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 June 30, 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 1,216,949,231 shares of common stock, $.01 par value, outstanding at June 30, 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		29
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3. Quantitative and Qualitative Disclosures About Market Risk		56
Item 4. Controls and Procedures		56
Part II—Other Information
Item 1. Legal Proceedings		57
Item 1A. Risk Factors		57
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		58
Item 6. Exhibits		59
Signature		60

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

Consolidated Income Statement ConocoPhillips

	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Revenues and Other Income
Sales and other operating revenues	$	6,781			5,348			14,299			10,469
Equity in earnings (losses) of affiliates		178			80			378			(69	)
Gain on dispositions		1,876			128			1,898			151
Other income		47			19			78			39
Total Revenues and Other Income		8,882			5,575			16,653			10,590
Costs and Expenses
Purchased commodities		2,922			2,002			6,114			4,227
Production and operating expenses		1,327			1,445			2,625			2,799
Selling, general and administrative expenses		134			167			291			353
Exploration expenses		98			610			649			1,115
Depreciation, depletion and amortization		1,625			2,329			3,604			4,576
Impairments		6,294			62			6,469			198
Taxes other than income taxes		198			197			429			377
Accretion on discounted liabilities		92			112			187			221
Interest and debt expense		306			312			621			593
Foreign currency transaction (gains) losses		13			(17	)		23			(1	)
Other expense		234			—			234			—
Total Costs and Expenses		13,243			7,219			21,246			14,458
Loss before income taxes		(4,361	)		(1,644	)		(4,593	)		(3,868	)
Income tax benefit		(935	)		(586	)		(1,766	)		(1,354	)
Net loss		(3,426	)		(1,058	)		(2,827	)		(2,514	)
Less: net income attributable to noncontrolling interests		(14	)		(13	)		(27	)		(26	)
Net Loss Attributable to ConocoPhillips	$	(3,440	)		(1,071	)		(2,854	)		(2,540	)
Net Loss Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	(2.78	)		(0.86	)		(2.30	)		(2.04	)
Diluted		(2.78	)		(0.86	)		(2.30	)		(2.04	)
Dividends Paid Per Share of Common Stock (dollars)	$	0.27			0.25			0.53			0.50
Average Common Shares Outstanding (in thousands)
Basic		1,236,831			1,244,892			1,240,037			1,244,724
Diluted		1,236,831			1,244,892			1,240,037			1,244,724

See Notes to Consolidated Financial Statements.

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Consolidated Statement of Comprehensive Income ConocoPhillips

	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Net Loss	$	(3,426	)		(1,058	)		(2,827	)		(2,514	)
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net loss		(10	)		(9	)		(19	)		(18	)
Net actuarial loss arising during the period		(32	)		(69	)		(39	)		(300	)
Reclassification adjustment for amortization of net actuarial losses included in net loss		66			74			156			182
Income taxes on defined benefit plans		(8	)		3			(34	)		53
Defined benefit plans, net of tax		16			(1	)		64			(83	)
Unrealized holding loss on securities		(424	)		—			(424	)		—
Unrealized loss on securities, net of tax		(424	)		—			(424	)		—
Foreign currency translation adjustments		27			(224	)		211			959
Foreign currency translation adjustments, net of tax		27			(224	)		211			959
Other Comprehensive Income (Loss), Net of Tax		(381	)		(225	)		(149	)		876
Comprehensive Loss		(3,807	)		(1,283	)		(2,976	)		(1,638	)
Less: comprehensive income attributable to noncontrolling interests		(14	)		(13	)		(27	)		(26	)
Comprehensive Loss Attributable to ConocoPhillips	$	(3,821	)		(1,296	)		(3,003	)		(1,664	)

See Notes to Consolidated Financial Statements.

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Consolidated Balance Sheet ConocoPhillips

	Millions of Dollars
	June 30			December 31
	2017			2016
Assets
Cash and cash equivalents	$	7,534			3,610
Short-term investments		2,733			50
Accounts and notes receivable (net of allowance of $4 million in 2017 and $5 million in 2016)		3,020			3,249
Accounts and notes receivable—related parties		143			165
Investment in Cenovus Energy		1,533			—
Inventories		1,019			1,018
Prepaid expenses and other current assets		3,897			517
Total Current Assets		19,879			8,609
Investments and long-term receivables		9,681			21,091
Loans and advances—related parties		522			581
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $62,018 million in 2017 and $73,075 million in 2016)		46,846			58,331
Other assets		1,076			1,160
Total Assets	$	78,004			89,772
Liabilities
Accounts payable	$	3,401			3,631
Accounts payable—related parties		33			22
Short-term debt		3,798			1,089
Accrued income and other taxes		791			484
Employee benefit obligations		509			689
Other accruals		1,394			994
Total Current Liabilities		9,926			6,909
Long-term debt		19,670			26,186
Asset retirement obligations and accrued environmental costs		7,631			8,425
Deferred income taxes		6,335			8,949
Employee benefit obligations		2,499			2,552
Other liabilities and deferred credits		1,444			1,525
Total Liabilities		47,505			54,546
Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2017—1,784,927,181 shares; 2016—1,782,079,107 shares)
Par value		18			18
Capital in excess of par		46,558			46,507
Treasury stock (at cost: 2017—567,977,950 shares; 2016—544,809,771 shares)		(37,981	)		(36,906	)
Accumulated other comprehensive loss		(6,342	)		(6,193	)
Retained earnings		28,033			31,548
Total Common Stockholders’ Equity		30,286			34,974
Noncontrolling interests		213			252
Total Equity		30,499			35,226
Total Liabilities and Equity	$	78,004			89,772

See Notes to Consolidated Financial Statements.

3

Consolidated Statement of Cash Flows ConocoPhillips

	Millions of Dollars
	Six Months Ended June 30
		2017		2016
Cash Flows From Operating Activities
Net loss	$	(2,827	)	(2,514	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization		3,604		4,576
Impairments		6,469		198
Dry hole costs and leasehold impairments		428		823
Accretion on discounted liabilities		187		221
Deferred taxes		(2,548	)	(1,457	)
Distributions received greater than equity losses (undistributed equity earnings)		(121	)	222
Gain on dispositions		(1,898	)	(151	)
Other		175		(17	)
Working capital adjustments
Decrease in accounts and notes receivable		313		1,097
Increase in inventories		(3	)	(23	)
Increase in prepaid expenses and other current assets		(135	)	(51	)
Decrease in accounts payable		(178	)	(454	)
Increase (decrease) in taxes and other accruals		75		(790	)
Net Cash Provided by Operating Activities		3,541		1,680
Cash Flows From Investing Activities
Capital expenditures and investments		(1,986	)	(2,954	)
Working capital changes associated with investing activities		(113	)	(363	)
Proceeds from asset dispositions		10,742		363
Net purchases of short-term investments		(2,653	)	(1,292	)
Collection of advances/loans—related parties		57		53
Other		176		6
Net Cash Provided by (Used in) Investing Activities		6,223		(4,187	)
Cash Flows From Financing Activities
Issuance of debt		—		4,594
Repayment of debt		(4,079	)	(827	)
Issuance of company common stock		(63	)	(45	)
Repurchase of company common stock		(1,075	)	—
Dividends paid		(662	)	(626	)
Other		(64	)	(79	)
Net Cash Provided by (Used in) Financing Activities		(5,943	)	3,017
Effect of Exchange Rate Changes on Cash and Cash Equivalents		103		(15	)
Net Change in Cash and Cash Equivalents		3,924		495
Cash and cash equivalents at beginning of period		3,610		2,368
Cash and Cash Equivalents at End of Period	$	7,534		2,863

See Notes to Consolidated Financial Statements.

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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 June 30, 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 11—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 June 30, 2017, the carrying value of our equity method investment in MWCC was $143 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
	June 30		December 31
	2017		2016
Crude oil and natural gas	$	447		418
Materials and supplies		572		600
	$	1,019		1,018

Inventories valued on the last-in, first-out (LIFO) basis totaled $296 million and $269 million at June 30, 2017 and December 31, 2016, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $45 million and $104 million at June 30, 2017 and December 31, 2016, respectively.

Note 4—Assets Held for Sale, Sold or Other Planned Dispositions

Assets Held for Sale

On April 12, 2017, we signed a definitive agreement with an affiliate of Hilcorp Energy Company 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 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 price is at or above $3.20 per million British thermal units. On the date of signing, we received a $135 million deposit, which is included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. The transaction closed on July 31, 2017, with cash proceeds of $2.5 billion after customary adjustments.

In the second quarter of 2017, we recorded a before-tax impairment of $3.3 billion to reduce the carrying value of our interests in the San Juan Basin to fair value. As of June 30, 2017, our San Juan Basin interests had a net carrying value of approximately $2.5 billion and were considered held for sale, resulting in the reclassification of $2.9 billion of properties, plants and equipment (PP&E) to “Prepaid expenses and other current assets” and $400 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 San Juan Basin, including the $3.3 billion impairment noted above, was $3.3 billion and $200 million for the six months ended June 30, 2017 and June 30, 2016, respectively. The San Juan Basin results of operations are reported within our Lower 48 segment.

On June 28, 2017, we signed a definitive agreement with an affiliate of Miller Thomson & Partners LLC to sell our interests in the Barnett for $305 million in cash, subject to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017. We recorded a before-tax impairment of $566 million in the second quarter of 2017 to reduce the carrying value of our investment to fair value. As of June 30, 2017, our Barnett interests had a net carrying value of approximately $302 million and were considered held for sale resulting in the reclassification of $345 million of PP&E to “Prepaid expenses and other current assets” and $49 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 Barnett, including the $566 million impairment noted above, was $585 million and $40 million for the six months ended June 30, 2017 and June 30, 2016, respectively. The Barnett results of operations are reported within our Lower 48 segment.

6

Assets Sold

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. The transaction closed on May 17, 2017. As of closing, consideration for the transaction was $10.4 billion of cash, a five-year uncapped contingent payment and 208 million Cenovus Energy common shares. Subsequent to closing, we received $600 million related to environmental claims, $317 million of which was received in the second quarter of 2017, and the remainder received in July 2017. The cash proceeds are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. The value of the shares at closing was $1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel.

