831	)		(768	)
Net income (loss)		599			(1,456	)
Less: net income attributable to noncontrolling interests		(13	)		(13	)
Net Income (Loss) Attributable to ConocoPhillips	$	586			(1,469	)
Net Income (Loss) Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	0.47			(1.18	)
Diluted		0.47			(1.18	)
Dividends Paid Per Share of Common Stock (dollars)	$	0.27			0.25
Average Common Shares Outstanding (in thousands)
Basic		1,243,280			1,244,557
Diluted		1,248,722			1,244,557

See Notes to Consolidated Financial Statements.

1

Consolidated Statement of Comprehensive Income ConocoPhillips

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Net Income (Loss)	$	599			(1,456	)
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income		(9	)		(9	)
Net actuarial loss arising during the period		(7	)		(231	)
Reclassification adjustment for amortization of net actuarial losses included in net income		90			108
Income taxes on defined benefit plans		(26	)		50
Defined benefit plans, net of tax		48			(82	)
Foreign currency translation adjustments		184			1,183
Foreign currency translation adjustments, net of tax		184			1,183
Other Comprehensive Income, Net of Tax		232			1,101
Comprehensive Income (Loss)		831			(355	)
Less: comprehensive income attributable to noncontrolling interests		(13	)		(13	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	818			(368	)

See Notes to Consolidated Financial Statements.

2

Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	March 31			December 31
	2017			2016
Assets
Cash and cash equivalents	$	3,109			3,610
Short-term investments		252			50
Accounts and notes receivable (net of allowance of $5 million in 2017 and $5 million in 2016)		3,105			3,249
Accounts and notes receivable—related parties		254			165
Inventories		1,097			1,018
Prepaid expenses and other current assets		2,911			517
Total Current Assets		10,728			8,609
Investments and long-term receivables		21,153			21,091
Loans and advances—related parties		522			581
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $66,400 million in 2017 and $73,075 million in 2016)		54,440			58,331
Other assets		1,130			1,160
Total Assets	$	87,973			89,772
Liabilities
Accounts payable	$	3,494			3,631
Accounts payable—related parties		37			22
Short-term debt		1,095			1,089
Accrued income and other taxes		756			484
Employee benefit obligations		465			689
Other accruals		1,679			994
Total Current Liabilities		7,526			6,909
Long-term debt		25,340			26,186
Asset retirement obligations and accrued environmental costs		7,884			8,425
Deferred income taxes		7,568			8,949
Employee benefit obligations		2,534			2,552
Other liabilities and deferred credits		1,520			1,525
Total Liabilities		52,372			54,546
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2017—1,784,150,651 shares; 2016—1,782,079,107 shares)
Par value		18			18
Capital in excess of par		46,510			46,507
Treasury stock (at cost: 2017—547,046,698 shares; 2016—544,809,771 shares)		(37,018	)		(36,906	)
Accumulated other comprehensive loss		(5,961	)		(6,193	)
Retained earnings		31,804			31,548
Total Common Stockholders’ Equity		35,353			34,974
Noncontrolling interests		248			252
Total Equity		35,601			35,226
Total Liabilities and Equity	$	87,973			89,772

See Notes to Consolidated Financial Statements.

3

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Three Months Ended March 31
		2017		2016
Cash Flows From Operating Activities
Net income (loss)	$	599		(1,456	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization		1,979		2,247
Impairments		175		136
Dry hole costs and leasehold impairments		406		360
Accretion on discounted liabilities		95		109
Deferred taxes		(1,314	)	(827	)
Distributions received greater than equity losses (undistributed equity earnings)		(43	)	252
Gain on dispositions		(22	)	(23	)
Other		(47	)	(126	)
Working capital adjustments
Decrease in accounts and notes receivable		78		549
Decrease (increase) in inventories		(76	)	61
Decrease in prepaid expenses and other current assets		10		9
Decrease in accounts payable		(129	)	(454	)
Increase (decrease) in taxes and other accruals		79		(416	)
Net Cash Provided by Operating Activities		1,790		421
Cash Flows From Investing Activities
Capital expenditures and investments		(966	)	(1,821	)
Working capital changes associated with investing activities		(26	)	(134	)
Proceeds from asset dispositions		35		135
Net purchases of short-term investments		(203	)	(302	)
Collection of advances/loans—related parties		57		53
Other		129		4
Net Cash Used in Investing Activities		(974	)	(2,065	)
Cash Flows From Financing Activities
Issuance of debt		—		4,594
Repayment of debt		(839	)	(64	)
Issuance of company common stock		(46	)	(42	)
Repurchase of company common stock		(112	)	—
Dividends paid		(331	)	(313	)
Other		(16	)	(38	)
Net Cash Provided by (Used in) Financing Activities		(1,344	)	4,137
Effect of Exchange Rate Changes on Cash and Cash Equivalents		27		5
Net Change in Cash and Cash Equivalents		(501	)	2,498
Cash and cash equivalents at beginning of period		3,610		2,368
Cash and Cash Equivalents at End of Period	$	3,109		4,866

See Notes to Consolidated Financial Statements.

4

Notes to Consolidated Financial Statements ConocoPhillips

Note 1—Basis of Presentation

The interim-period financial information presented in the financial statements included in this report is unaudited and, in the opinion of management, includes all known accruals and adjustments necessary for a fair presentation of the consolidated financial position of ConocoPhillips and its results of operations and cash flows for such periods. All such adjustments are of a normal and recurring nature unless otherwise disclosed. Certain notes and other information have been condensed or omitted from the interim financial statements included in this report. Therefore, these financial statements should be read in conjunction with the consolidated financial statements and notes included in our 2016 Annual Report on Form 10-K.

Note 2—Variable Interest Entities (VIEs)

We hold variable interests in VIEs that have not been consolidated because we are not considered the primary beneficiary. Information on our significant VIEs follows:

Australia Pacific LNG Pty Ltd (APLNG)

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary of APLNG because we share with Origin Energy and China Petrochemical Corporation (Sinopec) the power to direct the key activities of APLNG that most significantly impact its economic performance, which involve activities related to the production and commercialization of coalbed methane, as well as liquefied natural gas (LNG) processing and export marketing. As a result, we do not consolidate APLNG, and it is accounted for as an equity method investment.

As of March 31, 2017, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 5—Investments, Loans and Long-Term Receivables, and Note 10—Guarantees, for additional information.

Marine Well Containment Company, LLC (MWCC)

MWCC provides well containment equipment and technology and related services in the deepwater U.S. Gulf of Mexico. Its principal activities involve the development and maintenance of rapid-response hydrocarbon well containment systems that are deployable in the Gulf of Mexico on a call-out basis. We have a 10 percent ownership interest in MWCC, and it is accounted for as an equity method investment because MWCC is a limited liability company in which we are a Founding Member and exercise significant influence through our permanent seat on the ten-member Executive Committee responsible for overseeing the affairs of MWCC. In 2016, MWCC executed a $154 million term loan financing arrangement with an external financial institution whose terms required the financing be secured by letters of credit provided by certain owners of MWCC, including ConocoPhillips. In connection with the financing transaction, we issued a letter of credit of $22 million which can be drawn upon in the event of a default by MWCC on its obligation to repay the proceeds of the term loan. The fair value of this letter of credit is immaterial and not recognized on our consolidated balance sheet. MWCC is considered a VIE, as it has entered into arrangements that provide it with additional forms of subordinated financial support. We are not the primary beneficiary and do not consolidate MWCC because we share the power to govern the business and operation of the company and to undertake certain obligations that most significantly impact its economic performance with nine other unaffiliated owners of MWCC.

At March 31, 2017, the carrying value of our equity method investment in MWCC was $146 million. We have not provided any financial support to MWCC other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of MWCC.

5

Note 3—Inventories

Inventories consisted of the following:

	Millions of Dollars
	March 31 2017		December 31 2016
Crude oil and natural gas	$	509		418
Materials and supplies		588		600
	$	1,097		1,018

Inventories valued on the last-in, first-out (LIFO) basis totaled $379 million and $269 million at March 31, 2017 and December 31, 2016, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $121 million and $104 million at March 31, 2017 and December 31, 2016, respectively.

Note 4—Assets Held for Sale and Other Planned Dispositions

Assets Held for Sale

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) oil sands partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment. The cash portion of the consideration is subject to customary adjustments. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars for every $1 Canadian dollar by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 Canadian dollars per barrel. On the date of signing, we received a $130 million deposit from Cenovus, which is included in the “Cash Flows From Investing Activities” section in our consolidated statement of cash flows. Both FCCL and the western Canada gas assets are included in the Canada segment. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to close in the second quarter of 2017.

At March 31, 2017, the carrying value of our equity investment in FCCL was $9.0 billion. Our interests in the western Canada producing properties were considered held for sale resulting in the reclassification of $2.4 billion of properties, plants and equipment (PP&E) to “Prepaid expenses and other current assets” and $671 million of noncurrent liabilities, primarily asset retirement obligations, to “Other accruals,” on our consolidated balance sheet. The before-tax loss associated with our interests in the western Canada gas producing properties was $61 million and $145 million for the three months ended March 31, 2017 and March 31, 2016, respectively. We reported before-tax equity earnings of $120 million and a before-tax equity loss of $154 million related to FCCL for the three months ended March 31, 2017 and March 31, 2016, respectively.

Other Planned Dispositions

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3.0 billion of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary adjustments. The six-year contingent payment is effective beginning January 1, 2018, and is due annually for the periods in which the monthly U.S. Henry Hub (HH) price is at or above $3.20 per million British thermal units (MMBTU). The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017. The San Juan Basin results of operations are reported within the Lower 48 segment.

6

At March 31, 2017, the net carrying value was approximately $5.8 billion, consisting primarily of $6.2 billion of PP&E and $392 million of asset retirement obligations. The assets met held for sale criteria in April 2017. A noncash impairment will be recorded in the second quarter of 2017.

Note 5—Investments, Loans and Long-Term Receivables

APLNG

APLNG’s $8.5 billion project finance facility consists of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. All amounts have been drawn from the facility. APLNG made its first principal and interest repayment in March 2017 and will continue to make bi-annual payments until March 2029. At March 31, 2017, a balance of $8.2 billion was outstanding on the facility. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. In October 2016, we reached financial completion for Train 1, which reduced our associated guarantee by 60 percent. See Note 10—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 2—Variable Interest Entities (VIEs), for additional information.

During the first quarter of 2017, the outlook for crude oil prices weakened, and as a result, the estimated fair value of our investment in APLNG declined to an amount below carrying value. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded the impairment was not other than temporary under the guidance of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 323, “Investments—Equity Method and Joint Ventures.” In reaching this conclusion, we primarily considered: (1) the volatility and uncertainty in commodity markets; (2) the intent and ability of ConocoPhillips to retain our investment in APLNG; and (3) the short length of time carrying value has been less than market value (fair value exceeded carrying value as of December 31, 2016). Fair value has been estimated based on an internal discounted cash flow model using estimated future production, an outlook of future prices from a combination of exchanges (short-term) and pricing service companies (long-term), costs, a market outlook of foreign exchange rates provided by a third party, and a discount rate believed to be consistent with those used by principal market participants.

At March 31, 2017, the fair value of our investment in APLNG was estimated to be $8,629 million, resulting in an unrecognized impairment of $1,430 million. We will continue to monitor the relationship between the carrying value and the fair value of APLNG. Should we determine in the future there has been a loss in the value of our investment that is other than temporary, we would record a noncash impairment of our equity investment, calculated as the total difference between carrying value and fair value as of the end of the reporting period.

At March 31, 2017, the carrying value of our equity method investment in APLNG was $10,059 million. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

At March 31, 2017, the carrying value of our equity method investment in FCCL Partnership was $9,006 million, net of a $1,604 million reduction due to cumulative foreign currency translation effects. The balance is included in the “Investments and long-term receivables” line on our consolidated balance sheet. On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second quarter of 2017. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information.

