Edgar Filing: CONOCOPHILLIPS

10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934


		For the quarterly period ended		June 30, 2014

[ ]

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 [x] 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 [x] No [ ]

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

Large accelerated filer [x] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]

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

The registrant had 1,229,567,936 shares of common stock, $.01 par value, outstanding at June 30, 2014.

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		24

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29

Item 3. Quantitative and Qualitative Disclosures About Market Risk		49

Item 4. Controls and Procedures		49

Part II – Other Information		50

Item 1. Legal Proceedings		50

Item 1A. Risk Factors		50

Item 6. Exhibits		51

Signature		52

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
	2014		2013		2014		2013

Revenues and Other Income
Sales and other operating revenues	$	13,821		13,350		29,236		27,516
Equity in earnings of affiliates		672		494		1,244		856
Gain on dispositions		7		95		16		153
Other income		201		203		253		268

Total Revenues and Other Income		14,701		14,142		30,749		28,793

Costs and Expenses
Purchased commodities		5,495		5,521		12,622		11,355
Production and operating expenses		2,030		1,672		3,925		3,359
Selling, general and administrative expenses		218		193		400		358
Exploration expenses		517		321		813		598
Depreciation, depletion and amortization		2,070		1,832		3,962		3,639
Impairments		17		28		18		30
Taxes other than income taxes		612		642		1,263		1,534
Accretion on discounted liabilities		120		105		237		211
Interest and debt expense		155		139		326		269
Foreign currency transaction (gains) losses		7		(7)		25		(43)

Total Costs and Expenses		11,241		10,446		23,591		21,310

Income from continuing operations before income taxes		3,460		3,696		7,158		7,483
Provision for income taxes		1,395		1,630		2,976		3,393

Income From Continuing Operations		2,065		2,066		4,182		4,090
Income (loss) from discontinued operations*		33		(3)		53		126

Net income		2,098		2,063		4,235		4,216
Less: net income attributable to noncontrolling interests		(17)		(13)		(31)		(27)

Net Income Attributable to ConocoPhillips	$	2,081		2,050		4,204		4,189

Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	2,048		2,053		4,151		4,063
Income (loss) from discontinued operations		33		(3)		53		126

Net income	$	2,081		2,050		4,204		4,189

Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	1.65		1.66		3.36		3.30
Discontinued operations		0.03		-		0.04		0.10

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.68		1.66		3.40		3.40

Diluted
Continuing operations	$	1.64		1.65		3.34		3.28
Discontinued operations		0.03		-		0.04		0.10

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	1.67		1.65		3.38		3.38

Dividends Paid Per Share of Common Stock (dollars)	$	0.69		0.66		1.38		1.32

Average Common Shares Outstanding (in thousands)
Basic		1,236,057		1,229,773		1,235,515		1,229,504
Diluted		1,245,155		1,237,157		1,245,211		1,237,432

*Net of provision (benefit) for income taxes on discontinued operations of:	$	*(10)*		88		22		79

See Notes to Consolidated Financial Statements.


Consolidated Statement of Comprehensive Income		ConocoPhillips


	Millions of Dollars

	Three Months Ended June 30				Six Months Ended June 30

	2014		2013		2014		2013


Net Income	$	2,098		2,063		4,235		4,216
Other comprehensive income (loss)
Defined benefit plans
Reclassification adjustment for amortization of prior service credit included in net income		(1)		(2)		(3)		(3)
Net actuarial gain arising during the period		-		1		-		1
Reclassification adjustment for amortization of net actuarial losses included in net income		33		57		66		114
Nonsponsored plans*		(1)		-		5		1
Income taxes on defined benefit plans		(12)		(20)		(23)		(42)

Defined benefit plans, net of tax		19		36		45		71

Foreign currency translation adjustments		668		(1,684)		446		(2,328)
Reclassification adjustment for loss included in net income**		-		-		-		(4)
Income taxes on foreign currency translation adjustments**		9		10		5		14

Foreign currency translation adjustments, net of tax		677		(1,674)		451		(2,318)

Other Comprehensive Income (Loss), Net of Tax		696		(1,638)		496		(2,247)

Comprehensive Income		2,794		425		4,731		1,969
Less: comprehensive income attributable to noncontrolling interests		(17)		(13)		(31)		(27)

Comprehensive Income Attributable to ConocoPhillips	$	2,777		412		4,700		1,942

*Plans for which ConocoPhillips is not the primary obligor—primarily those administered by equity affiliates.

**Prior period amounts were reclassified to conform to current-period presentation.

See Notes to Consolidated Financial Statements.


Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	June 30 2014		December 31 2013

Assets
Cash and cash equivalents	$	6,142		6,246
Short-term investments*		288		272
Accounts and notes receivable (net of allowance of $8 million in 2014 and $8 million in 2013)		7,983		8,273
Accounts and notes receivable—related parties		221		214
Inventories		1,291		1,194
Prepaid expenses and other current assets		2,911		2,824

Total Current Assets		18,836		19,023
Investments and long-term receivables		24,943		23,907
Loans and advances—related parties		1,272		1,357
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $69,511 million in 2014 and $65,321 million in 2013)		75,424		72,827
Other assets		1,173		943

Total Assets	$	121,648		118,057


Liabilities
Accounts payable	$	9,192		9,250
Accounts payable—related parties		62		64
Short-term debt		1,664		589
Accrued income and other taxes		2,770		2,713
Employee benefit obligations		598		842
Other accruals		1,905		1,671

Total Current Liabilities		16,191		15,129
Long-term debt		19,570		21,073
Asset retirement obligations and accrued environmental costs		10,097		9,883
Deferred income taxes		16,007		15,220
Employee benefit obligations		2,345		2,459
Other liabilities and deferred credits		1,752		1,801

Total Liabilities		65,962		65,565


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2014—1,771,798,609 shares; 2013—1,768,169,906 shares)
Par value		18		18
Capital in excess of par		45,926		45,690
Treasury stock (at cost: 2014—542,230,673 shares; 2013—542,230,673 shares)		(36,780)		(36,780)
Accumulated other comprehensive income		2,498		2,002
Retained earnings		43,653		41,160

Total Common Stockholders’ Equity		55,315		52,090
Noncontrolling interests		371		402

Total Equity		55,686		52,492

Total Liabilities and Equity	$	121,648		118,057

*Includes marketable securities of:	$	77		135

See Notes to Consolidated Financial Statements.


Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Six Months Ended June 30
	2014			2013

Cash Flows From Operating Activities
Net income	$	4,235			4,216
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		3,962			3,639
Impairments		18			30
Dry hole costs and leasehold impairments		403			212
Accretion on discounted liabilities		237			211
Deferred taxes		633			684
Undistributed equity earnings		681			(228)
Gain on dispositions		(16	)		(153)
Income from discontinued operations		(53	)		(126)
Other		(192	)		(486)
Working capital adjustments
Decrease in accounts and notes receivable		80			659
Increase in inventories		(103	)		(179)
Increase in prepaid expenses and other current assets		(238	)		(236)
Increase in accounts payable		71			394
Increase (decrease) in taxes and other accruals		123			(340)

Net cash provided by continuing operating activities		9,841			8,297
Net cash provided by discontinued operations		117			174

Net Cash Provided by Operating Activities		9,958			8,471


Cash Flows From Investing Activities
Capital expenditures and investments		(8,141	)		(7,096)
Proceeds from asset dispositions		63			1,676
Net purchases of short-term investments		(8	)		(74)
Collection of advances/loans—related parties		77			71
Other		96			(46)

Net cash used in continuing investing activities		(7,913	)		(5,469)
Net cash used in discontinued operations		(50	)		(379)

Net Cash Used in Investing Activities		(7,963	)		(5,848)


Cash Flows From Financing Activities
Repayment of debt		(450	)		(898)
Change in restricted cash		-			748
Issuance of company common stock		46			(5)
Dividends paid		(1,711	)		(1,629)
Other		(28	)		(391)

Net cash used in continuing financing activities		(2,143	)		(2,175)
Net cash used in discontinued operations		-			-

Net Cash Used in Financing Activities		(2,143	)		(2,175)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		44			(157)


Net Change in Cash and Cash Equivalents		(104	)		291
Cash and cash equivalents at beginning of period		6,246			3,618

Cash and Cash Equivalents at End of Period	$	6,142			3,909

See Notes to Consolidated Financial Statements.


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 2013 Annual Report on Form 10-K.

Effective April 1, 2014, the Other International segment has been restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, the Latin America and Poland businesses have been moved from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Certain financial information has been revised for all prior periods presented to reflect the change in the composition of our operating segments. For additional information, see Note 17—Segment Disclosures and Related Information.

The results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algeria and Nigeria businesses have been classified as discontinued operations for all periods presented. See Note 2—Discontinued Operations, for additional information. Unless indicated otherwise, the information in the Notes to Consolidated Financial Statements relates to our continuing operations.

Note 2—Discontinued Operations

As part of our asset disposition program, we agreed to sell our interest in Kashagan and our Algeria and Nigeria businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment. We completed the sales of Kashagan and our Algeria business in the fourth quarter of 2013.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business. This originally included our upstream affiliates and Phillips (Brass) Limited, which owned a 17 percent interest in the Brass LNG Project. On July 30, 2014, we completed the sale of the upstream assets for a total sales price, after customary adjustments, of $1.5 billion, generating net proceeds of approximately $1.4 billion, after customary adjustments, inclusive of deposits previously received and less cash in the business at closing. In addition, we received a $33 million short-term promissory note. We received deposits of $550 million as of June 30, 2014, which included $435 million in 2012, $15 million in 2013, and $100 million in 2014. As of June 30, 2014, the net carrying value of our Nigerian upstream assets was $259 million.

In the first quarter of 2014, we and Oando agreed to terminate the sales agreement for Phillips (Brass) Limited. In July 2014, we transferred our interest in the Brass LNG Project to the remaining shareholders in Brass LNG Limited. The financial impact of the transfer was recorded in the second quarter of 2014 and did not have a material effect on our consolidated financial statements.