At closing, the carrying value of our equity investment in FCCL was $8.9 billion. The carrying value of our interest in the western Canada gas assets was $1.9 billion consisting primarily of $2.6 billion of PP&E, partly offset by asset retirement obligations of $585 million and approximately $100 million of environmental and other accruals. A before-tax gain of $1.85 billion is included in the “Gain on disposition” line on our consolidated income statement for the second quarter of 2017. An additional before-tax gain of $283 million will be recognized in the third quarter of 2017. We reported before-tax losses of $30 million and $324 million for the western Canada gas producing properties for the six-month periods ending June 30, 2017 and June 30, 2016, respectively. We reported before-tax equity earnings of $197 million and a before-tax equity loss of $98 million for FCCL for the same periods, respectively. Both FCCL and the western Canada gas assets were reported within our Canada segment.

For more information on the Canada disposition and our investment in Cenovus Energy see Note 6—Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 15—Accumulated Other Comprehensive Loss.

Other Planned Dispositions

On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets for $184 million subject to customary adjustments. The transaction is expected to close in the third quarter of 2017. As of June 30, 2017, the net carrying value was approximately $207 million, consisting primarily of $280 million of PP&E and $72 million of asset retirement obligations. The assets met the held for sale criteria in July 2017 and a noncash impairment will be recorded in the third quarter of 2017. The Panhandle results are reported within our Lower 48 segment.

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 June 30, 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 11—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 and second quarters of 2017, the outlook for crude oil prices deteriorated, and as a result of significantly reduced price outlooks, the estimated fair value of our investment in APLNG declined to an

7

amount below carrying value. Based on a review of the facts and circumstances surrounding this decline in fair value, we concluded in the second quarter of 2017 the impairment was other than temporary under the guidance of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) Topic 323, “Investments – Equity Method and Joint Ventures,” and the recognition of an impairment of our investment to fair value was necessary. In reaching this conclusion, we primarily considered the length of time and the extent to which fair value has been less than carrying value, as well as the trend in market outlook. 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.

Accordingly, we recorded a noncash $2,384 million, before- and after-tax impairment, in our second-quarter 2017 results. The impairment, which is included in the “Impairments” line on our consolidated income statement, had the effect of reducing our carrying value to $7,656 million, based on the present value of discounted expected future cash flows as of June 30, 2017. This carrying value is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

On May 17, 2017, we closed on the sale of our 50 percent nonoperated interest in the FCCL oil sands partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. For additional information on the Canada disposition and our investment in Cenovus Energy, see Note 4—Assets Held for Sale, Sold or Other Planned Dispositions and Note 6—Investment in Cenovus Energy.

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 June 30, 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—Investment in Cenovus Energy

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL oil sands partnership, as well as the majority of our western Canada gas assets. The transaction closed on May 17, 2017. Consideration for the transaction included 208 million Cenovus Energy common shares. See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, for additional information on the Canada disposition.

At closing, the fair value and cost basis of our investment in 208 million Cenovus Energy common shares was $1.96 billion based on a price of $9.41 per share on the New York Stock Exchange. Our ownership approximates to 16.9 percent of issued and outstanding Cenovus common shares, and under an investor agreement with Cenovus Energy, we have agreed not to transfer any of our Cenovus Energy common shares until six months from the closing date (the “Lock-up Termination Date”).

We have classified our investment as an available-for-sale equity security on our consolidated balance sheet and, as of June 30, 2017, our investment is carried at fair value of $1.53 billion, reflecting the closing price of Cenovus Energy shares on the New York Stock Exchange of $7.37 per share. The carrying value reflects a before- and after-tax unrealized loss of $424 million over our cost basis of $1.96 billion. The unrealized loss is reported as a component of accumulated other comprehensive loss. See Note 14—Fair Value Measurement, for additional information. Following the Lock-up Termination Date, we intend to decrease our investment over time through market transactions, private agreements or otherwise.

8

Note 7—Suspended Wells and Other Exploration Expenses

The capitalized cost of suspended wells at June 30, 2017, was $860 million, a decrease of $203 million from $1,063 million at year-end 2016. Two suspended wells in Shenandoah in the Gulf of Mexico totaling $94 million, one suspended well in Alaska totaling $17 million, and one suspended well in Malaysia totaling $23 million were charged to dry hole expense during the first six months of 2017 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2016.

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 8—Impairments

During the three- and six-month periods ended June 30, 2017 and 2016, we recognized before-tax impairment charges within the following segments:

	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2017		2016		2017		2016
Alaska	$	3		—		177		—
Lower 48		3,885		51		3,885		60
Canada		18		—		18		—
Europe and North Africa		4		10		5		137
Asia Pacific and Middle East		2,384		1		2,384		1
	$	6,294		62		6,469		198

In the three-month period ended June 30, 2017, our Lower 48 segment included impairments of $3,885 million primarily due to certain developed properties which were classified as held for sale at June 30, 2017, and were written down to fair value less costs to sell. See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, for additional information on our dispositions.

See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment included within the Asia Pacific and Middle East segment during the three-month period ended June 30, 2017.

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

Our Europe and North Africa segment included impairments of $137 million in the six-month period of 2016, primarily as a result of lower natural gas prices in the United Kingdom. Our Lower 48 segment included impairments of $51 million and $60 million respectively, in the three- and six-month periods of 2016, primarily as a result of lower natural gas prices and increased asset retirement obligation estimates.

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

Exploration expenses in the three- and six-month periods of 2017 and 2016 were aligned with our decision announced in 2015 to reduce deepwater exploration spending.

9

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.

In the second quarter of 2016, we recorded a $203 million before-tax impairment for the associated carrying value of our Gibson and Tiber undeveloped leaseholds in deepwater Gulf of Mexico. Additionally, in the first quarter of 2016, we recorded a $95 million before-tax impairment for the associated carrying value of capitalized undeveloped leasehold costs of the Melmar prospect, and a $73 million impairment in deepwater Gulf of Mexico, primarily as a result of changes in the estimated market value following the completion of an initial marketing effort.

Note 9—Debt

As of June 30, 2017, our revolving credit facility, expiring in June 2019, was $6.75 billion. The 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 June 30, 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 June 30, 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 June 30, 2017.

In the first quarter of 2017, we made a prepayment of $805 million on our floating rate term loan facility due in 2019. 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 June 30, 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.

On July 5, 2017, we prepaid the remaining balance of $645 million on our floating rate term loan facility.

In the second quarter of 2017, we redeemed $3.0 billion of debt across the following instruments:

• 6.65% Debentures due 2018 with principal of $297 million

• 5.75% Notes due 2019 with principal of $1.7 billion (partial redemption)

• 6.00% Notes due 2020 with principal of $1.0 billion

We incurred premiums above book value to redeem the debt instruments resulting in $234 million of expense which is reported in the “Other expense” line on our consolidated income statement.

10

In the second quarter, we gave notice to redeem the following debt instruments totaling $1.8 billion. The prepayments will occur on August 1, 2017, and we expect to incur approximately $50 million in premiums above book value, subject to pricing, related to these redemptions when paid.

• 5.20% Notes due 2018 with principal of $500 million

• 1.50% Notes due 2018 with principal of $750 million

• 5.75% Notes due 2019 with principal of $550 million

At June 30, 2017, we reclassified $2.7 billion from long-term to short-term debt, including the $1.8 billion of notes and the $645 million term loan facility discussed above.

At June 30, 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.

Note 10—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first six 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)		(2,854	)		27			(2,827	)		(2,540	)		26			(2,514	)
Dividends		(662	)		—			(662	)		(626	)		—			(626	)
Repurchase of company common stock		(1,075	)		—			(1,075	)		—			—			—
Distributions to noncontrolling interests		—			(67	)		(67	)		—			(59	)		(59	)
Other changes, net*		(97	)		1			(96	)		948			—			948
Balance at June 30	$	30,286			213			30,499			37,544			287			37,831

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

Note 11—Guarantees

At June 30, 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.

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APLNG Guarantees

At June 30, 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 June 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. Our maximum potential amount of future payments related to this guarantee became immaterial in the second quarter of 2017.

• 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 completion of a two-train test with milestones which we estimate should occur in the third quarter of 2017. Our maximum exposure at June 30, 2017, is $1.25 billion based upon our pro-rata share of the facility used at that date. At June 30, 2017, the carrying value of this guarantee was approximately $46 million.

• 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 June 30, 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 ($1.74 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 28 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $160 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.

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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 June 30, 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 June 30, 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 12—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 $1.31 billion. At June 30, 2017, the carrying value of this guarantee is approximately $98 million and the remaining term is seven years. Because Phillips 66 has indemnified us for 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 12—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.

13

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.

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 June 30, 2017, our balance sheet included a total environmental accrual of $188 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.

14

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 June 30, 2017, we had performance obligations secured by letters of credit of $265 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 International Chamber of Commerce (ICC) arbitration tribunals. 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.

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. 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 filed a request for annulment of this decision with ICSID and the annulment phase is ongoing.

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 is being conducted under the United Nations Commission on International Trade Laws (UNCITRAL) rules using a three-person tribunal. The arbitration is ongoing.

In June 2017, FAR Ltd. initiated arbitration before the ICC against ConocoPhillips Senegal B.V. in connection with the sale of ConocoPhillips Senegal B.V. to Woodside Energy Holdings (Senegal) Limited in 2016. The arbitral tribunal has not yet been constituted.

