COP 10-Q Quarterly Report Sept. 30, 2011

CONOCOPHILLIPS

10-Qs and 10-Ks

10-Q	Quarter ended March 31, 2025
10-K	Fiscal year ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-Q	Quarter ended March 31, 2024
10-K	Fiscal year ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-Q	Quarter ended March 31, 2023
10-K	Fiscal year ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-Q	Quarter ended March 31, 2022
10-K	Fiscal year ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-Q	Quarter ended March 31, 2021
10-K	Fiscal year ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-Q	Quarter ended March 31, 2020
10-K	Fiscal year ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-Q	Quarter ended March 31, 2019
10-K	Fiscal year ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-Q	Quarter ended March 31, 2018
10-K	Fiscal year ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-Q	Quarter ended March 31, 2017
10-K	Fiscal year ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-Q	Quarter ended March 31, 2016
10-K	Fiscal year ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-Q	Quarter ended March 31, 2015
10-K	Fiscal year ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-Q	Quarter ended March 31, 2014
10-K	Fiscal year ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-Q	Quarter ended March 31, 2013
10-K	Fiscal year ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-Q	Quarter ended March 31, 2012
10-K	Fiscal year ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-Q	Quarter ended March 31, 2011
10-K	Fiscal year ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-Q	Quarter ended March 31, 2010
10-K	Fiscal year ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on March 31, 2025
DEF 14A	Filed on April 1, 2024
DEF 14A	Filed on April 3, 2023
DEF 14A	Filed on March 28, 2022
DEF 14A	Filed on March 29, 2021
DEF 14A	Filed on March 30, 2020
DEF 14A	Filed on April 1, 2019
DEF 14A	Filed on April 2, 2018
DEF 14A	Filed on April 3, 2017
DEF 14A	Filed on March 28, 2016
DEF 14A	Filed on March 27, 2015
DEF 14A	Filed on March 28, 2014
DEF 14A	Filed on March 28, 2013
DEF 14A	Filed on March 28, 2012
DEF 14A	Filed on March 31, 2011
DEF 14A	Filed on March 31, 2010

10-Q 1 h84155e10vq.htm FORM 10-Q e10vq

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 September 30, 2011


[ ]		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		(I.R.S. Employer
incorporation or organization)		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 1,327,738,781 shares of common stock, $.01 par value, outstanding at September 30, 2011.

CONOCOPHILLIPS

TABLE OF CONTENTS


	Page
Part I — Financial Information		1

Item 1. Financial Statements		1
Consolidated Income Statement		1
Consolidated Balance Sheet		2
Consolidated Statement of Cash Flows		3
Notes to Consolidated Financial Statements		4
Supplementary Information—Condensed Consolidating Financial Information		26

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31

Item 3. Quantitative and Qualitative Disclosures About Market Risk		50

Item 4. Controls and Procedures		50

Part II — Other Information

Item 1. Legal Proceedings		51

Item 1A. Risk Factors		52

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		52

Item 6. Exhibits		53

Signature		54
EX-12
EX-31.1
EX-31.2
EX-32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS




Consolidated Income Statement		ConocoPhillips


	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010
Revenues and Other Income
Sales and other operating revenues*	$	62,784			47,208			184,941			137,715
Equity in earnings of affiliates		1,298			1,004			3,475			2,960
Gain (loss) on dispositions**		(480	)		1,398			214			4,671
Other income (loss)**		27			(61	)		207			92

Total Revenues and Other Income		63,629			49,549			188,837			145,438


Costs and Expenses
Purchased crude oil, natural gas and products		47,597			34,051			140,106			97,660
Production and operating expenses		2,768			2,583			8,002			7,729
Selling, general and administrative expenses		466			493			1,479			1,375
Exploration expenses		266			252			706			848
Depreciation, depletion and amortization		1,870			2,246			6,015			6,844
Impairments		486			59			488			1,682
Taxes other than income taxes*		4,579			4,227			13,773			12,511
Accretion on discounted liabilities		114			110			341			337
Interest and debt expense		235			264			744			914
Foreign currency transaction (gains) losses		68			(10	)		15			80

Total Costs and Expenses		58,449			44,275			171,669			129,980

Income before income taxes		5,180			5,274			17,168			15,458
Provision for income taxes		2,549			2,205			8,076			6,094

Net income		2,631			3,069			9,092			9,364
Less: net income attributable to noncontrolling interests		(15	)		(14	)		(46	)		(47	)

Net Income Attributable to ConocoPhillips	$	2,616			3,055			9,046			9,317


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic	$	1.93			2.06			6.48			6.26
Diluted		1.91			2.05			6.42			6.21


Dividends Paid Per Share of Common Stock (dollars)	$	.66			.55			1.98			1.60


Average Common Shares Outstanding (in thousands)
Basic		1,357,710			1,481,522			1,396,216			1,488,024
Diluted		1,369,562			1,493,080			1,408,846			1,499,367

* Includes excise taxes on petroleum products sales:	$	*3,596*			3,544			*10,532*			10,181

** 2010 has been reclassified to conform to current-year presentation.

See Notes to Consolidated Financial Statements.




Consolidated Balance Sheet		ConocoPhillips


	Millions of Dollars
	September 30			December 31
	2011			2010

Assets
Cash and cash equivalents	$	3,437			9,454
Short-term investments*		2,589			973
Accounts and notes receivable (net of allowance of $29 million in 2011 and $32 million in 2010)		14,440			13,787
Accounts and notes receivable—related parties		1,976			2,025
Investment in LUKOIL		-			1,083
Inventories		7,164			5,197
Prepaid expenses and other current assets		2,785			2,141

Total Current Assets		32,391			34,660
Investments and long-term receivables		32,152			31,581
Loans and advances—related parties		1,694			2,180
Net properties, plants and equipment		83,090			82,554
Goodwill		3,606			3,633
Intangibles		764			801
Other assets		992			905

Total Assets	$	154,689			156,314


Liabilities
Accounts payable	$	18,855			16,613
Accounts payable—related parties		1,980			1,786
Short-term debt		616			936
Accrued income and other taxes		4,573			4,874
Employee benefit obligations		894			1,081
Other accruals		2,018			2,129

Total Current Liabilities		28,936			27,419
Long-term debt		22,534			22,656
Asset retirement obligations and accrued environmental costs		9,286			9,199
Joint venture acquisition obligation—related party		3,769			4,314
Deferred income taxes		17,979			17,335
Employee benefit obligations		3,078			3,683
Other liabilities and deferred credits		2,781			2,599

Total Liabilities		88,363			87,205


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2011—1,746,731,975 shares; 2010—1,740,529,279 shares)
Par value		17			17
Capital in excess of par		44,610			44,132
Grantor trusts (at cost: 2011—189,697 shares; 2010—36,890,375 shares)		(11	)		(633	)
Treasury stock (at cost: 2011—418,803,497 shares; 2010—272,873,537 shares)		(28,671	)		(20,077	)
Accumulated other comprehensive income		3,203			4,773
Unearned employee compensation		(23	)		(47	)
Retained earnings		46,681			40,397

Total Common Stockholders’ Equity		65,806			68,562
Noncontrolling interests		520			547

Total Equity		66,326			69,109

Total Liabilities and Equity	$	154,689			156,314

*Includes marketable securities of:	$	*1,442*			602

See Notes to Consolidated Financial Statements.




Consolidated Statement of Cash Flows		ConocoPhillips


	Millions of Dollars
	Nine Months Ended
	September 30
	2011			2010

Cash Flows From Operating Activities
Net income	$	9,092			9,364
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		6,015			6,844
Impairments		488			1,682
Dry hole costs and leasehold impairments		290			327
Accretion on discounted liabilities		341			337
Deferred taxes		809			(935	)
Undistributed equity earnings		(1,392	)		(1,642	)
Gain on dispositions		(214	)		(4,671	)
Other		(216	)		(221	)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		(1,006	)		323
Decrease (increase) in inventories		(1,979	)		(2,898	)
Decrease (increase) in prepaid expenses and other current assets		(556	)		(459	)
Increase (decrease) in accounts payable		2,759			401
Increase (decrease) in taxes and other accruals		(597	)		2,402

Net Cash Provided by Operating Activities		13,834			10,854


Cash Flows From Investing Activities
Capital expenditures and investments		(9,394	)		(6,371	)
Proceeds from asset dispositions		2,158			12,233
Net purchases of short-term investments		(1,623	)		-
Long-term advances/loans—related parties		(14	)		(296	)
Collection of advances/loans—related parties		638			104
Other		96			114

Net Cash Provided by (Used in) Investing Activities		(8,139	)		5,784


Cash Flows From Financing Activities
Issuance of debt		-			96
Repayment of debt		(440	)		(5,304	)
Issuance of company common stock		109			59
Repurchase of company common stock		(7,984	)		(1,258	)
Dividends paid on company common stock		(2,761	)		(2,376	)
Other		(542	)		(544	)

Net Cash Used in Financing Activities		(11,618	)		(9,327	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(94	)		143


Net Change in Cash and Cash Equivalents		(6,017	)		7,454
Cash and cash equivalents at beginning of period		9,454			542

Cash and Cash Equivalents at End of Period	$	3,437			7,996

See Notes to Consolidated Financial Statements.



Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Interim Financial Information

The interim-period financial information presented in the financial statements included in this report is unaudited and includes all known accruals and adjustments, in the opinion of management, 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. To enhance your understanding of these interim financial statements, see the consolidated financial statements and notes included in our 2010 Annual Report on Form 10-K.

Note 2— Variable Interest Entities (VIEs)

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

We have a 30 percent ownership interest with a 50 percent governance interest in the OOO Naryanmarneftegaz (NMNG) joint venture to develop resources in the Timan-Pechora province of Russia. The NMNG joint venture is a VIE because we and our co-venturer, LUKOIL, have disproportionate interests, and LUKOIL was a related party at inception of the joint venture. Since LUKOIL is no longer a related party, we do not believe NMNG would be a VIE if reconsidered today. LUKOIL owns 70 percent versus our 30 percent direct interest; therefore, we have determined we are not the primary beneficiary of NMNG, and we use the equity method of accounting for this investment. The funding of NMNG has been provided with equity contributions, primarily for the development of the Yuzhno Khylchuyu (YK) Field. The book value of our investment in the venture was $677 million and $735 million at September 30, 2011, and December 31, 2010, respectively.

We have an agreement with Freeport LNG Development, L.P. (Freeport LNG) to participate in a liquefied natural gas (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. The terminal became operational in June 2008, and we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008, and the loan balance outstanding was $622 million at September 30, 2011, and $653 million at December 31, 2010. 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. We 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 investment.

Note 3—Inventories

Inventories consisted of the following:


	Millions of Dollars
	September 30		December 31
	2011		2010

Crude oil and petroleum products	$	6,164		4,254
Materials, supplies and other		1,000		943

	$	7,164		5,197

Inventories valued on the last-in, first-out (LIFO) basis totaled $5,883 million and $4,051 million at September 30, 2011, and December 31, 2010, respectively. The estimated excess of current replacement cost over LIFO cost of inventories amounted to approximately $7,300 million and $6,800 million at September 30, 2011, and December 31, 2010, respectively.

Note 4—Investments, Loans and Long-Term Receivables

Australia Pacific LNG

In April 2011, Australia Pacific LNG Pty Ltd (APLNG) and China Petrochemical Corporation (Sinopec) signed definitive agreements for APLNG to supply up to 4.3 million tonnes per annum of LNG for 20 years. The agreements also specify terms under which Sinopec subscribed for a 15 percent equity interest in APLNG, with both our ownership interest and Origin Energy’s ownership interest diluting to 42.5 percent. The Subscription Agreement was completed in August 2011, and we recorded a loss on disposition of $279 million before- and after-tax from the dilution. The book value of our investment in APLNG was reduced by $795 million, and we reduced the currency translation adjustment associated with our investment by $516 million.

LUKOIL

We completed the disposition of our interest in LUKOIL during the first quarter of 2011, realizing a before-tax gain of $360 million and cash proceeds of $1,243 million. The cost basis for shares sold was average cost.

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 September 30, 2011, included the following:

	•		$622 million in loan financing to Freeport LNG.
	•		$1,159 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 the consolidated balance sheet, while the short-term portion is in “Accounts and notes receivable—related parties.”