At June 30, 2014, our interest in the Nigeria business was considered held for sale, and accordingly, we classified $1,203 million of noncurrent assets in the “Prepaid expenses and other current assets” line on our consolidated balance sheet. In addition, we classified $811 million of deferred income taxes in the “Accrued income and other taxes” line and $14 million of asset retirement obligations in the “Other accruals” line on our consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group were as follows:


	Millions of Dollars
	June 30 2014		December 31 2013

Assets
Accounts and notes receivable	$	202		376
Inventories		3		9
Prepaid expenses and other current assets		79		72

Total current assets of discontinued operations		284		457
Investments and long-term receivables		-		60
Loans and advances—related parties		-		7
Net properties, plants and equipment		1,202		1,154
Other assets		1		1

Total assets of discontinued operations	$	1,487		1,679


Liabilities
Accounts payable	$	291		419
Accrued income and other taxes		112		72

Total current liabilities of discontinued operations		403		491
Asset retirement obligations and accrued environmental costs		14		14
Deferred income taxes		811		765

Total liabilities of discontinued operations	$	1,228		1,270

Sales and other operating revenues and income from discontinued operations related to the Disposition Group were as follows:


	Millions of Dollars
	Three Months Ended June 30					Six Months Ended June 30
	2014			2013		2014		2013


Sales and other operating revenues from discontinued operations	$	161			210		319		539


Income from discontinued operations before-tax	$	23			85		75		205
Income tax expense (benefit)		(10	)		88		22		79

Income (loss) from discontinued operations	$	33			(3)		53		126

Note 3—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:

Freeport LNG Development, L.P. (Freeport LNG)

We have an agreement with Freeport LNG to participate in an LNG receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which expires in 2033. When the terminal became operational in June 2008, we began making payments under the terminal use agreement. At June 30, 2014, the prepaid balance of the terminal use agreement was $305 million, which is primarily reflected in the “Other assets” line on our consolidated balance sheet. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $476 million at June 30, 2014, and $506 million at December 31, 2013.

In July 2013, we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. In July 2014, Freeport LNG received conditional approval from the Federal Energy Regulatory Commission (FERC). Upon satisfaction of their project financing conditions and receipt of FERC’s permission to construct, currently expected to occur in the fourth quarter of 2014, we will pay Freeport LNG a termination fee of approximately $520 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. When the agreement becomes effective, we expect to recognize an after-tax charge to earnings of approximately $520 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero.

Freeport LNG is a VIE because Freeport GP holds no equity in Freeport LNG, and the limited partners of Freeport LNG do not have any substantive decision making ability. Since we do not have the unilateral power to direct the key activities which most significantly impact its economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the terminal. We also performed an analysis of the expected losses and determined we are not the primary beneficiary. This expected loss analysis took into account that the credit support arrangement requires Freeport LNG to maintain sufficient commercial insurance to mitigate any loan losses. The loan to Freeport LNG is accounted for as a financial asset, and our investment in Freeport GP is accounted for as an equity method investment.

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 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, 2014, 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 9—Guarantees, for additional information.

Note 4—Inventories

Inventories consisted of the following:


	Millions of Dollars
	June 30 2014		December 31 2013


Crude oil and natural gas	$	490		452
Materials, supplies and other		801		742

	$	1,291		1,194

Inventories valued on the last-in, first-out (LIFO) basis totaled $346 million and $343 million at June 30, 2014 and December 31, 2013, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $180 million and $160 million at June 30, 2014, and December 31, 2013, respectively.

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. At June 30, 2014, $7.8 billion had been drawn from 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. See Note 9—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 3—Variable Interest Entities (VIEs), for additional information.

At June 30, 2014, the book value of our equity method investment in APLNG was $12,470 million, which included $1,694 million of cumulative translation effects due to strengthening of the Australian dollar relative to the U.S. dollar over time, and is included in the “Investments and long-term receivables” line on our consolidated balance sheet.

FCCL

In the first quarter of 2014, we received a $1.3 billion distribution from FCCL Partnership, our 50 percent owned business venture with Cenovus Energy Inc., which is included in the “Undistributed equity earnings” line on our consolidated statement of cash flows.

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. Significant loans to affiliated companies at June 30, 2014, included the following:

—

$476 million in loan financing to Freeport LNG. See Note 3—Variable Interest Entities (VIEs), for additional information.

—

$959 million in project financing to Qatar Liquefied Gas Company Limited (3) (QG3).

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

Note 6—Suspended Wells and Unproved Property Impairments

The capitalized cost of suspended wells at June 30, 2014, was $1,261 million, an increase of $267 million from $994 million at year-end 2013. No suspended wells were charged to dry hole expense during the first six months of 2014 relating to exploratory well costs capitalized for a period greater than one year as of December 31, 2013.

In June 2014, we decided not to pursue future development of the Amauligak discovery at this time. Accordingly, we recorded a $145 million before-tax property impairment for the carrying value of capitalized undeveloped leasehold costs associated with our Amauligak, Arctic Islands and other Beaufort properties, located offshore Canada. The impairment is included in the “Exploration expenses” line on our consolidated income statement.

Note 7—Debt

On June 23, 2014, we refinanced our revolving credit facility from a total of $7.5 billion to $7.0 billion, with a new expiration date of June 2019. Our revolving credit facility may be used for direct bank borrowings, for 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 as administered by ICE Benchmark Administration 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.

We have two commercial paper programs supported by our $7.0 billion revolving credit facility: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.15 billion program, which is used to fund commitments relating to QG3. Commercial paper maturities are generally limited to 90 days.

At June 30, 2014 and December 31, 2013, we had no direct outstanding borrowings under the revolving credit facility, with no letters of credit as of June 30, 2014 or December 31, 2013. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $912 million of commercial paper outstanding at June 30, 2014, compared with $961 million at December 31, 2013. Since we had $912 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at June 30, 2014.

At June 30, 2014, we classified $808 million of short-term debt as long-term debt, based on our ability and intent to refinance the obligation on a long-term basis under our revolving credit facility.

During the first six months of 2014, we repaid at maturity the aggregate principal amount of our $400 million 4.75% Notes due 2014.

During 2013, a lease of a semi-submersible floating production system (FPS) commenced for the Gumusut development, located in Malaysia, in which we are a co-venturer. As of June 30, 2014, the value of the capital lease asset and associated obligation for our proportionate interest in the FPS was $916 million with commissioning activities continuing. Following the startup of the FPS, the capital lease asset will be depreciated over a period consistent with the estimated proved reserves of Gumusut using the unit-of-production method with the associated depreciation included in the “Depreciation, depletion and amortization” line on our consolidated income statement.

Note 8—Noncontrolling Interests

Activity attributable to common stockholders’ equity and noncontrolling interests for the first six months of 2014 and 2013 was as follows:


	Millions of Dollars
	2014						2013
	Common Stockholders’ Equity		Non- Controlling Interest		Total Equity		Common Stockholders’ Equity		Non- Controlling Interest		Total Equity


Balance at January 1	$	52,090		402		52,492		47,987		440		48,427
Net income		4,204		31		4,235		4,189		27		4,216
Dividends		(1,711)		-		(1,711)		(1,629)		-		(1,629)
Distributions to noncontrolling interests		-		(62)		(62)		-		(43)		(43)
Other changes, net*		732		-		732		(2,039)		-		(2,039)

Balance at June 30	$	55,315		371		55,686		48,508		424		48,932

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

Note 9—Guarantees

At June 30, 2014, 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 either because the guarantees were issued prior to December 31, 2002, or because the fair value of the obligation is immaterial. In addition, unless otherwise stated, we are not currently performing with any significance under the guarantees and expect future performance to be either immaterial or have only a remote chance of occurrence.

APLNG Guarantees

At June 30, 2014, we have 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 2014 exchange rates:

—

We have guaranteed APLNG’s performance with regard to a construction contract executed in connection with APLNG’s issuance of the Train 1 and Train 2 Notices to Proceed. We estimate the remaining term of this guarantee is three years. Our maximum potential amount of future payments related to this guarantee is approximately $120 million and would become payable if APLNG cancels the applicable construction contract and does not perform with respect to the amounts owed to the contractor.

—

We have issued a construction completion guarantee related to the third-party project financing secured by APLNG. Our maximum potential amount of future payments under the guarantee is estimated to be $3.2 billion, which could be payable if the full debt financing capacity is utilized and completion of the project is not achieved. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones, which we estimate would occur beginning in 2016. Our maximum exposure at June 30, 2014, is approximately $2.9 billion based upon our pro-rata share of the facility used at that date. At June 30, 2014, the carrying value of this guarantee is $114 million.

—

In conjunction with our original acquisition of an ownership interest in APLNG in October 2008, we agreed to guarantee an existing obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 2 to 17 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $0.8 billion (approximately $2.0 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 31 years or the life of the venture. Our maximum potential amount of future payments related to these guarantees is approximately $210 million and would become payable if APLNG does not perform.

Other Guarantees

We have other guarantees with maximum future potential payment amounts totaling approximately $250 million, which consist primarily of guarantees of the residual value of leased corporate aircraft, guarantees to fund the short-term cash liquidity deficit of two joint ventures, a guarantee for our portion of a joint venture’s debt obligations and a guarantee of minimum charter revenue for an LNG vessel. These guarantees have remaining terms of up to 10 years or the life of the venture 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 non-performance of contractual terms by guaranteed parties.

Indemnifications

Over the years, we have entered into agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. These agreements include indemnifications for taxes, environmental liabilities, employee claims, and litigation. The terms of these indemnifications vary greatly. The majority of these indemnifications are related to environmental issues, the term is generally indefinite and the maximum amount of future payments is generally unlimited. The carrying amount recorded for these indemnifications at June 30, 2014, was approximately $70 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, 2014, were approximately $50 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 10—Contingencies and Commitments.

established procedures for handling claims subject to indemnification and related matters. We evaluated the impact of the indemnifications given and the Phillips 66 indemnifications received as of the separation date and concluded those fair values were immaterial.

Note 10—Contingencies and Commitments

A number of lawsuits involving a variety of claims arising in the ordinary course of business have been made 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.

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, 2014, our balance sheet included a total environmental accrual of $378 million, compared with $348 million at December 31, 2013, for remediation activities in the United States and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years. We have not reduced these accruals for possible insurance recoveries. 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 underpayments on certain Federal, State and privately owned properties and claims of alleged environmental contamination from historic operations. We will continue to defend ourselves vigorously in these matters.

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

Other Contingencies

We have contingent liabilities resulting from throughput agreements with pipeline and processing companies not associated with financing arrangements. Under these agreements, we may be required to provide any such company with additional funds through advances and penalties for fees related to throughput capacity not utilized. In addition, at June 30, 2014, we had performance obligations secured by letters of credit of $638 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. A separate arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Venezuela’s actions.

In 2008, Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, initiated arbitration before ICSID against The Republic of Ecuador, as a result of the newly enacted Windfall Profits Tax Law and government-mandated renegotiation of our production sharing contracts. Despite a restraining order issued by the ICSID tribunal, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the seized crude oil. In 2009, Ecuador took over operations in Blocks 7 and 21, fully expropriating our assets. In June 2010, the ICSID tribunal concluded it has jurisdiction to hear the expropriation claim. On April 24, 2012, Ecuador filed supplemental counterclaims asserting environmental damages, which we believe are not material. The ICSID tribunal issued a decision on liability on December 14, 2012, in favor of Burlington,

finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase is currently proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. As of June 2014, ConocoPhillips paid, under protest, tax assessments totaling approximately $236 million, which are primarily recorded in the “Investments and long-term receivables” line on our consolidated balance sheet. The arbitration hearing was conducted in Singapore in June 2014 under the United Nations Commission on International Trade Laws (UNCITRAL) arbitration rules, pursuant to the terms of the Tax Stability Agreement with the Timor-Leste government. Post-hearing briefs from both parties are due in August 2014. Subsequently, we will be awaiting the Tribunal’s decision. Future impacts on our business are not known at this time.