15

Note 13—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
	June 30 2017		December 31 2016
Assets
Prepaid expenses and other current assets	$	196		268
Other assets		42		44
Liabilities
Other accruals		182		300
Other liabilities and deferred credits		29		34

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 June 30						Six Months Ended June 30
	2017			2016			2017			2016
Sales and other operating revenues	$	52			(163	)		103			(166	)
Other income		(1	)		(3	)		—			(2	)
Purchased commodities		(31	)		130			(69	)		129

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

	Open Position Long/(Short)
	June 30 2017			December 31 2016
Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(41	)		(31	)
Basis		40			2

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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
	June 30 2017		December 31 2016
Assets
Prepaid expenses and other current assets	$	1		1
Liabilities
Other accruals		—		168

The (gains) 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 June 30					Six Months Ended June 30
	2017			2016		2017		2016
Foreign currency transaction (gains) losses	$	(4	)		86		3		183

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

	In Millions Notional Currency
	June 30 2017		December 31 2016
Sell U.S. dollar, buy other currencies*	USD	28		13
Buy U.S. dollar, sell other currencies**	USD	—		25
Buy British pound, sell other currencies***	GBP	6		1,069
Sell British pound, buy Norwegian krone	GBP	—		51

    *Primarily Canadian dollar.

  **Primarily British pound.

***Primarily Euro and Canadian dollar.

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Financial Instruments

We invest excess cash in financial instruments with maturities based on our cash forecasts for the various currency pools we manage. The maturities of these investments may from time to time extend beyond 90 days. The types of financial instruments in which we currently invest include:

• Time deposits: Interest bearing deposits placed with approved financial institutions.

• Commercial paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount to mature at par.

• Government or government agency obligations: Short-term securities issued by the U.S. government or U.S. government agencies.

These financial instruments appear in the “Cash and cash equivalents” line of our consolidated balance sheet if the maturities at the time we made the investments were 90 days or less; otherwise, these financial instruments are included in the “Short-term investments” line on our consolidated balance sheet.

	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	June 30 2017		December 31 2016		June 30 2017		December 31 2016
Cash	$	779		623		—		—
Time deposits
Remaining maturities from 1 to 90 days		5,316		2,987		1,510		39
Remaining maturities from 91 to 180 days		—		—		78		11
Commercial paper
Remaining maturities from 1 to 90 days		999		—		524		—
Remaining maturities from 91 to 180 days		—		—		621		—
Government obligations
Remaining maturities from 1 to 90 days		440		—		—		—
	$	7,534		3,610		2,733		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.

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.

18

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 June 30, 2017 and December 31, 2016, was $37 million and $42 million, respectively. For these instruments, no collateral was posted as of June 30, 2017 or December 31, 2016. If our credit rating had been downgraded below investment grade on June 30, 2017, we would be required to post $37 million of additional collateral, either with cash or letters of credit.

Note 14—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 market data. This also includes our investment in common shares of Cenovus Energy, currently subject to a trading restriction, which is valued using quotes for shares on the New York Stock Exchange. 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.

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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
	June 30, 2017								December 31, 2016
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Investment in Cenovus Energy	$	—		1,533		—		1,533		—		—		—		—
Commodity derivatives		130		82		26		238		194		96		22		312
Total assets	$	130		1,615		26		1,771		194		96		22		312
Liabilities
Commodity derivatives	$	131		69		11		211		207		105		22		334
Total liabilities	$	131		69		11		211		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
June 30, 2017
Assets	$	238		143		95		—		5		90
Liabilities		211		143		68		3		5		60
December 31, 2016
Assets	$	312		221		91		—		5		86
Liabilities		334		221		113		12		12		89

At June 30, 2017 and December 31, 2016, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Non-Recurring Fair Value Measurement

The following table summarizes the fair value hierarchy by major category and date of remeasurement for assets accounted for at fair value on a non-recurring basis:

	Millions of Dollars
			Fair Value Measurements Using
	Fair Value		Level 1 Inputs		Level 3 Inputs		Before- Tax Loss
June 30, 2017
Net PP&E (held for sale)	$	2,830		2,830		—		3,882
Cost and equity method investments		7,656		—		7,656		2,384

20

During the second quarter of 2017, net PP&E held for sale was written down to fair value, less costs to sell. The fair value of each asset was determined by its negotiated selling price. For additional information see Note 4—Assets Held for Sale, Sold or Other Planned Dispositions.

During the second quarter of 2017, our equity method investment in APLNG was determined to have fair value below its carrying value, and the impairment was considered to be other than temporary. See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment.

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.

• Investment in Cenovus Energy shares: See Note 6—Investment in Cenovus Energy for a discussion of the carrying value and fair value of our investment in Cenovus Energy shares.

• 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
	June 30		December 31		June 30		December 31
	2017		2016		2017		2016
Financial assets
Investment in Cenovus Energy	$	1,533		—		1,533		—
Commodity derivatives		95		91		95		91
Total loans and advances—related parties		644		701		644		701
Financial liabilities
Total debt, excluding capital leases		22,624		26,423		25,501		29,307
Commodity derivatives		65		101		65		101

21

Note 15—Accumulated Other Comprehensive Loss

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

	Millions of Dollars
	Defined Benefit Plans			Net Unrealized Loss on Securities			Foreign Currency Translation			Accumulated Other Comprehensive Loss
December 31, 2016	$	(547	)		—			(5,646	)		(6,193	)
Other comprehensive income (loss)		64			(424	)		211			(149	)
June 30, 2017	$	(483	)		(424	)		(5,435	)		(6,342	)

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 June 30				Six Months Ended June 30
	2017		2016		2017		2016
Defined benefit plans	$	36		42		90		105
Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	20		23		47		59

See Note 17—Employee Benefit Plans, for additional information.

Note 16—Cash Flow Information

	Millions of Dollars
	Six Months Ended June 30
	2017			2016
Cash Payments (Receipts)
Interest	$	676			526
Income taxes*		337			(366	)
Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(2,952	)		(1,599	)
Short-term investments sold		299			307
	$	(2,653	)		(1,292	)

*Net of $569 million in 2016 related to refunds received from the Internal Revenue Service.

During the first quarter of 2017, 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.

22

In April 2017, we received a $135 million deposit from an affiliate of Hilcorp Energy Company on the date of signing the definitive agreement to sell our interests in the San Juan Basin. This deposit is included in the “Other” line of the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows. See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, for additional information on our dispositions.

Note 17—Employee Benefit Plans

Pension and Postretirement Plans

	Millions of Dollars
	Pension Benefits												Other Benefits
	2017						2016						2017			2016
	U.S.			Int’l.			U.S.			Int’l.
Components of Net Periodic Benefit Cost
Three Months Ended June 30
Service cost	$	23			20			28			20			1			—
Interest cost		29			25			32			32			2			4
Expected return on plan assets		(31	)		(39	)		(35	)		(41	)		—			—
Amortization of prior service cost (credit)		1			(2	)		1			(2	)		(9	)		(8	)
Recognized net actuarial loss (gain)		17			12			23			7			—			(1	)
Settlements		37			—			45			—			—			—
Net periodic benefit cost	$	76			16			94			16			(6	)		(5	)
Six Months Ended June 30
Service cost	$	46			39			55			40			1			1
Interest cost		61			51			72			63			4			7
Expected return on plan assets		(65	)		(78	)		(78	)		(82	)		—			—
Amortization of prior service cost (credit)		2			(3	)		2			(3	)		(18	)		(17	)
Recognized net actuarial loss (gain)		36			24			42			14			(1	)		(1	)
Settlements		97			—			127			—			—			—
Net periodic benefit cost	$	177			33			220			32			(14	)		(10	)

During the first six months of 2017, we contributed $119 million to our domestic benefit plans and $62 million to our international benefit plans. In 2017, we expect to contribute approximately $460 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.

We recognized a proportionate share of prior actuarial losses from other comprehensive loss as pension settlement expense of $37 million and $97 million during the three- and six-month periods ended June 30, 2017, respectively.

23

Severance Accrual

As a result of selling our 50 percent nonoperated interest in the FCCL Partnership as well as the majority of our western Canada gas assets, and entering into a definitive agreement to sell our interests in the San Juan Basin, a reduction in our overall employee workforce began during the second quarter of 2017. Severance accruals of $16 million and $55 million were recorded during the three- and six-month periods ended June 30, 2017. The following table summarizes our severance accrual activity for the six-month period ended June 30, 2017:

	Millions of Dollars
Balance at December 31, 2016	$	80
Accruals		55
Benefit payments		(68	)
Balance at June 30, 2017	$	67

Of the remaining balance at June 30, 2017, $43 million is classified as short-term.

Note 18—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 June 30						Six Months Ended June 30
	2017			2016			2017			2016
Operating revenues and other income	$	30			28			59			55
Purchases		25			25			48			49
Operating expenses and selling, general and administrative expenses		14			12			26			28
Net interest (income) expense*		(3	)		(3	)		(6	)		(6	)

*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 19—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.

24

Analysis of Results by Operating Segment

	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Sales and Other Operating Revenues
Alaska	$	1,071			936			2,078			1,714
Lower 48		3,090			2,395			6,320			4,540
Intersegment eliminations		(2	)		(5	)		(5	)		(12	)
Lower 48		3,088			2,390			6,315			4,528
Canada		788			391			1,658			816
Intersegment eliminations		(89	)		(30	)		(175	)		(65	)
Canada		699			361			1,483			751
Europe and North Africa		1,011			736			2,454			1,659
Asia Pacific and Middle East		896			897			1,918			1,734
Corporate and Other		16			28			51			83
Consolidated sales and other operating revenues	$	6,781			5,348			14,299			10,469
Net Income (Loss) Attributable to ConocoPhillips
Alaska	$	199			147			188			145
Lower 48		(2,536	)		(771	)		(2,898	)		(1,591	)
Canada		1,379			(175	)		2,327			(469	)
Europe and North Africa		123			20			294			(31	)
Asia Pacific and Middle East		(2,172	)		72			(1,936	)		67
Other International		(9	)		(29	)		(57	)		(53	)
Corporate and Other		(424	)		(335	)		(772	)		(608	)
Consolidated net loss attributable to ConocoPhillips	$	(3,440	)		(1,071	)		(2,854	)		(2,540	)

	Millions of Dollars
	June 30 2017		December 31 2016
Total Assets
Alaska	$	12,163		12,314
Lower 48		17,637		22,673
Canada		6,122		17,548
Europe and North Africa		11,564		11,727
Asia Pacific and Middle East		17,389		20,451
Other International		116		97
Corporate and Other		13,013		4,962
Consolidated total assets	$	78,004		89,772