7

Loans and Long-Term Receivables

As part of our normal ongoing business operations, and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans made to certain affiliated and non-affiliated companies. At March 31, 2017, significant loans to affiliated companies included $639 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

The long-term portion of these loans is included in the “Loans and advances—related parties” line on our consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

Note 6—Suspended Wells and Other Exploration Expenses

The capitalized cost of suspended wells at March 31, 2017, was $834 million, a decrease of $229 million from $1,063 million at year-end 2016. Two suspended wells in Shenandoah in the Gulf of Mexico totaling $94 million and one suspended well in Alaska totaling $17 million were charged to dry hole expense during the first three months of 2017 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2016.

In February 2017, we reached a settlement agreement on our contract for the Athena drilling rig, initially secured for our four-well commitment program in Angola. As a result of the cancellation, we recorded a before-tax charge of $43 million net in the first quarter of 2017.

This charge is included in the “Exploration expenses” line on our consolidated income statement.

Note 7—Impairments

During the three-month periods ended March 31, 2017 and 2016, we recognized before-tax impairment charges within the following segments:

	Millions of Dollars
	Three Months Ended March 31
	2017		2016
Alaska	$	174		—
Lower 48		—		9
Europe and North Africa		1		127
	$	175		136

The first quarter of 2017 included an impairment in our Alaska segment of $174 million for the associated PP&E carrying value of our small interest in a nonoperated producing property.

The first quarter of 2016 included impairments in our Europe and North Africa segment of $127 million, primarily as a result of lower natural gas prices in the United Kingdom.

The charges discussed below are included in the “Exploration expenses” line on our consolidated income statement and are not reflected in the table above.

In the first quarter of 2017, we recorded a before-tax impairment of $51 million for the associated carrying value of capitalized undeveloped leasehold costs of Shenandoah in deepwater Gulf of Mexico following the suspension of appraisal activity by the operator.

8

In the first quarter of 2016, due to lack of commerciality of a drilled well, we recorded a before-tax impairment of $95 million for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect in deepwater Gulf of Mexico. Additionally, following the completion of an initial marketing effort in the Gulf of Mexico, we recorded a before-tax impairment of $73 million, primarily due to changes in the estimated market value.

Note 8—Debt

As of March 31, 2017, our revolving credit facility, expiring in June 2019, was $6.75 billion. This credit facility supports two commercial paper programs: the ConocoPhillips $6.25 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $500 million program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At March 31, 2017 and December 31, 2016, we had no direct outstanding borrowings under the revolving credit facility and no letters of credit. We had no commercial paper outstanding at March 31, 2017 or December 31, 2016, under both the ConocoPhillips and the ConocoPhillips Qatar Funding Ltd. commercial paper programs. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at March 31, 2017.

In the first quarter of 2017, we made a prepayment of $805 million on our floating rate term loan due in 2019. As of March 31, 2017, the remaining balance on our term loan facility is $645 million. We have the right at any time and from time to time to prepay the term loan, in whole or in part, without premium or penalty upon notice to the Administrative Agent.

The term loan facility contains customary covenants regarding, among other matters, material compliance with laws and restrictions against certain consolidations, mergers and asset sales and creation of certain liens on our assets and consolidated subsidiaries. The term loan facility also contains financial covenants including a total debt to capitalization ratio, excluding the impacts of certain noncash impairments and foreign currency translation adjustments as defined in the Term Loan Agreement, which may not exceed 65 percent. At March 31, 2017, we were in compliance with this covenant.

The term loan facility includes customary events of default (subject to specified cure periods, materiality qualifiers and exceptions), including the failure to pay any interest, principal or fees when due, the failure to perform or the violation of any covenant contained in the term loan facility, the making of materially inaccurate or false representations or warranties, a default on certain material indebtedness, insolvency or bankruptcy, a change of control and the occurrence of material Employee Retirement Income Security Act of 1974 (ERISA) events and certain judgments against us or our material subsidiaries.

At March 31, 2017, we had $283 million of certain variable rate demand bonds (VRDBs) outstanding with maturities ranging through 2035. The VRDBs are redeemable at the option of the bondholders on any business day. The VRDBs are included in the “Long-term debt” line on our consolidated balance sheet.

9

Note 9—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first three months of 2017 and 2016 was as follows:

	Millions of Dollars
	2017									2016
	Common Stockholders’ Equity			Non- Controlling Interest			Total Equity			Common Stockholders’ Equity			Non- Controlling Interest			Total Equity
Balance at January 1	$	34,974			252			35,226			39,762			320			40,082
Net income (loss)		586			13			599			(1,469	)		13			(1,456	)
Dividends		(331	)		—			(331	)		(313	)		—			(313	)
Repurchase of company common stock		(112	)		—			(112	)		—			—			—
Distributions to noncontrolling interests		—			(17	)		(17	)		—			(16	)		(16	)
Other changes, net*		236			—			236			1,109			1			1,110
Balance at March 31	$	35,353			248			35,601			39,089			318			39,407

*Includes components of other comprehensive income, which are disclosed separately in the Consolidated Statement of Comprehensive Income.

Note 10—Guarantees

At March 31, 2017, we were liable for certain contingent obligations under various contractual arrangements as described below. We recognize a liability, at inception, for the fair value of our obligation as a guarantor for newly issued or modified guarantees. Unless the carrying amount of the liability is noted below, we have not recognized a liability because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At March 31, 2017, we had outstanding multiple guarantees in connection with our 37.5 percent ownership interest in APLNG. The following is a description of the guarantees with values calculated utilizing March 2017 exchange rates:

• We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is one year. Our maximum potential amount of future payments related to this guarantee is approximately $10 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

• We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. In October 2016, we reached financial completion for Train 1, releasing a portion of our guarantee. Our remaining guarantee of the project financing will be released upon meeting certain two Train completion tests with milestones which we estimate should occur this year. Our maximum exposure at March 31, 2017, is $1.24 billion based upon our pro-rata share of the facility used at that date. At March 31, 2017, the carrying value of this guarantee was approximately $46 million.

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• During the third quarter of 2016, we issued a guarantee for our pro-rata portion of the funds in a project finance reserve account. We estimate the remaining term of this guarantee is 12 years. Our maximum exposure under this guarantee is approximately $100 million and may become payable if an enforcement action is commenced by the project finance lenders against APLNG. At March 31, 2017, the carrying value of this guarantee was approximately $9 million.

• In conjunction with our original purchase of an ownership interest in APLNG from Origin Energy in October 2008, we agreed to reimburse Origin Energy for our share of the existing contingent liability arising under guarantees of an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of up to 25 years. Our maximum potential liability for future payments, or cost of volume delivery, under these guarantees is estimated to be $1 billion ($1.76 billion in the event of intentional or reckless breach), and would become payable if APLNG fails to meet its obligations under these agreements and the obligations cannot otherwise be mitigated. Future payments are considered unlikely, as the payments, or cost of volume delivery, would only be triggered if APLNG does not have enough natural gas to meet these sales commitments and if the co-venturers do not make necessary equity contributions into APLNG.

• We have guaranteed the performance of APLNG with regard to certain other contracts executed in connection with the project’s continued development. The guarantees have remaining terms of up to 29 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $150 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $540 million, which consist primarily of a guarantee of the residual value of a leased office building, guarantees of the residual value of leased corporate aircraft, and a guarantee for our portion of a joint venture’s project finance reserve accounts. These guarantees have remaining terms of up to six years and would become payable if, upon sale, certain asset values are lower than guaranteed amounts, business conditions decline at guaranteed entities, or as a result of nonperformance of contractual terms by guaranteed parties.

Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at March 31, 2017, was approximately $100 million. We amortize the indemnification liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of indemnity. In cases where the indemnification term is indefinite, we will reverse the liability when we have information the liability is essentially relieved or amortize the liability over an appropriate time period as the fair value of our indemnification exposure declines. Although it is reasonably possible future payments may exceed amounts recorded, due to the nature of the indemnifications, it is not possible to make a reasonable estimate of the maximum potential amount of future payments. Included in the recorded carrying amount at March 31, 2017, were approximately $40 million of environmental accruals for known contamination that are included in the “Asset retirement obligations and accrued environmental costs” line on our consolidated balance sheet. For additional information about environmental liabilities, see Note 11—Contingencies and Commitments.

On March 1, 2015, a supplier to one of the refineries included in Phillips 66 as part of the separation of our downstream businesses formally registered Phillips 66 as a party to the supply agreement, thereby triggering a guarantee we provided at the time of separation. Our maximum potential liability for future payments under this guarantee, which would become payable if Phillips 66 does not perform its contractual obligations under the supply agreement, is approximately $1.35 billion. At March 31, 2017, the carrying value of this guarantee is approximately $98 million and the remaining term is eight years. Because Phillips 66 has indemnified us for

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losses incurred under this guarantee, we have recorded an indemnification asset from Phillips 66 of approximately $98 million. The recorded indemnification asset amount represents the estimated fair value of the guarantee; however, if we are required to perform under the guarantee, we would expect to recover from Phillips 66 any amounts in excess of that value, provided Phillips 66 is a going concern.

Note 11—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated but no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to factors such as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes.

Environmental

We are subject to international, federal, state and local environmental laws and regulations. When we prepare our consolidated financial statements, we record accruals for environmental liabilities based on management’s best estimates, using all information that is available at the time. We measure estimates and base liabilities on currently available facts, existing technology, and presently enacted laws and regulations, taking into account stakeholder and business considerations. When measuring environmental liabilities, we also consider our prior experience in remediation of contaminated sites, other companies’ cleanup experience, and data released by the U.S. Environmental Protection Agency (EPA) or other organizations. We consider unasserted claims in our determination of environmental liabilities, and we accrue them in the period they are both probable and reasonably estimable.

Although liability of those potentially responsible for environmental remediation costs is generally joint and several for federal sites and frequently so for other sites, we are usually only one of many companies cited at a particular site. Due to the joint and several liabilities, we could be responsible for all cleanup costs related to any site at which we have been designated as a potentially responsible party. We have been successful to date in sharing cleanup costs with other financially sound companies. Many of the sites at which we are potentially responsible are still under investigation by the EPA or the agency concerned. Prior to actual cleanup, those potentially responsible normally assess the site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or may attain a settlement of liability. Where it appears that other potentially responsible parties may be financially unable to bear their proportional share, we consider this inability in estimating our potential liability, and we adjust our accruals accordingly. 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.

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We are currently participating in environmental assessments and cleanups at numerous federal Superfund and comparable state and international sites. After an assessment of environmental exposures for cleanup and other costs, we make accruals on an undiscounted basis (except those acquired in a purchase business combination, which we record on a discounted basis) for planned investigation and remediation activities for sites where it is probable future costs will be incurred and these costs can be reasonably estimated.

At March 31, 2017, our balance sheet included a total environmental accrual of $260 million, compared with $247 million at December 31, 2016, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. In the future, we may be involved in additional environmental assessments, cleanups and proceedings.

Legal Proceedings

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at March 31, 2017, we had performance obligations secured by letters of credit of $266 million (issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, commercial activities and services incident to the ordinary conduct of business.

In 2007, we announced we had been unable to reach agreement with respect to our migration to an empresa mixta structure mandated by the Venezuelan government’s Nationalization Decree. As a result, Venezuela’s national oil company, Petróleos de Venezuela S.A. (PDVSA), or its affiliates, directly assumed control over ConocoPhillips’ interests in the Petrozuata and Hamaca heavy oil ventures and the offshore Corocoro development project. In response to this expropriation, we filed a request for international arbitration on November 2, 2007, with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID). An arbitration hearing was held before an ICSID tribunal during the summer of 2010. On September 3, 2013, an ICSID arbitration tribunal held that Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in June 2007. On January 17, 2017, the Tribunal reconfirmed the decision that the expropriation was unlawful. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions. Separate arbitrations for contractual compensation against PDVSA are also pending before an International Chamber of Commerce (ICC) arbitration tribunal. In addition, ConocoPhillips brought fraudulent transfer actions in the U.S. District Court of Delaware, alleging that PDVSA has taken actions to improperly expatriate assets from the United States to Venezuela in an effort to avoid judgment creditors.