Note 11—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 the 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 2014		December 31 2013

Assets
Prepaid expenses and other current assets	$	1,189		871
Other assets		81		64
Liabilities
Other accruals		1,162		890
Other liabilities and deferred credits		74		58

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
	2014		2013		2014		2013


Sales and other operating revenues	$	184		25		421		(183)
Other income		1		1		2		3
Purchased commodities		(163)		(14)		(384)		171

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


	Open Position Long/(Short)
	June 30 2014		December 31 2013

Commodity
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(48)		(18)
Basis		(5)		(10)

Foreign Currency Exchange Derivatives

We have foreign currency exchange rate risk resulting from international operations. Our foreign currency exchange derivative activity primarily consists of transactions designed to mitigate 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 2014		December 31 2013

Assets
Prepaid expenses and other current assets	$	7		1

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

2014

2013

2014

2013

Foreign currency transaction (gains) losses

(7)

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


	In Millions Notional Currency
		June 30 2014		December 31 2013


Buy U.S. dollar, sell other currencies*	USD		460		6
Buy British pound, sell euro	GBP		41		17

*Primarily Canadian dollar and Norwegian krone.

Financial Instruments

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


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments
	June 30 2014		December 31 2013		June 30 2014		December 31 2013


Cash	$	812		636		-		-
Money Market Funds		400		-		-		-
Time deposits
Remaining maturities from 1 to 90 days		4,570		5,336		188		137
Remaining maturities from 91 to 180 days		-		-		23		-
Commercial paper
Remaining maturities from 1 to 90 days		360		274		77		135

	$	6,142		6,246		288		272

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 us.

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

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on June 30, 2014 and December 31, 2013, was $135 million and $57 million, respectively. For these instruments, no collateral was posted as of June 30, 2014 or December 31, 2013. If our credit rating had been lowered one level from its “A” rating (per Standard and Poor’s) on June 30, 2014, we would be required to post no additional collateral to our counterparties. If we had been downgraded below investment grade, we would be required to post $135 million of additional collateral, either with cash or letters of credit.

Note 12—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 that are 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 2014 or 2013.

Recurring Fair Value Measurement

Financial assets and liabilities reported at fair value on a recurring basis primarily include commodity derivatives and certain investments to support nonqualified deferred compensation plans. The deferred compensation investments are measured at fair value using unadjusted prices available from national securities exchanges; therefore, these assets are categorized as Level 1 in the fair value hierarchy. 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. Level 3 derivative assets and liabilities consist of OTC swaps, options and forward purchase and sale contracts that are long term in nature and where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value. Level 3 activity was not material for all periods presented.

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


	Millions of Dollars
	June 30, 2014								December 31, 2013

	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total

Assets
Deferred compensation investments	$	311		-		-		311		306		-		-		306
Commodity derivatives		855		403		12		1,270		744		177		10		931

Total assets	$	1,166		403		12		1,581		1,050		177		10		1,237


Liabilities
Commodity derivatives	$	823		402		11		1,236		765		172		7		944

Total liabilities	$	823		402		11		1,236		765		172		7		944

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 offset 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, 2014
Assets	$	1,270		1,046		224		15		41		168
Liabilities		1,236		1,046		190		1		48		141


December 31, 2013
Assets	$	931		827		104		6		12		86
Liabilities		944		827		117		26		9		82

At June 30, 2014 and December 31, 2013, we did not present any amounts gross on our consolidated balance sheet where we had the right of setoff.

Reported Fair Values of Financial Instruments

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

—

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

—

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

—

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
2014

December 31
2013

June 30
2014

December 31
2013

Financial assets

Deferred compensation investments

311

306

311

306

Commodity derivatives

209

Total loans and advances—related parties

1,444

1,528

1,588

1,680

Financial liabilities

Total debt, excluding capital leases

20,279

20,740

23,889

23,553

Commodity derivatives

189

Note 13—Accumulated Other Comprehensive Income

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

Millions of Dollars

Defined
Benefit Plans

Foreign
Currency
Translation

Accumulated
Other
Comprehensive
Income

December 31, 2013

(824)

2,826

2,002

Other comprehensive income

451

496

June 30, 2014

(779)

3,277

2,498

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

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


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30

	2014		2013		2014		2013

Defined Benefit Plans	$	20		36		40		71

Above amounts are included in the computation of net periodic benefit cost and are presented net of tax expense of:	$	12		20		23		42

See Note 15—Employee Benefit Plans, for additional information.

Note 14—Cash Flow Information


	Millions of Dollars
	Six Months Ended June 30
	2014		2013

Cash Payments
Interest	$	311		259
Income taxes		2,321		2,861


Net Sales (Purchases) of Short-Term Investments
Short-term investments purchased	$	(492)		(97)
Short-term investments sold		484		23

	$	(8)		(74)

Note 15—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits								Other Benefits
	2014				2013				2014		2013
	U.S.		Int’l.		U.S.		Int’l.

Components of Net Periodic Benefit Cost
Three Months Ended June 30
Service cost	$	31		28		34		25		-		1
Interest cost		41		42		36		36		7		6
Expected return on plan assets		(53)		(46)		(46)		(39)		-		-
Amortization of prior service cost (credit)		2		(2)		1		(2)		(1)		(1)
Recognized net actuarial loss		19		14		38		18		-		1

Net periodic benefit cost	$	40		36		63		38		6		7


Six Months Ended June 30
Service cost	$	62		56		69		51		1		2
Interest cost		82		84		72		73		14		12
Expected return on plan assets		(106)		(92)		(93)		(80)		-		-
Amortization of prior service cost (credit)		3		(4)		3		(4)		(2)		(2)
Recognized net actuarial loss (gain)		38		29		75		37		(1)		2

Net periodic benefit cost	$	79		73		126		77		12		14

During the first six months of 2014, we contributed $208 million to our domestic benefit plans and $67 million to our international benefit plans.

Note 16—Related Party Transactions

We consider our equity method investments to be related parties. Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Operating revenues and other income	$	36		31		57		39
Purchases		52		49		100		90
Operating expenses and selling, general and administrative expenses		52		43		104		89
Net interest (income) expense*		(12)		7		(24)		16

*	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 17—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, Asia Pacific and Middle East, and Other International.

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial statements, and the impact on our segment presentation was immaterial.

In 2012, we agreed to sell our Nigeria and Algeria businesses and our interest in Kashagan. We sold Kashagan and our Algeria business in the fourth quarter of 2013. Results for the Disposition Group have been reported as discontinued operations in all periods presented. For additional information, see Note 2—Discontinued Operations.

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 attributable to ConocoPhillips. Intersegment sales are at prices that approximate market.

Analysis of Results by Operating Segment


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013

Sales and Other Operating Revenues
Alaska	$	2,407		2,169		4,593		4,273

Lower 48		5,530		4,901		12,114		9,723
Intersegment eliminations		(22)		(26)		(60)		(55)

Lower 48		5,508		4,875		12,054		9,668

Canada		1,168		1,405		3,027		2,660
Intersegment eliminations		(145)		(155)		(490)		(313)

Canada		1,023		1,250		2,537		2,347

Europe		2,745		2,408		5,954		5,861
Intersegment eliminations		(44)		-		(44)		-

Europe		2,701		2,408		5,910		5,861

Asia Pacific and Middle East		2,151		2,086		4,100		4,304
Other International		3		457		5		940
Corporate and Other		28		105		37		123

Consolidated sales and other operating revenues	$	13,821		13,350		29,236		27,516


Net Income Attributable to ConocoPhillips
Alaska	$	627		682		1,225		1,225
Lower 48		265		233		589		338
Canada		182		5		538		138
Europe		259		263		606		717
Asia Pacific and Middle East		845		1,017		1,587		1,935
Other International		121		26		92		45
Corporate and Other		(251)		(173)		(486)		(335)
Discontinued operations		33		(3)		53		126

Consolidated net income attributable to ConocoPhillips	$	2,081		2,050		4,204		4,189


	Millions of Dollars
	June 30 2014		December 31 2013

Total Assets
Alaska	$	12,602		11,662
Lower 48		30,367		29,552
Canada		22,195		22,394
Europe		17,575		17,223
Asia Pacific and Middle East		27,033		25,473
Other International		1,954		1,705
Corporate and Other		8,433		8,367
Discontinued operations		1,489		1,681

Consolidated total assets	$	121,648		118,057

Note 18—Income Taxes

Our effective tax rates from continuing operations for the second quarter and first six months of 2014 were 40 percent and 42 percent, respectively, compared with 44 percent and 45 percent for the same periods of 2013. The lower rates were primarily due to a smaller proportion of income in higher tax jurisdictions in 2014. The effective tax rate for the first six months of 2013 was favorably impacted by the tax resolution associated with the sale of certain western Canada properties which occurred in a prior year.

For both the second quarter and the first six months of 2014, the effective tax rate in excess of the domestic federal statutory rate of 35 percent was primarily due to foreign taxes.

Note 19—New Accounting Standards

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2014-09, “Revenue from Contracts with Customers,” 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 Accounting Standards Codification (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. The ASU is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. Entities may choose to adopt the standard using either a full retrospective approach or a modified retrospective approach. We are currently evaluating the impact of the adoption of this ASU.

Supplementary Information—Condensed Consolidating Financial Information

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

—

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

—

All other nonguarantor subsidiaries of ConocoPhillips.

—

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

During 2013, ConocoPhillips Australia Funding Company’s guaranteed, publicly held debt was repaid. Beginning in the first quarter of 2014, financial information for ConocoPhillips Australia Funding Company was presented in the “All Other Subsidiaries” column of our condensed consolidating financial information.

In April 2014, ConocoPhillips received a $32 billion dividend from ConocoPhillips Company to settle certain accumulated intercompany balances. This consisted of a $15 billion distribution of earnings and a $17 billion return of capital. The transaction was reflected in the second quarter 2014 Condensed Consolidating Financial Information for ConocoPhillips and ConocoPhillips Company and 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.