25

Note 20—Income Taxes

Our effective tax rates for the second quarter and six-month period ended June 30, 2017, were 21 percent and 38 percent, respectively, compared with 36 percent and 35 percent for the same periods of 2016. The amounts of U.S. and foreign income (loss) from continuing operations before income taxes, with a reconciliation of tax at the federal statutory rate with the provision for income taxes were:

	Millions of Dollars												Percent of Pre-Tax Income (Loss)
	Three Months Ended June  30						Six Months Ended June  30						Three Months Ended June  30						Six Months Ended June  30
	2017			2016			2017			2016			2017			2016			2017			2016
Income (loss) from continuing operations before income taxes
United States	$	(4,269	)		(1,373	)		(5,063	)		(2,964	)		97.9	%		83.5			110.2			76.6
Foreign		(92	)		(271	)		470			(904	)		2.1			16.5			(10.2	)		23.4
	$	(4,361	)		(1,644	)		(4,593	)		(3,868	)		100.0	%		100.0			100.0			100.0
Federal statutory income tax	$	(1,526	)		(575	)		(1,608	)		(1,354	)		35.0	%		35.0			35.0			35.0
Non-U.S. effective tax rates		69			104			335			173			(1.6	)		(6.3	)		(7.3	)		(4.5	)
Canada disposition		(172	)		—			(1,168	)		—			3.9			—			25.4			—
Recovery of outside basis		(4	)		(12	)		(839	)		(23	)		0.1			0.7			18.3			0.6
Adjustment to tax reserves		—			—			822			—			—			—			(17.9	)		—
APLNG impairment		834			—			834			—			(19.1	)		—			(18.2	)		—
State income tax		(99	)		(78	)		(88	)		(110	)		2.3			4.7			1.9			2.8
Enhanced oil recovery credit		(29	)		(17	)		(45	)		(34	)		0.7			1.0			1.0			0.9
Other		(8	)		(8	)		(9	)		(6	)		0.1			0.5			0.2			0.2
	$	(935	)		(586	)		(1,766	)		(1,354	)		21.4	%		35.6			38.4			35.0

The impairment of our APLNG investment did not generate a tax benefit. See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, for information on the impairment of our APLNG investment.

Our effective tax rate for the second quarter and six-month period ended June 30, 2017, was favorably impacted by tax benefits of $172 million and $1,168 million, respectively, associated with our Canada disposition. The benefit was 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 $822 million related to the recovery of outside basis. However, since we believe it is not likely we will receive a corresponding cash tax savings of this amount, the benefit has been offset by a full reserve. See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, for additional information on our Canada disposition.

During the second quarter of 2016, previously unrecognized state deferred tax assets were recognized. As a result, a $68 million tax benefit is reflected in the “Income tax benefit” line on our consolidated income statement.

26

Note 21—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 January 2016, the FASB issued ASU No. 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU No. 2016-01), to meet its objective of providing more decision-useful information about financial instruments. The ASU, among other things, requires entities to record the changes in fair value of equity investments, other than investments accounted for using the equity method, within net income. Under this ASU, entities will no longer be able to recognize unrealized holding gains and losses on available-for-sale securities in other comprehensive income. The ASU also requires additional disclosures relating to fair value measurement categories for financial assets and liabilities and eliminates certain disclosure requirements related to financial instruments measured at amortized cost. ASU No. 2016-01 is effective for interim and annual periods beginning after December 15, 2017, and the ASU should be adopted using a cumulative-effect adjustment to retained earnings as of the date of adoption.

Upon adoption of the standard, we will make a cumulative-effect adjustment to reclassify the accumulated unrealized holding gains and losses related to our investment in Cenovus Energy from other comprehensive income to retained earnings, and from the date of adoption, we will begin reporting the changes in the fair value of our investment within net income. The impact on our consolidated financial statements and disclosures will depend on the amount of accumulated unrealized holding gains and losses recognized in other comprehensive income at December 31, 2017, and changes in the fair value of our investment in Cenovus Energy subsequent to that date. For additional information on our investment in Cenovus Energy, see Note 6—Investment in Cenovus Energy, Note 14—Fair Value Measurement, and Note 15—Accumulated Other Comprehensive Loss.

27

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.

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.

28

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/or 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.

In May 2017, ConocoPhillips Company received a $9.8 billion return of capital from a nonguarantor subsidiary to settle certain accumulated intercompany balances. The transaction had no impact on our consolidated financial statements.

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

29

	Millions of Dollars
	Three Months Ended June 30, 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	$	—			2,954			—			3,827			—			6,781
Equity in earnings (losses) of affiliates		(3,235	)		(2,297	)		—			153			5,557			178
Gain on dispositions		—			16			—			1,860			—			1,876
Other income		1			13			—			33			—			47
Intercompany revenues		12			74			41			792			(919	)		—
Total Revenues and Other Income		(3,222	)		760			41			6,665			4,638			8,882
Costs and Expenses
Purchased commodities		—			2,637			—			1,038			(753	)		2,922
Production and operating expenses		—			139			—			1,189			(1	)		1,327
Selling, general and administrative expenses		2			110			—			22			—			134
Exploration expenses		—			33			—			65			—			98
Depreciation, depletion and amortization		—			204			—			1,421			—			1,625
Impairments		—			1,074			—			5,220			—			6,294
Taxes other than income taxes		—			36			—			162			—			198
Accretion on discounted liabilities		—			10			—			82			—			92
Interest and debt expense		125			171			36			139			(165	)		306
Foreign currency transaction (gains) losses		(15	)		2			19			7			—			13
Other expenses		217			17			—			—			—			234
Total Costs and Expenses		329			4,433			55			9,345			(919	)		13,243
Loss before income taxes		(3,551	)		(3,673	)		(14	)		(2,680	)		5,557			(4,361	)
Income tax provision (benefit)		(111	)		(438	)		11			(397	)		—			(935	)
Net loss		(3,440	)		(3,235	)		(25	)		(2,283	)		5,557			(3,426	)
Less: net income attributable to noncontrolling interests		—			—			—			(14	)		—			(14	)
Net Loss Attributable to ConocoPhillips	$	(3,440	)		(3,235	)		(25	)		(2,297	)		5,557			(3,440	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(3,821	)		(3,616	)		30			(2,263	)		5,849			(3,821	)
Income Statement	Three Months Ended June 30, 2016
Revenues and Other Income
Sales and other operating revenues	$	—			2,284			—			3,064			—			5,348
Equity in earnings (losses) of affiliates		(1,003	)		(21	)		—			145			959			80
Gain on dispositions		—			63			—			65			—			128
Other income		—			1			—			18			—			19
Intercompany revenues		26			68			60			928			(1,082	)		—
Total Revenues and Other Income		(977	)		2,395			60			4,220			(123	)		5,575
Costs and Expenses
Purchased commodities		—			1,998			—			682			(678	)		2,002
Production and operating expenses		—			488			—			1,191			(234	)		1,445
Selling, general and administrative expenses		2			136			—			29			—			167
Exploration expenses		—			551			—			59			—			610
Depreciation, depletion and amortization		—			306			—			2,023			—			2,329
Impairments		—			37			—			25			—			62
Taxes other than income taxes		—			39			—			158			—			197
Accretion on discounted liabilities		—			12			—			100			—			112
Interest and debt expense		126			164			57			135			(170	)		312
Foreign currency transaction (gains) losses		2			—			(79	)		60			—			(17	)
Total Costs and Expenses		130			3,731			(22	)		4,462			(1,082	)		7,219
Income (Loss) before income taxes		(1,107	)		(1,336	)		82			(242	)		959			(1,644	)
Income tax provision (benefit)		(36	)		(333	)		19			(236	)		—			(586	)
Net income (loss)		(1,071	)		(1,003	)		63			(6	)		959			(1,058	)
Less: net income attributable to noncontrolling interests		—			—			—			(13	)		—			(13	)
Net Income (Loss) Attributable to ConocoPhillips	$	(1,071	)		(1,003	)		63			(19	)		959			(1,071	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(1,296	)		(1,228	)		51			(215	)		1,392			(1,296	)

30

	Millions of Dollars
	Six Months Ended June 30, 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	$	—			6,069			—			8,230			—			14,299
Equity in earnings (losses) of affiliates		(2,578	)		(1,124	)		—			313			3,767			378
Gain on dispositions		—			29			—			1,869			—			1,898
Other income		1			15			—			62			—			78
Intercompany revenues		29			145			83			1,586			(1,843	)		—
Total Revenues and Other Income		(2,548	)		5,134			83			12,060			1,924			16,653
Costs and Expenses
Purchased commodities		—			5,402			—			2,228			(1,516	)		6,114
Production and operating expenses		—			280			—			2,347			(2	)		2,625
Selling, general and administrative expenses		6			246			—			44			(5	)		291
Exploration expenses		—			405			—			244			—			649
Depreciation, depletion and amortization		—			455			—			3,149			—			3,604
Impairments		—			1,074			—			5,395			—			6,469
Taxes other than income taxes		—			85			—			344			—			429
Accretion on discounted liabilities		—			20			—			167			—			187
Interest and debt expense		254			336			73			278			(320	)		621
Foreign currency transaction (gains) losses		(22	)		2			68			(25	)		—			23
Other expense		217			17			—			—			—			234
Total Costs and Expenses		455			8,322			141			14,171			(1,843	)		21,246
Loss before income taxes		(3,003	)		(3,188	)		(58	)		(2,111	)		3,767			(4,593	)
Income tax provision (benefit)		(149	)		(610	)		6			(1,013	)		—			(1,766	)
Net loss		(2,854	)		(2,578	)		(64	)		(1,098	)		3,767			(2,827	)
Less: net income attributable to noncontrolling interests		—			—			—			(27	)		—			(27	)
Net Loss Attributable to ConocoPhillips	$	(2,854	)		(2,578	)		(64	)		(1,125	)		3,767			(2,854	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(3,003	)		(2,727	)		17			(901	)		3,611			(3,003	)
Income Statement	Six Months Ended June 30, 2016
Revenues and Other Income
Sales and other operating revenues	$	—			4,356			—			6,113			—			10,469
Equity in earnings of affiliates		(2,430	)		(771	)		—			(299	)		3,431			(69	)
Gain on dispositions		—			85			—			66			—			151
Other income (loss)		—			(5	)		—			44			—			39
Intercompany revenues		44			149			116			1,453			(1,762	)		—
Total Revenues and Other Income		(2,386	)		3,814			116			7,377			1,669			10,590
Costs and Expenses
Purchased commodities		—			3,846			—			1,561			(1,180	)		4,227
Production and operating expenses		—			741			—			2,295			(237	)		2,799
Selling, general and administrative expenses		5			290			—			64			(6	)		353
Exploration expenses		—			982			—			133			—			1,115
Depreciation, depletion and amortization		—			563			—			4,013			—			4,576
Impairments		—			41			—			157			—			198
Taxes other than income taxes		—			96			—			281			—			377
Accretion on discounted liabilities		—			24			—			197			—			221
Interest and debt expense		250			298			112			272			(339	)		593
Foreign currency transaction (gains) losses		(42	)		2			233			(194	)		—			(1	)
Total Costs and Expenses		213			6,883			345			8,779			(1,762	)		14,458
Loss before income taxes		(2,599	)		(3,069	)		(229	)		(1,402	)		3,431			(3,868	)
Income tax provision (benefit)		(59	)		(639	)		1			(657	)		—			(1,354	)
Net loss		(2,540	)		(2,430	)		(230	)		(745	)		3,431			(2,514	)
Less: net income attributable to noncontrolling interests		—			—			—			(26	)		—			(26	)
Net Loss Attributable to ConocoPhillips	$	(2,540	)		(2,430	)		(230	)		(771	)		3,431			(2,540	)
Comprehensive Income (Loss) Attributable to ConocoPhillips	$	(1,664	)		(1,554	)		4			230			1,320			(1,664	)