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In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims is complete. In February 2017, the tribunal unanimously awarded Burlington $380 million for Ecuador’s unlawful expropriation and breach of the U.S.-Ecuador bilateral investment treaty. The tribunal also issued a separate decision finding Ecuador to be entitled to $42 million for limited environmental and infrastructure impacts associated with the operations of Burlington and its co-venturer. Ecuador recently filed a request for annulment of this decision with ICSID. The schedule for the annulment process has not yet been set.

In December 2016, ConocoPhillips Angola filed a notice of arbitration against Sonangol E.P. under the Block 36 Production Sharing Contract relating to disputes arising thereunder. The arbitration will be conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person tribunal. The schedule for this arbitration has not yet been set.

Note 12—Derivative and Financial Instruments

Derivative Instruments

We use futures, forwards, swaps and options in various markets to meet our customer needs and capture market opportunities. Our commodity business primarily consists of natural gas, crude oil, bitumen, LNG and natural gas liquids.

Our derivative instruments are held at fair value on our consolidated balance sheet. Where these balances have the right of setoff, they are presented on a net basis. Related cash flows are recorded as operating activities on our consolidated statement of cash flows. On our consolidated income statement, realized and unrealized gains and losses are recognized either on a gross basis if directly related to our physical business or a net basis if held for trading. Gains and losses related to contracts that meet and are designated with the normal purchase normal sale exception are recognized upon settlement. We generally apply this exception to eligible crude contracts. We do not use hedge accounting for our commodity derivatives.

The following table presents the gross fair values of our commodity derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

	Millions of Dollars
	March 31 2017		December 31 2016
Assets
Prepaid expenses and other current assets	$	199		268
Other assets		52		44
Liabilities
Other accruals		196		300
Other liabilities and deferred credits		41		34

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The gains (losses) from commodity derivatives incurred, and the line items where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Sales and other operating revenues	$	51			(3	)
Other income		1			1
Purchased commodities		(38	)		(1	)

The table below summarizes our material net exposures resulting from outstanding commodity derivative contracts:

	Open Position Long/(Short)
	March 31 2017			December 31 2016
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(30	)		(31	)
Basis		31			2

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily relates to managing our cash-related and foreign currency exchange rate exposures, such as firm commitments for capital programs or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates. We do not elect hedge accounting on our foreign currency exchange derivatives.

The following table presents the gross fair values of our foreign currency exchange derivatives, excluding collateral, and the line items where they appear on our consolidated balance sheet:

	Millions of Dollars
	March 31 2017		December 31 2016
Assets
Prepaid expenses and other current assets	$	—		1
Liabilities
Other accruals		2		168

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The losses from foreign currency exchange derivatives incurred and the line item where they appear on our consolidated income statement were:

	Millions of Dollars
	Three Months Ended March 31
	2017		2016
Foreign currency transaction losses	$	7		97

We had the following net notional position of outstanding foreign currency exchange derivatives:

	In Millions Notional Currency
March 31 2017		December 31 2016
Sell U.S. dollar, buy other currencies*	USD	212		13
Buy U.S. dollar, sell other currencies**	USD	—		25
Buy British pound, sell other currencies***	GBP	12		1,069
Sell British pound, buy Norwegian krone	GBP	—		51

    *Primarily Canadian dollar and Norwegian krone.

  **Primarily British pound.

***Primarily Euro and Canadian dollar.

Financial Instruments

We have certain financial instruments on our consolidated balance sheet related to interest-bearing time deposits and commercial papers. These held-to-maturity financial instruments are included in “Cash and cash equivalents” on our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these investments are included in “Short-term investments” on our consolidated balance sheet.

	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	March 31 2017		December 31 2016		March 31 2017		December 31 2016
Cash	$	842		623		—		—
Time deposits
Remaining maturities from 1 to 90 days		2,267		2,987		190		39
Remaining maturities from 91 to 180 days		—		—		62		11
	$	3,109		3,610		252		50

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, short-term investments, over-the-counter (OTC) derivative contracts and trade receivables. Our cash equivalents and short-term investments are placed in high-quality commercial paper, money market funds, government debt securities and time deposits with major international banks and financial institutions.

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The credit risk from our OTC derivative contracts, such as forwards and swaps, derives from the counterparty to the transaction. Individual counterparty exposure is managed within predetermined credit limits and includes the use of cash-call margins when appropriate, thereby reducing the risk of significant nonperformance. We also use futures, swaps and option contracts that have a negligible credit risk because these trades are cleared with an exchange clearinghouse and subject to mandatory margin requirements until settled; however, we are exposed to the credit risk of those exchange brokers for receivables arising from daily margin cash calls, as well as for cash deposited to meet initial margin requirements.

Our trade receivables result primarily from our petroleum operations and reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk. The majority of these receivables have payment terms of 30 days or less, and we continually monitor this exposure and the creditworthiness of the counterparties. We do not generally require collateral to limit the exposure to loss; however, we will sometimes use letters of credit, prepayments and master netting arrangements to mitigate credit risk with counterparties that both buy from and sell to us, as these agreements permit the amounts owed by us or owed to others to be offset against amounts due to us.

Certain of our derivative instruments contain provisions that require us to post collateral if the derivative exposure exceeds a threshold amount. We have contracts with fixed threshold amounts and other contracts with variable threshold amounts that are contingent on our credit rating. The variable threshold amounts typically decline for lower credit ratings, while both the variable and fixed threshold amounts typically revert to zero if we fall below investment grade. Cash is the primary collateral in all contracts; however, many also permit us to post letters of credit as collateral, such as transactions administered through the New York Mercantile Exchange.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on March 31, 2017 and December 31, 2016, was $35 million and $42 million, respectively. For these instruments, no collateral was posted as of March 31, 2017 or December 31, 2016. If our credit rating had been downgraded below investment grade on March 31, 2017, we would be required to post $35 million of additional collateral, either with cash or letters of credit.

Note 13—Fair Value Measurement

We carry a portion of our assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclosed according to the quality of valuation inputs under the following hierarchy:

• Level 1: Quoted prices (unadjusted) in an active market for identical assets or liabilities.

• Level 2: Inputs other than quoted prices that are directly or indirectly observable.

• Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. There were no material transfers in or out of Level 1 during 2017 or 2016.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives. Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 2 derivative assets and liabilities primarily represent OTC swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or pricing service companies that are all corroborated by

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market data. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.

The following table summarizes the fair value hierarchy for gross financial assets and liabilities (i.e., unadjusted where the right of setoff exists for commodity derivatives accounted for at fair value on a recurring basis):

	Millions of Dollars
	March 31, 2017					December 31, 2016
		Level 1	Level 2	Level 3	Total		Level 1	Level 2	Level 3	Total
Assets
Commodity derivatives	$	135	95	21	251		194	96	22	312
Total assets	$	135	95	21	251		194	96	22	312
Liabilities
Commodity derivatives	$	152	70	15	237		207	105	22	334
Total liabilities	$	152	70	15	237		207	105	22	334

The following table summarizes those commodity derivative balances subject to the right of setoff as presented on our consolidated balance sheet. We have elected to offset the recognized fair value amounts for multiple derivative instruments executed with the same counterparty in our financial statements when a legal right of setoff exists.    

	Millions of Dollars
		Gross Amounts Recognized	Gross Amounts Offset	Net Amounts Presented	Cash Collateral	Gross Amounts without Right of Setoff	Net Amounts
March 31, 2017
Assets	$	251	157	94	—	4	90
Liabilities		237	157	80	16	5	59
December 31, 2016
Assets	$	312	221	91	—	5	86
Liabilities		334	221	113	12	12	89

At March 31, 2017 and December 31, 2016, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Reported Fair Values of Financial Instruments

We used the following methods and assumptions to estimate the fair value of financial instruments:

• Cash and cash equivalents and short-term investments: The carrying amount reported on the balance sheet approximates fair value.

• Accounts and notes receivable (including long-term and related parties): The carrying amount reported on the balance sheet approximates fair value. The valuation technique and methods used to estimate the fair value of the current portion of fixed-rate related party loans is consistent with Loans and advances—related parties.

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• Loans and advances—related parties: The carrying amount of floating-rate loans approximates fair value. The fair value of fixed-rate loan activity is measured using market observable data and is categorized as Level 2 in the fair value hierarchy. See Note 5—Investments, Loans and Long-Term Receivables, for additional information.

• Accounts payable (including related parties) and floating-rate debt: The carrying amount of accounts payable and floating-rate debt reported on the balance sheet approximates fair value.

• Fixed-rate debt: The estimated fair value of fixed-rate debt is measured using prices available from a pricing service that is corroborated by market data; therefore, these liabilities are categorized as Level 2 in the fair value hierarchy.

The following table summarizes the net fair value of financial instruments (i.e., adjusted where the right of setoff exists for commodity derivatives):

	Millions of Dollars
	Carrying Amount				Fair Value
	March 31		December 31		March 31		December 31
	2017		2016		2017		2016
Financial assets
Commodity derivatives	$	94		91		94		91
Total loans and advances—related parties		641		701		641		701
Financial liabilities
Total debt, excluding capital leases		25,616		26,423		28,734		29,307
Commodity derivatives		64		101		64		101

Note 14—Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss in the equity section of our consolidated balance sheet included:

	Millions of Dollars
	Defined Benefit Plans			Foreign Currency Translation			Accumulated Other Comprehensive Income (Loss)
December 31, 2016	$	(547	)		(5,646	)		(6,193	)
Other comprehensive income		48			184			232
March 31, 2017	$	(499	)		(5,462	)		(5,961	)

There were no items within accumulated other comprehensive loss related to noncontrolling interests.

The following table summarizes reclassifications out of accumulated other comprehensive loss:

	Millions of Dollars
	Three Months Ended March 31
	2017		2016
Defined benefit plans	$	53		63

The above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of $28 million and $36 million for the three-month periods ended March 31, 2017 and 2016, respectively. See Note 16—Employee Benefit Plans, for additional information.

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Note 15—Cash Flow Information    

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Cash Payments (Receipts)
Interest	$	327			244
Income taxes		150			133
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(243	)		(302	)
Short-term investments sold		40			—
	$	(203	)		(302	)

During the quarter, we recognized a $180 million adverse cash impact from the settlement of cross-currency swap transactions which is included in the “Cash Flows From Operating Activities” section of our consolidated statement of cash flows.

We received a $130 million deposit from Cenovus Energy on the date of signing the definitive agreement to sell certain Canadian assets. This deposit is included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information on our Canada disposition.

Note 16—Employee Benefit Plans    

Pension and Postretirement Plans    

	Millions of Dollars
	Pension Benefits												Other Benefits
Three Months Ended	March 31												March 31
	2017						2016						2017			2016
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Service cost	$	23			19			27			20			—			1
Interest cost		32			26			40			31			2			3
Expected return on plan assets		(34	)		(39	)		(43	)		(41	)		—			—
Amortization of prior service cost (credit)		1			(1	)		1			(1	)		(9	)		(9	)
Recognized net actuarial loss (gain)		19			12			19			7			(1	)		—
Settlements		60			—			82			—			—			—
Net periodic benefit cost	$	101			17			126			16			(8	)		(5	)

During the first three months of 2017, we contributed $19 million to our domestic benefit plans and $41 million to our international benefit plans. In 2017, we expect to contribute approximately $340 million to our domestic qualified and nonqualified pension and postretirement benefit plans and $120 million to our international qualified and nonqualified pension and postretirement benefit plans.

During the three-month period ended March 31, 2017, lump-sum benefit payments exceeded the sum of service and interest costs for the fiscal year for the U.S. qualified pension plan and certain U.S. nonqualified supplemental retirement plans. As a result, we recognized a proportionate share of prior actuarial losses from other comprehensive income as pension settlement expense of $60 million.