WRB Refining LP fully repaid its outstanding loans from us with payments of $150 million in the third quarter of 2011 and $400 million in the second quarter of 2011.

Significant long-term receivables from, and loans to, non-affiliated companies at September 30, 2011, included $365 million related to seller financing of U.S. retail marketing assets. Long-term receivables and the long-term portion of these loans are included in the “Investments and long-term receivables” line item on the consolidated balance sheet, while the short-term portion related to non-affiliate loans is in “Accounts and notes receivable.”

Other

We have investments remeasured at fair value on a recurring basis to support certain nonqualified deferred compensation plans. The fair value of these assets at September 30, 2011, was $315 million, and at December 31, 2010, was $325 million. Substantially the entire value is categorized in Level 1 of the fair value hierarchy. These investments are measured at fair value using a market approach based on quotations from national securities exchanges.

Merey Sweeny, L.P. (MSLP) is a limited partnership that owns a delayed coker and related facilities at the Sweeny Refinery. MSLP processes our long residue, which is produced from heavy sour crude oil, for a processing fee. Fuel-grade petroleum coke is produced as a by-product and becomes the property of MSLP. Prior to August 28, 2009, MSLP was owned 50/50 by us and Petróleos de Venezuela S.A. (PDVSA). Under the agreements that govern the relationships between the partners, certain defaults by PDVSA with respect to

supply of crude oil to the Sweeny Refinery gave us the right to acquire PDVSA’s 50 percent ownership interest in MSLP. On August 28, 2009, we exercised that right. PDVSA has initiated arbitration in the International Chamber of Commerce challenging our actions, and the arbitration process is underway. We continue to use the equity method of accounting for our investment in MSLP.

Note 5—Assets Held for Sale or Sold

On August 31, 2011, we sold our refinery in Wilhelmshaven, Germany, which had been operating as a terminal since the fourth quarter of 2009. The refinery was included in our Refining and Marketing segment and at the time of disposition had a net carrying value of $211 million, which included $243 million of properties, plants and equipment. The $228 million before-tax loss on this disposition was included in the “Gain (loss) on dispositions” line in the consolidated income statement.

Note 6—Properties, Plants and Equipment

Our investment in properties, plants and equipment (PP&E), with the associated accumulated depreciation, depletion and amortization (Accum. DD&A), was:


	Millions of Dollars
	September 30, 2011						December 31, 2010
	Gross		Accum.		Net		Gross		Accum.		Net
	PP&E		DD&A		PP&E		PP&E		DD&A		PP&E
Exploration and Production (E&P)	$	122,378		54,763		67,615		116,805		50,501		66,304
Midstream		133		84		49		128		80		48
Refining and Marketing (R&M)		21,848		8,012		13,836		23,579		8,999		14,580
LUKOIL Investment		-		-		-		-		-		-
Chemicals		-		-		-		-		-		-
Emerging Businesses		1,026		208		818		981		161		820
Corporate and Other		1,750		978		772		1,732		930		802

	$	147,135		64,045		83,090		143,225		60,671		82,554

Note 7—Suspended Wells

The capitalized cost of suspended wells at September 30, 2011, was $1,044 million, an increase of $31 million from $1,013 million at year-end 2010. For the category of exploratory well costs capitalized for a period greater than one year as of December 31, 2010, no wells were charged to dry hole expense during the first nine months of 2011.

Note 8—Impairments

During the three- and nine-month periods of 2011 and 2010, we recognized the following before-tax impairment charges:


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011		2010
E&P
United States	$	-		29		-		29
International		-		4		-		5
R&M
United States		486		-		487		17
International		-		-		1		1,600
Emerging Businesses		-		26		-		31

	$	486		59		488		1,682

2011

The third quarter and nine-month periods of 2011 included the $484 million impairment of our refinery and associated pipelines and terminals in Trainer, Pennsylvania. In September 2011, we announced plans to seek a buyer for the refinery and have idled the facility. If unable to sell the refinery, we expect to permanently close the plant by the end of the first quarter of 2012.

2010

The nine-month period of 2010 included the $1,502 million impairment of our refinery in Wilhelmshaven, Germany, due to canceled plans for a project to upgrade the refinery, and a $98 million property impairment in international R&M to write-off capitalized project costs, as a result of our decision to end our participation in a new refinery project in Yanbu Industrial City, Saudi Arabia.

Fair Value Remeasurements

There were no material fair value impairments as of September 30, 2011. The following table shows the values of assets at December 31, 2010, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition:


	Millions of Dollars
			Fair Value
			Measurements Using
			Level 1		Level 3		Before-
	Fair Value *		Inputs		Inputs		Tax Loss
December 31, 2010
Net properties, plants and equipment (held for use)	$	307		-		307		1,604*	*
Net properties, plants and equipment (held for sale)		23		5		18		43
Equity method investments		735		-		735		645

*Represents the fair value at the time of the impairment.

**Includes a $55 million leasehold impairment charged to exploration expenses.

During 2010, net properties, plants and equipment held for use with a carrying amount of $1,911 million were written down to a fair value of $307 million, resulting in a before-tax loss of $1,604 million. The fair values were determined by the use of internal discounted cash flow models using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants and cash flow multiples for similar assets and alternative use.

Also during 2010, net properties, plants and equipment held for sale with a carrying amount of $64 million were written down to their fair value of $23 million less cost to sell of $2 million for a net $21 million, resulting in a before-tax loss of $43 million. The fair values were primarily determined by binding negotiated selling prices with third parties, with some adjusted for the fair value of certain liabilities retained.

In addition, an equity method investment associated with our E&P segment was determined to have a fair value below carrying amount, and the impairment was considered to be other than temporary. This investment with a book value of $1,380 million was written down to its fair value of $735 million, resulting in a charge of $645 million before-tax. The fair value was determined by the application of an internal discounted cash flow model using estimates of future production, prices, costs and a discount rate believed to be consistent with those used by principal market participants; the analysis also considered market data for certain undeveloped properties.

Note 9—Debt

In August 2011, we increased our total revolving credit facilities from $7.85 billion to $8.0 billion. We replaced our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. The terms of the new revolving credit facility are similar to the terms of the replaced facility. We also have a $500 million facility expiring in July 2012.

We have two commercial paper programs supported by the $8.0 billion revolving credit facilities: the ConocoPhillips $6.35 billion program, primarily a funding source for short-term working capital needs, and the ConocoPhillips Qatar Funding Ltd. $1.5 billion program, which is used to fund commitments relating to the QG3 Project. Commercial paper maturities are generally limited to 90 days.

At both September 30, 2011, and December 31, 2010, we had no direct outstanding borrowings under our revolving credit facilities, but $40 million in letters of credit had been issued. In addition, under the two commercial paper programs, there was $1,127 million of commercial paper outstanding at September 30, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,127 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at September 30, 2011.

During the first nine months of 2011, $328 million of our 9.375% Notes were repaid at their maturity.

At September 30, 2011, we classified $1,060 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 facilities.

Note 10—Joint Venture Acquisition Obligation

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, $723 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $518 million in the first nine months of 2011, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of

the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

Note 11—Noncontrolling Interests

Activity for the equity attributable to noncontrolling interests for the first nine months of 2011 and 2010 was as follows:


	Millions of Dollars
	2011									2010
	Common			Non-						Common			Non-
	Stockholders’			Controlling			Total			Stockholders’			Controlling			Total
	Equity			Interests			Equity			Equity			Interests			Equity
Balance at January 1	$	68,562			547			69,109			62,023			590			62,613
Net income		9,046			46			9,092			9,317			47			9,364
Dividends		(2,761	)		-			(2,761	)		(2,376	)		-			(2,376	)
Repurchase of company common stock		(7,984	)		-			(7,984	)		(1,258	)		-			(1,258	)
Distributions to noncontrolling interests		-			(70	)		(70	)		-			(80	)		(80	)
Other changes, net*		(1,057	)		(3	)		(1,060	)		1,655			(1	)		1,654

Balance at September 30	$	65,806			520			66,326			69,361			556			69,917

*Includes components of other comprehensive income, which are disclosed separately in Note 15—Comprehensive Income.

Note 12—Guarantees

At September 30, 2011, 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 guarantee and expect future performance to be either immaterial or have only a remote chance of occurrence.

Construction Completion Guarantees

In December 2005, we issued a construction completion guarantee for 30 percent of the $4.0 billion in loan facilities of QG3, which were used to finance the construction of an LNG train in Qatar. Of the $4.0 billion in loan facilities, we committed to provide $1.2 billion. The maximum potential amount of future payments to third-party lenders under the guarantee is estimated to be $850 million, which could become payable if the full debt financing is utilized and completion of the QG3 Project is not achieved. The project financing will be nonrecourse to ConocoPhillips upon certified completion. Completion assessment is ongoing with certification expected later in 2011. At September 30, 2011, the carrying value of the guarantee to third-party lenders was $11 million.

Guarantees of Joint Venture Debt

At September 30, 2011, we had guarantees outstanding for our portion of certain joint venture debt obligations, which have terms of up to 14 years. The maximum potential amount of future payments under the guarantees is approximately $70 million. Payment would be required if a joint venture defaults on its debt obligations.

Other Guarantees

	•		In conjunction with our purchase of an ownership interest in APLNG from Origin Energy in 2008, we agreed to participate, if and when requested, in any parent company guarantees that were outstanding at that time. These parent company guarantees cover the obligation of APLNG to deliver natural gas under several sales agreements with remaining terms of 6 to 20 years. Our maximum potential amount of future payments, or cost of volume delivery, under these guarantees is estimated to be $1,282 million ($2,824 million in the event of intentional or reckless breach) at September 2011 exchange rates based on our 42.5 percent share of the remaining contracted volumes, which could 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. Additionally, we have guaranteed the performance of APLNG with regard to certain contracts executed in connection with APLNG’s issuance of the Train 1 Notice to Proceed. One guarantee is for the life of the venture, and the others extend for a maximum of five years. Our maximum potential amount of future payments related to these guarantees is estimated to be $177 million at September 30, 2011.

	•		We have other guarantees with maximum future potential payment amounts totaling $450 million, which consist primarily of guarantees to fund the short-term cash liquidity deficits of certain joint ventures, guarantees of minimum charter revenue for two LNG vessels, one small construction completion guarantee, guarantees of the lease payment obligations of a joint venture, guarantees of the residual value of leased corporate aircraft, and guarantees of the performance of a business partner or some of its customers. These guarantees generally extend up to 13 years or life of the venture.

Indemnifications

Over the years, we have entered into various agreements to sell ownership interests in certain corporations, joint ventures and assets that gave rise to qualifying indemnifications. Agreements associated with these sales include indemnifications for taxes, environmental liabilities, permits and licenses, employee claims, real estate indemnity against tenant defaults, 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 September 30, 2011, was $399 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 were $231 million of environmental accruals for known contamination that are included in asset retirement obligations and accrued environmental costs at September 30, 2011. For additional information about environmental liabilities, see Note 13—Contingencies and Commitments.

Note 13—Contingencies and Commitments

A number of lawsuits involving a variety of claims have been made against ConocoPhillips that arise in the ordinary course of business. 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. In the case of 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 state 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 state agencies 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 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 September 30, 2011, our balance sheet included a total environmental accrual of $926 million, compared with $994 million at December 31, 2010. 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

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 September 30, 2011, we had performance obligations secured by letters of credit of $1,962 million (of which $40 million was issued under the provisions of our revolving credit facility, and the remainder was issued as direct bank letters of credit) related to various purchase commitments for materials, supplies, services and items of permanent investment 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, 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, and we are currently awaiting an interim decision on key legal and factual issues.

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 ICSID, Ecuador confiscated the crude oil production of Burlington and its co-venturer and sold the illegally 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. An arbitration hearing on case merits occurred in March 2011. On September 30, 2011, Ecuador filed a supplemental counterclaim asserting environmental damages, which we believe will not be material. The arbitration process is ongoing.

Note 14—Financial Instruments and Derivative Contracts

Financial Instruments

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

	•		Time Deposits: Interest bearing deposits placed with approved financial institutions.
	•		Commercial Paper: Unsecured promissory notes issued by a corporation, commercial bank, or government agency purchased at a discount, maturing at par.
	•		Government or government agency obligations: Negotiable debt obligations issued by a government or government agency.