	Millions of Dollars
	Three Months Ended June 30, 2014
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	$	-		5,105		-		8,716		-		13,821
Equity in earnings of affiliates		2,119		2,514		-		539		(4,500)		672
Gain on dispositions		-		2		-		5		-		7
Other income		-		27		-		174		-		201
Intercompany revenues		19		111		71		1,598		(1,799)		-

Total Revenues and Other Income		2,138		7,759		71		11,032		(6,299)		14,701


Costs and Expenses
Purchased commodities		-		4,431		-		2,631		(1,567)		5,495
Production and operating expenses		-		481		-		1,596		(47)		2,030
Selling, general and administrative expenses		3		156		-		59		-		218
Exploration expenses		-		238		-		279		-		517
Depreciation, depletion and amortization		-		261		-		1,809		-		2,070
Impairments		-		17		-		-		-		17
Taxes other than income taxes		-		71		-		541		-		612
Accretion on discounted liabilities		-		15		-		105		-		120
Interest and debt expense		148		62		58		72		(185)		155
Foreign currency transaction (gains) losses		(22)		2		151		(124)		-		7

Total Costs and Expenses		129		5,734		209		6,968		(1,799)		11,241

Income (loss) from continuing operations before income taxes		2,009		2,025		(138)		4,064		(4,500)		3,460
Provision (benefit) for income taxes		(39)		(94)		(4)		1,532		-		1,395

Income (Loss) From Continuing Operations		2,048		2,119		(134)		2,532		(4,500)		2,065
Income from discontinued operations		33		33		-		33		(66)		33

Net income (loss)		2,081		2,152		(134)		2,565		(4,566)		2,098
Less: net income attributable to noncontrolling interests		-		-		-		(17)		-		(17)

Net Income (Loss) Attributable to ConocoPhillips	$	2,081		2,152		(134)		2,548		(4,566)		2,081


Comprehensive Income (Loss) Attributable to ConocoPhillips	$	2,777		2,848		(14)		3,220		(6,054)		2,777


	Millions of Dollars
	Three Months Ended June 30, 2013
Income Statement	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated

Revenues and Other Income
Sales and other operating revenues	$	-		4,622		-		-		8,728		-		13,350
Equity in earnings of affiliates*		2,159		2,314		-		-		682		(4,661)		494
Gain on dispositions		-		3		-		-		92		-		95
Other income		-		163		-		-		40		-		203
Intercompany revenues*		21		110		2		76		1,226		(1,435)		-

Total Revenues and Other Income		2,180		7,212		2		76		10,768		(6,096)		14,142


Costs and Expenses
Purchased commodities		-		3,980		-		-		2,756		(1,215)		5,521
Production and operating expenses		-		405		-		-		1,285		(18)		1,672
Selling, general and administrative expenses		2		128		-		-		63		-		193
Exploration expenses		-		190		-		-		131		-		321
Depreciation, depletion and amortization		-		220		-		-		1,612		-		1,832
Impairments		-		-		-		-		28		-		28
Taxes other than income taxes		-		48		-		-		594		-		642
Accretion on discounted liabilities		-		14		-		-		91		-		105
Interest and debt expense*		157		79		2		59		44		(202)		139
Foreign currency transaction (gains) losses		24		1		-		(183)		151		-		(7)

Total Costs and Expenses		183		5,065		2		(124)		6,755		(1,435)		10,446

Income from continuing operations before income taxes		1,997		2,147		-		200		4,013		(4,661)		3,696
Provision (benefit) for income taxes		(56)		(12)		-		16		1,682		-		1,630

Income From Continuing Operations		2,053		2,159		-		184		2,331		(4,661)		2,066
Loss from discontinued operations		(3)		(3)		-		-		(3)		6		(3)

Net income		2,050		2,156		-		184		2,328		(4,655)		2,063
Less: net income attributable to noncontrolling interests		-		-		-		-		(13)		-		(13)

Net Income Attributable to ConocoPhillips	$	2,050		2,156		-		184		2,315		(4,655)		2,050


Comprehensive Income Attributable to ConocoPhillips	$	412		518		-		54		650		(1,222)		412

“Interest and debt expense” for ConocoPhillips was revised to reflect contractually agreed interest rates, with offsetting adjustments in the “Equity in earnings of affiliates” and “Intercompany revenues” lines for ConocoPhillips, ConocoPhillips Company and All Other Subsidiaries. There was no impact to Total Consolidated balances.


			Millions of Dollars
			Six Months Ended June 30, 2014
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			$	-		11,248		-		17,988		-		29,236
Equity in earnings of affiliates				4,331		4,965		-		1,260		(9,312)		1,244
Gain on dispositions				-		1		-		15		-		16
Other income				-		45		-		208		-		253
Intercompany revenues				39		265		142		3,241		(3,687)		-

Total Revenues and Other Income				4,370		16,524		142		22,712		(12,999)		30,749


Costs and Expenses
Purchased commodities				-		9,948		-		5,921		(3,247)		12,622
Production and operating expenses				-		841		-		3,134		(50)		3,925
Selling, general and administrative expenses				6		280		-		128		(14)		400
Exploration expenses				-		382		-		431		-		813
Depreciation, depletion and amortization				-		503		-		3,459		-		3,962
Impairments				-		18		-		-		-		18
Taxes other than income taxes				-		164		-		1,099		-		1,263
Accretion on discounted liabilities				-		29		-		208		-		237
Interest and debt expense				307		132		116		147		(376)		326
Foreign currency transaction (gains) losses				3		2		12		8		-		25

Total Costs and Expenses				316		12,299		128		14,535		(3,687)		23,591

Income from continuing operations before income taxes				4,054		4,225		14		8,177		(9,312)		7,158
Provision (benefit) for income taxes				(97)		(106)		(2)		3,181		-		2,976

Income From Continuing Operations				4,151		4,331		16		4,996		(9,312)		4,182
Income from discontinued operations				53		53		-		53		(106)		53

Net income				4,204		4,384		16		5,049		(9,418)		4,235
Less: net income attributable to noncontrolling interests				-		-		-		(31)		-		(31)

Net Income Attributable to ConocoPhillips			$	4,204		4,384		16		5,018		(9,418)		4,204


Comprehensive Income (Loss) Attributable to ConocoPhillips			$	4,700		4,880		(5)		5,475		(10,350)		4,700


	Millions of Dollars
	Six Months Ended June 30, 2013
Income Statement	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated


Revenues and Other Income
Sales and other operating revenues	$	-		9,085		-		-		18,431		-		27,516
Equity in earnings of affiliates*		4,269		4,686		-		-		1,156		(9,255)		856
Gain on dispositions		-		1		-		-		152		-		153
Other income		1		208		-		-		59		-		268
Intercompany revenues*		41		235		13		154		2,385		(2,828)		-

Total Revenues and Other Income		4,311		14,215		13		154		22,183		(12,083)		28,793


Costs and Expenses
Purchased commodities		-		7,908		-		-		5,821		(2,374)		11,355
Production and operating expenses		-		721		-		-		2,658		(20)		3,359
Selling, general and administrative expenses		6		250		-		-		120		(18)		358
Exploration expenses		-		333		-		-		265		-		598
Depreciation, depletion and amortization		-		429		-		-		3,210		-		3,639
Impairments		-		-		-		-		30		-		30
Taxes other than income taxes		-		125		-		-		1,409		-		1,534
Accretion on discounted liabilities		-		28		-		-		183		-		211
Interest and debt expense*		311		160		12		118		84		(416)		269
Foreign currency transaction (gains) losses		41		9		-		(281)		188		-		(43)

Total Costs and Expenses		358		9,963		12		(163)		13,968		(2,828)		21,310

Income from continuing operations before income taxes		3,953		4,252		1		317		8,215		(9,255)		7,483
Provision (benefit) for income taxes		(110)		(17)		-		21		3,499		-		3,393

Income From Continuing Operations		4,063		4,269		1		296		4,716		(9,255)		4,090
Income from discontinued operations		126		126		-		-		126		(252)		126

Net income		4,189		4,395		1		296		4,842		(9,507)		4,216
Less: net income attributable to noncontrolling interests		-		-		-		-		(27)		-		(27)

Net Income Attributable to ConocoPhillips	$	4,189		4,395		1		296		4,815		(9,507)		4,189


Comprehensive Income Attributable to ConocoPhillips	$	1,942		2,148		1		71		2,535		(4,755)		1,942


*“Interest and debt expense” for ConocoPhillips was revised to reflect contractually agreed interest rates, with offsetting adjustments in the “Equity in earnings of affiliates” and “Intercompany revenues” lines for ConocoPhillips, ConocoPhillips Company and All Other Subsidiaries. There was no impact to Total Consolidated balances.


	Millions of Dollars
	June 30, 2014
Balance Sheet	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated

Assets
Cash and cash equivalents	$	-		1,601		260		4,281		-		6,142
Short-term investments		-		-		-		288		-		288
Accounts and notes receivable		11		3,060		22		7,980		(2,869)		8,204
Inventories		-		128		-		1,163		-		1,291
Prepaid expenses and other current assets		17		493		7		2,442		(48)		2,911

Total Current Assets		28		5,282		289		16,154		(2,917)		18,836
Investments, loans and long-term receivables*		59,711		75,553		4,238		38,051		(151,338)		26,215
Net properties, plants and equipment		-		9,606		-		65,818		-		75,424
Other assets		42		277		118		1,611		(875)		1,173

Total Assets	$	59,781		90,718		4,645		121,634		(155,130)		121,648


Liabilities and Stockholders’ Equity
Accounts payable	$	-		4,222		4		7,897		(2,869)		9,254
Short-term debt		1,501		6		5		152		-		1,664
Accrued income and other taxes		-		62		-		2,708		-		2,770
Employee benefit obligations		-		406		-		192		-		598
Other accruals		202		755		81		915		(48)		1,905

Total Current Liabilities		1,703		5,451		90		11,864		(2,917)		16,191
Long-term debt		7,538		5,206		2,977		3,849		-		19,570
Asset retirement obligations and accrued environmental costs		-		1,324		-		8,773		-		10,097
Deferred income taxes		-		598		-		15,414		(5)		16,007
Employee benefit obligations		-		1,713		-		632		-		2,345
Other liabilities and deferred credits*		1,785		11,780		1,631		21,585		(35,029)		1,752

Total Liabilities		11,026		26,072		4,698		62,117		(37,951)		65,962
Retained earnings		37,132		21,094		(1,484)		17,384		(30,473)		43,653
Other common stockholders’ equity		11,623		43,552		1,431		41,762		(86,706)		11,662
Noncontrolling interests		-		-		-		371		-		371

Total Liabilities and Stockholders’ Equity	$	59,781		90,718		4,645		121,634		(155,130)		121,648

*Includes intercompany loans.