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Severance Accrual

As a result of entering into a definitive agreement during the first quarter to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, a reduction in our overall employee workforce is expected in 2017. Severance accruals of $39 million were recorded during the three-month period ended March 31, 2017. The following table summarizes our severance accrual activity for the three-month period ended March 31, 2017:

	Millions of Dollars
Balance at December 31, 2016	$	80
Accruals		39
Benefit payments		(45	)
Foreign currency translation adjustments		(1	)
Balance at March 31, 2017	$	73

Of the remaining balance at March 31, 2017, $48 million is classified as short-term.

Note 17—Related Party Transactions

Our related parties primarily include equity method investments and certain trusts for the benefit of employees.

Significant transactions with our equity affiliates were:

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Operating revenues and other income	$	29			27
Purchases		23			24
Operating expenses and selling, general and administrative expenses		12			16
Net interest (income) expense*		(3	)		(3	)

*We paid interest to, or received interest from various affiliates. See Note 5—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 18—Segment Disclosures and Related Information

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. We manage our operations through six operating segments, which are primarily defined by geographic region: Alaska, Lower 48, Canada, Europe and North Africa, Asia Pacific and Middle East, and Other International.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead and certain technology activities, including licensing revenues. Corporate assets include all cash and cash equivalents and short-term investments.

We evaluate performance and allocate resources based on net income (loss) attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

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Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Sales and Other Operating Revenues
Alaska	$	1,007			778
Lower 48		3,230			2,145
Intersegment eliminations		(3	)		(7	)
Lower 48		3,227			2,138
Canada		870			425
Intersegment eliminations		(86	)		(35	)
Canada		784			390
Europe and North Africa		1,443			923
Asia Pacific and Middle East		1,022			837
Corporate and Other		35			55
Consolidated sales and other operating revenues	$	7,518			5,121
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	(11	)		(2	)
Lower 48		(362	)		(820	)
Canada		948			(294	)
Europe and North Africa		171			(51	)
Asia Pacific and Middle East		236			(5	)
Other International		(48	)		(24	)
Corporate and Other		(348	)		(273	)
Consolidated net income (loss) attributable to ConocoPhillips	$	586			(1,469	)

	Millions of Dollars
	March 31 2017		December 31 2016
Total Assets
Alaska	$	12,095		12,314
Lower 48		21,746		22,673
Canada		17,707		17,548
Europe and North Africa		11,562		11,727
Asia Pacific and Middle East		20,058		20,451
Other International		99		97
Corporate and Other		4,706		4,962
Consolidated total assets	$	87,973		89,772

Note 19—Income Taxes

Our effective tax rate for the first quarter of 2017 was 358 percent compared with 35 percent for the first quarter of 2016. The increase in the effective tax rate was primarily due to the recognition of deferred tax benefits associated with the disposition of certain Canadian assets, discussed below, and lower before-tax losses in low tax jurisdictions. This is partially offset by our higher before-tax income in high tax jurisdictions.

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership and the majority of our western Canada gas assets. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to

22

close in the second quarter of 2017. During the first quarter, we recorded a $996 million financial accounting tax benefit primarily associated with a deferred tax recovery related to the Canadian capital gains exclusion component of the transaction and the recognition of previously unrealizable Canadian capital asset tax basis. The disposition, along with the associated restructuring of our Canadian operations, may generate an additional tax benefit of approximately $800 million. However, since we believe it is not likely we will receive a corresponding cash tax savings of this amount, the benefit has not been recorded. See Note 4—Assets Held for Sale and Other Planned Dispositions, for additional information on our Canada disposition.

Note 20—New Accounting Standards

In May 2014, the FASB issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers” (ASU No. 2014-09), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. This ASU supersedes the revenue recognition requirements in FASB ASC Topic 605, “Revenue Recognition,” and most industry-specific guidance. This ASU sets forth a five-step model for determining when and how revenue is recognized. Under the model, an entity will be required to recognize revenue to depict the transfer of goods or services to a customer at an amount reflecting the consideration it expects to receive in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts.

In August 2015, the FASB issued ASU No. 2015-14, “Deferral of the Effective Date,” which defers the effective date of ASU No. 2014-09. The ASU is now effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted for interim and annual periods beginning after December 15, 2016. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach.

ASU No. 2014-09 was amended in March 2016 by the provisions of ASU No. 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” in April 2016 by the provisions of ASU No. 2016-10, “Identifying Performance Obligations and Licensing,” in May 2016 by the provisions of ASU No. 2016-12, “Narrow-Scope Improvements and Practical Expedients,” and in December 2016 by the provisions of ASU No. 2016-20, “Technical Corrections and Improvements to Topic 606, Revenue From Contracts With Customers.”

We will adopt the provisions of ASU No. 2014-09, as amended, with effect from January 1, 2018, and have elected not to early adopt the standard. We intend to adopt the new standard using the modified retrospective approach which we will apply only to contracts within the scope of the standard that are not complete at the date of initial application. Under this approach, we will apply the guidance retrospectively only to the most current period presented in the financial statements. We continue to assess the impact of adoption of the standard on our current accounting policies and revenue-related disclosures. The impact to our financial statements is expected to be immaterial.

In February 2016, the FASB issued ASU No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB ASC Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. While we continue to evaluate the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures.

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In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments” (ASU No. 2016-13), which sets forth the current expected credit loss model, a new forward-looking impairment model for certain financial instruments based on expected losses rather than incurred losses. The ASU is effective for interim and annual periods beginning after December 15, 2019, and early adoption of the standard is permitted. Entities are required to adopt ASU No. 2016-13 using a modified retrospective approach, subject to certain limited exceptions. We are currently evaluating the impact of the adoption of this ASU.

24

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I, with respect to publicly held debt securities. ConocoPhillips Company is 100 percent owned by ConocoPhillips. ConocoPhillips Canada Funding Company I is an indirect, 100 percent owned subsidiary of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Canada Funding Company I, with respect to its publicly held debt securities. Similarly, ConocoPhillips has fully and unconditionally guaranteed the payment obligations of ConocoPhillips Company with respect to its publicly held debt securities. In addition, ConocoPhillips Company has fully and unconditionally guaranteed the payment obligations of ConocoPhillips with respect to its publicly held debt securities. All guarantees are joint and several. The following condensed consolidating financial information presents the results of operations, financial position and cash flows for:

• ConocoPhillips, ConocoPhillips Company and ConocoPhillips Canada Funding Company I (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).

• All other nonguarantor subsidiaries of ConocoPhillips.

• The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes.

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	Millions of Dollars
	Three Months Ended March 31, 2017
Income Statement	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I			All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Revenues and Other Income
Sales and other operating revenues	$	—			3,115			—			4,403			—			7,518
Equity in earnings of affiliates		657			1,173			—			160			(1,790	)		200
Gain on dispositions		—			13			—			9			—			22
Other income		—			2			—			29			—			31
Intercompany revenues		17			71			42			794			(924	)		—
Total Revenues and Other Income		674			4,374			42			5,395			(2,714	)		7,771
Costs and Expenses
Purchased commodities		—			2,765			—			1,190			(763	)		3,192
Production and operating expenses		—			141			—			1,158			(1	)		1,298
Selling, general and administrative expenses		4			136			—			22			(5	)		157
Exploration expenses		—			372			—			179			—			551
Depreciation, depletion and amortization		—			251			—			1,728			—			1,979
Impairments		—			—			—			175			—			175
Taxes other than income taxes		—			49			—			182			—			231
Accretion on discounted liabilities		—			10			—			85			—			95
Interest and debt expense		129			165			37			139			(155	)		315
Foreign currency transaction (gains) losses		(7	)		—			49			(32	)		—			10
Total Costs and Expenses		126			3,889			86			4,826			(924	)		8,003
Income (loss) before income taxes		548			485			(44	)		569			(1,790	)		(232	)
Income tax benefit		(38	)		(172	)		(5	)		(616	)		—			(831	)
Net income (loss)		586			657			(39	)		1,185			(1,790	)		599
Less: net income attributable to noncontrolling interests		—			—			—			(13	)		—			(13	)
Net Income (Loss) Attributable to ConocoPhillips	$	586			657			(39	)		1,172			(1,790	)		586
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	818			889			(13	)		1,362			(2,238	)		818
Income Statement	Three Months Ended March 31, 2016
Revenues and Other Income
Sales and other operating revenues	$	—			2,072			—			3,049			—			5,121
Equity in losses of affiliates		(1,427	)		(750	)		—			(444	)		2,472			(149	)
Gain on dispositions		—			22			—			1			—			23
Other income (loss)		—			(6	)		—			26			—			20
Intercompany revenues		18			81			56			525			(680	)		—
Total Revenues and Other Income		(1,409	)		1,419			56			3,157			1,792			5,015
Costs and Expenses
Purchased commodities		—			1,848			—			879			(502	)		2,225
Production and operating expenses		—			253			—			1,104			(3	)		1,354
Selling, general and administrative expenses		3			154			—			35			(6	)		186
Exploration expenses		—			431			—			74			—			505
Depreciation, depletion and amortization		—			257			—			1,990			—			2,247
Impairments		—			4			—			132			—			136
Taxes other than income taxes		—			57			—			123			—			180
Accretion on discounted liabilities		—			12			—			97			—			109
Interest and debt expense		124			134			55			137			(169	)		281
Foreign currency transaction (gains) losses		(44	)		2			312			(254	)		—			16
Total Costs and Expenses		83			3,152			367			4,317			(680	)		7,239
Loss before income taxes		(1,492	)		(1,733	)		(311	)		(1,160	)		2,472			(2,224	)
Income tax benefit		(23	)		(306	)		(18	)		(421	)		—			(768	)
Net loss		(1,469	)		(1,427	)		(293	)		(739	)		2,472			(1,456	)
Less: net income attributable to noncontrolling interests		—			—			—			(13	)		—			(13	)
Net Loss Attributable to ConocoPhillips	$	(1,469	)		(1,427	)		(293	)		(752	)		2,472			(1,469	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(368	)		(326	)		(47	)		445			(72	)		(368	)

26

	Millions of Dollars
	March 31, 2017
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			313		58			2,738		—			3,109
Short-term investments		—			—		—			252		—			252
Accounts and notes receivable		12			1,814		25			3,876		(2,368	)		3,359
Inventories		—			142		—			955		—			1,097
Prepaid expenses and other current assets		1			155		7			2,773		(25	)		2,911
Total Current Assets		13			2,424		90			10,594		(2,393	)		10,728
Investments, loans and long-term receivables*		38,761			62,802		2,280			31,145		(113,313	)		21,675
Net properties, plants and equipment		—			5,818		—			48,622		—			54,440
Other assets		40			2,345		216			1,271		(2,742	)		1,130
Total Assets	$	38,814			73,389		2,586			91,632		(118,448	)		87,973
Liabilities and Stockholders’ Equity
Accounts payable	$	—			2,356		2			3,541		(2,368	)		3,531
Short-term debt		(9	)		999		6			99		—			1,095
Accrued income and other taxes		—			61		—			695		—			756
Employee benefit obligations		—			336		—			129		—			465
Other accruals		101			259		49			1,295		(25	)		1,679
Total Current Liabilities		92			4,011		57			5,759		(2,393	)		7,526
Long-term debt		8,173			12,635		1,708			2,824		—			25,340
Asset retirement obligations and accrued environmental costs		—			944		—			6,940		—			7,884
Deferred income taxes		—			—		—			9,778		(2,210	)		7,568
Employee benefit obligations		—			1,906		—			628		—			2,534
Other liabilities and deferred credits*		1,758			9,927		778			14,240		(25,183	)		1,520
Total Liabilities		10,023			29,423		2,543			40,169		(29,786	)		52,372
Retained earnings		25,280			14,672		(580	)		13,253		(20,821	)		31,804
Other common stockholders’ equity		3,511			29,294		623			37,962		(67,841	)		3,549
Noncontrolling interests		—			—		—			248		—			248
Total Liabilities and Stockholders’ Equity	$	38,814			73,389		2,586			91,632		(118,448	)		87,973
*Includes intercompany loans.
Balance Sheet	December 31, 2016
Assets
Cash and cash equivalents	$	—			358		13			3,239		—			3,610
Short-term investments		—			—		—			50		—			50
Accounts and notes receivable		22			1,968		23			6,103		(4,702	)		3,414
Inventories		—			84		—			934		—			1,018
Prepaid expenses and other current assets		2			116		8			415		(24	)		517
Total Current Assets		24			2,526		44			10,741		(4,726	)		8,609
Investments, loans and long-term receivables*		37,901			64,434		2,296			31,643		(114,602	)		21,672
Net properties, plants and equipment		—			6,301		—			52,030		—			58,331
Other assets		40			2,194		220			1,240		(2,534	)		1,160
Total Assets	$	37,965			75,455		2,560			95,654		(121,862	)		89,772
Liabilities and Stockholders’ Equity
Accounts payable	$	—			4,683		1			3,671		(4,702	)		3,653
Short-term debt		(10	)		999		6			94		—			1,089
Accrued income and other taxes		—			85		—			399		—			484
Employee benefit obligations		—			489		—			200		—			689
Other accruals		171			271		40			536		(24	)		994
Total Current Liabilities		161			6,527		47			4,900		(4,726	)		6,909
Long-term debt		8,975			12,635		1,710			2,866		—			26,186
Asset retirement obligations and accrued environmental costs		—			925		—			7,500		—			8,425
Deferred income taxes		—			—		—			10,972		(2,023	)		8,949
Employee benefit obligations		—			1,901		—			651		—			2,552
Other liabilities and deferred credits*		417			10,391		748			17,832		(27,863	)		1,525
Total Liabilities		9,553			32,379		2,505			44,721		(34,612	)		54,546
Retained earnings		25,025			14,015		(541	)		12,883		(19,834	)		31,548
Other common stockholders’ equity		3,387			29,061		596			37,798		(67,416	)		3,426
Noncontrolling interests		—			—		—			252		—			252
Total Liabilities and Stockholders’ Equity	$	37,965			75,455		2,560			95,654		(121,862	)		89,772
*Includes intercompany loans.