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


	Millions of Dollars
	Carrying Amount
	Cash and Cash Equivalents				Short-Term Investments*
	September 30		December 31		September 30		December 31
	2011		2010		2011		2010
Cash	$	902		1,284		-		-

Time Deposits
Remaining maturities from 1 to 90 days		1,988		6,154		696		302
Remaining maturities from 91 to 180 days		-		-		451		69
Commercial Paper
Remaining maturities from 1 to 90 days		516		1,566		828		525
Remaining maturities from 91 to 182 days		-		-		614		-
Government Obligations
Remaining maturities from 1 to 90 days		31		450		-		77
Remaining maturities from 91 to 180 days		-		-		-		-

	$	3,437		9,454		2,589		973

*Carrying value approximates fair value.

Derivative Instruments

We use financial and commodity-based derivative contracts to manage exposures to fluctuations in foreign currency exchange rates, commodity prices, and interest rates, or to capture market opportunities. Since we are not currently using cash flow hedge accounting, all gains and losses, realized or unrealized, from derivative contracts have been recognized in the consolidated income statement. Gains and losses from derivative contracts held for trading not directly related to our physical business, whether realized or unrealized, have been reported net in the “Other income (loss)” line of our consolidated income statement.

Purchase and sales contracts with fixed minimum notional volumes for commodities that are readily convertible to cash (e.g., crude oil, natural gas and gasoline) are recorded on the balance sheet as derivatives unless the contracts are eligible for and we elect the normal purchases and normal sales exception (i.e., contracts to purchase or sell quantities we expect to use or sell over a reasonable period in the normal course of business). We record most of our contracts to buy or sell natural gas and the majority of our contracts to sell power as derivatives, but we do apply the normal purchases and normal sales exception to certain long-term contracts to sell our natural gas production. We generally apply this normal purchases and normal sales exception to eligible crude oil and refined product commodity purchase and sales contracts;

however, we may elect not to apply this exception (e.g., when another derivative instrument will be used to mitigate the risk of the purchase or sales contract but hedge accounting will not be applied, in which case both the purchase or sales contract and the derivative contract mitigating the resulting risk will be recorded on the balance sheet at fair value).

We generally value our exchange-traded derivatives using closing prices provided by the exchange as of the balance sheet date, and these are classified as Level 1 in the fair value hierarchy. Where exchange-provided prices are adjusted, non-exchange quotes are used or when the instrument lacks sufficient liquidity, we generally classify those exchange-cleared contracts as Level 2. Over-the-counter (OTC) financial swaps and physical commodity forward purchase and sales contracts are generally valued using quotations provided by brokers and price index developers, such as Platts and Oil Price Information Service. These quotes are corroborated with market data and are classified as Level 2. In certain less liquid markets or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC swaps and physical commodity purchase and sales contracts are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. A contract that is initially classified as Level 3 due to absence or insufficient corroboration of broker quotes over a material portion of the contract will transfer to Level 2 when the portion of the trade having no quotes or insufficient corroboration becomes an insignificant portion of the contract. A contract would also transfer to Level 2 if we began using a corroborated broker quote that has become available. Conversely, if a corroborated broker quote ceases to be available or used by us, the contract would transfer from Level 2 to Level 3. There were no material transfers in or out of Level 1.

Financial OTC and physical commodity options are valued using industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic measures. The degree to which these inputs are observable in the forward markets determines whether the options are classified as Level 2 or 3.

We use a mid-market pricing convention (the mid-point between bid and ask prices). When appropriate, valuations are adjusted to reflect credit considerations, generally based on available market evidence.

The fair value hierarchy for our derivative assets and liabilities accounted for at fair value on a recurring basis was:


	Millions of Dollars
	September 30, 2011								December 31, 2010
	Level 1		Level 2		Level 3		Total		Level 1			Level 2		Level 3		Total

Assets
Commodity derivatives*	$	3,851		1,895		68		5,814		1,456			1,744		63		3,263
Interest rate derivatives		-		31		-		31		-			20		-		20
Foreign currency exchange derivatives		-		10		-		10		-			15		-		15

Total assets		3,851		1,936		68		5,855		1,456			1,779		63		3,298


Liabilities
Commodity derivatives*		3,839		1,713		21		5,573		1,611			1,737		36		3,384
Foreign currency exchange derivatives		-		18		-		18		-			9		-		9

Total liabilities		3,839		1,731		21		5,591		1,611			1,746		36		3,393

Net assets (liabilities)	$	12		205		47		264		(155	)		33		27		(95	)

* 2010 has been reclassified to conform to current-year presentation.

The derivative values above are based on analysis of each contract as the fundamental unit of account; therefore, derivative assets and liabilities with the same counterparty are not reflected net where the right of setoff exists. Gains or losses from contracts in one level may be offset by gains or losses on contracts in another level or by changes in values of physical contracts or positions that are not reflected in the table above.

As reflected in the table above, Level 3 activity was not material.

Commodity Derivative Contracts — We operate in the worldwide crude oil, bitumen, refined product, natural gas, LNG, natural gas liquids and electric power markets and are exposed to fluctuations in the prices for these commodities. These fluctuations can affect our revenues, as well as the cost of operating, investing and financing activities. Generally, our policy is to remain exposed to the market prices of commodities; however, we use futures, forwards, swaps and options in various markets to balance physical systems, meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial amount of trading not directly related to our physical business. We also use the market knowledge gained from these activities to capture market opportunities such as moving physical commodities to more profitable locations, storing commodities to capture seasonal or time premiums, and blending commodities to capture quality upgrades. Derivatives may be used to optimize these activities which may move our risk profile away from market average prices.

The fair value of commodity derivative assets and liabilities and the line items where they appear on our consolidated balance sheet were:


	Millions of Dollars
	September 30		December 31
	2011		2010

Assets
Prepaid expenses and other current assets	$	5,595		3,073
Other assets		300		211
Liabilities
Other accruals		5,387		3,212
Other liabilities and deferred credits		267		193

Hedge accounting has not been used for any item in the table. The amounts shown are presented gross (i.e., without netting assets and liabilities with the same counterparty where the right of setoff exists).

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						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010

Sales and other operating revenues	$	437			227			(276	)		(430	)
Other income		1			3			(8	)		(26	)
Purchased crude oil, natural gas and products		(46	)		(270	)		179			596

Hedge accounting has not been used for any item in the table.

The following table summarizes our material net exposures resulting from outstanding commodity derivative contracts. These financial and physical derivative contracts are primarily used to manage price exposures on our underlying operations. The underlying exposures may be from non-derivative positions, such as inventory volumes or firm natural gas transport contracts. Financial derivative contracts may also offset physical derivative contracts, such as forward sales contracts.


	Open Position
	Long/(Short)
	September 30			December 31
	2011			2010

Commodity
Crude oil, refined products and natural gas liquids (millions of barrels)		(38	)		(16	)
Natural gas and power (billions of cubic feet equivalent)
Fixed price		(53	)		(69	)
Basis		(75	)		(43	)

Interest Rate Derivative Contracts— During the second quarter of 2010, we executed interest rate swaps to synthetically convert $500 million of our 4.60% fixed-rate notes due in 2015 to a floating rate based on the London Interbank Offered Rate (LIBOR). These swaps qualify for and are designated as fair-value hedges using the short-cut method of hedge accounting. The short-cut method permits the assumption that changes in the value of the derivative perfectly offset changes in the value of the debt; therefore, no gain or loss has been recognized due to hedge ineffectiveness.

The adjustments to the fair values of the interest rate swaps and hedged debt have not been material.

Foreign Currency Exchange Derivatives — We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to movements in currency exchange rates, although we may choose to selectively hedge certain foreign currency exchange rate exposures, such as firm commitments for capital projects or local currency tax payments, dividends, and cash returns from net investments in foreign affiliates to be remitted within the coming year.

The fair value of foreign currency exchange derivative assets and liabilities, and the line items where they appear on our consolidated balance sheet were:


	Millions of Dollars
	September 30		December 31
	2011		2010

Assets
Prepaid expenses and other current assets	$	8		14
Other assets		2		1
Liabilities
Other accruals		18		7
Other liabilities and deferred credits		-		2

Hedge accounting has not been used for any item in the table. The amounts shown are presented gross.

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


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011			2010
Foreign exchange transaction (gains) losses	$	3		18		(3	)		121

Hedge accounting has not been used for any item in the table.

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

In Millions

Notional Currency*

September 30

December 31

2011

2010

Foreign Exchange Derivatives

Sell U.S. dollar, buy other currencies**

USD

1,565

569

Sell euro, buy British pound

EUR

176

253

*Denominated in U.S. dollars (USD) and euros (EUR).

**Primarily euro, Canadian dollar, Norwegian krone and British pound.

Credit Risk

Financial instruments potentially exposed to concentrations of credit risk consist primarily of cash equivalents, 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.

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.

The aggregate fair value of all derivative instruments with such credit-risk-related contingent features that were in a liability position on September 30, 2011, and December 31, 2010, was $139 million and $225 million, respectively, for which no collateral was posted. If our credit rating were lowered one level from its “A” rating (per Standard and Poor’s) on September 30, 2011, we would be required to post no additional collateral to our counterparties. If we were downgraded below investment grade, we would be required to post $139 million of additional collateral, either with cash or letters of credit.

Fair Values of Financial Instruments

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

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

•

Investment in LUKOIL shares: We completed the disposition of our interest in LUKOIL during the first quarter of 2011. At December 31, 2010, our investment in LUKOIL was carried at fair value of $1,083 million, reflecting a closing price of LUKOIL American Depositary Receipts (ADRs) on the London Stock Exchange of $56.50 per share.

•

Debt: The carrying amount of our floating-rate debt approximates fair value. The fair value of the fixed-rate debt is estimated based on quoted market prices.

•

Fixed-rate 5.3 percent joint venture acquisition obligation: Fair value is estimated based on the net present value of the future cash flows, discounted at September 30, 2011, and December 31, 2010, using effective yield rates of 1.25 percent and 1.87 percent, respectively, based on yields of U.S. Treasury securities of similar average duration adjusted for our average credit risk spread and the amortizing nature of the obligation principal. See Note 10—Joint Venture Acquisition Obligation, for additional information.

•

Commodity swaps: Fair value is estimated based on forward market prices and approximates the exit price at period end. When forward market prices are not available, fair value is estimated using the forward prices of a similar commodity with adjustments for differences in quality or location.

•

Futures: Fair values are based on quoted market prices obtained from the New York Mercantile Exchange, the Intercontinental Exchange (ICE) Futures, or other traded exchanges.

•

Interest rate swap contracts: Fair value is estimated based on a pricing model and market observable interest rate swap curves obtained from a third-party market data provider.

•

Forward-exchange contracts: Fair values are estimated by comparing the contract rate to the forward rates in effect at the end of the respective reporting periods, and approximate the exit prices at those dates.

Our commodity derivative and financial instruments were:


	Millions of Dollars
	Carrying Amount				Fair Value
	September 30		December 31		September 30		December 31
	2011		2010		2011		2010
Financial assets
Foreign currency exchange derivatives	$	10		15		10		15
Interest rate derivatives		31		20		31		20
Commodity derivatives		762		624		762		624
Investment in LUKOIL		-		1,083		-		1,083
Financial liabilities
Total debt, excluding capital leases		23,118		23,553		27,074		26,144
Joint venture acquisition obligation		4,492		5,009		5,041		5,600
Foreign currency exchange derivatives		18		9		18		9
Commodity derivatives		426		426		426		426

The amounts shown for derivatives in the preceding table are presented net (i.e., assets and liabilities with the same counterparty are netted where the right of setoff exists). In addition, the September 30, 2011, commodity derivative assets and liabilities appear net of $53 million of obligations to return cash collateral and $148 million of rights to reclaim cash collateral, respectively. The December 31, 2010, commodity derivative assets and liabilities appear net of $5 million of obligations to return cash collateral and $324 million of rights to reclaim cash collateral, respectively. No collateral was deposited or held for the foreign currency derivatives or interest rate derivatives.