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	Millions of Dollars
	June 30, 2017
Balance Sheet	ConocoPhillips			ConocoPhillips Company		ConocoPhillips Canada Funding Company I			All Other Subsidiaries		Consolidating Adjustments			Total Consolidated
Assets
Cash and cash equivalents	$	—			1,162		34			6,338		—			7,534
Short-term investments		—			—		—			2,733		—			2,733
Accounts and notes receivable		82			1,656		35			3,608		(2,218	)		3,163
Investment in Cenovus Energy		—			1,533		—			—		—			1,533
Inventories		—			112		—			907		—			1,019
Prepaid expenses and other current assets		1			436		7			3,480		(27	)		3,897
Total Current Assets		83			4,899		76			17,066		(2,245	)		19,879
Investments, loans and long-term receivables*		34,470			56,453		2,377			18,838		(101,935	)		10,203
Net properties, plants and equipment		—			4,330		—			42,516		—			46,846
Other assets		43			2,906		203			1,235		(3,311	)		1,076
Total Assets	$	34,596			68,588		2,656			79,655		(107,491	)		78,004
Liabilities and Stockholders’ Equity
Accounts payable	$	—			2,357		2			3,293		(2,218	)		3,434
Short-term debt		1,688			2,000		6			104		—			3,798
Accrued income and other taxes		—			76		—			715		—			791
Employee benefit obligations		—			382		—			127		—			509
Other accruals		102			680		45			594		(27	)		1,394
Total Current Liabilities		1,790			5,495		53			4,833		(2,245	)		9,926
Long-term debt		3,784			11,338		1,706			2,842		—			19,670
Asset retirement obligations and accrued environmental costs		—			560		—			7,071		—			7,631
Deferred income taxes		—			—		—			9,111		(2,776	)		6,335
Employee benefit obligations		—			1,874		—			625		—			2,499
Other liabilities and deferred credits*		5,298			8,972		824			15,285		(28,935	)		1,444
Total Liabilities		10,872			28,239		2,583			39,767		(33,956	)		47,505
Retained earnings		21,510			11,437		(605	)		10,852		(15,161	)		28,033
Other common stockholders’ equity		2,214			28,912		678			28,823		(58,374	)		2,253
Noncontrolling interests		—			—		—			213		—			213
Total Liabilities and Stockholders’ Equity	$	34,596			68,588		2,656			79,655		(107,491	)		78,004
*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.

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	Millions of Dollars
	Six Months Ended June 30, 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	$	(137	)		(1,475	)		21			5,926			(794	)		3,541
Cash Flows From Investing Activities
Capital expenditures and investments		—			(1,125	)		—			(1,729	)		868			(1,986	)
Working capital changes associated with investing activities		—			39			—			(152	)		—			(113	)
Proceeds from asset dispositions		—			9,909			—			10,716			(9,883	)		10,742
Purchases of short-term investments		—			—			—			(2,653	)		—			(2,653	)
Long-term advances/loans—related parties		—			(63	)		—			(20	)		83			—
Collection of advances/loans—related parties		658			63			—			2,138			(2,802	)		57
Intercompany cash management		4,882			(4,214	)		—			(668	)		—			—
Other		—			43			—			133			—			176
Net Cash Provided by Investing Activities		5,540			4,652			—			7,765			(11,734	)		6,223
Cash Flows From Financing Activities
Issuance of debt		—			20			—			63			(83	)		—
Repayment of debt		(3,717	)		(2,394	)		—			(770	)		2,802			(4,079	)
Issuance of company common stock		49			—			—			—			(112	)		(63	)
Repurchase of company common stock		(1,075	)		—			—			—			—			(1,075	)
Dividends paid		(662	)		—			—			(906	)		906			(662	)
Other		2			—			—			(9,081	)		9,015			(64	)
Net Cash Used in Financing Activities		(5,403	)		(2,374	)		—			(10,694	)		12,528			(5,943	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			1			—			102			—			103
Net Change in Cash and Cash Equivalents		—			804			21			3,099			—			3,924
Cash and cash equivalents at beginning of period		—			358			13			3,239			—			3,610
Cash and Cash Equivalents at End of Period	$	—			1,162			34			6,338			—			7,534
Statement of Cash Flows	Six Months Ended June 30, 2016
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	(153	)		572			(5	)		2,229			(963	)		1,680
Cash Flows From Investing Activities
Capital expenditures and investments		—			(823	)		—			(2,532	)		401			(2,954	)
Working capital changes associated with investing activities		—			(76	)		—			(287	)		—			(363	)
Proceeds from asset dispositions		2,300			160			—			227			(2,324	)		363
Purchases of short-term investments		—			—			—			(1,292	)		—			(1,292	)
Long-term advances/loans—related parties		—			(803	)		—			—			803			—
Collection of advances/loans—related parties		—			—			—			1,626			(1,573	)		53
Intercompany cash management		(3,190	)		2,127			—			1,063			—			—
Other		—			2			—			4			—			6
Net Cash Provided by (Used in) Investing Activities		(890	)		587			—			(1,191	)		(2,693	)		(4,187	)
Cash Flows From Financing Activities
Issuance of debt		1,600			2,994			—			803			(803	)		4,594
Repayment of debt		—			(1,573	)		—			(827	)		1,573			(827	)
Issuance of company common stock		70			—			—			—			(115	)		(45	)
Dividends paid		(626	)		—			—			(1,078	)		1,078			(626	)
Other		(1	)		(2,319	)		—			318			1,923			(79	)
Net Cash Provided by (Used in) Financing Activities		1,043			(898	)		—			(784	)		3,656			3,017
Effect of Exchange Rate Changes on Cash and Cash Equivalents		—			—			—			(15	)		—			(15	)
Net Change in Cash and Cash Equivalents		—			261			(5	)		239			—			495
Cash and cash equivalents at beginning of period		—			4			15			2,349			—			2,368
Cash and Cash Equivalents at End of Period	$	—			265			10			2,588			—			2,863

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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 55.

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 12,200 employees worldwide and total assets of $78 billion as of June 30, 2017.

Overview

The energy landscape continues to be challenged as global production oversupply caused ongoing weakness in commodity prices in the first half of the year.

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, these 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.

During the first half of the year, we took significant actions that allowed us to make substantial progress on some of our stated priorities. We have considerably accelerated these priorities with plans to reduce debt to less than $20 billion and triple our annual planned share buybacks from $1 billion to $3 billion, both in 2017. On a longer-term basis, we have adjusted our targeted debt level to $15 billion and aim to repurchase up to $6 billion of our common stock by year-end 2019. Through the second quarter, we have made prepayments totaling $4 billion on our long-term debt, repurchased 23 million shares of our common stock totaling $1 billion and continued the disposition of noncore assets in our portfolio.

34

On May 17, 2017, we completed the sale of 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 to Cenovus Energy. As of closing, consideration for the transaction was $10.4 billion of cash, 208 million Cenovus Energy shares, and a five-year uncapped contingent payment. Subsequent to closing, we received $600 million related to environmental claims, $317 million of which was received in the second quarter of 2017, and the remainder received in July 2017. The contingent payment, calculated and paid on a quarterly basis, is $6 million Canadian dollars (CAD) for every $1 CAD by which the Western Canada Select (WCS) quarterly average crude price exceeds $52 CAD per barrel. Proceeds from this transaction are being directed to our stated cash priorities.

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 six-year contingent payment is effective beginning January 1, 2018, and is due annually for periods in which the monthly U.S. Henry Hub price is at or above $3.20 per million British thermal units (MMBTU). The transaction closed on July 31, 2017, with cash proceeds of $2.5 billion after customary adjustments. Proceeds from this transaction will be used for general corporate purposes.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett for $305 million plus net customary adjustments. Proceeds from this transaction will be used for general corporate purposes.

On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets for $184 million subject to customary adjustments. The transaction is expected to close in the third quarter of 2017.

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

Our 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 1,437 thousand barrels of oil equivalent per day (MBOED) in the second quarter of 2017, an underlying increase of 4 percent compared with the same period of 2016 when adjusted for the impact of closed and signed dispositions of 278 MBOED in 2017 and 429 MBOED in 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. 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. However, oil prices in the second quarter of 2017 declined marginally as the return of Libyan and Nigerian production and lower OPEC compliance slowed the re-balancing process.

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),

35

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.