	Millions of Dollars
	December 31, 2013
Balance Sheet	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated

Assets
Cash and cash equivalents	$	-		2,434		-		229		3,583		-		6,246
Short-term investments		-		-		-		-		272		-		272
Accounts and notes receivable		73		2,122		2		-		9,267		(2,977)		8,487
Inventories		-		174		-		-		1,020		-		1,194
Prepaid expenses and other current assets		20		535		-		35		2,311		(77)		2,824

Total Current Assets		93		5,265		2		264		16,453		(3,054)		19,023
Investments, loans and long-term receivables*		86,836		100,052		-		4,259		34,795		(200,678)		25,264
Net properties, plants and equipment		-		9,313		-		-		63,514		-		72,827
Other assets		38		260		-		103		1,394		(852)		943

Total Assets	$	86,967		114,890		2		4,626		116,156		(204,584)		118,057


Liabilities and Stockholders’ Equity
Accounts payable	$	-		3,388		-		4		8,899		(2,977)		9,314
Short-term debt		395		4		-		5		185		-		589
Accrued income and other taxes		-		223		-		-		2,517		(27)		2,713
Employee benefit obligations		-		566		-		-		276		-		842
Other accruals		210		639		-		81		790		(49)		1,671

Total Current Liabilities		605		4,820		-		90		12,667		(3,053)		15,129
Long-term debt		9,047		5,208		-		2,980		3,838		-		21,073
Asset retirement obligations and accrued environmental costs		-		1,289		-		-		8,594		-		9,883
Deferred income taxes		94		557		-		-		14,569		-		15,220
Employee benefit obligations		-		1,791		-		-		668		-		2,459
Other liabilities and deferred credits*		31,693		9,422		-		1,603		22,204		(63,121)		1,801

Total Liabilities		41,439		23,087		-		4,673		62,540		(66,174)		65,565
Retained earnings		34,636		31,835		-		(1,500)		12,848		(36,659)		41,160
Other common stockholders’ equity		10,892		59,968		2		1,453		40,366		(101,751)		10,930
Noncontrolling interests		-		-		-		-		402		-		402

Total Liabilities and Stockholders’ Equity	$	86,967		114,890		2		4,626		116,156		(204,584)		118,057

*Includes intercompany loans.


			Millions of Dollars
Statement of Cash Flows			Six Months Ended June 30, 2014
			ConocoPhillips		ConocoPhillips Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated
Cash Flows From Operating Activities
Net cash provided by continuing operating activities			$	14,876		95		31		9,912		(15,073)		9,841
Net cash provided by discontinued operations				-		170		-		219		(272)		117

Net Cash Provided by Operating Activities				14,876		265		31		10,131		(15,345)		9,958


Cash Flows From Investing Activities
Capital expenditures and investments				-		(1,981)		-		(7,106)		946		(8,141)
Proceeds from asset dispositions				16,912		13		-		60		(16,922)		63
Net sales of short-term investments				-		-		-		(8)		-		(8)
Long-term advances/loans—related parties				-		(546)		-		(7)		553		-
Collection of advances/loans—related parties				-		30		-		47		-		77
Intercompany cash management				(29,908)		33,248		-		(3,340)		-		-
Other				-		103		-		(7)		-		96

Net cash provided by (used in) continuing investing activities				(12,996)		30,867		-		(10,361)		(15,423)		(7,913)
Net cash used in discontinued operations				-		(1)		-		(50)		1		(50)

Net Cash Provided by (Used in) Investing Activities				(12,996)		30,866		-		(10,411)		(15,422)		(7,963)


Cash Flows From Financing Activities
Issuance of debt				-		-		-		553		(553)		-
Repayment of debt				(400)		-		-		(50)		-		(450)
Issuance of company common stock				234		-		-		-		(188)		46
Dividends paid				(1,711)		(15,088)		-		(275)		15,363		(1,711)
Other				(3)		(16,876)		-		875		15,976		(28)

Net cash provided by (used in) continuing financing activities				(1,880)		(31,964)		-		1,103		30,598		(2,143)
Net cash used in discontinued operations				-		-		-		(169)		169		-

Net Cash Provided by (Used in) Financing Activities				(1,880)		(31,964)		-		934		30,767		(2,143)


Effect of Exchange Rate Changes on Cash and Cash Equivalents				-		-		-		44		-		44


Net Change in Cash and Cash Equivalents				-		(833)		31		698		-		(104)
Cash and cash equivalents at beginning of period				-		2,434		229		3,583		-		6,246

Cash and Cash Equivalents at End of Period			$	-		1,601		260		4,281		-		6,142


	Millions of Dollars
	Six Months Ended June 30, 2013*
Statement of Cash Flows	ConocoPhillips		ConocoPhillips Company		ConocoPhillips Australia Funding Company		ConocoPhillips Canada Funding Company I		All Other Subsidiaries		Consolidating Adjustments		Total Consolidated

Cash Flows From Operating Activities
Net cash provided by (used in) continuing operating activities	$	(183)		1,333		-		(2)		7,644		(495)		8,297
Net cash provided by discontinued operations		-		91		-		-		417		(334)		174

Net Cash Provided by (Used in) Operating Activities		(183)		1,424		-		(2)		8,061		(829)		8,471


Cash Flows From Investing Activities
Capital expenditures and investments		-		(1,016)		-		-		(6,080)		-		(7,096)
Proceeds from asset dispositions		-		56		-		-		1,670		(50)		1,676
Net purchases of short-term investments		-		-		-		-		(74)		-		(74)
Long-term advances/loans—related parties		-		(113)		-		-		(536)		649		-
Collection of advances/loans—related parties		-		138		750		2		1,609		(2,428)		71
Intercompany cash management		855		752		-		-		(1,607)		-		-
Other		-		3		-		-		(49)		-		(46)

Net cash provided by (used in) continuing investing activities		855		(180)		750		2		(5,067)		(1,829)		(5,469)
Net cash used in discontinued operations		-		(52)		-		-		(379)		52		(379)

Net Cash Provided by (Used in) Investing Activities		855		(232)		750		2		(5,446)		(1,777)		(5,848)


Cash Flows From Financing Activities
Issuance of debt		-		523		-		-		126		(649)		-
Repayment of debt		-		(1,566)		(750)		-		(1,010)		2,428		(898)
Change in restricted cash		748		-		-		-		-		-		748
Issuance of company common stock		206		-		-		-		-		(211)		(5)
Dividends paid		(1,629)		-		(4)		-		(945)		949		(1,629)
Other		1		31		-		-		(473)		50		(391)

Net cash used in continuing financing activities		(674)		(1,012)		(754)		-		(2,302)		2,567		(2,175)
Net cash used in discontinued operations		-		-		-		-		(39)		39		-

Net Cash Used in Financing Activities		(674)		(1,012)		(754)		-		(2,341)		2,606		(2,175)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-		-		-		-		(157)		-		(157)


Net Change in Cash and Cash Equivalents		(2)		180		(4)		-		117		-		291
Cash and cash equivalents at beginning of period		2		12		6		59		3,539		-		3,618

Cash and Cash Equivalents at End of Period	$	-		192		2		59		3,656		-		3,909

Revised to reflect intercompany cash management activities previously presented as cash flows from continuing operating activities as both continuing activities and discontinued operations in “Cash Flows from Investing Activities” and “Cash Flows From Financing Activities.” There was no impact to Total Consolidated balances.

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Due to discontinued operations reporting, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on production and proved reserves. Headquartered in Houston, Texas, we have operations and activities in 27 countries. At June 30, 2014, we had approximately 19,200 employees worldwide and total assets of $122 billion.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects. Our value proposition to our shareholders is to deliver 3 to 5 percent production and cash margin growth, achieve ongoing competitive dividends and returns on capital, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. To achieve these goals, we plan to continue to invest in high-margin developments, optimize our portfolio, apply technical capability and maintain financial flexibility.

In 2013, we successfully achieved the targets we set to sell non-core assets, advance major projects, progress development drilling and exploration programs and maintain a competitive dividend. Our success has enabled us to focus on growth in 2014, which we intend to deliver through investments in our legacy assets, continued success in our development drilling and exploration programs, continued ramp up in our unconventional plays and additional project startups, which include anticipated startups in Canada, Malaysia and the United Kingdom in 2014. As a result, we expect to deliver 3 to 5 percent volume and margin growth in 2014. In the second quarter of 2014, we achieved production of 1,594 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 37 MBOED. Excluding Libya, our production from continuing operations was 1,556 MBOED. Adjusted for Libya and downtime, production from continuing operations increased by 60 MBOED, or 4 percent, compared with the second quarter of 2013.

Consistent with our commitment to offer our shareholders a competitive dividend, in July 2014, our Board of Directors increased our quarterly dividend by 5.8 percent to $0.73 per share. Through June 2014, we generated $9.8 billion in cash from continuing operations, which included a $1.3 billion distribution from our 50 percent owned FCCL Partnership. We also paid dividends on our common stock of $1.7 billion and ended the quarter with $6.1 billion in cash and cash equivalents.

We participate in a capital-intensive industry. As a result, we invest significant capital to acquire acreage, explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. In December 2013, we announced a capital budget of $16.7 billion for 2014, and this guidance remains unchanged. We funded $8.1 billion of capital expenditures through June 2014. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on organic growth in volumes and margins through higher-margin oil, condensate and LNG projects and limited investment in North American natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. In the second quarter of 2014, our average liquids production from continuing operations, excluding Libya, increased 11 percent compared with the same period of 2013. However, there are often long lead times from the time we make an investment to the time the investment is operational and begins generating financial returns. We expect our capital expenditures to be approximately $16.0 billion per year through 2017. Our investment in higher-value products and geographic areas is expected to contribute to additional margin growth.

Basis of Presentation

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial results, and the impact on our segment presentation was immaterial. For additional information, see Note 17—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008, supply disruptions or fears thereof caused by civil unrest or military conflicts, 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, as a result of advances in technology responsible for the rapid growth of shale production, successful exploration and development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which will provide the financial flexibility to withstand challenging business cycles.

Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, 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 U.S. Henry Hub (HH) natural gas:

LOGO

Brent crude oil prices averaged $109.63 per barrel in the second quarter of 2014, an increase of 7 percent compared with $102.44 per barrel in the second quarter of 2013, and an increase of 1 percent compared with $108.22 per barrel in the first quarter of 2014. Prices have been supported by continued geopolitical risks impacting supplies, as well as global oil demand growth. Industry crude prices for WTI averaged $103.05 per barrel in the second quarter of 2014, an increase of 9 percent compared with $94.12 per barrel in the second quarter of 2013, and an increase of 4 percent compared with $98.75 per barrel in the first quarter of 2014. Strong U.S. refinery runs and new pipeline and rail infrastructure contributed to reducing the discount of WTI relative to global oil prices during the second quarter of 2014.

Henry Hub natural gas prices averaged $4.68 per thousand cubic feet (MCF) in the second quarter of 2014, an increase of 14 percent compared with $4.10 per MCF in the second quarter of 2013 and a decrease of 5 percent compared with $4.94 per MCF in the first quarter of 2014. Strong growth in demand in 2014 versus 2013, particularly winter weather-driven demand, pushed natural gas prices higher early in the year. During the spring months of 2014, prices fell modestly relative to the first quarter of 2014, as seasonal demand subsided.