Note 15—Comprehensive Income (Loss)

ConocoPhillips’ comprehensive income (loss) was as follows:


	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010
Net income	$	2,631			3,069			9,092			9,364
After-tax changes in:
Defined benefit plans
Net prior service cost		1			2			2			6
Net actuarial gain		44			33			111			103
Nonsponsored plans		3			14			10			35

Net defined benefit plans		48			49			123			144

Unrealized gain on securities		-			423			-			423
Less: reclassification adjustment for gain on securities recognized in net income		-			-			(158	)		-

Net unrealized gain on securities		-			423			(158	)		423

Foreign currency translation adjustments		(2,454	)		2,052			(1,020	)		774
Less: reclassification adjustment for gains included in net income		(516	)		-			(516	)		-

Net foreign currency translation adjustments		(2,970	)		2,052			(1,536	)		774
Hedging activities		-			-			1			(1	)

Comprehensive income (loss)		(291	)		5,593			7,522			10,704
Less: comprehensive income attributable to noncontrolling interests		(15	)		(14	)		(46	)		(47	)

Comprehensive income (loss) attributable to ConocoPhillips	$	(306	)		5,579			7,476			10,657

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


	Millions of Dollars
	September 30			December 31
	2011			2010

Defined benefit plans liability adjustments	$	(1,235	)		(1,358	)
Net unrealized gain on securities		-			158
Foreign currency translation adjustments		4,444			5,980
Deferred net hedging loss		(6	)		(7	)

Accumulated other comprehensive income	$	3,203			4,773

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

Note 16—Cash Flow Information


	Millions of Dollars
	Nine Months Ended
	September 30
	2011			2010
Cash Payments
Interest	$	748			996
Income taxes		7,703			6,022


Net Purchases of Short-Term Investments
Short-term investments purchased	$	(6,642	)		-
Short-term investments sold		5,019			-

	$	(1,623	)		-

Note 17—Employee Benefit Plans

Pension and Postretirement Plans


	Millions of Dollars
	Pension Benefits												Other Benefits
Components of Net Periodic Benefit Cost	2011						2010						2011			2010
	U.S.			Int’l.			U.S.			Int’l.
Three Months Ended September 30
Service cost	$	56			25			58			22			3			3
Interest cost		62			45			65			42			10			11
Expected return on plan assets		( 70	)		(44	)		(56	)		(37	)		-			-
Amortization of prior service cost		2			-			2			-			(1	)		-
Recognized net actuarial (gain) loss		42			11			42			14			(1	)		(1	)

Net periodic benefit costs	$	92			37			111			41			11			13


Nine Months Ended September 30
Service cost	$	169			74			172			67			8			8
Interest cost		185			133			195			126			31			34
Expected return on plan assets		(210	)		(131	)		(168	)		(110	)		-			-
Amortization of prior service cost		7			-			7			-			(5	)		2
Recognized net actuarial (gain) loss		124			34			125			41			(4	)		(5	)

Net periodic benefit costs	$	275			110			331			124			30			39

In the third quarter of 2011, we recognized pension settlement losses of $19 million. None were recognized in the nine-month period of 2010. During the first nine months of 2011, we contributed $642 million to our domestic benefit plans and $177 million to our international benefit plans.

Compensation and Benefits Trust

In August 2011, all of the approximately 36 million shares of company common stock held by the Compensation and Benefits Trust (CBT) were transferred to ConocoPhillips, and those shares are now held as non-voting treasury stock. Because the CBT is consolidated by us, the transfer of its shares from “Grantor trusts” to “Treasury stock” in the equity section of our balance sheet was recorded at the shares’ historical carrying value of approximately $610 million. This transfer did not affect total equity, shares outstanding, or earnings per share. The CBT no longer holds any assets.

Note 18—Related Party Transactions

Significant transactions with related parties were:


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011		2010
Operating revenues and other income (a)	$	1,976		2,556		6,147		6,540
Purchases (b)		5,328		3,897		15,309		11,245
Operating expenses and selling, general and administrative expenses (c)		94		88		308		253
Net interest expense (d)		18		16		55		53


(a)		We sold natural gas to DCP Midstream, LLC and crude oil to the Malaysian Refining Company Sdn. Bhd. (MRC), among others, for processing and marketing. Natural gas liquids, solvents and petrochemical feedstocks were sold to Chevron Phillips Chemical Company LLC (CPChem), and gas oil and hydrogen feedstocks were sold to Excel Paralubes. Both periods of 2010 included sales of refined products to CFJ Properties and LUKOIL, which were no longer considered related parties beginning in the third and fourth quarters of 2010, respectively, due to the sales of our interests. Natural gas, crude oil, blendstock and other intermediate products were sold to WRB Refining LP. In addition, we charged several of our affiliates, including CPChem and MSLP, for the use of common facilities, such as steam generators, waste and water treaters, and warehouse facilities.

(b)		We purchased refined products from WRB and MRC. We purchased natural gas and natural gas liquids from DCP Midstream and CPChem for use in our refinery processes and other feedstocks from various affiliates. Both periods of 2010 included purchases of crude oil from LUKOIL, which was no longer considered a related party beginning in the fourth quarter of 2010. We also paid fees to various pipeline equity companies for transporting finished refined products and natural gas, as well as a price upgrade to MSLP for heavy crude processing. We purchased base oils and fuel products from Excel Paralubes for use in our refinery and lubricants businesses.

(c)		We paid processing fees to various affiliates. Additionally, we paid transportation fees to pipeline equity companies.

(d)		We paid and/or received interest to/from various affiliates, including FCCL Partnership. See Note 4—Investments, Loans and Long-Term Receivables, for additional information on loans to affiliated companies.

Note 19—Segment Disclosures and Related Information

We have organized our reporting structure based on the grouping of similar products and services, resulting in six operating segments:

E&P —This segment primarily explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis.

Midstream —This segment gathers, processes and markets natural gas produced by ConocoPhillips and others, and fractionates and markets natural gas liquids, predominantly in the United States and Trinidad. The Midstream segment primarily consists of our 50 percent equity investment in DCP Midstream.

R&M —This segment purchases, refines, markets and transports crude oil and petroleum products, mainly in the United States, Europe and Asia.

LUKOIL Investment —This segment represents our past investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. In the first quarter of 2011, we completed the divestiture of our entire interest in LUKOIL.

Chemicals —This segment manufactures and markets petrochemicals and plastics on a worldwide basis. The Chemicals segment consists of our 50 percent equity investment in CPChem.

Emerging Businesses —This segment represents our investment in new technologies or businesses outside our normal scope of operations.

Corporate and Other includes general corporate overhead, most interest expense and various other corporate activities. 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						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010
Sales and Other Operating Revenues
E&P
United States	$	8,465			6,983			24,658			22,003
International		7,907			7,416			24,462			20,842
Intersegment eliminations—U.S.		(1,963	)		(1,385	)		(5,555	)		(4,117	)
Intersegment eliminations—international		(2,046	)		(2,007	)		(6,049	)		(5,896	)

E&P		12,363			11,007			37,516			32,832

Midstream
Total sales		2,384			1,609			6,829			5,326
Intersegment eliminations		(95	)		(76	)		(380	)		(263	)

Midstream		2,289			1,533			6,449			5,063

R&M
United States		32,210			23,168			96,982			69,397
International		16,113			11,631			44,739			30,910
Intersegment eliminations—U.S.		(213	)		(175	)		(772	)		(563	)
Intersegment eliminations—international		(15	)		(10	)		(54	)		(84	)

R&M		48,095			34,614			140,895			99,660

LUKOIL Investment		-			-			-			-

Chemicals		3			3			8			8

Emerging Businesses
Total sales		214			196			572			590
Intersegment eliminations		(186	)		(153	)		(516	)		(459	)

Emerging Businesses		28			43			56			131

Corporate and Other		6			8			17			21

Consolidated sales and other operating revenues	$	62,784			47,208			184,941			137,715


Net Income Attributable to ConocoPhillips
E&P
United States	$	816		563		2,496		1,856
International		946		1,001		4,142		5,654

Total E&P		1,762		1,564		6,638		7,510

Midstream		137		77		340		215

R&M
United States		789		199		1,883		993
International		-		69		154		(1,008	)

Total R&M		789		268		2,037		(15	)

LUKOIL Investment		-		1,310		239		2,226
Chemicals		197		132		589		380
Emerging Businesses		(2	)	(20	)	(23	)	(24	)
Corporate and Other		(267	)	(276	)	(774	)	(975	)

Consolidated net income attributable to ConocoPhillips	$	2,616		3,055		9,046		9,317


	Millions of Dollars
	September 30		December 31
	2011		2010
Total Assets
E&P
United States	$	36,378		35,607
International		62,892		63,086

Total E&P		99,270		98,693

Midstream		2,467		2,506

R&M
United States		27,525		26,028
International		9,897		8,463
Goodwill		3,606		3,633

Total R&M		41,028		38,124

LUKOIL Investment		-		1,129
Chemicals		2,896		2,732
Emerging Businesses		978		964
Corporate and Other		8,050		12,166

Consolidated total assets	$	154,689		156,314

Note 20—Income Taxes

Our effective tax rate for the third quarter and first nine months of 2011 was 49 percent and 47 percent, respectively, compared with 42 percent and 39 percent for the same two periods of 2010. The increase in the effective tax rate for the third quarter of 2011, versus the third quarter of 2010, was due primarily to the impact of asset dispositions in both years and the effect of the 2011 United Kingdom tax law change, offset in part by a higher proportion of income in higher tax jurisdictions in 2010. The change in the effective tax rate for the first nine months of 2011, compared with the same period of 2010, was due primarily to asset dispositions occurring in 2010 and the 2011 U.K. tax law change, offset in part by the 2010 impairment of our Wilhelmshaven Refinery and a higher proportion of income in higher tax jurisdictions in 2010. For periods in which the effective tax rate was in excess of the domestic federal statutory rate of 35 percent, it was primarily due to foreign taxes.

In the United Kingdom, legislation was enacted on July 19, 2011, which increases the supplementary corporate tax rate applicable to U.K. upstream activity from 20 percent to 32 percent, retroactively effective from March 24, 2011. This results in the overall U.K. upstream corporate tax rate increasing from 50 percent to 62 percent. The enactment created additional tax expense during the third quarter of 2011 of $234 million. This is comprised of $106 million for the revaluation of the U.K. upstream deferred tax liability, in addition to charges of $75 million to reflect the new rate from March 24, 2011, through June 30, 2011, and $53 million to reflect the new rate from July 1, 2011, through September 30, 2011.

Note 21—New Accounting Standards

In June 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-5, “Comprehensive Income.” This ASU amends FASB Accounting Standards Codification Topic 220, “Comprehensive Income,” and requires the presentation of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. We currently plan to use the two consecutive statement approach upon adoption of this ASU.

In September 2011, the FASB issued ASU 2011-8, “Intangibles — Goodwill and Other.” This ASU provides for the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If the assessment of qualitative factors determines it is more likely than not the carrying value of a reporting unit is less than fair value, performing the two-step goodwill impairment analysis would not be necessary. This ASU is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011, with early adoption permitted. We are currently evaluating the impact of this ASU.

Note 22—Planned Separation of Downstream Businesses

On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our refining, marketing and transportation business into a stand-alone, publicly traded corporation via a tax-free distribution. We expect the new downstream company will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations. The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling, execution of separation and intercompany agreements and final Board approval, and is expected to be completed in the second quarter of 2012.

Supplementary Information—Condensed Consolidating Financial Information

We have various cross guarantees among ConocoPhillips, ConocoPhillips Company, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to publicly held debt securities. ConocoPhillips Company is wholly owned by ConocoPhillips. ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I and ConocoPhillips Canada Funding Company II are indirect, wholly owned subsidiaries of ConocoPhillips Company. ConocoPhillips and ConocoPhillips Company have fully and unconditionally guaranteed the payment obligations of ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II, with respect to their 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, ConocoPhillips Australia Funding Company, ConocoPhillips Canada Funding Company I, and ConocoPhillips Canada Funding Company II (in each case, reflecting investments in subsidiaries utilizing the equity method of accounting).
	•		All other nonguarantor subsidiaries of ConocoPhillips.
	•		The consolidating adjustments necessary to present ConocoPhillips’ results on a consolidated basis.