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 Henry Hub natural gas:

Brent crude oil prices averaged $49.83 per barrel in the second quarter of 2017, an increase of 9 percent compared with $45.57 per barrel in the second quarter of 2016, and a decrease of 7 percent compared with $53.78 per barrel in the first quarter of 2017. Industry crude prices for WTI averaged $48.24 per barrel in the second quarter of 2017, an increase of 6 percent compared with $45.48 per barrel in the second quarter of 2016, and a decrease of 7 percent compared with $51.83 per barrel in the first quarter of 2017.

Henry Hub natural gas prices averaged $3.19 per MMBTU in the second quarter of 2017, an increase of 64 percent compared with $1.95 per MMBTU in the second quarter of 2016, and a decrease of 4 percent compared with $3.32 per MMBTU in the first quarter of 2017. Prices improved relative to the same period of 2016 as a result of reduced production and lower U.S. inventories, but declined from the prior quarter as natural gas production increased in the contiguous United States.

Our realized bitumen price increased from $18.11 per barrel in the second quarter of 2016 to $22.42 per barrel in the same period of 2017, primarily due to higher blend sales prices, which include the significant increase in the WCS benchmark price, partly offset by higher diluent costs. Compared with $21.56 per barrel in the first quarter of 2017, our second-quarter 2017 realized bitumen price was slightly improved due to a higher blend sales price and lower blend ratio for Surmont Heavy Blend.

Our total average realized price was $36.08 per barrel of oil equivalent (BOE) in the second quarter of 2017, an increase of 30 percent compared with $27.79 per BOE in the second quarter of 2016, reflecting increased average realized prices for all commodities.

36

Key Operating and Financial Summary

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

• Cash provided by operating activities exceeded capital expenditures and dividends for the fourth consecutive quarter.

• Achieved second-quarter production excluding Libya of 1,425 MBOED; 3 percent year-over-year underlying production growth when excluding the impact of closed and signed dispositions. Increasing full-year underlying production, while also lowering capital expenditures guidance.

• Closed Canada transaction, announced strategic San Juan Basin and Barnett asset dispositions for total consideration of up to $3.3 billion, and signed an agreement in July for the sale of Panhandle. Expect over $16 billion of dispositions during 2017.

• Strengthened balance sheet through $3.0 billion of early debt retirement in the second quarter and a further $2.4 billion debt committed to be retired in the third quarter; expect year-end debt of less than $20 billion.

• Repurchased $1.0 billion in shares during the quarter, with ending share count reduced by 2 percent from the first quarter. On track for $3 billion in share repurchases in 2017.

• Executed second-quarter turnaround activity in Malaysia, Alaska, Europe, Australia and Canada; activity ongoing in the third quarter.

• Reduced year-over-year production and operating expenses by 8 percent.

• Improved full-year outlook for capital expenditures and production guidance.

Outlook

Capital and Production Guidance

Third-quarter 2017 production is expected to be 1,170 to 1,210 MBOED, which excludes Libya and reflects expected impacts from the San Juan Basin, the Barnett and Panhandle dispositions. Our full-year production on the same basis is expected to be 1,340 to 1,370 MBOED.

Full-year guidance for capital expenditures has been lowered to $4.8 billion, which achieves an expanded scope of activity at lower cost.

Marketing Activities

In line with our strategic objectives, we are currently marketing certain noncore assets primarily associated with North American natural gas. 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 transaction closed on July 31, 2017, with cash proceeds of $2.5 billion after customary adjustments. On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett for $305 million plus net customary adjustments. On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets for $184 million subject to customary adjustments. Given our recent sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets, 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.

Restructuring Costs

In the second quarter of 2017, we recorded a before-tax gross severance accrual of $16 million, primarily due to our Canada and San Juan Basin dispositions. As we further rationalize our assets and costs, we expect to incur additional restructuring charges during the remainder of 2017. 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.

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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. While we may incur additional future impairment charges to 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.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 2017, is based on a comparison with the corresponding periods 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 June 30						Six Months Ended June 30
	2017			2016			2017			2016
Alaska	$	199			147			188			145
Lower 48		(2,536	)		(771	)		(2,898	)		(1,591	)
Canada		1,379			(175	)		2,327			(469	)
Europe and North Africa		123			20			294			(31	)
Asia Pacific and Middle East		(2,172	)		72			(1,936	)		67
Other International		(9	)		(29	)		(57	)		(53	)
Corporate and Other		(424	)		(335	)		(772	)		(608	)
Net loss attributable to ConocoPhillips	$	(3,440	)		(1,071	)		(2,854	)		(2,540	)

Net loss attributable to ConocoPhillips increased $2,369 million in the second quarter and $314 million in the six-month period of 2017, mainly due to higher proved property and equity investment impairments, including a combined $2.5 billion after-tax charge related to the announced sales of our interests in the San Juan Basin and the Barnett, and a $2.4 billion before- and after-tax impairment of our equity investment in Australia Pacific LNG Pty Ltd (APLNG). Losses were additionally increased by a $185 million after-tax charge associated with our early retirement of debt in the second quarter of 2017.

These losses were partly offset by:

• Higher realized commodity prices.

• A $1.4 billion after-tax gain in the second quarter of 2017 on the sale of certain Canadian assets.

• Recognition of deferred tax benefits totaling $996 million in the first quarter of 2017, primarily related to the disposition of certain Canadian assets.

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

• Lower depreciation, depletion and amortization (DD&A) expense, mainly due to lower unit-of-production rates from reserves revisions, lower volumes and disposition impacts.

See the “Segment Results” section for additional information.

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Income Statement Analysis

Sales and other operating revenues increased 27 percent in the second quarter and 37 percent in the six-month period of 2017, mainly due to higher realized prices across all commodities, partly offset by lower sales volumes, primarily in our Lower 48 segment.

Equity in earnings (losses) of affiliates increased $447 million in the six-month period of 2017, primarily due to higher realized commodity prices at FCCL, Qatar Liquefied Gas Company Limited (3) (QG3) and APLNG, as well as increased volumes at APLNG given the ramp-up of Trains 1 and 2. The increase in earnings was partly offset by increased DD&A expense at APLNG also due to higher volumes.

Gain on dispositions increased $1,748 million in the second quarter and $1,747 million in the six-month period of 2017, primarily due to a $1,855 million before-tax gain on the sale of our 50 percent nonoperated interest in the FCCL oil sands partnership, as well as the majority of our western Canada gas assets.

Purchased commodities increased 46 percent in the second quarter and 45 percent in the six-month period of 2017, largely as a result of higher natural gas prices.

Exploration expenses decreased 84 percent in the second quarter and 42 percent in the six-month period of 2017, primarily due to reduced leasehold impairment expense and dry hole costs.

Leasehold impairment expense was reduced mainly due to the absence of 2016 before-tax charges of $203 million in the second quarter for our Gibson and Tiber leaseholds. Additionally, the expense was reduced by the absence of a $95 million charge for our Melmar leasehold and a $73 million charge for various Gulf of Mexico leases after completion of an initial marketing effort, both in the first quarter of 2016. The reduction was partly offset by a before-tax charge of $51 million in the first quarter of 2017 for Shenandoah in deepwater Gulf of Mexico.

Dry hole costs were reduced mainly due to the absence of before-tax charges in deepwater Gulf of Mexico of $249 million in the second quarter of 2016 for our Gibson and Tiber wells, and $128 million in the six-month period of 2016 for our Melmar well. The decrease in dry hole costs was partly offset by before-tax charges totaling $291 million in the first quarter of 2017 for multiple wells in Shenandoah, including wells previously suspended.

For additional information on leasehold impairments and dry hole costs, see Note 7—Suspended Wells and Other Exploration Expenses, and Note 8—Impairments, in the Notes to Consolidated Financial Statements.

DD&A decreased 30 percent in the second quarter and 21 percent in the six-month period of 2017, mainly due to lower unit-of-production rates from reserves revisions and lower volumes. DD&A was further decreased in both periods due to disposition impacts in our Canada, Lower 48 and Asia Pacific and Middle East segments.

Impairments increased $6.2 billion in the second quarter and $6.3 billion in the six-month period of 2017, mainly due to a $3.3 billion before-tax impairment of our interests in the San Juan Basin, which were classified as held for sale and written down to fair value less costs to sell, and a $2.4 billion before- and after-tax impairment of our equity investment in APLNG, mainly due to reduced price outlooks. For additional information on our San Juan Basin disposition and APLNG impairment, see Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, and the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements.

Other expense included a before-tax charge of $234 million in the second quarter of 2017 for premiums on early debt retirements.

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Summary Operating Statistics

	Three Months Ended June 30				Six Months Ended June 30
	2017		2016		2017		2016
Average Net Production
Crude oil (MBD)*		590		592		595		605
Natural gas liquids (MBD)		127		145		131		145
Bitumen (MBD)		137		160		179		163
Natural gas (MMCFD)**		3,499		3,893		3,653		3,894
Total Production (MBOED)***		1,437		1,546		1,514		1,562
	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	48.16		42.72		49.58		36.78
Natural gas liquids (per barrel)		20.99		16.55		23.05		14.45
Bitumen (per barrel)		22.42		18.11		21.89		9.49
Natural gas (per thousand cubic feet)		3.83		2.49		3.83		2.74
	Millions of Dollars
Exploration Expenses
General administrative, geological and geophysical, lease rental, and other	$	76		147		221		292
Leasehold impairment		8		214		71		394
Dry holes		14		249		357		429
	$	98		610		649		1,115

    *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 June 30, 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 decreased 7 percent in the second quarter and 3 percent in the six-month period of 2017. The decrease in total average production in both periods, primarily resulted from normal field decline and noncore asset dispositions, including our Canada transaction which was completed in the second quarter of 2017. The decrease in production was partly offset by production from major developments, including tight oil plays in the Lower 48; Surmont 2 and FCCL in Canada; Kebabangan gas field in Malaysia; APLNG in Australia; the Greater Britannia Area in the United Kingdom; and the Greater Ekofisk Area in Norway. Improved drilling and well performance in Canada, Alaska, Norway, and China, also partly offset the decrease in production in both periods. In the second quarter of 2017, we achieved production of 1,437 MBOED. Excluding Libya, second-quarter production was 1,425 MBOED. Adjusted for the second-quarter impact of closed and signed dispositions of 278 MBOED in 2017 and 429 MBOED in 2016, our underlying production increased 30 MBOED, or 3 percent, compared with the second quarter of 2016.