Bitumen prices continued to strengthen in the second quarter of 2014, mainly as a result of higher refinery demand, as well as increased rail volumes and pipeline capacity improvements. Our realized bitumen price was $65.82 per barrel in the second quarter of 2014, an increase of 18 percent compared with $55.69 per barrel in the second quarter of 2013 and an increase of 17 percent compared with $56.47 per barrel in the first quarter of 2014.

Our total average realized price was $70.17 per barrel of oil equivalent (BOE) in the second quarter of 2014, an increase of 5 percent compared with $66.82 per BOE in the second quarter of 2013, which reflected higher average realized prices across all commodities. In the first six months of 2014, our total realized price was $70.68 per BOE, an increase of 4 percent compared with $67.70 per BOE in the first six months of 2013. This reflected higher overall bitumen and natural gas prices, partially offset by lower crude oil prices.

Key Operating and Financial Highlights

—

Strong second-quarter production of 1,556 MBOED from continuing operations, excluding Libya, a 6.5 percent increase compared with 2013; total production of 1,594 MBOED.

—

4 percent production growth, adjusted for Libya and downtime, in the second-quarter 2014.

—

Eagle Ford and Bakken combined production increased by 38 percent compared with second-quarter 2013.

—

Major projects in Canada, Malaysia and the United Kingdom are on track for startup in the second half of 2014.

—

Continued progress toward 2015 major project startups, including Eldfisk II, Surmont 2 and APLNG.

—

Exploration and appraisal activity ongoing; conventional drilling underway in Angola, Senegal, Australia and the Gulf of Mexico; unconventional activities continue in Canada, the Lower 48 and Poland.

—

Completed sale of Nigerian upstream business in July for net proceeds of $1.4 billion, inclusive of deposits previously received.

—

Increased quarterly dividend by 5.8 percent in July.

Outlook

Production and Other Guidance

We expect to achieve 3 to 5 percent volume and margin growth in 2014. The third and fourth quarter 2014 production guidance for continuing operations, excluding Libya, is unchanged. Third-quarter 2014 production is expected to be 1,435 to 1,485 MBOED. This range reflects a high level of seasonal planned maintenance and turnaround activity. Fourth-quarter production is expected to be 1,590 to 1,640 MBOED. This range anticipates project startups in Canada, Malaysia and the United Kingdom and reflects a strong anticipated exit rate at year-end. We are raising the midpoint of our 2014 full-year production outlook for continuing operations, excluding Libya. Full-year production guidance is now approximately 1,525 to 1,550 MBOED.

For other guidance items, we are providing a mid-year update. Previous guidance for depreciation of $8.5 billion, corporate expense of $0.95 billion and full-year capital of $16.7 billion remain unchanged. Exploration expense guidance of $1.5 billion is also unchanged and includes risked dry hole expense. Production and selling, general and administrative expense outlook is up modestly from prior guidance and is expected to be in the range of $8.7 billion to $8.9 billion.

Sale of Nigeria Business Update

As previously announced, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business, which originally included our upstream affiliates and Phillips (Brass) Limited, which owned a 17 percent interest in the Brass LNG Project. The upstream sale closed on July 30, 2014, and generated net proceeds of approximately $1.4 billion, after customary adjustments, inclusive of deposits previously received. In July 2014, we transferred our 17 percent interest in the Brass LNG Project to the remaining shareholders in Brass LNG Limited. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Freeport LNG

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas. In July 2013, we and Freeport LNG agreed to terminate this agreement, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. In July 2014, Freeport LNG received conditional approval from the Federal Energy Regulatory Commission (FERC). Upon satisfaction of their project financing conditions and receipt of FERC’s permission to construct, currently expected to occur in the fourth quarter of 2014, we will pay Freeport LNG a termination fee of approximately $520 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $50 million

for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $520 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 million to $60 million per year in operating costs over the next 19 years. For additional information, see Note 3—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and six-month periods ended June 30, 2014, is based on a comparison with the corresponding periods of 2013.

A summary of income (loss) from continuing operations by business segment follows:


	Millions of Dollars
	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Alaska	$	627		682		1,225		1,225
Lower 48		265		233		589		338
Canada		182		5		538		138
Europe		259		263		606		717
Asia Pacific and Middle East		862		1,030		1,618		1,962
Other International		121		26		92		45
Corporate and Other		(251)		(173)		(486)		(335)

Income from continuing operations	$	2,065		2,066		4,182		4,090

Earnings for ConocoPhillips were flat in the second quarter of 2014, and earnings for the six-month period ended June 30, 2014, increased 2 percent. Both periods of 2014 reflected improvements primarily from higher prices, higher volumes, a continued portfolio shift to liquids and a higher proportion of production in high-margin areas. These items were largely offset by:

—

Higher leasehold impairments in Canada.

—

Higher operating expenses.

—

Higher corporate expenses, largely due to lower licensing revenues and capitalized interest.

—

Lower recognition of net gains associated with pending claims and settlements. The second quarter and six-month period of 2014 included net gains of $138 million after-tax and $99 million after-tax, respectively, compared with net gains of $234 million after-tax for the comparable periods of 2013.

—

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48 and Europe.

—

Lower gains from asset sales. Earnings for the second quarter of 2014 included gains of $5 million after-tax, compared with gains of $71 million after-tax in the second quarter of 2013. Gains realized in the six-month period of 2014 were $11 million after-tax, compared with gains of $341 million after-tax in the six-month period of 2013.

Earnings in the six-month period of 2014 also benefitted from lower production taxes in Alaska, which mainly resulted from higher capital spending and lower production volumes, and improved marketing of third-party North American natural gas volumes. These increases were partly offset by an $83 million after-tax loss

related to releases of capacity on transportation and storage capacity agreements in the six-month period of 2014.

See the “Segment Results” section for additional information on our segment results.

Income Statement Analysis

Sales and other operating revenues increased 4 percent in the second quarter and 6 percent in the six-month period of 2014 due to higher prices and volumes.

Equity in earnings of affiliates increased 36 percent in the second quarter and 45 percent in the six-month period of 2014. The increases in both periods of 2014 primarily resulted from higher earnings from FCCL Partnership, largely as a result of higher bitumen prices and volumes. The increase in equity earnings in the six-month period of 2014 was partially offset by lower earnings from Australia Pacific LNG Pty Ltd (APLNG), primarily due to higher operating expenses and DD&A.

Gain on dispositions decreased 93 percent in the second quarter and 90 percent in the six-month period of 2014. Gains realized in the second quarter of 2013 mainly resulted from the disposition of certain properties located in southwest Louisiana. Additional gains realized in the six-month period of 2013 primarily included the disposition of our interest in the Interconnector Pipeline in Europe, partly offset by a loss on the disposition of the majority of our producing zones located in the Cedar Creek Anticline in the Lower 48.

Purchased commodities increased 11 percent in the six-month period of 2014, largely as a result of higher natural gas prices, in addition to a $130 million loss related to transportation and storage capacity agreements located in the Lower 48, partly offset by lower purchased volumes.

Production and operating expenses increased 21 percent in the second quarter and 17 percent in the six-month period of 2014. Both periods in 2013 included the benefit of a $142 million accrual reduction related to FERC approval of cost allocation (pooling) agreements with the remaining owners of the Trans-Alaska Pipeline System (TAPS). Additional increases in both periods of 2014 were mostly due to increased activity in the Lower 48, as well as higher well workovers and maintenance in Europe, Alaska, Australia and China.

Exploration expenses increased 61 percent in the second quarter and 36 percent in the six-month period of 2014. The increase in both periods of 2014 was primarily attributable to the $145 million impairment of undeveloped leasehold costs associated with the offshore Canada Amauligak discovery, Arctic Islands and other Beaufort properties, as a result of our decision not to pursue future development at this time. Higher dry hole costs, mostly associated with the Gulf of Mexico, also contributed to the increase in both periods of 2014.

DD&A increased 13 percent in the second quarter and 9 percent in the six-month period of 2014. The increase in both periods of 2014 was mostly associated with higher production volumes in the Lower 48 and the United Kingdom, partly offset by lower unit-of-production rates in Canada associated with year-end 2013 price-related reserve revisions and lower natural gas production volumes.

Taxes other than income taxes decreased 18 percent in the six-month period of 2014, mainly due to lower production taxes in Alaska, as a result of higher capital spending and lower crude oil production volumes.

Interest and debt expense increased 21 percent in the six-month period of 2014, primarily due to lower capitalized interest on projects.

Foreign currency transaction losses in the six-month period of 2014, compared with foreign currency transaction gains in the six-month period of 2013, were primarily attributable to fluctuations in the U.S. dollar versus Norwegian krone and Malaysian ringgit exchange rates.

See Note 18—Income Taxes, in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Summary Operating Statistics

Three Months Ended
June 30

Six Months Ended
June 30

2014

2013

2014

2013

Average Net Production

Crude oil (MBD)*

596

585

597

605

Natural gas liquids (MBD)

167

158

163

159

Bitumen (MBD)

128

100

126

104

Natural gas (MMCFD)**

3,998

3,998

3,950

3,980

Total Production (MBOED)

1,557

1,510

1,544

1,531

Dollars Per Unit

Average Sales Prices

Crude oil (per barrel)

103.39

100.07

102.51

103.06

Natural gas liquids (per barrel)

40.36

37.80

43.31

40.39

Bitumen (per barrel)

65.82

55.69

61.21

47.04

Natural gas (per thousand cubic feet)***

6.82

6.25

7.18

6.22

Millions of Dollars

Exploration Expenses

General administrative, geological and geophysical, and lease rentals

183

145

410

386

Leasehold impairment

189

235

110

Dry holes

145

168

102

517

321

813

598

Excludes discontinued operations.

*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.

***Prior periods revised to conform to current-year presentation.

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At June 30, 2014, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations, including Libya, increased 3 percent in the second quarter of 2014 and 1 percent in the six-month period of 2014, while average liquids production increased 6 percent and 2 percent over the corresponding periods in 2013. The increase in total average production primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada; increased drilling programs, mostly in the Lower 48, western Canada, Norway and China; and lower planned and unplanned downtime. These increases were largely offset by normal field decline, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, and unfavorable market impacts. The impact from asset dispositions also partially offset the increases in production in the six-month period of 2014. Adjusted for Libya and downtime, production from continuing operations increased by 60 MBOED, or 4 percent, compared with the second quarter of 2013.

Segment Results

Alaska


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	627		682		1,225		1,225


Average Net Production
Crude oil (MBD)		170		176		173		183
Natural gas liquids (MBD)		16		15		16		16
Natural gas (MMCFD)		45		38		50		47


Total Production (MBOED)		193		197		197		207


Average Sales Prices
Crude oil (dollars per barrel)	$	108.93		106.09		107.67		108.35
Natural gas (dollars per thousand cubic feet)		6.03		4.03		5.59		4.73

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. As of June 30, 2014, Alaska contributed 21 percent of our worldwide liquids production and 1 percent of our natural gas production.