This condensed consolidating financial information should be read in conjunction with the accompanying consolidated financial statements and notes. Certain previously reported amounts appearing on the 2010 income statement have been reclassified to conform to current-year presentation.


	Millions of Dollars
	Three Months Ended September 30, 2011
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			38,753			-		-			-			24,031			-			62,784
Equity in earnings of affiliates		2,895			3,287			-		-			-			870			(5,754	)		1,298
Gain on dispositions		-			-			-		-			-			(480	)		-			(480	)
Other income (loss)		(1	)		(63	)		-		-			-			91			-			27
Intercompany revenues		1			934			11		23			9			9,734			(10,712	)		-

Total Revenues and Other Income		2,895			42,911			11		23			9			34,246			(16,466	)		63,629


Costs and Expenses
Purchased crude oil, natural gas and products		-			35,596			-		-			-			22,265			(10,264	)		47,597
Production and operating expenses		-			1,133			-		-			-			1,678			(43	)		2,768
Selling, general and administrative expenses		2			306			-		-			-			142			16			466
Exploration expenses		-			99			-		-			-			167			-			266
Depreciation, depletion and amortization		-			378			-		-			-			1,492			-			1,870
Impairments		-			485			-		-			-			1			-			486
Taxes other than income taxes		-			1,303			-		-			-			3,276			-			4,579
Accretion on discounted liabilities		-			17			-		-			-			97			-			114
Interest and debt expense		427			104			10		19			8			88			(421	)		235
Foreign currency transaction (gains) losses		-			7			-		(106	)		(101	)		268			-			68

Total Costs and Expenses		429			39,428			10		(87	)		(93	)		29,474			(10,712	)		58,449

Income before income taxes		2,466			3,483			1		110			102			4,772			(5,754	)		5,180
Provision for income taxes		(150	)		588			-		2			16			2,093			-			2,549

Net income		2,616			2,895			1		108			86			2,679			(5,754	)		2,631
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(15	)		-			(15	)

Net Income Attributable to ConocoPhillips	$	2,616			2,895			1		108			86			2,664			(5,754	)		2,616


Income Statement	Three Months Ended September 30, 2010
Revenues and Other Income
Sales and other operating revenues	$	-		28,283		-	-		-		18,925		-		47,208
Equity in earnings of affiliates		3,214		3,728		-	-		-		711		(6,649	)	1,004
Gain on dispositions		-		7		-	-		-		1,391		-		1,398
Other income (loss)		-		52		-	-		(28	)	(85	)	-		(61	)
Intercompany revenues		1		439		11	22		8		6,675		(7,156	)	-

Total Revenues and Other Income		3,215		32,509		11	22		(20	)	27,617		(13,805	)	49,549


Costs and Expenses
Purchased crude oil, natural gas and products		-		25,561		-	-		-		15,385		(6,895	)	34,051
Production and operating expenses		-		1,125		-	-		-		1,479		(21	)	2,583
Selling, general and administrative expenses		2		332		-	-		-		160		(1	)	493
Exploration expenses		-		91		-	-		-		161		-		252
Depreciation, depletion and amortization		-		388		-	-		-		1,858		-		2,246
Impairments		-		-		-	-		-		59		-		59
Taxes other than income taxes		-		1,328		-	-		-		2,900		(1	)	4,227
Accretion on discounted liabilities		-		15		-	-		-		95		-		110
Interest and debt expense		243		111		10	19		10		109		(238	)	264
Foreign currency transaction (gains) losses		-		(22	)	-	50		47		(85	)	-		(10	)

Total Costs and Expenses		245		28,929		10	69		57		22,121		(7,156	)	44,275

Income (loss) before income taxes		2,970		3,580		1	(47	)	(77	)	5,496		(6,649	)	5,274
Provision for income taxes		(85	)	366		-	(2	)	(15	)	1,941		-		2,205

Net income (loss)		3,055		3,214		1	(45	)	(62	)	3,555		(6,649	)	3,069
Less: net income attributable to noncontrolling interests		-		-		-	-		-		(14	)	-		(14	)

Net Income (Loss) Attributable to ConocoPhillips	$	3,055		3,214		1	(45	)	(62	)	3,541		(6,649	)	3,055


	Millions of Dollars
	Nine Months Ended September 30, 2011
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Income Statement	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Revenues and Other Income
Sales and other operating revenues	$	-			114,877			-		-			-			70,064			-			184,941
Equity in earnings of affiliates		9,773			10,462			-		-			-			2,017			(18,777	)		3,475
Gain on dispositions		-			311			-		-			-			(97	)		-			214
Other income (loss)		(1	)		49			-		-			-			159			-			207
Intercompany revenues		3			3,037			34		69			26			28,958			(32,127	)		-

Total Revenues and Other Income		9,775			128,736			34		69			26			101,101			(50,904	)		188,837


Costs and Expenses
Purchased crude oil, natural gas and products		-			106,919			-		-			-			64,071			(30,884	)		140,106
Production and operating expenses		-			3,348			-		-			-			4,815			(161	)		8,002
Selling, general and administrative expenses		11			972			-		-			-			475			21			1,479
Exploration expenses		-			221			-		-			-			482			3			706
Depreciation, depletion and amortization		-			1,149			-		-			-			4,866			-			6,015
Impairments		-			486			-		-			-			2			-			488
Taxes other than income taxes		-			3,839			-		-			-			9,935			(1	)		13,773
Accretion on discounted liabilities		-			51			-		-			-			290			-			341
Interest and debt expense		1,109			327			31		58			24			300			(1,105	)		744
Foreign currency transaction (gains) losses		-			(9	)		-		(50	)		(93	)		167			-			15

Total Costs and Expenses		1,120			117,303			31		8			(69	)		85,403			(32,127	)		171,669

Income before income taxes		8,655			11,433			3		61			95			15,698			(18,777	)		17,168
Provision for income taxes		(391	)		1,660			1		1			24			6,781			-			8,076

Net income		9,046			9,773			2		60			71			8,917			(18,777	)		9,092
Less: net income attributable to noncontrolling interests		-			-			-		-			-			(46	)		-			(46	)

Net Income Attributable to ConocoPhillips	$	9,046			9,773			2		60			71			8,871			(18,777	)		9,046


Income Statement	Nine Months Ended September 30, 2010
Revenues and Other Income
Sales and other operating revenues	$	-		85,619	-	-		-		52,096		-		137,715
Equity in earnings of affiliates		9,751		10,916	-	-		-		2,384		(20,091	)	2,960
Gain on dispositions		-		23	-	-		-		4,648		-		4,671
Other income (loss)		-		153	-	-		(28	)	(33	)	-		92
Intercompany revenues		4		713	34	65		58		19,556		(20,430	)	-

Total Revenues and Other Income		9,755		97,424	34	65		30		78,651		(40,521	)	145,438


Costs and Expenses
Purchased crude oil, natural gas and products		-		76,927	-	-		-		40,397		(19,664	)	97,660
Production and operating expenses		-		3,314	-	-		-		4,487		(72	)	7,729
Selling, general and administrative expenses		9		948	-	-		-		445		(27	)	1,375
Exploration expenses		-		188	-	-		-		660		-		848
Depreciation, depletion and amortization		-		1,204	-	-		-		5,640		-		6,844
Impairments		-		17	-	-		-		1,665		-		1,682
Taxes other than income taxes		-		3,901	-	-		-		8,611		(1	)	12,511
Accretion on discounted liabilities		-		46	-	-		-		291		-		337
Interest and debt expense		662		359	31	58		37		433		(666	)	914
Foreign currency transaction (gains) losses		-		13	-	(5	)	(6	)	78		-		80

Total Costs and Expenses		671		86,917	31	53		31		62,707		(20,430	)	129,980

Income (loss) before income taxes		9,084		10,507	3	12		(1	)	15,944		(20,091	)	15,458
Provision for income taxes		(233	)	756	1	11		5		5,554		-		6,094

Net income (loss)		9,317		9,751	2	1		(6	)	10,390		(20,091	)	9,364
Less: net income attributable to noncontrolling interests		-		-	-	-		-		(47	)	-		(47	)

Net Income (Loss) Attributable to ConocoPhillips	$	9,317		9,751	2	1		(6	)	10,343		(20,091	)	9,317


	Millions of Dollars
	September 30, 2011
						ConocoPhillips		ConocoPhillips			ConocoPhillips
						Australia		Canada			Canada
				ConocoPhillips		Funding		Funding			Funding			All Other		Consolidating			Total
Balance Sheet	ConocoPhillips			Company		Company		Company I			Company II			Subsidiaries		Adjustments			Consolidated
Assets
Cash and cash equivalents	$	-			162		2		31			2			3,661		(421	)		3,437
Short-term investments		-			-		-		-			-			2,589		-			2,589
Accounts and notes receivable		54			7,924		-		-			-			20,115		(11,677	)		16,416
Inventories		-			4,048		-		-			-			3,116		-			7,164
Prepaid expenses and other current assets		20			1,255		-		1			-			1,509		-			2,785

Total Current Assets		74			13,389		2		32			2			30,990		(12,098	)		32,391
Investments, loans and long-term receivables*		92,670			125,521		773		1,407			593			54,972		(242,090	)		33,846
Net properties, plants and equipment		-			19,271		-		-			-			63,819		-			83,090
Goodwill		-			3,606		-		-			-			-		-			3,606
Intangibles		-			738		-		-			-			26		-			764
Other assets		65			273		-		2			3			649		-			992

Total Assets	$	92,809			162,798		775		1,441			598			150,456		(254,188	)		154,689


Liabilities and Stockholders’ Equity
Accounts payable	$	-			17,607		-		3			1			15,322		(12,098	)		20,835
Short-term debt		(5	)		26		-		-			-			595		-			616
Accrued income and other taxes		-			514		-		2			-			4,057		-			4,573
Employee benefit obligations		-			667		-		-			-			227		-			894
Other accruals		153			513		19		32			14			1,287		-			2,018

Total Current Liabilities		148			19,327		19		37			15			21,488		(12,098	)		28,936
Long-term debt		11,849			3,619		750		1,250			499			4,567		-			22,534
Asset retirement obligations and accrued environmental costs		-			1,652		-		-			-			7,634		-			9,286
Joint venture acquisition obligation		-			-		-		-			-			3,769		-			3,769
Deferred income taxes		(1	)		4,020		-		13			20			13,927		-			17,979
Employee benefit obligations		-			2,241		-		-			-			837		-			3,078
Other liabilities and deferred credits*		21,856			34,930		-		62			4			19,149		(73,220	)		2,781

Total Liabilities		33,852			65,789		769		1,362			538			71,371		(85,318	)		88,363
Retained earnings		40,180			31,359		4		(35	)		(10	)		26,178		(50,995	)		46,681
Other common stockholders’ equity		18,777			65,650		2		114			70			52,387		(117,875	)		19,125
Noncontrolling interests		-			-		-		-			-			520		-			520

Total Liabilities and Stockholders’ Equity	$	92,809			162,798		775		1,441			598			150,456		(254,188	)		154,689


Balance Sheet	December 31, 2010
Assets
Cash and cash equivalents	$	-		718	-	29		4		8,703	-		9,454
Short-term investments		-		-	-	-		-		973	-		973
Accounts and notes receivable		36		9,126	1	-		-		16,625	(9,976	)	15,812
Investment in LUKOIL		-		-	-	-		-		1,083	-		1,083
Inventories		-		3,121	-	-		-		2,076	-		5,197
Prepaid expenses and other current assets		23		824	-	2		-		1,292	-		2,141

Total Current Assets		59		13,789	1	31		4		30,752	(9,976	)	34,660
Investments, loans and long-term receivables*		84,446		111,993	762	1,445		577		50,563	(216,025	)	33,761
Net properties, plants and equipment		-		19,524	-	-		-		63,030	-		82,554
Goodwill		-		3,633	-	-		-		-	-		3,633
Intangibles		-		760	-	-		-		41	-		801
Other assets		55		254	1	3		3		589	-		905

Total Assets	$	84,560		149,953	764	1,479		584		144,975	(226,001	)	156,314


Liabilities and Stockholders’ Equity
Accounts payable	$	-		14,939	-	2		-		13,434	(9,976	)	18,399
Short-term debt		(5	)	354	-	-		-		587	-		936
Accrued income and other taxes		-		431	-	-		6		4,437	-		4,874
Employee benefit obligations		-		773	-	-		-		308	-		1,081
Other accruals		242		620	9	15		6		1,237	-		2,129

Total Current Liabilities		237		17,117	9	17		12		20,003	(9,976	)	27,419
Long-term debt		11,832		3,674	750	1,250		499		4,651	-		22,656
Asset retirement obligations and accrued environmental costs		-		1,686	-	-		-		7,513	-		9,199
Joint venture acquisition obligation		-		-	-	-		-		4,314	-		4,314
Deferred income taxes		(1	)	3,659	-	16		(2	)	13,663	-		17,335
Employee benefit obligations		-		2,779	-	-		-		904	-		3,683
Other liabilities and deferred credits*		10,752		32,268	-	114		61		19,169	(59,765	)	2,599

Total Liabilities		22,820		61,183	759	1,397		570		70,217	(69,741	)	87,205
Retained earnings		33,897		21,584	3	(94	)	(81	)	20,162	(35,074	)	40,397
Other common stockholders’ equity		27,843		67,186	2	176		95		54,049	(121,186	)	28,165
Noncontrolling interests		-		-	-	-		-		547	-		547

Total Liabilities and Stockholders’ Equity	$	84,560		149,953	764	1,479		584		144,975	(226,001	)	156,314


* Includes intercompany loans.