On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as most of our western Canada gas assets to Cenovus Energy. Production associated with these assets was 140 MBOED and 253 MBOED in the second quarters of 2017 and 2016, respectively, and 209 MBOED and 256 MBOED in the corresponding six-month periods.

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On April 12, 2017, we signed a definitive agreement to sell our interests in the San Juan Basin, which produced 120 MBOED and 127 MBOED in the second quarters of 2017 and 2016, respectively, and 116 MBOED and 124 MBOED in the corresponding six-month periods. The transaction closed on July 31, 2017.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett, which produced 10 MBOED and 11 MBOED in both the second quarters and six-month periods of 2017 and 2016, respectively. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017.

On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets, which produced 8 MBOED in the second quarters of 2017 and 2016, respectively, as well as in the corresponding six-month periods.

Year-end 2016 reserves associated with our Canadian transaction and the disposition of our interests in the San Juan Basin were 1.3 billion barrels of oil equivalent (BBOE) and 0.6 BBOE, respectively.

Segment Results

Alaska

	Three Months Ended June 30				Six Months Ended June 30
	2017		2016		2017		2016
Net Income Attributable to ConocoPhillips (millions of dollars)	$	199		147		188		145
Average Net Production
Crude oil (MBD)		169		163		172		167
Natural gas liquids (MBD)		14		11		15		12
Natural gas (MMCFD)		7		27		7		33
Total Production (MBOED)		184		179		188		185
Average Sales Prices
Crude oil (dollars per barrel)	$	49.95		44.39		50.94		37.85
Natural gas (dollars per thousand cubic feet)		1.43		4.82		2.25		4.83

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids and natural gas. As of June 30, 2017, Alaska contributed 21 percent of our worldwide liquids production and less than 1 percent of our worldwide natural gas production.

Earnings from Alaska increased 35 percent in the second quarter and 30 percent in the six-month period of 2017. The increase in earnings in the second quarter was primarily due to higher crude oil realized prices and sales volumes, a $29 million state tax audit settlement and lower DD&A expense due to reserve revisions. The second-quarter earnings increase was partly offset by the absence of a $57 million after-tax benefit in 2016 for the recognition of state deferred tax assets and a $36 million after-tax gain on the sale of our interest in the Beluga River natural gas field.

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In addition to the items discussed above, the increase in earnings in the six-month period was partly offset by 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, higher exploration expense from increased seismic activity in the Western North Slope and higher dry hole costs, and a state deferred tax asset valuation allowance.

Average production increased 3 percent in the second quarter and 2 percent in the six-month period of 2017, as the impact of normal field decline and our 2016 noncore asset dispositions was more than offset by well performance in the Western North Slope, Greater Prudhoe and Greater Kuparuk areas and lower downtime in the second quarter of 2017.

Lower 48

	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Net Loss Attributable to ConocoPhillips (millions of dollars)	$	(2,536	)		(771	)		(2,898	)		(1,591	)
Average Net Production
Crude oil (MBD)		179			206			177			204
Natural gas liquids (MBD)		79			90			77			88
Natural gas (MMCFD)		1,142			1,244			1,129			1,230
Total Production (MBOED)		448			503			442			497
Average Sales Prices
Crude oil (dollars per barrel)	$	43.38			39.50			44.61			33.33
Natural gas liquids (dollars per barrel)		18.99			14.59			20.48			12.07
Natural gas (dollars per thousand cubic feet)		2.72			1.70			2.77			1.75

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 June 30, 2017, the Lower 48 contributed 28 percent of our worldwide liquids production and 31 percent of our worldwide natural gas production.

Losses from Lower 48 increased by $1,765 million in the second quarter and $1,307 million in the six-month period of 2017, primarily due to proved property impairments totaling $2.5 billion after-tax for our interests in the San Juan Basin and the Barnett, which were classified as held for sale at June 30, 2017.

The losses were partly offset by:

• Lower DD&A expense, mainly due to a lower unit-of-production rate from reserve revisions, as well as lower volumes and the cessation of depreciation for our San Juan Basin asset which was classified as held for sale in the second quarter.

• Higher realized crude oil, natural gas and natural gas liquids prices, mainly in the first quarter of 2017.

• Lower exploration expenses, including the absence of 2016 after-tax dry hole costs and leasehold impairment charges totaling $439 million related to our Gibson, Tiber and Melmar wells and leases; as well as a $47 million impairment for leases in deepwater Gulf of Mexico primarily resulting from changes in the estimated market value following the completion of an initial marketing effort. 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.

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In the second quarter of 2017, our average realized crude oil price of $43.38 per barrel was 10 percent less than WTI of $48.24 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 three- and six-month periods of 2017. The decrease was mainly attributable to normal field decline, partly offset by new production and well performance, primarily from Eagle Ford, Bakken and the Permian Basin, and lower unplanned downtime.

Asset Disposition Update

On April 12, 2017, we signed a definitive agreement with an affiliate of Hilcorp Energy Company 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 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 price is at or above $3.20 per million British thermal units. The transaction closed on July 31, 2017, with cash proceeds of $2.5 billion after customary adjustments.

On June 28, 2017, we signed a definitive agreement with an affiliate of Miller Thomson & Partners LLC to sell our interests in the Barnett for $305 million in cash, subject to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017.

On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets for $184 million subject to customary adjustments. The transaction is expected to close in the third quarter of 2017.

See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions, in the Notes to Consolidated Financial Statements, for additional information regarding our asset dispositions.

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Canada

	Three Months Ended June 30					Six Months Ended June 30
	2017		2016			2017		2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	1,379		(175	)		2,327		(469	)
Average Net Production
Crude oil (MBD)		3		8			4		8
Natural gas liquids (MBD)		13		22			19		24
Bitumen (MBD)
Consolidated operations		52		19			52		23
Equity affiliates		85		141			127		140
Total bitumen		137		160			179		163
Natural gas (MMCFD)		247		532			367		549
Total Production (MBOED)		194		279			263		286
Average Sales Prices
Crude oil (dollars per barrel)	$	43.35		37.70			43.66		31.74
Natural gas liquids (dollars per barrel)		20.96		13.70			21.19		12.65
Bitumen (dollars per barrel)
Consolidated operations		19.28		13.76			17.35		7.34
Equity affiliates		24.19		18.74			23.83		9.84
Total bitumen		22.42		18.11			21.89		9.49
Natural gas (dollars per thousand cubic feet)		2.00		0.95			1.97		1.08

Our Canadian operations mainly consist of an oil sands development in the Athabasca Region of northeastern Alberta and a liquids-rich unconventional play in western Canada. As of June 30, 2017, Canada contributed 22 percent of our worldwide liquids production and 10 percent of our worldwide natural gas production.

Earnings from Canada increased by $1,554 million in the second quarter and $2,796 million in the six-month period of 2017, primarily due to an after-tax gain of $1.4 billion on the sale of certain Canadian assets, further discussed below, in the second quarter of 2017. The first-quarter 2017 recognition of $996 million in deferred tax benefits related to the capital gains component of our disposition and the recognition of previously unrealizable Canadian tax basis also increased earnings in the six-month period. Additionally, higher realized prices across all commodities and lower DD&A expense from disposition impacts further improved earnings in both periods.

Total average production decreased 30 percent in the second quarter and 8 percent in the six-month period of 2017. The production decrease in both periods was primarily due to the Canada disposition and normal field decline, partly offset by production ramp-up at Surmont 2 and well performance at FCCL.

Asset Disposition Update

On March 29, 2017, we signed a definitive agreement with Cenovus Energy to sell our 50 percent nonoperated interest in the FCCL oil sands partnership, as well as the majority of our western Canada gas assets. The transaction closed on May 17, 2017. See Note 4—Assets Held for Sale, Sold or Other Planned Dispositions and Note 6—Investment in Cenovus Energy in the Notes to Consolidated Financial Statements, for additional information regarding our Canada disposition.

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Europe and North Africa

	Three Months Ended June 30				Six Months Ended June 30
	2017		2016		2017		2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	123		20		294		(31	)
Average Net Production
Crude oil (MBD)		136		105		138		114
Natural gas liquids (MBD)		9		6		8		6
Natural gas (MMCFD)		476		458		509		482
Total Production (MBOED)		224		187		232		201
Average Sales Prices
Crude oil (dollars per barrel)	$	50.98		45.77		52.30		39.78
Natural gas liquids (dollars per barrel)		24.88		22.16		29.31		20.67
Natural gas (dollars per thousand cubic feet)		4.95		4.30		5.44		4.68

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 June 30, 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 $103 million in the second quarter and $325 million in the six-month period of 2017. The earnings increase in the second quarter was primarily due to a $41 million tax benefit in Norway; higher crude oil and natural gas prices; lower production and operating expenses; lower DD&A, mainly due to reserve revisions and foreign currency impacts in the United Kingdom; and higher sales volumes.

Additionally, earnings increased in the six-month period due to the absence of first-quarter 2016 after-tax proved property impairments of $60 million in the United Kingdom.