27

	Millions of Dollars
	Three Months Ended March 31, 2017
Statement of Cash Flows	ConocoPhillips			ConocoPhillips Company			ConocoPhillips Canada Funding Company I		All Other Subsidiaries			Consolidating Adjustments			Total Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(97	)		1,014			45		1,581			(753	)		1,790
Cash Flows From Investing Activities
Capital expenditures and investments		—			(149	)		—		(819	)		2			(966	)
Working capital changes associated with investing activities		—			55			—		(81	)		—			(26	)
Proceeds from asset dispositions		—			46			—		18			(29	)		35
Purchases of short-term investments		—			—			—		(203	)		—			(203	)
Long-term advances/loans—related parties		—			(30	)		—		—			30			—
Collection of advances/loans—related parties		—			63			—		2,138			(2,144	)		57
Intercompany cash management		1,341			1,037			—		(2,378	)		—			—
Other		—			—			—		129			—			129
Net Cash Provided by (Used in) Investing Activities		1,341			1,022			—		(1,196	)		(2,141	)		(974	)
Cash Flows From Financing Activities
Issuance of debt		—			—			—		30			(30	)		—
Repayment of debt		(805	)		(2,081	)		—		(97	)		2,144			(839	)
Issuance of company common stock		3			—			—		—			(49	)		(46	)
Repurchase of company common stock		(112	)		—			—		—			—			(112	)
Dividends paid		(331	)		—			—		(802	)		802			(331	)
Other		1			—			—		(44	)		27			(16	)
Net Cash Used in Financing Activities		(1,244	)		(2,081	)		—		(913	)		2,894			(1,344	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		27			—			27
Net Change in Cash and Cash Equivalents		—			(45	)		45		(501	)		—			(501	)
Cash and cash equivalents at beginning of period		—			358			13		3,239			—			3,610
Cash and Cash Equivalents at End of Period	$	—			313			58		2,738			—			3,109
Statement of Cash Flows	Three Months Ended March 31, 2016
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(153	)		(284	)		1		1,011			(154	)		421
Cash Flows From Investing Activities
Capital expenditures and investments		—			(504	)		—		(1,516	)		199			(1,821	)
Working capital changes associated with investing activities		—			(21	)		—		(113	)		—			(134	)
Proceeds from asset dispositions		2,300			60			—		75			(2,300	)		135
Net sales (purchases) of short-term investments		—			—			—		(302	)		—			(302	)
Long-term advances/loans—related parties		—			(51	)		—		—			51			—
Collection of advances/loans—related parties		—			—			—		2,198			(2,145	)		53
Intercompany cash management		(3,438	)		3,206			—		232			—			—
Other		—			8			—		(4	)		—			4
Net Cash Provided by (Used in) Investing Activities		(1,138	)		2,698			—		570			(4,195	)		(2,065	)
Cash Flows From Financing Activities
Issuance of debt		1,600			2,994			—		51			(51	)		4,594
Repayment of debt		—			(2,145	)		—		(64	)		2,145			(64	)
Issuance of company common stock		7			—			—		—			(49	)		(42	)
Dividends paid		(313	)		—			—		(203	)		203			(313	)
Other		(3	)		(2,320	)		—		184			2,101			(38	)
Net Cash Provided by (Used in) Financing Activities		1,291			(1,471	)		—		(32	)		4,349			4,137
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—		5			—			5
Net Change in Cash and Cash Equivalents		—			943			1		1,554			—			2,498
Cash and cash equivalents at beginning of period		—			4			15		2,349			—			2,368
Cash and Cash Equivalents at End of Period	$	—			947			16		3,903			—			4,866

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Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis is the company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes. It contains forward-looking statements including, without limitation, statements relating to the company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions identify forward-looking statements. The company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the company’s disclosures under the heading: “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 48.

The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to net income (loss) attributable to ConocoPhillips.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Our diverse portfolio primarily includes resource-rich North American unconventional assets and oil sands assets in Canada; lower-risk conventional assets in North America, Europe, Asia and Australia; several liquefied natural gas (LNG) developments; and an inventory of global conventional and unconventional exploration prospects. Headquartered in Houston, Texas, we had operations and activities in 17 countries, approximately 13,100 employees worldwide and total assets of $88 billion as of March 31, 2017.

Overview

Despite increases since the fourth quarter of 2016, global production oversupply caused commodity prices to remain challenged in the first quarter of 2017.

In the fourth quarter of 2016, given our view that commodity prices were likely to remain lower and more volatile, we announced an updated value proposition. Our value proposition principles, which are to maintain a strong investment grade balance sheet, grow our dividend and pursue disciplined growth, remained essentially unchanged; however, we took steps to improve our competitiveness and resilience by establishing clear priorities for allocating future cash flows. In order, those priorities are: invest capital at a level that maintains flat production volumes and pay our existing dividend; grow our existing dividend; reduce debt to a level we believe is sufficient to maintain a strong investment grade rating through price cycles; repurchase shares; and invest capital to grow absolute production. In conjunction with updating our value proposition, we outlined a 2017 to 2019 operating plan that achieves our cash allocation priorities at Brent prices at or above $50 per barrel with asset sales of $5 billion to $8 billion.

In the first quarter of 2017, we made significant progress toward delivering on our priorities. We increased our quarterly dividend by 6 percent to $0.265 per share, made a prepayment of $805 million on our term loan due in 2019, and repurchased 2.2 million shares of our common stock.    

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) oil sands partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the

29

date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment. The cash portion of the consideration is subject to customary adjustments. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars for every $1 Canadian dollar by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 Canadian dollars per barrel. With the proceeds from this deal, we plan to significantly accelerate our value proposition by reducing debt to $20 billion and tripling our annual planned share buybacks from $1 billion to $3 billion, both in 2017. On a longer-term basis, this will result in a targeted debt level of $15 billion and repurchases of up to $6 billion of our common stock by year-end 2019.

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary closing adjustments. The six-year contingent payment is effective beginning January 1, 2018, and is due annually for periods in which the monthly U.S. Henry Hub (HH) price is at or above $3.20 per million British thermal units (MMBTU). Proceeds from this transaction will be used for general corporate purposes.

For additional information on our dispositions, see Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.

Our recently announced asset dispositions are in line with our strategy, announced in November 2016, to focus on low cost-of-supply projects in our portfolio that strategically fit our development plans. We are focused on delivering on our value proposition, and are aggressively executing on our stated plans, which we believe position the company for success in the current environment of price uncertainty and ongoing volatility.

Operationally, we continue to focus on safely executing our capital program and remaining attentive to our costs. We produced 1,593 thousand barrels of oil equivalent per day (MBOED) in the first quarter of 2017, an increase of 15 MBOED compared with the same period of 2016. We continue to pursue sustainable operating cost reductions within our business. Operating costs include production and operating expense; selling, general and administrative expense; and exploration general and administrative, geological and geophysical, lease rental and other expense.

Business Environment

Global oil market conditions remain challenged but are improving. Global market fundamentals are trending toward a better balance; however, it will take time for the high level of global inventories to drop to more normal levels.

Global oil prices experienced elevated levels of volatility throughout 2016 with first quarter Brent crude oil prices reaching a 10-year quarterly average low of $33.89 per barrel. Global oil prices began to improve at the end of 2016 and through the first quarter of 2017 in response to stronger global demand and slower production growth.

The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply-and-demand conditions. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Among other dynamics that could influence world energy markets and commodity prices are global economic health, supply disruptions or fears thereof caused by civil unrest or military conflicts, actions taken by Organization of Petroleum Exporting Countries (OPEC), environmental laws, tax regulations, governmental policies and weather-related disruptions. North America’s energy landscape has been transformed from resource scarcity to an abundance of supply, primarily due to advances in technology responsible for the rapid growth of tight oil production, successful exploration and rising production from the Canadian oil sands. Our strategy is to create value through price cycles by delivering on the financial and operational priorities that underpin our value proposition.

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Our earnings and operating cash flows generally correlate with industry price levels for crude oil and natural gas, the prices of which are subject to factors external to the company and over which we have no control. The following graph depicts the trend in average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and HH natural gas:

Brent crude oil prices averaged $53.78 per barrel in the first quarter of 2017, an increase of 59 percent compared with $33.89 per barrel in the first quarter of 2016, and an increase of 9 percent compared with $49.46 in the fourth quarter of 2016. Industry crude prices for WTI averaged $51.83 per barrel in the first quarter of 2017, an increase of 56 percent compared with $33.27 per barrel in the first quarter of 2016, and an increase of 5 percent compared with $49.18 in the fourth quarter of 2016.

Henry Hub natural gas prices averaged $3.32 per MMBTU in the first quarter of 2017, an increase of 59 percent compared with $2.09 per MMBTU in the first quarter of 2016, and an increase of 11 percent compared with $2.98 per MMBTU in the fourth quarter of 2016. Prices improved relative to the same period of 2016 as a result of growth in demand for natural gas coupled with reduced production.

Our realized bitumen price increased from $1.74 per barrel in the first quarter of 2016 to $21.56 per barrel in the same period of 2017, primarily due to the significant increase in the WCS benchmark price as a result of increases to WTI pricing, partly offset by higher diluent costs. Compared with $21.64 per barrel in the fourth quarter of 2016, our first-quarter 2017 realized bitumen price was essentially flat.

Our total average realized price was $36.18 per barrel of oil equivalent (BOE) in the first quarter of 2017, an increase of 58 percent compared with $22.94 per BOE in the first quarter of 2016, reflecting increased average realized prices for all commodities.

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Key Operating and Financial Summary

Significant items during the first quarter of 2017 included the following:

• Achieved first-quarter production excluding Libya of 1,584 MBOED; 2 percent production growth adjusted for downtime and dispositions.

• Reduced production and operating expenses by 4 percent year over year.

• Increased quarterly dividend by 6 percent.

• Announced strategic Canadian and San Juan Basin asset dispositions in March and April, respectively, for total consideration of approximately $16 billion.

• Strengthened balance sheet through $0.8 billion of early debt retirement; announced revised debt target of $15 billion by year-end 2019.

• Progressed share buyback program and increased authorization to $6 billion.