	Millions of Dollars
	Nine Months Ended September 30, 2011
							ConocoPhillips		ConocoPhillips			ConocoPhillips
							Australia		Canada			Canada
				ConocoPhillips			Funding		Funding			Funding			All Other			Consolidating			Total
Statement of Cash Flows	ConocoPhillips			Company			Company		Company I			Company II			Subsidiaries			Adjustments			Consolidated
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	10,645			(3,268	)		2		6			(6	)		9,732			(3,277	)		13,834


Cash Flows From Investing Activities
Capital expenditures and investments		-			(1,563	)		-		-			-			(7,831	)		-			(9,394	)
Proceeds from asset dispositions		-			428			-		-			-			1,730			-			2,158
Net purchases of short-term investments		-			-			-		-			-			(1,623	)		-			(1,623	)
Long-term advances/loans—related parties		-			(113	)		-		(4	)		-			(4,562	)		4,665			(14	)
Collection of advances/loans—related parties		(1	)		1,172			-		-			-			1,504			(2,037	)		638
Other		-			7			-		-			-			89			-			96

Net Cash Provided by (Used in) Investing Activities		(1	)		(69	)		-		(4	)		-			(10,693	)		2,628			(8,139	)


Cash Flows From Financing Activities
Issuance of debt		-			4,558			-		-			4			103			(4,665	)		-
Repayment of debt		-			(1,821	)		-		-			-			(656	)		2,037			(440	)
Issuance of company common stock		109			-			-		-			-			-			-			109
Repurchase of company common stock		(7,984	)		-			-		-			-			-			-			(7,984	)
Dividends paid on common stock		(2,761	)		-			-		-			-			(2,856	)		2,856			(2,761	)
Other		(8	)		54			-		-			-			(588	)		-			(542	)

Net Cash Provided by (Used in) Financing Activities		(10,644	)		2,791			-		-			4			(3,997	)		228			(11,618	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-			(10	)		-		-			-			(84	)		-			(94	)


Net Change in Cash and Cash Equivalents		-			(556	)		2		2			(2	)		(5,042	)		(421	)		(6,017	)
Cash and cash equivalents at beginning of period		-			718			-		29			4			8,703			-			9,454

Cash and Cash Equivalents at End of Period	$	-			162			2		31			2			3,661			(421	)		3,437


Statement of Cash Flows	Nine Months Ended September 30, 2010
Cash Flows From Operating Activities
Net Cash Provided by (Used in) Operating Activities	$	4,567		2,616		-	5	(3	)	6,288		(2,619	)	10,854


Cash Flows From Investing Activities
Capital expenditures and investments		-		(1,207	)	-	-	-		(5,487	)	323		(6,371	)
Proceeds from asset dispositions		-		179		-	-	-		12,154		(100	)	12,233
Long-term advances/loans—related parties		-		(335	)	-	-	-		(1,408	)	1,447		(296	)
Collection of advances/loans—related parties		-		79		-	-	384		1,379		(1,738	)	104
Other		-		14		-	-	-		100		-		114

Net Cash Provided by (Used in) Investing Activities		-		(1,270	)	-	-	384		6,738		(68	)	5,784


Cash Flows From Financing Activities
Issuance of debt		-		1,309		-	-	-		234		(1,447	)	96
Repayment of debt		(990	)	(2,645	)	-	-	(378	)	(3,029	)	1,738		(5,304	)
Issuance of company common stock		59		-		-	-	-		-		-		59
Repurchase of company common stock		(1,258	)	-		-	-	-		-		-		(1,258	)
Dividends paid on common stock		(2,376	)	-		-	-	-		(2,575	)	2,575		(2,376	)
Other		(2	)	27		-	-	-		(346	)	(223	)	(544	)

Net Cash Used in Financing Activities		(4,567	)	(1,309	)	-	-	(378	)	(5,716	)	2,643		(9,327	)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		-		15		-	-	-		128		-		143


Net Change in Cash and Cash Equivalents		-		52		-	5	3		7,438		(44	)	7,454
Cash and cash equivalents at beginning of period		-		122		-	18	1		554		(153	)	542

Cash and Cash Equivalents at End of Period	$	-		174		-	23	4		7,992		(197	)	7,996

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 49.

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

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is an international, integrated energy company. We are the third-largest U.S. integrated energy company, based on market capitalization. At September 30, 2011, we had approximately 29,700 employees worldwide and total assets of $155 billion.

Earnings of the company depend largely on the profitability of our Exploration and Production (E&P) and Refining and Marketing (R&M) segments. Crude oil and natural gas prices, along with refining margins, are the most significant factors in our profitability. Industry crude prices for West Texas Intermediate (WTI) averaged $89.70 per barrel in the third quarter of 2011, an increase of 18 percent compared with the third quarter of 2010, and a decrease of 12 percent compared with the second quarter of 2011. Global oil prices eased during the third quarter of 2011, compared with the second quarter of 2011, as a result of concerns about slowing global economic growth and the reduction in oil demand growth.

Henry Hub natural gas prices averaged $4.20 per million British thermal units in the third quarter of 2011, a 4 percent decrease compared with the third quarter of 2010, and a 3 percent decrease compared with the second quarter of 2011. U.S. natural gas prices decreased slightly during the third quarter of 2011, as continued strong production outweighed increased demand. The higher production levels have moved this year’s storage inventory levels closer to last year’s record-high storage levels.

Earnings for our E&P segment generally correlate with industry price levels for crude oil and natural gas. E&P earnings were $1,762 million in the third quarter of 2011, which accounted for 67 percent of our total company earnings in the quarter. This compares with E&P earnings of $1,564 million in the third quarter of 2010 and $2,524 million in the second quarter of 2011.

Domestic refining margins continued to significantly increase in the third quarter of 2011, and international refining margins also improved. The U.S. 3:2:1 crack spread, which is primarily WTI-based, increased 186 percent in the third quarter of 2011, compared with the third quarter of 2010, and 20 percent compared with the second quarter of 2011. These improvements were a result of increased crude supplies in the Midcontinent area, causing WTI to trade at a deeper discount relative to waterborne crudes. Refineries capable of processing WTI and crude oils that are WTI-based continued to benefit from the lower crude oil prices. In contrast, East Coast refining, which relies primarily on Brent-based crudes, has been under severe market pressure. Product imports, weakness in motor fuel demand, and costly regulatory requirements are key challenges in this difficult environment.

The N.W. Europe 3:1:2 crack spread increased 33 percent in the third quarter of 2011, compared with the third quarter of 2010, and 10 percent compared with the second quarter of 2011.

Our R&M segment reported earnings of $789 million in the third quarter of 2011, compared with earnings of $268 million in the third quarter of 2010 and $766 million in the second quarter of 2011. R&M earnings in the third quarter of 2011 included a $314 million after-tax impairment of our Trainer Refinery in Pennsylvania and a $77 million after-tax loss on sale of our Wilhelmshaven Refinery (WRG) in Germany. Consistent with our stated strategic initiatives to improve our financial position and optimize our asset portfolio, we sold WRG in August 2011. In September 2011, we announced our intention to sell the Trainer Refinery, which has been idled and will permanently close by the end of the first quarter 2012 if a sales transaction is unsuccessful.

RESULTS OF OPERATIONS

Unless otherwise indicated, discussion of results for the three- and nine-month periods ended September 30, 2011, is based on a comparison with the corresponding periods of 2010.

Consolidated Results

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


	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010

E&P	$	1,762			1,564			6,638			7,510
Midstream		137			77			340			215
R&M		789			268			2,037			(15	)
LUKOIL Investment		-			1,310			239			2,226
Chemicals		197			132			589			380
Emerging Businesses		(2	)		(20	)		(23	)		(24	)
Corporate and Other		(267	)		(276	)		(774	)		(975	)

Net income attributable to ConocoPhillips	$	2,616			3,055			9,046			9,317

Earnings for ConocoPhillips decreased 14 percent in the third quarter of 2011, and 3 percent for the nine-month period ended September 30, 2011. The third quarter and nine-month periods of 2010 included gains of $952 million and $3,877 million after-tax, respectively, from asset dispositions and LUKOIL share sales. In addition, the nine-month period of 2010 included a $1,103 million after-tax impairment of WRG. Excluding these items, as well as impacts from 2011 asset dispositions and the $314 million after-tax impairment of our Trainer Refinery in the third quarter of 2011, earnings in both periods of 2011 improved primarily as a result of:

	•		Higher prices in our E&P segment. Commodity price benefits were somewhat offset by higher taxes.
	•		Improved results from our R&M operations, reflecting higher U.S. refining margins.

These items were partially offset by the absence of equity earnings from LUKOIL due to the divestiture of our interest.

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

Income Statement Analysis

Sales and other operating revenues for the third quarter and nine-month periods of 2011 increased 33 percent and 34 percent, respectively, while purchased crude oil, natural gas and products increased 40 percent and 43 percent, respectively. The increases were mainly due to significantly higher prices for petroleum products, crude oil and natural gas liquids (NGL).

Equity in earnings of affiliates for the third quarter and nine-month periods of 2011 increased 29 percent and 17 percent, respectively. The increases in both periods primarily resulted from:

	•		Improved earnings from WRB Refining LP, primarily due to higher refining margins.
	•		Earnings from Qatar Liquefied Gas Company Limited (3) (QG3), primarily due to sales of liquefied natural gas (LNG) following production startup, which occurred in October 2010.
	•		Improved earnings from Chevron Phillips Chemical Company LLC (CPChem), mainly due to higher margins in the olefins and polyolefins business line.
	•		Improved earnings from DCP Midstream, LLC, mainly as a result of higher NGL prices.
	•		Improved earnings from FCCL Partnership, primarily due to higher commodity prices and volumes.

These increases in equity earnings were partially offset by the absence of equity earnings from LUKOIL due to the divestiture of our interest. The nine-month period of 2011 also included an $85 million before-tax write-off of our investment associated with the cancelation of the Denali gas pipeline project.

Gain (loss) on dispositions for the third quarter of 2011 was a $480 million loss, compared with a gain of $1,398 million in the same period of 2010. The gain in the nine-month period of 2011 was $214 million, compared with $4,671 million in the 2010 nine-month period. Both 2010 periods included $1,219 million and $1,318 million, respectively, in gains from the sale of LUKOIL shares. The nine-month period of 2010 also included a $2,878 million gain on sale of our Syncrude oil sands mining operation. Losses realized in the third quarter of 2011 were primarily the result of the dilution of our equity interest in Australia Pacific LNG Pty Ltd (APLNG) from 50 percent to 42.5 percent and the disposition of WRG. Additionally, the nine-month period of 2011 included gains from the sale of certain E&P assets located in the Lower 48 and the remaining divestiture of our LUKOIL shares.

Production and operating expenses increased 7 percent in the third quarter of 2011, primarily as a result of higher operating costs, maintenance and unfavorable foreign currency impacts.

Exploration expenses decreased 17 percent in the nine-month period of 2011, primarily as a result of the Shah Project cancelation in the nine-month period of 2010.