Average production increased 20 percent in the second quarter and 15 percent in the six-month period of 2017. The increase in both periods was mainly due to improved drilling and well performance in Norway, new production from the Greater Britannia Area and Norway, and the resumption of production in Libya. Lower planned downtime for turnarounds in Norway and the United Kingdom also improved production, primarily in the second quarter of 2017. The increase in 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 June 30					Six Months Ended June 30
	2017			2016		2017			2016
Net Income (Loss) Attributable to ConocoPhillips (millions of dollars)	$	(2,172	)		72		(1,936	)		67
Average Net Production
Crude oil (MBD)
Consolidated operations		89			95		91			98
Equity affiliates		14			15		13			14
Total crude oil		103			110		104			112
Natural gas liquids (MBD)
Consolidated operations		4			8		4			8
Equity affiliates		8			8		8			7
Total natural gas liquids		12			16		12			15
Natural gas (MMCFD)
Consolidated operations		612			730		666			749
Equity affiliates		1,015			902		975			851
Total natural gas		1,627			1,632		1,641			1,600
Total Production (MBOED)		387			398		389			393
Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	49.28			43.55		51.56			38.35
Equity affiliates		50.55			46.35		53.19			40.40
Total crude oil		49.44			43.91		51.77			38.60
Natural gas liquids (dollars per barrel)
Consolidated operations		34.54			29.67		40.03			28.64
Equity affiliates		34.49			29.18		38.54			28.38
Total natural gas liquids		34.50			29.42		39.04			28.51
Natural gas (dollars per thousand cubic feet)
Consolidated operations		5.05			3.96		5.00			4.10
Equity affiliates		4.29			2.32		4.15			2.90
Total natural gas		4.58			3.06		4.50			3.47

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 June 30, 2017, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 45 percent of our worldwide natural gas production.

Earnings decreased by $2,244 million in the second quarter and $2,003 million in the six-month period of 2017, primarily due to a $2,384 million before- and after-tax charge for the impairment of our APLNG investment in the second quarter. The earnings decrease was partly offset by higher realized prices across all commodities, including LNG and crude oil, which improved our equity earnings from APLNG and QG3, respectively, and higher sales volumes at APLNG.

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See the “APLNG” section of Note 5—Investments, Loans and Long-Term Receivables, in the Notes to Consolidated Financial Statements, for information on the impairment of our APLNG investment.

Average production decreased 3 percent in the second quarter and 1 percent in the six-month period of 2017, mainly due to the disposition of our working interest in the offshore South Natuna Sea Block B Production Sharing Contract (PSC) in Indonesia; PSC impacts in Indonesia, Malaysia and Australia; and normal field decline in China. Higher planned downtime in the second quarter of 2017 for maintenance work in Malaysia also contributed to the production decrease in both periods. The production decrease was partly offset by 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.

Other International

	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Net Loss Attributable to ConocoPhillips (millions of dollars)	$	(9	)		(29	)		(57	)		(53	)

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

Losses from our Other International operations decreased $20 million in the second quarter of 2017 primarily due to the absence of 2016 rig stacking costs in Angola. In the six-month period of 2017, losses increased $4 million due to a $28 million after-tax charge for the cancellation of our Athena drilling rig contract in the first quarter of 2017, partly offset by lower rig stacking costs in Angola.

Exploration Update

In July 2017, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. executed an Additional Contract for the exploration and exploitation of unconventional reservoirs in an area identified as the VMM-2 Block. As a result, ConocoPhillips Colombia Ventures Ltd. and Canacol Energy Colombia S.A. also executed a joint operating agreement. We have an 80 percent operated working interest in the block.

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Corporate and Other

	Millions of Dollars
	Three Months Ended June 30						Six Months Ended June 30
	2017			2016			2017			2016
Net Loss Attributable to ConocoPhillips
Net interest	$	(174	)		(234	)		(427	)		(456	)
Corporate general and administrative expenses		(64	)		(72	)		(157	)		(157	)
Technology		—			1			9			22
Other		(186	)		(30	)		(197	)		(17	)
	$	(424	)		(335	)		(772	)		(608	)

Net interest consists of interest and financing expense, net of interest income and capitalized interest. Net interest decreased by $60 million in the second quarter and $29 million in the six-month period of 2017, compared with the same period of 2016, primarily due to impacts from the fair market value method of apportioning interest expense in the United States, partly offset by lower capitalized interest on projects.

Corporate general and administrative expenses decreased by $8 million in the second quarter of 2017, compared with the same period of 2016, primarily due to lower pension settlement expense. Expenses were flat in the six-month period of 2017.

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 $13 million in the six-month period of 2017, 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, other costs not directly associated with an operating segment and premiums incurred on the early retirement of debt. “Other” expenses increased by $156 million in the second quarter and $180 million in the six-month period of 2017, mainly due to premiums on our early retirement of debt.

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CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators

	Millions of Dollars
	June 30 2017			December 31 2016
Short-term debt	$	3,798			1,089
Total debt		23,468			27,275
Total equity		30,499			35,226
Percent of total debt to capital*		43	%		44
Percent of floating-rate debt to total debt		7	%		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, proceeds from asset sales, our commercial paper and credit facility programs, and our shelf registration statement. During the first six months of 2017, the primary uses of our available cash were $1,986 million to support our ongoing capital expenditures and investments program, $1,075 million to repurchase common stock, $662 million to pay dividends, and $2,653 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. In the second quarter of 2017, we also reduced various debt instruments and notes by $3.0 billion dollars. During the first six months of 2017, cash and cash equivalents increased by $3,924 million to $7,534 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 $3,541 million for the first six months of 2017, compared with $1,680 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 prioritization 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 six months of 2017 were $10.7 billion compared with $363 million for the corresponding period of 2016. All cash deposits and proceeds from asset dispositions are included in the “Cash Flows From Investing Activities” section of our consolidated statement of cash flows.

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. The transaction closed on May 17, 2017. As of June 30, 2017, consideration for the sale included $10.7 billion of cash proceeds. After June 30, 2017, we received $283 million related to environmental claims.

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. On the date of signing, we received a $135 million deposit from an affiliate of Hilcorp Energy Company. The transaction closed on July 31, 2017, with cash proceeds of $2.5 billion after customary adjustments.

On June 28, 2017, we signed a definitive agreement to sell our interests in the Barnett for $305 million in cash, subject to customary adjustments. The transaction is subject to specific conditions precedent being satisfied, including regulatory approval, and is expected to close in the third quarter of 2017.

On July 25, 2017, we signed a definitive agreement to sell our interest in the Panhandle assets for $184 million subject to customary adjustments. The transaction is expected to close in the third quarter of 2017.

For additional information on our dispositions, see Note 4—Assets Held for Sale, Sold or 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 June 30, 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.

As of June 30, 2017, we have two commercial paper programs. The ConocoPhillips $6.25 billion commercial paper program is available to fund short-term working capital needs. 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 June 30, 2017 or December 31, 2016, under the ConocoPhillips nor 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 June 30, 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

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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 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 June 30, 2017 and December 31, 2016, we had direct bank letters of credit of $265 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 11—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 June 30, 2017, was $23.5 billion, a decrease of $3.8 billion from the balance at December 31, 2016. Given the cash proceeds related to our disposition in Canada, in the second quarter we redeemed $3.0 billion of debt across the following instruments:

• 6.65% Debentures due 2018 with principal of $297 million

• 5.75% Notes due 2019 with principal of $1.7 billion (partial redemption)

• 6.00% Notes due 2020 with principal of $1.0 billion

We incurred premiums above book value to redeem the debt instruments resulting in $234 million of expense which is reported in the “Other expense” line on our consolidated income statement.

In the second quarter of 2017, we gave notice to redeem the following debt instruments totaling $1.8 billion. The prepayments will occur on August 1, 2017, and we expect to incur approximately $50 million in premiums above book value, subject to pricing, related to these redemptions when paid.

• 5.20% Notes due 2018 with principal of $500 million

• 1.50% Notes due 2018 with principal of $750 million

• 5.75% Notes due 2019 with principal of $550 million

During the first quarter of 2017, we made an $805 million prepayment of our floating rate term loan due in 2019. We prepaid the remaining $645 million balance on July 5, 2017.

On a longer-term basis our debt target is $15 billion by year-end 2019. For more information, see Note 9—Debt, in the Notes to Consolidated Financial Statements.

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At June 30, 2017, we reclassified $2.7 billion from long-term to short-term debt, including the $1.8 billion of notes and the $645 million term loan facility discussed above.

Purchase obligations, which are contractual obligations primarily related to market-based contracts in our commodity business and agreements to access and utilize the capacity of third-party equipment and facilities, are expected to be $5 billion for the full year of 2017.

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. In May 2017, we announced a quarterly dividend of $0.265 per share. The dividend was paid June 1, 2017, to stockholders of record at the close of business on May 15, 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 25.7 million shares at a cost of $1.2 billion through June 30, 2017.

Capital Expenditures

	Millions of Dollars
	Six Months Ended June 30
	2017		2016
Alaska	$	457		503
Lower 48		726		817
Canada		147		468
Europe and North Africa		412		574
Asia Pacific and Middle East		202		485
Other International		10		78
Corporate and Other		32		29
Capital expenditures and investments	$	1,986		2,954

During the first six 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; appraisal activity in Australia; and exploration activity in Malaysia.

Full-year guidance for capital expenditures has been lowered to $4.8 billion, which achieves an expanded scope of activity at lower cost.

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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 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 12—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

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costs at various sites that typically are not owned by us, but allegedly contain waste attributable to our past operations. As of June 30, 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 June 30, 2017, our balance sheet included a total environmental accrual of $188 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 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 21—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 announced dispositions (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 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 six months ended June 30, 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 June 30, 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

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that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance, Commercial and Chief Financial Officer concluded our disclosure controls and procedures were operating effectively as of June 30, 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 second 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**
April 1-30, 2017		1,574,010	$	48.91		1,574,010	$	5,685
May 1-31, 2017		7,606,302		47.03		7,606,302		5,327
June 1-30, 2017		11,750,940		44.93		11,750,940		4,799
Total		20,931,252	$	45.99		20,931,252	$	4,799

  *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†	Asset Purchase and Sale Agreement Amending Agreement, dated as of May 16, 2017, by and among ConocoPhillips Company, ConocoPhillips Canada Resources Corp., ConocoPhillips Canada Energy Partnership, ConocoPhillips Western Canada Partnership, ConocoPhillips Canada (BRC) Partnership, ConocoPhillips Canada E&P ULC, and Cenovus Energy Inc. (incorporated by reference to Exhibit 2.2 to the Current Report of ConocoPhillips on Form 8-K filed on May 18, 2017; File No. 001-32395).
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.

† The schedules to this exhibit have been omitted pursuant to Item 601(b)(2) of Regulation S-K. ConocoPhillips 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)

August 1, 2017

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