Alaska earnings decreased 8 percent in the second quarter and remained flat in the six-month period of 2014 compared with the same periods of 2013. Earnings in both periods of 2014 were mainly impacted by the absence of a $97 million after-tax benefit associated with a ruling by FERC in 2013, more fully described below, lower crude oil volumes and higher operating expenses. These reductions to earnings were largely offset by lower production taxes, which resulted from higher 2014 capital spending and lower crude oil production volumes. Higher crude oil prices also partially offset the decrease in earnings in the second quarter of 2014.

In 2012, the major owners of TAPS filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, FERC approved the proposed settlement and pooling agreement without modification. As a result, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax.

Average production decreased 2 percent in the second quarter and 5 percent in the six-month period of 2014, compared with the corresponding periods of 2013. The reduction in both periods of 2014 was mainly due to normal field decline, partially offset by lower unplanned downtime.

Alaska LNG (AKLNG) Update

In June 2014, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c., TransCanada Corporation and the State of Alaska, signed a joint venture agreement to begin preliminary front-end engineering and design on the AKLNG Project. In July 2014, an application was filed with the U.S. Department of Energy for a permit to export up to 20 million metric tons of LNG annually. Significant engineering, technical, regulatory, fiscal, commercial and permitting issues will need to be resolved prior to a final investment decision on the potential $45 billion to $65 billion (gross) project.

Lower 48


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	265		233		589		338


Average Net Production
Crude oil (MBD)		191		147		181		147
Natural gas liquids (MBD)		100		91		96		89
Natural gas (MMCFD)		1,495		1,516		1,482		1,479


Total Production (MBOED)		540		491		524		483


Average Sales Prices
Crude oil (dollars per barrel)	$	93.73		93.56		92.69		93.63
Natural gas liquids (dollars per barrel)		31.28		29.30		33.54		29.43
Natural gas (dollars per thousand cubic feet)		4.43		3.85		4.75		3.53

As of June 30, 2014, the Lower 48 contributed 31 percent of our worldwide liquids production and 38 percent of our natural gas production. The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico.

Earnings from the Lower 48 increased 14 percent in the second quarter and 74 percent in the six-month period of 2014 compared with the same periods of 2013. Earnings in both periods of 2014 primarily benefitted from increased crude oil volumes and stronger natural gas prices. These increases to earnings were partially offset by higher DD&A, mostly due to higher crude oil production, the absence of a $69 million after-tax gain on disposition of certain properties in southwest Louisiana recognized in the second quarter of 2013, and higher operating expenses, taxes and dry hole expenses. Dry hole expenses in both periods of 2014 were approximately $85 million after-tax for the nonoperated Coronado Miocene appraisal and Deep Nansen wildcat wells in the Gulf of Mexico, compared with approximately $40 million after-tax in both periods of 2013 for the Thorn well. Additional benefits to earnings in the six-month period of 2014 included approximately $100 million after-tax from marketing third-party natural gas volumes, higher natural gas liquids prices, and the absence of a $52 million after-tax loss recognized in the six-month period of 2013 from the disposition of the majority of our producing zones in the Cedar Creek Anticline. These increases in the six-month period of 2014 were partially offset by an $83 million after-tax loss recognized upon the release of underutilized transportation and storage capacity at rates below our contractual rates, in addition to a $35 million after-tax legal accrual.

Rising U.S. production and an increase in pipeline capacity to the Gulf Coast have put downward pressure on Gulf Coast crude oil prices. Prices for Permian Basin crude oil production have been impacted by production increases exceeding pipeline offtake additions. Our average realized prices in the Lower 48 have historically correlated with WTI prices; however, in the second half of 2013, our Lower 48 crude differential versus WTI began to widen. In the second quarter of 2014, our average realized crude oil price of $93.73 per barrel was 9 percent less than WTI of $103.05 per barrel. Current market dynamics indicate this crude differential may remain relatively wide in the near-term.

Total average production in the Lower 48 increased 10 percent in the second quarter and 8 percent in the six-month period of 2014. Average crude oil production increased 30 percent and 23 percent over the same periods, respectively. The increases in both periods of 2014 were mainly attributable to new production, primarily from the Eagle Ford and Bakken, and improved drilling and well performance. These increases in production were partially offset by normal field decline and higher unplanned downtime.

Canada


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	182		5		538		138


Average Net Production
Crude oil (MBD)		12		14		12		14
Natural gas liquids (MBD)		25		25		25		26
Bitumen (MBD)
Consolidated operations		14		12		13		12
Equity affiliates		114		88		113		92

Total bitumen		128		100		126		104
Natural gas (MMCFD)		713		788		710		797


Total Production (MBOED)		284		271		282		276


Average Sales Prices
Crude oil (dollars per barrel)	$	86.33		81.09		83.27		76.92
Natural gas liquids (dollars per barrel)		46.56		44.08		51.36		47.16
Bitumen (dollars per barrel)
Consolidated operations		68.00		59.67		64.95		48.55
Equity affiliates		65.55		55.13		60.75		46.85
Total bitumen		65.82		55.69		61.21		47.04
Natural gas (dollars per thousand cubic feet)		4.13		3.28		4.96		3.08

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. As of June 30, 2014, Canada contributed 18 percent of our worldwide liquids production and 18 percent of our natural gas production.

Earnings from Canada increased $177 million in the second quarter and $400 million in the six-month period of 2014 compared with the corresponding periods of 2013. The increases in earnings in both periods of 2014 were largely due to higher bitumen and natural gas prices, higher bitumen volumes and lower DD&A from western Canada. The lower DD&A mainly resulted from lower unit-of-production rates related to year-end 2013 price-related reserve revisions and lower natural gas production volumes.

These increases to earnings were partly offset by the $109 million after-tax impairment of undeveloped leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties. This resulted from our decision not to pursue future development at this time; however, we remain committed to the potential of the area as technology develops and the price environment improves.

Earnings for the six-month period of 2013 also included the recognition of a $224 million tax benefit, which related to the favorable tax resolution associated with the sale of certain western Canada properties in a previous year. For additional information on the Amauligak impairment, see Note 6—Suspended Wells and Unproved Property Impairments, in the Notes to Consolidated Financial Statements.

Total average production increased 5 percent in the second quarter and 2 percent in the six-month period of 2014, while bitumen production increased 28 percent and 21 percent over the same periods, respectively. The increases in total production in both periods of 2014 were mainly attributable to improved drilling and well performance from western Canada and Christina Lake in FCCL, the ramp-up of production from Christina Lake Phase E and lower planned downtime. These increases were partly offset by normal field decline and higher royalty impacts, which resulted from higher prices.

Exploration Update

In the second quarter of 2014, we entered into a farm-in agreement to acquire a 30 percent nonoperated interest in six exploration licenses covering approximately five million gross acres in the deepwater Shelburne Basin, offshore Nova Scotia. Pending regulatory approval, we anticipate drilling will begin in the second half of 2015.

Europe


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	259		263		606		717


Average Net Production
Crude oil (MBD)		126		100		130		112
Natural gas liquids (MBD)		7		5		7		6
Natural gas (MMCFD)		480		409		476		435


Total Production (MBOED)		213		173		216		190


Average Sales Prices
Crude oil (dollars per barrel)	$	111.38		102.74		110.17		109.29
Natural gas liquids (dollars per barrel)		57.32		49.29		58.99		55.88
Natural gas (dollars per thousand cubic feet)		8.99		10.26		9.95		10.55

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Greenland. As of June 30, 2014, our Europe operations contributed 16 percent of our worldwide liquids production and 12 percent of our natural gas production.

Earnings for Europe decreased 2 percent in the second quarter and 15 percent in the six-month period of 2014 compared with the same periods of 2013. Earnings in both periods of 2014 were primarily impacted by higher DD&A, which mostly resulted from increased production volumes from Jasmine, higher taxes and operating expenses and lower gains from asset dispositions. Gains realized in the six-month period of 2013 mainly included an $83 million after-tax gain on the disposition of our interest in the Interconnector Pipeline. These decreases in earnings in both periods of 2014 were partly offset by higher crude oil and natural gas volumes. Lower foreign currency transaction gains also contributed to the reduction in earnings in the six-month period of 2014.

Average production increased 23 percent in the second quarter and 14 percent in the six-month period of 2014, mostly due to the continued ramp-up of production from Jasmine and Ekofisk South, the startup of the new sour gas plant at East Irish Sea, improved drilling and well performance in Norway and lower planned downtime. These increases were partly offset by normal field decline.

Asia Pacific and Middle East


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	862		1,030		1,618		1,962


Average Net Production
Crude oil (MBD)
Consolidated operations		76		84		81		85
Equity affiliates		16		15		15		15

Total crude oil		92		99		96		100


Natural gas liquids (MBD)
Consolidated operations		11		14		12		14
Equity affiliates		8		8		7		8

Total natural gas liquids		19		22		19		22


Natural gas (MMCFD)
Consolidated operations		748		726		738		705
Equity affiliates		516		493		492		488

Total natural gas		1,264		1,219		1,230		1,193


Total Production (MBOED)		322		324		320		321


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	105.65		97.77		105.30		103.76
Equity affiliates		108.09		100.05		107.82		103.89
Total crude oil		106.07		98.13		105.71		103.78
Natural gas liquids (dollars per barrel)
Consolidated operations		71.52		66.54		75.48		72.81
Equity affiliates		68.84		64.63		73.71		71.08
Total natural gas liquids		70.46		65.79		74.80		72.18
Natural gas (dollars per thousand cubic feet)
Consolidated operations*		10.32		10.62		10.32		10.90
Equity affiliates		10.46		8.84		10.45		9.10
Total natural gas*		10.38		9.90		10.37		10.16

*Prior periods revised to conform to current-year presentation.

The Asia Pacific and Middle East segment has operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh and Brunei. As of June 30, 2014, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 31 percent of our natural gas production.

Asia Pacific and Middle East earnings decreased 16 percent in the second quarter and 18 percent in the six-month period of 2014 compared with the same periods of 2013. The reduction in earnings in both periods of 2014 was mainly due to the absence of a $146 million after-tax insurance settlement received in the second quarter of 2013 associated with the Bohai Bay seepage incidents. Lower crude oil and LNG sales volumes; higher expenses from equity affiliates; higher operating expenses; foreign currency losses in 2014, compared with foreign currency gains in 2013; and lower natural gas prices, mostly from Indonesia, also contributed to the decrease in earnings in both periods of 2014. These decreases were partly offset by higher LNG and crude oil prices.

Average production remained relatively flat in both the second quarter and six-month period of 2014 compared with the same periods of 2013. Increased production and lower unplanned downtime were mostly offset by normal field decline. The increases in the second quarter of 2014 were also partially offset by unfavorable effects on production sharing contracts, as a result of higher prices. Production increases in the six-month period of 2014 were also partially offset by higher planned maintenance at Qatar Liquefied Gas Company Limited (3) (QG3).