Depreciation, depletion and amortization (DD&A) for the third quarter and nine-month periods of 2011 decreased 17 percent and 12 percent, respectively. The decreases were mostly associated with our E&P segment, reflecting lower production volumes.

Impairments for the third quarter of 2011 increased $427 million, mainly as a result of the Trainer Refinery impairment. Impairments in the nine-month period of 2011 decreased $1,194 million, primarily due to the $1,502 million impairment of WRG in the second quarter of 2010, partially offset by the third quarter 2011 Trainer impairment.

Taxes other than income taxes for the third quarter and nine-month periods of 2011 increased 8 percent and 10 percent, respectively, primarily due to higher production taxes as a result of higher crude oil prices and higher excise taxes on petroleum product sales.

Interest and debt expense decreased 19 percent in the nine-month period of 2011, primarily due to lower debt levels.

See Note 20—Income Taxes in the Notes to Consolidated Financial Statements, for information regarding our provision for income taxes and effective tax rate.

Segment Results

E&P

Three Months Ended

Nine Months Ended

September 30

2011

2010

2011

2010

Millions of Dollars

Net Income Attributable to ConocoPhillips

Alaska

501

361

1,540

1,259

Lower 48

315

202

956

597

United States

816

563

2,496

1,856

International

946

1,001

4,142

5,654

1,762

1,564

6,638

7,510

Dollars Per Unit

Average Sales Prices

Crude oil and natural gas liquids (per barrel)

United States

90.95

65.71

91.54

68.19

International

104.40

71.75

103.31

72.72

Total consolidated operations

97.10

69.22

97.34

70.74

Equity affiliates

99.24

72.95

99.31

72.25

Total E&P

97.24

69.45

97.47

70.83

Bitumen (per barrel)

International

45.79

47.96

49.79

50.65

Equity affiliates

60.65

52.38

61.50

52.82

Total E&P

58.14

51.50

59.69

52.48

Natural gas (per thousand cubic feet)*

United States

4.17

4.10

4.17

4.40

International

6.88

5.38

6.71

5.48

Total consolidated operations

5.77

4.86

5.70

5.05

Equity affliliates

2.85

2.82

2.91

2.84

Total E&P

5.45

4.80

5.39

4.99

*Prior periods reclassified to conform to current-year presentation which includes intrasegment transfer pricing.

Millions of Dollars

Worldwide Exploration Expenses

General administrative; geological and geophysical; and lease rentals

115

130

416

521

Leasehold impairment

122

180

Dry holes

111

168

147

266

252

706

848


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011		2010
	Thousands of Barrels Daily
Operating Statistics
Crude oil and natural gas liquids produced
Alaska		199		215		212		228
Lower 48		174		160		161		159

United States		373		375		373		387
Canada		37		40		37		41
Europe		159		207		178		213
Asia Pacific/Middle East		94		144		120		142
Africa		30		80		41		79

Total consolidated operations		693		846		749		862
Equity affiliates
Asia Pacific/Middle East		22		-		23		-
Russia		26		51		32		54

		741		897		804		916


Synthetic oil produced
Consolidated operations—Canada		-		-		-		15


Bitumen produced
Consolidated operations—Canada		11		10		10		9
Equity affiliates—Canada		53		49		55		50

		64		59		65		59


	Millions of Cubic Feet Daily
Natural gas produced*
Alaska		56		82		61		86
Lower 48		1,561		1,738		1,557		1,728

United States		1,617		1,820		1,618		1,814
Canada		929		974		940		1,012
Europe		511		731		616		812
Asia Pacific/Middle East		700		748		705		713
Africa		161		158		157		147

Total consolidated operations		3,918		4,431		4,036		4,498
Equity affiliates
Asia Pacific/Middle East		479		134		503		112

		4,397		4,565		4,539		4,610

*Represents quantities available for sale. Excludes gas equivalent of natural gas liquids included above.

The E&P segment explores for, produces, transports and markets crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At September 30, 2011, our E&P production operations were located in the United States, Norway, the United Kingdom, Canada, Australia, offshore Timor-Leste in the Timor Sea, Indonesia, China, Vietnam, Libya, Nigeria, Algeria, Qatar and Russia. Total E&P production on a barrel-of-oil-equivalent (BOE) basis averaged 1,538,000 BOE per day in the third quarter of 2011, compared with 1,717,000 BOE per day in the third quarter of 2010. Production for the nine-month period of 2011 averaged 1,626,000 BOE per day, compared with 1,758,000 BOE per day for the same period in 2010.

Our E&P operations reported earnings of $1,762 million in the third quarter of 2011, an increase of 13 percent compared with the third quarter of 2010. E&P earnings for the first nine months of 2011 were $6,638 million, a 12 percent decrease compared with the same period of 2010. See the “Business Environment and Executive Overview” section for additional information on industry crude oil and natural gas prices.

U.S. E&P
Our U.S. E&P operations reported earnings of $816 million in the third quarter of 2011, a 45 percent increase compared with the same period in 2010. U.S. E&P earnings for the nine-month period of 2011 were $2,496 million, a 34 percent increase compared with the same period in 2010. The increases for both periods of 2011 were primarily the result of higher crude oil and natural gas liquids prices, and to a lesser extent, lower DD&A. These increases were partially offset by higher production taxes, primarily in Alaska, and higher operating expenses. The third quarter of 2011 also benefitted from higher crude sales. In addition, the nine-month period of 2011 included higher gains from asset sales in the Lower 48, partially offset by lower sales volumes.

U.S. E&P production averaged 643,000 BOE per day in the third quarter of 2011, a decrease of 5 percent from 678,000 BOE per day in the third quarter of 2010. The decrease was mainly due to field decline and asset dispositions, which were partially offset by new production, primarily from shale plays in the Lower 48.

International E&P
International E&P earnings were $946 million in the third quarter of 2011, a 5 percent decrease compared with the third quarter of 2010. International E&P earnings for the first nine months of 2011 were $4,142 million, a 27 percent decrease compared with the same period in 2010. Earnings in the third quarter and nine-month period of 2011 included a $279 million loss on the dilution of our equity interest in APLNG from 50 percent to 42.5 percent. In addition, both periods were impacted by $234 million in additional income tax expense, as a result of legislation enacted in the United Kingdom in July 2011. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities; $75 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through June 30, 2011; and $53 million for the impact of the higher tax rates on third quarter 2011 earnings. Additionally, the nine-month period of 2010 included the $2,679 million after-tax gain on sale of Syncrude. Excluding the impact from these items, earnings increased in both periods of 2011, primarily due to higher prices, LNG sales from QG3 and lower DD&A. These increases to earnings were partially offset by lower volumes and higher taxes.

International E&P production averaged 895,000 BOE per day in the third quarter of 2011, a decrease of 14 percent from 1,039,000 BOE per day in the third quarter of 2010. The decrease primarily resulted from suspended operations in Libya and in Bohai Bay, China, asset dispositions and downtime. Normal field decline was largely offset by new production.

Midstream

Three Months Ended

Nine Months Ended

September 30

2011

2010

2011

2010

Millions of Dollars

Net Income Attributable to ConocoPhillips*

137

340

215

*Includes DCP Midstream-related earnings:

217

123

Dollars Per Barrel

Average Sales Prices

U.S. natural gas liquids*

Consolidated

59.26

40.55

57.32

44.23

Equity affiliates

52.09

36.66

50.66

40.14

*Based on index prices from the Mont Belvieu and Conway market hubs that are weighted by natural gas liquids component and location mix.

Thousands of Barrels Daily

Operating Statistics*

Natural gas liquids extracted

204

198

197

192

Natural gas liquids fractionated**

148

134

144

150

*Includes our share of equity affiliate.
**Excludes DCP Midstream.

The Midstream segment purchases raw natural gas from producers and gathers natural gas through an extensive network of pipeline gathering systems. The natural gas is then processed to extract natural gas liquids from the raw gas stream. The remaining “residue” gas is marketed to electrical utilities, industrial users, and gas marketing companies. Most of the natural gas liquids are fractionated—separated into individual components like ethane, butane and propane—and marketed as chemical feedstock, fuel or blendstock. The Midstream segment consists of our 50 percent equity investment in DCP Midstream, LLC, as well as our other natural gas gathering and processing operations, and natural gas liquids fractionation, trading and marketing businesses, primarily in the United States and Trinidad.

Earnings from the Midstream segment increased 78 percent in the third quarter of 2011 and 58 percent in the first nine months of 2011. The increases in both periods were primarily due to higher NGL prices.

R&M


	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011		2010
	Millions of Dollars
Net Income (Loss) Attributable to ConocoPhillips
United States	$	789		199		1,883		993
International		-		69		154		(1,008	)

	$	789		268		2,037		(15	)

Dollars Per Gallon

U.S. Average Wholesale Prices*

Gasoline

3.04

2.21

2.99

2.21

Distillates

3.16

2.24

3.11

2.23

*Excludes excise taxes.


	Thousands of Barrels Daily
Operating Statistics
Refining operations*
United States
Crude oil capacity		1,986		1,986	1,986	1,986
Crude oil runs		1,827		1,833	1,782	1,830
Capacity utilization (percent)		92	%	92	90	92
Refinery production		1,991		1,992	1,964	1,998
International
Crude oil capacity		426		671	426	671
Crude oil runs		396		399	406	362
Capacity utilization (percent)		93	%	60	95	54
Refinery production		407		407	416	370
Worldwide
Crude oil capacity		2,412		2,657	2,412	2,657
Crude oil runs		2,223		2,232	2,188	2,192
Capacity utilization (percent)		92	%	84	91	82
Refinery production		2,398		2,399	2,380	2,368


Petroleum products sales volumes
United States
Gasoline		1,134		1,103	1,150	1,122
Distillates		907		874	873	868
Other products		402		432	408	395

		2,443		2,409	2,431	2,385
International		746		697	703	602

		3,189		3,106	3,134	2,987

*Includes our share of equity affiliates.

The R&M segment refines crude oil and other feedstocks into petroleum products (such as gasoline, distillates and aviation fuels); buys, sells and transports crude oil; and buys, transports, distributes and markets petroleum products. R&M has operations mainly in the United States, Europe and Asia.

R&M reported earnings of $789 million during the third quarter of 2011, an increase of $521 million compared with the third quarter of 2010. Earnings for the nine-month period of 2011 were $2,037 million, an increase of $2,052 million compared with the same period in 2010. See the “Business Environment and Executive Overview” section for additional information on industry refining margins.

U.S. R&M
U.S. R&M earnings were $789 million in the third quarter of 2011, an increase of $590 million compared with the third quarter of 2010. Earnings for the first nine months of 2011 were $1,883 million, an increase of $890 million. Earnings for both periods of 2011 improved primarily due to significantly higher refining margins, which were partially offset by the $314 million after-tax impairment and warehouse inventory write-down associated with our Trainer Refinery. Earnings in the third quarter of 2011 also benefitted from improved marketing margins. Additionally, the nine-month period of 2010 included the $113 million after-tax gain on sale of our 50 percent interest in CFJ Properties.

Our U.S. refining capacity utilization rate was 92 percent in the third quarter of 2011 and in the third quarter of 2010. The current year rate primarily reflects higher unplanned downtime and run reductions due to East Coast market conditions, offset by lower turnaround activity and maintenance.

International R&M
International R&M broke even in the third quarter of 2011, and earnings were $154 million for the nine-month period of 2011, compared with earnings of $69 million and a loss of $1,008 million for the respective periods in 2010. Higher refining and marketing margins in the third quarter of 2011 were offset by the $77 million after-tax loss on sale of WRG and foreign currency losses. Earnings for the nine-month period of 2011 increased primarily due to the absence of the 2010 WRG impairment and foreign currency gains in 2011, partially offset by lower refining margins.

Our international refining capacity utilization rate was 93 percent in the third quarter of 2011, compared with 60 percent in the third quarter of 2010. The increase primarily resulted from the removal of WRG from our refining capacities effective January 1, 2011, partially offset by higher turnaround activity and unplanned downtime in the third quarter of 2011.