Outlook

Capital and Production Guidance

Second-quarter 2017 production is expected to be 1,495 to 1,535 MBOED, excluding Libya and the impacts of our recently announced Canada and San Juan dispositions.

Full-year 2017 production and capital expenditures guidance, excluding the impacts from the Canada and San Juan Basin dispositions, are unchanged.

Marketing Activities

In line with our strategic objectives, we are currently marketing certain noncore assets primarily associated with North American natural gas. Given our recently announced agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion, we have adjusted our outlook on total consideration from asset dispositions from the previously-stated range of $5 billion to $8 billion over the next two years, to more than $16 billion in 2017. On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million.

Restructuring Costs

In the first quarter of 2017, we recorded a before-tax gross severance accrual of $39 million, primarily due to our recently announced Canada disposition. We expect to incur additional restructuring charges during the remainder of 2017 due to our aforementioned Canada and San Juan dispositions. As the analysis is ongoing, it is not reasonably practicable to quantify the financial impact, but the impact could be material to our results of operations for the periods in which the restructuring costs are incurred.

Impairments

As we continue to market certain noncore assets, primarily associated with North American natural gas, it is reasonably likely we will incur future impairment charges. Within our Lower 48 segment, we expect to record an estimated noncash before-tax impairment of approximately $3 billion in the second quarter of 2017 associated with the announced disposition of our interests in the San Juan Basin.

While we may incur additional future impairment charges to investments in nonconsolidated entities accounted for under the equity method and long-lived assets, it is not reasonably practicable to quantify their financial impacts. These impacts could be material to our results of operations for the periods in which they are incurred.

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RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three-month period ended March 31, 2017, is based on a comparison with the corresponding period of 2016.

Consolidated Results

A summary of the company’s net income (loss) attributable to ConocoPhillips by business segment follows:

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Alaska	$	(11	)		(2	)
Lower 48		(362	)		(820	)
Canada		948			(294	)
Europe and North Africa		171			(51	)
Asia Pacific and Middle East		236			(5	)
Other International		(48	)		(24	)
Corporate and Other		(348	)		(273	)
Net income (loss) attributable to ConocoPhillips	$	586			(1,469	)

Net income (loss) attributable to ConocoPhillips increased $2,055 million in the first quarter of 2017, compared with the same period of 2016, mainly due to:

• Recognition of deferred tax benefits totaling $996 million primarily related to the expected disposition of certain Canadian assets.

• Higher realized commodity prices.

• Improved equity earnings, mainly due to higher realized prices and sales volumes.

• Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-production rates from reserve additions, as well as lower volumes.

The increase in income was partly offset by higher production taxes and property taxes; proved property impairment expense, primarily in our Alaska segment; and exploration expenses.

See the “Segment Results” section for additional information.

Income Statement Analysis

Sales and other operating revenues increased 47 percent in the first quarter of 2017, mainly due to higher realized prices across all commodities.

Equity in earnings (losses) of affiliates increased 234 percent in the first quarter of 2017. The increase in earnings was primarily due to higher realized commodity prices, primarily at FCCL, and increased volumes at Australia Pacific LNG Pty Ltd (APLNG) given the ramp-up of Trains 1 and 2.

Purchased commodities increased 43 percent in the first quarter of 2017, largely as a result of higher natural gas prices.

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Exploration expenses increased 9 percent in the first quarter of 2017. Exploration expenses increased primarily due to higher dry hole costs, partly offset by reduced leasehold impairment expense.

Dry hole costs increased mainly due to charges totaling $291 million in the first quarter of 2017 for multiple wells in Shenandoah, including wells previously suspended. The increase in dry hole costs was partly offset by the absence of a $110 million before-tax charge in 2016 for the Melmar prospect in deepwater Gulf of Mexico.

Leasehold impairment expense was reduced mainly due to the absence of 2016 before-tax charges of $95 million for our Melmar leasehold and $73 million for various Gulf of Mexico leases after completion of an initial marketing effort. The reduction was partly offset by a before-tax charge of $51 million for Shenandoah in deepwater Gulf of Mexico.

For additional information on leasehold impairments and other exploration expenses, see Note 6—Suspended Wells and Other Exploration Expenses, and Note 7—Impairments, in the Notes to Consolidated Financial Statements.

DD&A decreased 12 percent in the first quarter of 2017, mainly due to lower unit-of-production rates from reserves revisions, as well as lower volumes. The impacts of these drivers to DD&A expense were most significant in our Lower 48 segment.

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Summary Operating Statistics

	Three Months Ended March 31
	2017		2016
Average Net Production
Crude oil (MBD)*		601		617
Natural gas liquids (MBD)		134		146
Bitumen (MBD)		223		166
Natural gas (MMCFD)**		3,809		3,895
Total Production (MBOED)***		1,593		1,578
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	50.97		31.47
Natural gas liquids (per barrel)		24.87		12.30
Bitumen (per barrel)		21.56		1.74
Natural gas (per thousand cubic feet)		3.84		2.99
	Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, and lease rental, and other	$	145		145
Leasehold impairment		63		180
Dry holes		343		180
	$	551		505

    *Thousands of barrels per day.

  **Millions of cubic feet per day. Represents quantities available for sale and excludes gas equivalent of natural gas liquids included above.

***Thousands of barrels of oil equivalent per day.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At March 31, 2017, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar and Libya.

Total production from operations increased 1 percent in the first quarter of 2017 compared with the same period of 2016. The increase in total average production primarily resulted from additional production from major developments, including tight oil plays in the Lower 48; Surmont 2 and FCCL in Canada; APLNG in Australia; the Kebabangan gas field in Malaysia; the Western North Slope in Alaska; and the Greater Britannia Area in the United Kingdom. Improved drilling and well performance in Canada, Norway, Alaska, and China, as well as lower unplanned downtime in the Lower 48 and resumed production in Libya, also contributed to the increase in production. The production increase was partly offset by normal field decline; the loss of 36 MBOED attributable to noncore assets disposed in 2016, including our working interest in the offshore South Natuna Sea Block B Production Sharing Contract (PSC) in Indonesia; royalty rate impacts in Canada; and PSC impacts in Indonesia and Malaysia. In the first quarter of 2017, we achieved production of 1,593 MBOED. Excluding production from Libya, first quarter production was 1,584 MBOED. Adjusted for the net impact from dispositions of 36 MBOED and reduced downtime of 18 MBOED, our production increased by 24 MBOED, or 2 percent, compared with the first quarter of 2016.

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets. Production associated with these assets was 279 MBOED and 258 MBOED in the first quarters of 2017 and 2016, respectively. The transaction is subject to specific conditions being satisfied, including regulatory review, and is expected to close in the second quarter of 2017. On April 12, 2017, we signed a definitive agreement to sell our interests in the San

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Juan Basin, which produced 111 MBOED and 122 MBOED in the first quarters of 2017 and 2016, respectively. The transaction is subject to specific conditions being satisfied, including regulatory review, and is expected to close in the third quarter of 2017. Year-end 2016 reserves associated with our Canadian transaction and San Juan Basin assets being disposed were 1.3 billion barrels of oil equivalent (BBOE) and 0.6 BBOE, respectively.

Segment Results

Alaska

	Three Months Ended March 31
	2017			2016
Net Loss Attributable to ConocoPhillips (millions of dollars)	$	(11	)		(2	)
Average Net Production
Crude oil (MBD)		175			170
Natural gas liquids (MBD)		15			14
Natural gas (MMCFD)		7			38
Total Production (MBOED)		191			191
Average Sales Prices
Crude oil (dollars per barrel)	$	52.09			32.54
Natural gas (dollars per thousand cubic feet)		3.53			4.84

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of March 31, 2017, Alaska contributed 20 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Losses from Alaska increased by $9 million in the first quarter of 2017, compared with the same period of 2016. The increase in losses was primarily due to a $110 million after-tax impairment charge for the associated properties, plants and equipment carrying value of our small interest in a nonoperated producing property. Additionally, losses increased due to a state deferred tax asset valuation allowance; higher exploration expense, primarily from increased seismic activity in the Western North Slope and higher dry hole costs; higher DD&A, mainly due to increased capital additions; and increased property taxes resulting from the absence of a settlement ruling which lowered taxes in 2016. The increase in losses was largely offset by higher crude oil realized prices in the first quarter of 2017.

Average production in the first quarter of 2017 was flat compared with the corresponding period of 2016, as the impact of normal field decline and our 2016 noncore asset dispositions was offset by new production in the Western North Slope, Greater Prudhoe and Greater Kuparuk areas, as well as improved base production performance.

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Lower 48

	Three Months Ended March 31
	2017			2016
Net Loss Attributable to ConocoPhillips (millions of dollars)	$	(362	)		(820	)
Average Net Production
Crude oil (MBD)		176			202
Natural gas liquids (MBD)		75			86
Natural gas (MMCFD)		1,116			1,216
Total Production (MBOED)		437			491
Average Sales Prices
Crude oil (dollars per barrel)	$	45.89			27.04
Natural gas liquids (dollars per barrel)		22.07			9.45
Natural gas (dollars per thousand cubic feet)		2.83			1.80

The Lower 48 segment consists of operations located in the U.S. Lower 48 states, as well as producing properties and exploration activities in the Gulf of Mexico. As of March 31, 2017, the Lower 48 contributed 26 percent of our worldwide liquids production and 29 percent of our worldwide natural gas production.

Losses from Lower 48 decreased 56 percent in the first quarter of 2017, compared with the same period of 2016 primarily due to:

• Higher realized crude oil, natural gas and natural gas liquids prices.

• Lower DD&A expense, mainly due to a lower unit-of-production rate from reserve additions, as well as lower volumes.

• Lower exploration expenses, including the absence of 2016 after-tax leasehold impairment charges of $62 million and $47 million related to our Melmar leasehold and certain other leases in the Gulf of Mexico, respectively, as well as the absence of a $71 million after-tax dry hole charge in 2016 for the Melmar prospect. The reduction in expense was partly offset by dry hole costs and a leasehold impairment charge in the first quarter of 2017 associated with Shenandoah.

• Lower production and operating expenses, mainly due to cost efficiencies.

The decrease in losses was partly offset by lower crude oil, natural gas and natural gas liquids sales volumes.

In the first quarter of 2017, our average realized crude oil price of $45.89 per barrel was 11 percent less than WTI of $51.83 per barrel. The differential is driven primarily by local market dynamics in the Gulf Coast and Bakken, and may remain relatively wide in the near term.

Total average production decreased 11 percent in the first quarter of 2017, compared with the first quarter of 2016. The decrease in total production was mainly attributable to normal field decline, partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin, as well as the absence of the impacts of a third-party gas plant fire in 2016.

Asset Disposition Update

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billon of total proceeds, comprised of $2.7 billion in cash and a contingent payment of up to $300 million. The cash portion of the proceeds is subject to customary closing adjustments. We expect to record an estimated noncash before-tax impairment on the assets of approximately $3 billion in the second quarter of

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2017. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017. See Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Canada

	Three Months Ended March 31
	2017		2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	948		(294	)
Average Net Production
Crude oil (MBD)		6		8
Natural gas liquids (MBD)		23		25
Bitumen (MBD)
Consolidated operations		52		27
Equity affiliates		171		139
Total bitumen		223		166
Natural gas (MMCFD)		488		566
Total Production (MBOED)		333		293
Average Sales Prices
Crude oil (dollars per barrel)	$	43.82		26.11
Natural gas liquids (dollars per barrel)		21.32		11.69
Bitumen (dollars per barrel)
Consolidated operations		15.63		2.54
Equity affiliates		23.63		1.59
Total bitumen		21.56		1.74
Natural gas (dollars per thousand cubic feet)		1.95		1.20

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. As of March 31, 2017, Canada contributed 26 percent of our worldwide liquids production and 13 percent of our worldwide natural gas production.

Earnings from Canada increased by $1,242 million in the first quarter of 2017, compared with the same period of 2016, primarily due to the recognition of $996 million in deferred tax benefits related to the capital gains component of the expected disposition of certain Canadian assets further discussed below and the recognition of previously unrealizable Canadian tax basis. Additionally, earnings increased due to higher realized prices across all commodities.