Other International


	Three Months Ended June 30				Six Months Ended June 30
	2014		2013		2014		2013


Income From Continuing Operations (millions of dollars)	$	121		26		92		45


Average Net Production
Crude oil (MBD)
Consolidated operations		1		44		1		44
Equity affiliates		4		5		4		5

Total crude oil		5		49		5		49


Natural gas (MMCFD)		1		28		2		29


Total Production (MBOED)		5		54		5		54


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	107.33		102.82		107.33		107.16
Equity affiliates		72.59		69.96		70.16		72.65
Total crude oil		74.91		99.79		71.42		103.71
Natural gas (dollars per thousand cubic feet)		-		4.65		6.65		4.76

The Other International segment includes operations in Libya and Russia, as well as exploration activities in Colombia, Poland, Angola, Senegal and Azerbaijan. As of June 30, 2014, Other International contributed 1 percent of our worldwide liquids production.

Other International earnings increased $95 million in the second quarter and $47 million in the six-month period of 2014 compared with the same periods of 2013. Earnings in both periods of 2014 primarily benefitted from the recognition of other income of $154 million after-tax associated with the favorable resolution of a contingent liability, partially offset by lower volumes from Libya and lower earnings from equity affiliates, which mostly resulted from the 2013 disposition of our equity investment in Phoenix Park Processors Limited, located in Trinidad and Tobago. Lower gains from asset dispositions and higher exploration expenses also partially offset the increase in earnings in the six-month period of 2014.

Average production decreased 91 percent in the both the second quarter and six-month period of 2014 compared with the same periods in 2013. The decreases primarily resulted from the shutdown of the Es Sider crude oil export terminal in Libya, which began at the end of July 2013. Libya production remains shut in, as the Es Sider Terminal closure has continued into the third quarter of 2014.

Exploration Update

In June 2014, we spud the Kamoxi-1 well, located offshore Angola, as part of a four-well drilling program. During the second quarter of 2014, drilling also commenced on the FAN-1 well, offshore Senegal, as part of a two-well drilling program. In Colombia, we expect to begin exploratory drilling in the La Luna Shale in the second half of 2014.

Asset Dispositions

In July 2014, we sold our Nigeria upstream affiliates, and we transferred our 17 percent interest in the Brass LNG Project to the remaining shareholders in Brass LNG Limited. In 2013, we sold our Algeria business and our interest in Kashagan. Results of operations related to Nigeria, Algeria and Kashagan have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Corporate and Other


	Millions of Dollars

	Three Months Ended June 30					Six Months Ended June 30
	2014			2013		2014			2013

Income (Loss) From Continuing Operations
Net interest	$	(158	)		(127)		(321	)		(235)
Corporate general and administrative expenses		(51	)		(43)		(82	)		(70)
Technology		(20	)		41		(48	)		33
Other		(22	)		(44)		(35	)		(63)

	$	(251	)		(173)		(486	)		(335)

Net interest consists of interest and financing expense, net of interest income and capitalized interest, as well as premiums incurred on the early retirement of debt. Net interest increased 24 percent in the second quarter and 37 percent in the six-month period of 2014 compared with the same periods in 2013, mainly as a result of lower capitalized interest on projects sold or completed and lower interest income.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands, unconventional reservoirs, LNG, and subsurface, arctic and deepwater technologies, with an underlying commitment to environmental responsibility. Losses from Technology were $20 million in the second quarter and $48 million in the six-month period of 2014, compared with earnings of $41 million and $33 million, respectively, in the same periods of 2013. The reduction in earnings primarily resulted from lower licensing revenues and higher research and development expenses.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. “Other expenses” decreased 50 percent in the second quarter and 44 percent in the six-month period of 2014, primarily as a result of foreign currency transaction gains in both periods of 2014, compared with foreign currency transaction losses in both periods of 2013. These reductions to expense were partially offset by higher environmental expenses.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars

	June 30 2014			December 31 2013


Short-term debt	$	1,664			589
Total debt		21,234			21,662
Total equity		55,686			52,492
Percent of total debt to capital*		28	%		29
Percent of floating-rate debt to total debt**		8	%		8

*Capital includes total debt and total equity.

**Includes effect of interest rate swaps.

To meet our short- and long-term liquidity requirements, we look to a variety of funding sources. Cash generated from continuing operating activities is the primary source of funding. During the first six months of 2014, the primary uses of our available cash were $8,141 million to support our ongoing capital expenditures and investments program, $1,711 million to pay dividends and $450 million to repay debt. During the first six months of 2014, cash and cash equivalents decreased by $104 million, to $6,142 million.

In addition to cash flows from operating activities, we rely on our commercial paper and credit facility programs and our shelf registration statement to support our short- and long-term liquidity requirements. 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 continuing operating activities was $9,841 million for the first six months of 2014, compared with $8,297 million for the corresponding period of 2013, a 19 percent increase. The increase was primarily due to the $1.3 billion distribution from FCCL in the first quarter of 2014. This distribution resulted from our $2.8 billion prepayment of the remaining joint venture acquisition obligation in 2013, which substantially increased the financial flexibility of our 50 percent owned FCCL Partnership. We do not expect this individually significant distribution to recur in the future under current economic conditions.

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 acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiencies, weather conditions, 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.

Asset Sales

On July 30, 2014, we sold our Nigeria upstream affiliates for net proceeds of approximately $1.4 billion, after customary adjustments, inclusive of deposits previously received. In 2013, we sold our Algeria business and

our interest in Kashagan. Results of operations related to Nigeria, Algeria and Kashagan have been classified as discontinued operations in all periods presented in this Form 10-Q. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.15 billion commercial paper program, which is used to fund commitments relating to QG3. At both June 30, 2014 and December 31, 2013, we had no direct borrowings or letters of credit issued under the revolving credit facility. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, $912 million of commercial paper was outstanding at June 30, 2014, compared with $961 million at December 31, 2013. Since we had $912 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at June 30, 2014.

Certain of our project-related 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, 2014 and December 31, 2013, we had direct bank letters of credit of $638 million and $827 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

Shelf Registration

We have a universal shelf registration statement on file with the U.S. Securities and Exchange Commission 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 9—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 Spending” section.

Our debt balance at June 30, 2014, was $21.2 billion, a decrease of $428 million from the balance at December 31, 2013. Our short-term debt balance at June 30, 2014, increased $1.1 billion compared with December 31, 2013, primarily as a result of the timing of scheduled maturities. During the first six months of 2014, we repaid notes at maturity totaling $400 million. For more information, see Note 7—Debt, in the Notes to Consolidated Financial Statements.

In May 2014, we announced a dividend of 69 cents per share. The dividend was paid June 2, 2014, to stockholders of record at the close of business on May 23, 2014. In July 2014, we announced a 5.8 percent increase in the quarterly dividend rate to 73 cents per share. The dividend will be paid September 2, 2014, to stockholders of record at the close of business on July 21, 2014.

Capital Spending


	Millions of Dollars

	Six Months Ended June 30

	2014		2013


Alaska	$	805		545
Lower 48		2,697		2,647
Canada		1,137		1,097
Europe		1,252		1,547
Asia Pacific and Middle East		1,942		1,164
Other International		239		42
Corporate and Other		69		54

Capital expenditures and investments from continuing operations	$	8,141		7,096

Discontinued operations in Kashagan, Nigeria and Algeria	$	50		379
Joint venture acquisition obligation (principal)—Canada		-		381

Capital Program	$	8,191		7,856

During the first six months of 2014, capital expenditures and investments from continuing operations supported key exploration and development programs, primarily:

—

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

—

Development of coalbed methane projects associated with the APLNG joint venture in Australia.

—

Oil sands development and ongoing liquids-rich plays in Canada.

—

In Europe, development activities in the Greater Ekofisk, Jasmine and Clair Ridge areas, and appraisal activities in the Greater Clair Area.

—

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

—

Exploration and appraisal drilling in deepwater Gulf of Mexico.

—

Continued development of offshore fields in Malaysia and Indonesia and ongoing exploration and development activity offshore Australia and China.

—

Exploration activities in Angola and Senegal.

Contingencies

Legal Matters

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 2013 Annual Report on Form 10-K.

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

operations. As of December 31, 2013, we reported we had been notified of potential liability under CERCLA and comparable state laws at 15 sites around the United States. As of June 30, 2014, there was no change in the number of sites.

At June 30, 2014, our balance sheet included a total environmental accrual of $378 million, compared with $348 million at December 31, 2013, 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 2013 Annual Report on Form 10-K.

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. You can 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 the following:

—

Fluctuations in crude oil, bitumen, natural gas, LNG and natural gas liquids prices.

—

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

—

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.

—

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; comply with government regulations; or make capital expenditures required to maintain compliance.

—

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, terrorism, cyber attacks or infrastructure constraints or disruptions.

—

International monetary conditions and exchange controls.

—

Substantial investment or reduced demand for products 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; other political, economic or diplomatic developments; and international monetary fluctuations.

—

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

—

Limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets.

—

Delays in, or our inability to, execute asset dispositions.

—

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 factors generally described in Item 1A—Risk Factors in our 2013 Annual Report on Form 10-K.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the six months ended June 30, 2014, does not differ materially from that discussed under Item 7A in our 2013 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that 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, 2014, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Executive Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Act, of ConocoPhillips’ disclosure controls and procedures (as defined in Rule 13a-15(e) of the Act). Based upon that evaluation, our Chairman and Chief Executive Officer and our Executive Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of June 30, 2014.

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 2014 and any material developments with respect to matters previously reported in ConocoPhillips’ 2013 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 the U.S. Securities and Exchange Commission (SEC) regulations.

On April 30, 2012, the separation of our downstream businesses 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.

New Matters—ConocoPhillips

The New Mexico Environment Department has issued a Notice of Violation (NOV) to ConocoPhillips alleging failure to comply with two air emission monitoring requirements at the East Vacuum Liquid Recovery/CO2 Plant in southeastern New Mexico. The agency is seeking a penalty of over $100,000. The Plant has corrected these issues and is working with the agency to resolve the NOV.

New Matters—Phillips 66

The Phillips 66 Wood River Refinery has received a NOV from the U.S. Environmental Protection Agency (EPA) alleging various flaring-related violations between 2009 and 2013. It is anticipated the EPA will seek the installation of additional flare controls and yet to be determined penalties as part of any settlement.

On July 8, 2014, the Bay Area Air Quality Management District (District) issued a $175,000 demand to settle 18 NOVs issued in 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

On July 8, 2014, the District issued a $259,000 demand to settle 20 NOVs issued in 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

Item 1A. RISK FACTORS

There have been no material changes from the risk factors disclosed in Item 1A of our 2013 Annual Report on Form 10-K.

Item 6. EXHIBITS


10.1		2014 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of ConocoPhillips filed on May 14, 2014; 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.

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 5, 2014