Total average production increased 14 percent in the first quarter of 2017, compared with the same period of 2016. The production increase was primarily due to production ramp-ups and well performance at Surmont 2 and FCCL, partly offset by price-related royalty rate impacts, normal field decline, and the impacts of a fire at Syncrude’s Mildred Lake Upgrader which provides synthetic crude to Surmont for blending as diluent.

Asset Disposition Update

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second

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quarter of 2017. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment due during periods in which the WCS crude prices exceed $52 Canadian dollars per barrel. The cash portion of the consideration is subject to customary adjustments. Based on Cenovus’ share price on March 31, 2017, we expect to record an estimated gain on sale of approximately $2 billion, upon closing, which is expected in the second quarter of 2017. The amount of actual gain recognized may differ from our estimate, subject to post-closing adjustments and Cenovus’ share price and exchange rates on the date of close. See Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

Europe and North Africa

	Three Months Ended March 31
	2017		2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	171		(51	)
Average Net Production
Crude oil (MBD)		140		125
Natural gas liquids (MBD)		9		7
Natural gas (MMCFD)		544		507
Total Production (MBOED)		240		216
Average Sales Prices
Crude oil (dollars per barrel)	$	53.34		35.47
Natural gas liquids (dollars per barrel)		31.21		18.78
Natural gas (dollars per thousand cubic feet)		5.86		5.03

The Europe and North Africa segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, the Norwegian Sea, and Libya. As of March 31, 2017, our Europe and North Africa operations contributed 16 percent of our worldwide liquids production and 14 percent of our worldwide natural gas production.

Earnings for Europe and North Africa operations increased $222 million in the first quarter of 2017, compared with the same period of 2016. The earnings increase was primarily due to higher crude oil, natural gas and natural gas liquids realized prices; the absence of 2016 after-tax proved property impairments in the United Kingdom of $60 million; and lower DD&A, mainly due to foreign currency impacts in the United Kingdom.

Average production increased 11 percent in the first quarter of 2017, compared with the corresponding period of 2016. The increase was mainly due to improved drilling and well performance in Norway; new production from the Greater Ekofisk and Greater Britannia areas; the resumption of production in Libya, where we had four crude liftings in the first quarter of 2017; and higher Norway gas offtake. The increased production was partly offset by normal field decline in Norway and the United Kingdom.

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Asia Pacific and Middle East

	Three Months Ended March 31
	2017		2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	236		(5	)
Average Net Production
Crude oil (MBD)
Consolidated operations		91		100
Equity affiliates		13		12
Total crude oil		104		112
Natural gas liquids (MBD)
Consolidated operations		5		7
Equity affiliates		7		7
Total natural gas liquids		12		14
Natural gas (MMCFD)
Consolidated operations		719		769
Equity affiliates		935		799
Total natural gas		1,654		1,568
Total Production (MBOED)		392		387
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	53.74		33.11
Equity affiliates		55.58		33.50
Total crude oil		53.98		33.15
Natural gas liquids (dollars per barrel)
Consolidated operations		42.96		27.62
Equity affiliates		43.20		27.45
Total natural gas liquids		43.10		27.54
Natural gas (dollars per thousand cubic feet)
Consolidated operations		4.96		4.24
Equity affiliates		4.00		3.56
Total natural gas		4.42		3.90

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Brunei. As of March 31, 2017, Asia Pacific and Middle East contributed 12 percent of our worldwide liquids production and 43 percent of our worldwide natural gas production.

Earnings increased by $241 million in the first quarter of 2017, compared with the same period of 2016, primarily due to higher realizations across all commodities, including LNG and crude oil which improved our equity earnings from APLNG and Qatar Liquefied Gas Company Limited (3) (QG3), respectively, and higher sales volumes mainly at APLNG. The earnings increase was partly offset by higher DD&A expense and increased power costs from Trains 1 and 2 being online at APLNG.

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Average production increased 1 percent in the first quarter of 2017, compared with the same period of 2016, mainly due to new production from the ramp-up of APLNG in Australia and the Kebabangan gas field in Malaysia, and improved drilling and well performance in China. The production increase was partly offset by the disposition of our working interest in the offshore South Natuna Sea Block B PSC in Indonesia; PSC impacts in Indonesia, Malaysia and Australia; and normal field decline in China.

Other International

	Three Months Ended March 31
	2017			2016
Net Loss Attributable to ConocoPhillips (millions of dollars)	$	(48	)		(24	)

The Other International segment consists of exploration activities in Colombia and Chile.

Losses from our Other International operations increased $24 million in the first quarter of 2017, compared with the same period of 2016. The increase in losses was primarily due to a $28 million after-tax charge for the cancellation of our Athena drilling rig contract in the first quarter of 2017.

Corporate and Other

	Millions of Dollars
	Three Months Ended March 31
	2017			2016
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(253	)		(222	)
Corporate general and administrative expenses		(93	)		(85	)
Technology		9			21
Other		(11	)		13
	$	(348	)		(273	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased by $31 million in the first quarter of 2017, compared with the same period of 2016, primarily due to lower capitalized interest on projects, higher interest expense, and impacts from the fair market value method of apportioning interest expense in the United States.

Corporate general and administrative expenses increased by $8 million in the first quarter of 2017, compared with the same period of 2016, primarily due to increases from market impacts on certain compensation programs and staff costs, partly offset by lower pension settlement expense.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on tight oil reservoirs, heavy oil and oil sands, as well as LNG. Earnings from Technology decreased $12 million in the first quarter of 2017, compared with the same period of 2016. The decrease was primarily due to lower licensing revenues, partly offset by reduced technology program spend.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation and other costs not directly associated with an operating segment. “Other” expenses increased by $24 million in the first quarter of 2017, mainly due to foreign currency impacts.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	March 31 2017			December 31 2016
Short-term debt	$	1,095			1,089
Total debt		26,435			27,275
Total equity		35,601			35,226
Percent of total debt to capital*		43	%		44
Percent of floating-rate debt to total debt		6	%		9

*Capital includes total debt and total equity.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources, including cash generated from operating activities. We rely on cash flows from operating activities, proceeds from asset sales, our commercial paper and credit facility programs, and our shelf registration statement to support short- and long-term liquidity requirements. The primary uses of our available cash were $966 million to support our ongoing capital expenditures and investments program, $331 million to pay dividends, $112 million to repurchase common stock, and $203 million net purchases of short-term investments. In the first quarter of 2017, we made a prepayment of $805 million on our term loan due in 2019. During the first three months of 2017, cash and cash equivalents decreased by $501 million to $3,109 million.

We believe current cash balances and cash generated by operations, together with access to external sources of funds as described below in the “Significant Sources of Capital” section, will be sufficient to meet our funding requirements in the near and long term, including our capital spending program, dividend payments and required debt payments.

Significant Sources of Capital

Operating Activities

Cash provided by operating activities was $1,790 million for the first three months of 2017, compared with $421 million for the corresponding period of 2016. The increase was primarily due to higher realized prices across all commodities.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry have historically been volatile and are driven by market conditions over which we have no control. Absent other mitigating factors, as these prices and margins fluctuate, we would expect a corresponding change in our operating cash flows.

The level of absolute production volumes, as well as product and location mix, impacts our cash flows. Production levels are impacted by such factors as the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. As we undertake cash conservation efforts, our reserve replacement efforts could be delayed thus limiting our ability to replace depleted reserves.

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Investing Activities

Proceeds from asset sales for the first three months of 2017 were $35 million compared with $135 million for the corresponding period of 2016.

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing. Consideration for the transaction consists of $10.6 billion of cash payable at closing, 208 million Cenovus shares, and a five-year uncapped contingent payment triggered during quarterly periods in which the average WCS crude prices exceed $52 Canadian dollars per barrel. The cash portion of the consideration is subject to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approvals, and is expected to close in the second quarter of 2017. On the date of signing, we received a $130 million deposit from Cenovus Energy, which is included in the “Cash Flows From Investing Activities” section in our consolidated statement of cash flows.

On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin for up to $3 billion of total proceeds including $2.7 billion in cash, subject to customary adjustments, and a contingent payment of up to $300 million. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017.

For additional information on our dispositions, see Note 4—Assets Held for Sale and Other Planned Dispositions, in the Notes to Consolidated Financial Statements, and the Results of Operations section within Management’s Discussion and Analysis.

Commercial Paper and Credit Facilities

At March 31, 2017, we had a revolving credit facility totaling $6.75 billion, expiring in June 2019. Our revolving credit facility may be used for direct bank borrowings, the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or any of its consolidated subsidiaries.

Credit facility borrowings may bear interest at a margin above rates offered by certain designated banks in the London interbank market or at a margin above the overnight federal funds rate or prime rates offered by certain designated banks in the United States. The agreement calls for commitment fees on available, but unused, amounts. The agreement also contains early termination rights if our current directors or their approved successors cease to be a majority of the Board of Directors.

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.25 billion commercial paper program. We also have the ConocoPhillips Qatar Funding Ltd. $500 million commercial paper program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days. We had no commercial paper outstanding at March 31, 2017 or December 31, 2016, under either the ConocoPhillips or the ConocoPhillips Qatar Funding Ltd commercial paper program. We had no direct borrowings or letters of credit issued under the revolving credit facility. Since we had no commercial paper outstanding and had issued no letters of credit, we had access to $6.75 billion in borrowing capacity under our revolving credit facility at March 31, 2017.

With recent improved commodity prices, Moody’s Investor Services improved their outlook for our debt from “negative” to “positive” while Fitch and Standard & Poor’s both reflected an improvement from “negative” to “stable” during the first quarter of 2017. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were downgraded, it could increase the cost of corporate debt available to us and restrict our access to the commercial paper markets. If our credit rating were to deteriorate to a level

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prohibiting us from accessing the commercial paper market, we would still be able to access funds under our revolving credit facility.

Certain of our project-related contracts, commercial contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At March 31, 2017 and December 31, 2016, we had direct bank letters of credit of $266 million and $304 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business. In the event of credit ratings downgrades, we may be required to post additional letters of credit.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements.

For information about guarantees, see Note 10—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

For information about our capital expenditures and investments, see the “Capital Expenditures” section.

Our debt balance at March 31, 2017, was $26.4 billion, a decrease of $0.8 billion from the balance at December 31, 2016, primarily as a result of an $805 million prepayment of our term loan due in 2019. Our short-term debt balance at March 31, 2017, increased $6 million compared with December 31, 2016, primarily as a result of the timing of scheduled maturities.

On March 29, 2017, we signed a definitive agreement to sell our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, for total consideration of approximately $13.3 billion, based on Cenovus’ share price at the date of signing, before customary adjustments to the cash portion. The transaction is subject to specific conditions precedent being satisfied, including regulatory review and approval, and is expected to close in the second quarter of 2017. We intend to use a portion of the proceeds to reduce debt to $20 billion in 2017. On a longer-term basis our debt target is $15 billion by year-end 2019. For more information, see Note 4—Assets Held for Sale and Other Planned Dispositions and Note 8—Debt, in the Notes to Consolidated Financial Statements.

In January 2017, we announced a 6 percent increase in the quarterly dividend to $0.265 per share. The dividend was paid March 1, 2017, to stockholders of record at the close of business on February 14, 2017.

On November 10, 2016, our Board of Directors authorized the purchase of up to $3 billion of our common stock over the next three years. During the first quarter of 2017, our Board of Directors approved an increase in the existing share repurchase authorization to a total of $6 billion, with an expectation of $3 billion occurring in 2017 and the remaining $3 billion allocated to 2018 and 2019. Since our share repurchase program began in November 2016, share repurchases totaled 4.8 million shares at a cost of $238 million through March 31, 2017.

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Capital Expenditures

	Millions of Dollars
	Three Months Ended March 31
	2017		2016
Alaska	$	228		320
Lower 48		343		580
Canada		62		254
Europe and North Africa		200		303
Asia Pacific and Middle East		109		306
Other International		5		41
Corporate and Other		19		17
Capital expenditures and investments	$	966		1,821

During the first three months of 2017, capital expenditures and investments supported key exploration and development programs, primarily:

• Oil and natural gas development and exploration activities in the Lower 48, including Eagle Ford, Bakken, and the Permian Basin.

• Alaska activities related to development in the Western North Slope, Greater Kuparuk Area, and the Greater Prudhoe Area.

• Development activities, in Europe, including the Greater Ekofisk Area, Aasta Hansteen, and Clair Ridge.

• Continued oil sands development and appraisal activities in liquids-rich plays in Canada.

• Appraisal drilling in deepwater Gulf of Mexico.

• Continued development in Malaysia, Indonesia, China and Australia; exploration activity in Malaysia and appraisal activity in Australia.

Contingencies

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been filed against ConocoPhillips. We also may be required to remove or mitigate the effects on the environment of the placement, storage, disposal or release of certain chemical, mineral and petroleum substances at various active and inactive sites. We regularly assess the need for accounting recognition or disclosure of these contingencies. In the case of all known contingencies (other than those related to income taxes), we accrue a liability when the loss is probable and the amount is reasonably estimable. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. We do not reduce these liabilities for potential insurance or third-party recoveries. If applicable, we accrue receivables for probable insurance or other third-party recoveries. With respect to income-tax-related contingencies, we use a cumulative probability-weighted loss accrual in cases where sustaining a tax position is less than certain.

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and

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the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 11—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal Matters

We are subject to various lawsuits and claims including but not limited to matters involving oil and gas royalty and severance tax payments, gas measurement and valuation methods, contract disputes, environmental damages, personal injury, and property damage. Our primary exposures for such matters relate to alleged royalty and tax underpayments on certain federal, state and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 63–65 of our 2016 Annual Report on Form 10-K.

We occasionally receive requests for information or notices of potential liability from the Environmental Protection Agency (EPA) and state environmental agencies alleging that we are a potentially responsible party under the Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or an equivalent state statute. On occasion, we also have been made a party to cost recovery litigation by those agencies or by private parties. These requests, notices and lawsuits assert potential liability for remediation costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of March 31, 2017, there were 14 sites around the United States in which we were identified as a potentially responsible party under CERCLA and comparable state laws.

At March 31, 2017, our balance sheet included a total environmental accrual of $260 million, compared with $247 million at December 31, 2016, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

Notwithstanding any of the foregoing, and as with other companies engaged in similar businesses, environmental costs and liabilities are inherent concerns in our operations and products, and there can be no assurance that material costs and liabilities will not be incurred. However, we currently do not expect any material adverse effect upon our results of operations or financial position as a result of compliance with current environmental laws and regulations.

Climate Change

There has been a broad range of proposed or promulgated state, national and international laws focusing on greenhouse gas (GHG) reduction. These proposed or promulgated laws apply or could apply in countries where we have interests or may have interests in the future. Laws in this field continue to evolve, and while it is not possible to accurately estimate either a timetable for implementation or our future compliance costs relating to implementation, such laws, if enacted, could have a material impact on our results of operations and financial condition. Examples of legislation and precursors for possible regulation that do or could affect our

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operations include the EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)) and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that trigger regulation of GHGs under the Clean Air Act, may trigger more climate-based claims for damages, and may result in longer agency review time for development projects.

For other examples of legislation or precursors for possible regulation and factors on which the ultimate impact on our financial performance will depend, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 65–66 of our 2016 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2016-02, “Leases” (ASU No. 2016-02), which establishes comprehensive accounting and financial reporting requirements for leasing arrangements. This ASU supersedes the existing requirements in FASB Accounting Standards Codification (ASC) Topic 840, “Leases,” and requires lessees to recognize substantially all lease assets and lease liabilities on the balance sheet. The provisions of ASU No. 2016-02 also modify the definition of a lease and outline requirements for recognition, measurement, presentation, and disclosure of leasing arrangements by both lessees and lessors. The ASU is effective for interim and annual periods beginning after December 15, 2018, and early adoption of the standard is permitted. Entities are required to adopt the ASU using a modified retrospective approach, subject to certain optional practical expedients, and apply the provisions of ASU No. 2016-02 to leasing arrangements existing at or entered into after the earliest comparative period presented in the financial statements. While we continue to evaluate the ASU, we expect the adoption of the ASU to have a material impact on our consolidated financial statements and disclosures. For additional information, see Note 20—New Accounting Standards, in the Notes to Consolidated Financial Statements.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Examples of forward-looking statements contained in this report include our expected production growth and outlook on the business environment generally, our expected capital budget and capital expenditures, and discussions concerning future dividends. You can often identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,” “will,” “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about ourselves and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including, but not limited to, the following:

• Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices, including a prolonged decline in these prices relative to historical or future expected levels.

• The impact of recent, significant declines in prices for crude oil, bitumen, natural gas, LNG and natural gas liquids, which may result in recognition of impairment costs on our long-lived assets, leaseholds and nonconsolidated equity investments.

• Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas developments, including due to operating hazards, drilling risks and the inherent uncertainties in predicting reserves and reservoir performance.

• Inability to maintain reserves replacement rates consistent with prior periods, whether as a result of the recent, significant declines in commodity prices or otherwise.

• Unsuccessful exploratory drilling activities or the inability to obtain access to exploratory acreage.

• Unexpected changes in costs or technical requirements for constructing, modifying or operating exploration and production facilities.

• Legislative and regulatory initiatives addressing environmental concerns, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring or water disposal.

• Lack of, or disruptions in, adequate and reliable transportation for our crude oil, bitumen, natural gas, LNG and natural gas liquids.

• Inability to timely obtain or maintain permits, including those necessary for drilling and/or development, construction of LNG terminals or regasification facilities; failure to comply with applicable laws and regulations; or inability to make capital expenditures required to maintain compliance with any necessary permits or applicable laws or regulations.

• Failure to complete definitive agreements and feasibility studies for, and to timely complete construction of, announced and future exploration and production and LNG development.

• Potential disruption or interruption of our operations due to accidents, extraordinary weather events, civil unrest, political events, war, terrorism, cyber attacks or infrastructure constraints or disruptions.

• Changes in international monetary conditions and exchange controls, including changes in foreign currency exchange rates.

• Reduced demand for our products or the use of competing energy products, including alternative energy sources.

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• Substantial investment in and development of alternative energy sources, including as a result of existing or future environmental rules and regulations.

• Liability for remedial actions, including removal and reclamation obligations, under environmental regulations.

• Liability resulting from litigation.

• General domestic and international economic and political developments, including armed hostilities; expropriation of assets; changes in governmental policies relating to crude oil, bitumen, natural gas, LNG and natural gas liquids pricing, regulation or taxation; and other political, economic or diplomatic developments.

• Volatility in the commodity futures markets.

• Changes in tax and other laws, regulations (including alternative energy mandates), or royalty rules applicable to our business.

• Competition in the oil and gas exploration and production industry.

• Any limitations on our access to capital or increase in our cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

• Our inability to execute asset dispositions or delays in the completion of any asset dispositions we elect to pursue, including our previously announced dispositions of certain of our assets in western Canada and our San Juan Basin assets (collectively, the “Sale Transactions”) as well as any future asset dispositions we may undertake.

• Potential failure to obtain, or delays in obtaining, any necessary regulatory approvals for the Sale Transactions, or that such approvals may require modification to the terms of the Sale Transactions or the operation of our remaining business.

• Potential disruption of our operations as a result of the Sale Transactions, including the diversion of management time and attention.

• Our inability to deploy the net proceeds from any asset dispositions we undertake, including the Sale Transactions, in the manner and timeframe we currently anticipate, if at all.

• Our inability to liquidate the common stock to be issued to us by Cenovus Energy as part of our sale of certain assets in western Canada at prices we deem acceptable, or at all.

• Our inability to obtain economical financing for development, construction or modification of facilities and general corporate purposes.

• The operation and financing of our joint ventures.

• The ability of our customers and other contractual counterparties to satisfy their obligations to us.

• Our inability to realize anticipated cost savings and expenditure reductions.

• The factors generally described in Item 1A—Risk Factors in our 2016 Annual Report on Form 10-K and any additional risks described in our other filings with the SEC.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the three months ended March 31, 2017, does not differ materially from that discussed under Item 7A in our 2016 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure information required to be disclosed in reports we file or submit under the Securities Exchange Act of 1934, as amended (the Act), is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and that such information is accumulated and communicated to management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. As of March 31, 2017, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance, Commercial and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance,

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Commercial and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of March 31, 2017.

There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the first quarter of 2017 and any material developments with respect to matters previously reported in ConocoPhillips’ 2016 Annual Report on Form 10-K. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to U.S. Securities and Exchange Commission regulations.

On April 30, 2012, the separation of our downstream business was completed, creating two independent energy companies: ConocoPhillips and Phillips 66. In connection with the separation, we entered into an Indemnification and Release Agreement, which provides for cross-indemnities between Phillips 66 and us and established procedures for handling claims subject to indemnification and related matters, such as legal proceedings. We have included matters where we remain or have subsequently become a party to a proceeding relating to Phillips 66, in accordance with SEC regulations. We do not expect any of those matters to result in a net claim against us.

Matters previously reported—Phillips 66

In October 2016, after Phillips 66 received a Notice of Intent to Sue from Sierra Club, Phillips 66 entered into a voluntary settlement with the Illinois Environmental Agency for alleged violations of wastewater requirements at the Wood River Refinery. The settlement involves certain capital projects and payment of $125,000. After the settlement was filed with the Court for final approval, the Sierra Club sought and was granted approval to intervene in the case. Phillips 66 is working to obtain Court approval for the settlement.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2016 Annual Report on Form 10-K.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

  Millions of Dollars  

Period	Total Number of Shares Purchased*		Average Price         Paid per  Share		Total Number of         Shares Purchased as Part of Publicly         Announced Plans or Programs**		Approximate Dollar         Value of Shares That May Yet Be         Purchased Under the Plans or Programs**
January 1-31, 2017		1,583,173	$	50.53		1,583,173	$	2,794
February 1-28, 2017		653,754		48.95		653,754		2,762
March 1-31, 2017		—		—		—		5,762
Total		2,236,927	$	50.07		2,236,927		5,762

  *There were no repurchases of common stock from company employees in connection with the company’s broad-based employee incentive plans.

**On November 10, 2016, we announced a share repurchase program for up to $3 billion of common stock over the next three years. On March 29, 2017, we announced plans to double our share repurchase program to $6 billion of common stock over the next three years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

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Item 6. EXHIBITS

2.1*†	Purchase and Sale Agreement, dated March 29, 2017, by and among the Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips CanadaPhillips (BRC) Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc.
10.1*	Form of Key Employee Award Terms and Conditions, as part of the ConocoPhillips Stock Option Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.
10.2*	Form of Performance Share Unit Award Terms and Conditions for Performance Period 17, as part of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.
10.3*	Form of Performance Share Unit Award Terms and Conditions for Performance Period 17 for eligible employees on the Canada payroll, as part of the ConocoPhillips Performance Share Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.
10.4*	Form of Key Employee Award Terms and Conditions as part of the ConocoPhillips Restricted Stock Program granted under the 2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips, dated February 14, 2017.
12*	Computation of Ratio of Earnings to Fixed Charges.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32*	Certifications pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Schema Document.
101.CAL*	XBRL Calculation Linkbase Document.
101.LAB*	XBRL Labels Linkbase Document.
101.PRE*	XBRL Presentation Linkbase Document.
101.DEF*	XBRL Definition Linkbase Document.

* Filed herewith.

† ConocoPhillips has requested confidential treatment for certain portions of this exhibit pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended. The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant agrees to furnish a copy of any schedule omitted from this exhibit to the SEC upon request.

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONOCOPHILLIPS

/s/ Glenda M. Schwarz

Glenda M. Schwarz

Vice President and Controller

(Chief Accounting and Duly Authorized Officer)

May 4, 2017

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