LUKOIL Investment


	Millions of Dollars
	Three Months Ended				Nine Months Ended
	September 30				September 30
	2011		2010		2011		2010
Net Income Attributable to ConocoPhillips	$	-		1,310		239		2,226


Operating Statistics
Crude oil production (thousands of barrels daily)		-		366		-		380
Natural gas produced (millions of cubic feet daily)		-		338		-		339
Refinery crude oil processed (thousands of barrels daily)		-		263		-		252

This segment represents our former investment in the ordinary shares of OAO LUKOIL, an international, integrated oil and gas company headquartered in Russia. We sold our remaining interest in LUKOIL in the first quarter of 2011.

Earnings in the nine-month period of 2011 primarily represented the realized gain on remaining share sales. Earnings for the three- and nine-month periods of 2010 primarily reflected earnings from the equity investment in LUKOIL we held at the time, in addition to gains on the partial sale of our LUKOIL investment.

Chemicals

Millions of Dollars

Three Months Ended

Nine Months Ended

September 30

2011

2010

2011

2010

Net Income Attributable to ConocoPhillips

197

132

589

380

The Chemicals segment consists of our 50 percent interest in Chevron Phillips Chemical Company LLC (CPChem), which we account for under the equity method. CPChem uses natural gas liquids and other feedstocks to produce petrochemicals. These products are then marketed and sold, or used as feedstocks to produce plastics and commodity chemicals.

Earnings from the Chemicals segment increased 49 percent in the third quarter of 2011 and 55 percent in the nine-month period of 2011, compared with the corresponding periods of 2010. The increases in both periods of 2011 primarily resulted from higher margins, volumes and equity earnings in the olefins and polyolefins business line. The specialties, aromatics and styrenics business line also contributed to the increase in earnings.

Emerging Businesses


	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010
Net Income (Loss) Attributable to ConocoPhillips
Power	$	32			8			71			54
Other		(34	)		(28	)		(94	)		(78	)

	$	(2	)		(20	)		(23	)		(24	)

The Emerging Businesses segment represents our investment in new technologies or businesses outside our normal scope of operations. Activities within this segment are currently focused on power generation and innovation of new technologies, such as those related to conventional and nonconventional hydrocarbon recovery, refining, alternative energy, biofuels and the environment.

Emerging Businesses reported a loss of $2 million in the third quarter of 2011, and a loss of $23 million in the nine-month period of 2011. The increase in “Power” earnings in the third quarter and nine-month period of 2011 was primarily due to the absence of 2010 impairment charges related to a U.S. cogeneration plant, which was sold in December 2010. The earnings increase was partially offset by lower international power generation results in the nine-month period of 2011. Higher technology development expenses contributed to the increase in “Other” losses for both periods in 2011.

Corporate and Other


	Millions of Dollars
	Three Months Ended						Nine Months Ended
	September 30						September 30
	2011			2010			2011			2010
Net Income (Loss) Attributable to ConocoPhillips
Net interest	$	(166	)		(285	)		(512	)		(761	)
Corporate general and administrative expenses		(34	)		(37	)		(143	)		(120	)
Other		(67	)		46			(119	)		(94	)

	$	(267	)		(276	)		(774	)		(975	)

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 decreased 42 percent in the third quarter of 2011 and 33 percent in the first nine months of 2011. The decrease in both periods of 2011 was primarily due to the absence of a $114 million after-tax premium on early debt retirement which occurred in the third quarter of 2010. In addition, the nine-month period of 2011 benefitted from lower interest expense due to lower debt levels and higher interest income.

Corporate general and administrative expenses increased 19 percent in the nine-month period of 2011, mainly due to costs related to overhead and compensation and benefit plans.

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. The earnings decrease in the “Other” category in the third quarter of 2011 primarily reflected foreign currency transaction losses, compared with foreign currency transaction gains in the corresponding period of 2010. The earnings decrease in the nine-month period of 2011 was mostly due to various tax-related adjustments.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	September 30			December 31
	2011			2010
Short-term debt	$	616			936
Total debt	$	23,150			23,592
Total equity	$	66,326			69,109
Percent of total debt to capital*		26	%		25
Percent of floating-rate debt to total debt**		9	%		10

*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 operating activities is the primary source of funding. In addition, during the first nine months of 2011, we received $2,158 million in proceeds from asset sales, including $1,243 million in cash proceeds from the divestiture of our remaining interest in LUKOIL in the first quarter of 2011. During the first nine months of 2011, available cash was used to support our ongoing capital expenditures and investments program, repurchase common stock, make net purchases of short-term investments, pay dividends and repay debt. Total dividends paid on our common stock during the first nine months were $2,761 million. During the first nine months of 2011, cash and cash equivalents decreased by $6,017 million to $3,437 million. Of this decrease, $1,623 million relates to movement of cash and cash equivalents into short-term investments.

In addition to cash flows from operating activities and proceeds from asset sales, 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 and short-term investment 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, required debt payments and the funding requirements to FCCL Partnership.

Significant Sources of Capital

Operating Activities
During the first nine months of 2011, cash of $13,834 million was provided by operating activities, a 27 percent increase from cash from operations of $10,854 million in the corresponding period of 2010. The increase was primarily due to stronger crude oil and natural gas liquids prices, improved refining margins and higher distributions from equity affiliates.

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, as well as refining and marketing margins. During the first nine months of 2011, crude oil prices were higher than in the same period of 2010. Prices and margins in our industry are typically 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 our production volumes also impacts our cash flows. These production levels are impacted by such factors as acquisitions and dispositions of fields, field production decline rates, new technologies, operating efficiency, 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 historically this variability has not been as significant as that caused by commodity prices.

In addition, the level and quality of output from our refineries impacts our cash flows. The output at our refineries is impacted by such factors as operating efficiency, maintenance turnarounds, market conditions, feedstock availability and weather conditions. We actively manage the operations of our refineries and, typically, any variability in their operations has not been as significant to cash flows as that caused by refining margins.

Asset Sales
Proceeds from asset sales during the first nine months of 2011 were $2.2 billion, including $1.2 billion from the sale of our remaining interest in LUKOIL. Other asset sales primarily included mature North American natural gas assets. This compares with proceeds of $12.2 billion in the first nine months of 2010, which included $4.6 billion from the sale of our 9.03 percent interest in the Syncrude Canada Ltd. joint venture. Over the remainder of 2011, and through the end of 2012, we plan to raise an additional $7 billion to $12 billion from sales of non-strategic assets.

Commercial Paper and Credit Facilities
In August 2011, we increased our total revolving credit facilities from $7.85 billion to $8.0 billion. We replaced our $7.35 billion revolving credit facility with a $7.5 billion facility expiring in August 2016. The terms of the new revolving credit facility are similar to the terms of the replaced facility. We also have a $500 million facility expiring in July 2012. Our revolving credit facilities may be used as direct bank borrowings, as support for issuances of letters of credit totaling up to $750 million, or as support for our commercial paper programs. The revolving credit facilities do not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreements contain 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 by any of its consolidated subsidiaries.

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

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.35 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $1.5 billion commercial paper program, which is used to fund commitments relating to the QG3 Project. At September 30, 2011, and December 31, 2010, we had no direct borrowings under the revolving credit facilities, but $40 million in letters of credit had been issued at both periods. In addition, under the two ConocoPhillips commercial paper programs, $1,127 million of commercial paper was outstanding at September 30, 2011, compared with $1,182 million at December 31, 2010. Since we had $1,127 million of commercial paper outstanding and had issued $40 million of letters of credit, we had access to $6.8 billion in borrowing capacity under our revolving credit facilities at September 30, 2011.

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

Off-Balance Sheet Arrangements

As part of our normal ongoing business operations and consistent with normal industry practice, we enter into numerous agreements with other parties to pursue business opportunities, which share costs and apportion risks among the parties as governed by the agreements. At September 30, 2010, we were liable for certain contingent obligations under our agreements with respect to QG3.

We own a 30 percent interest in QG3, an integrated project to produce and liquefy natural gas from Qatar’s North Field. The other participants in the project are affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent). Our interest is held through a jointly owned company, Qatar Liquefied Gas Company Limited (3), for which we use the equity method of accounting. QG3 secured project financing of $4 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from commercial banks, and $1.2 billion from ConocoPhillips. The ConocoPhillips loan facilities have substantially the same terms as the ECA and commercial bank facilities. Prior to project completion certification, all loans, including the ConocoPhillips loan facilities, are guaranteed by the participants, based on their respective ownership interests. Accordingly, our maximum exposure to this financing structure is $1.2 billion. Upon completion certification, currently expected later in 2011, all project loan facilities, including the ConocoPhillips loan facilities, will become nonrecourse to the project participants. At September 30, 2011, QG3 had approximately $3.9 billion outstanding under all the loan facilities, including the $1.2 billion from ConocoPhillips.

For additional information about guarantees, see Note 12—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 September 30, 2011, was $23.2 billion, a decrease of $442 million from the balance at December 31, 2010. In the fourth quarter of 2011, we plan to repay $500 million of 6.5% Notes when they mature.

We are obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to FCCL. Quarterly principal and interest payments of $237 million began in the second quarter of 2007 and will continue until the balance is paid. Of the principal obligation amount, $723 million was short-term and was included in the “Accounts payable—related parties” line on our September 30, 2011, consolidated balance sheet. The principal portion of these payments, which totaled $518 million in the first nine months of 2011, is included in the “Other” line in the financing activities section of our consolidated statement of cash flows. Interest accrues at a fixed annual rate of 5.3 percent on the unpaid principal balance. Fifty percent of the quarterly interest payment is reflected as a capital contribution and is included in the “Capital expenditures and investments” line on our consolidated statement of cash flows.

We have provided loan financing to WRB Refining LP, to assist it in meeting its operating and capital spending requirements. In June 2011, $400 million was repaid to ConocoPhillips and in September 2011, $150 million was repaid. No outstanding balance remains.

In October 2011, we announced a dividend of 66 cents per share. The dividend will be paid December 1, 2011, to stockholders of record at the close of business October 17, 2011.

On March 24, 2010, our Board of Directors authorized the purchase of up to $5 billion of our common stock through 2011. Repurchase of shares under this authorization was completed during the first quarter of 2011. On February 11, 2011, the Board authorized the purchase of up to an additional $10 billion of our common stock over the subsequent two years. Under both programs, repurchases totaled 174 million shares at a cost of $11.8 billion through September 30, 2011. We had cash and cash equivalents of $3.4 billion and short-term

investments of $2.6 billion at September 30, 2011. A portion of those balances is expected to be used toward the completion of the repurchase program in the fourth quarter of 2011.

Capital Spending

Capital Expenditures and Investments


	Millions of Dollars
	Nine Months Ended
	September 30
	2011		2010
E&P
United States—Alaska	$	585		544
United States—Lower 48		2,781		1,041
International		5,266		4,022

		8,632		5,607

Midstream		9		1

R&M
United States		500		479
International		128		180

		628		659

LUKOIL Investment		-		-
Chemicals		-		-
Emerging Businesses		21		7
Corporate and Other		104		97

	$	9,394		6,371

United States	$	3,990		2,162
International		5,404		4,209

	$	9,394		6,371

E&P

Capital spending for E&P during the first nine months of 2011 totaled $8.6 billion. The expenditures supported key exploration and development projects including:

	•		Oil and natural gas exploration and development activities in the Lower 48, including the Eagle Ford, Bakken and North Barnett shale plays, as well as the Permian and San Juan Basins. Exploration leasing and drilling activities occurred in a number of different shale plays.

	•		Alaska development activities related to existing producing fields.

	•		Oil sands projects and ongoing natural gas projects in Canada.

	•		Further development of coalbed methane projects associated with the APLNG joint venture in Australia.

	•		In Asia Pacific, continued development in China, new fields offshore Malaysia and ongoing exploration and development activity offshore Indonesia.

	•		In the North Sea, development activities in the Greater Ekofisk area, Jasmine and Clair Ridge, as well as exploration drilling activities.

	•		The Kashagan Field in the Caspian Sea.

	•		Onshore developments in Nigeria and Algeria.

R&M

Capital spending for R&M during the first nine months of 2011 totaled $628 million and included projects related to sustaining and improving the existing business with a focus on safety, regulatory compliance and reliability.

Contingencies

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

Environmental
We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. For a discussion of the most significant of these environmental laws and regulations, including those with associated remediation obligations, see the “Environmental” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 57, 58 and 59 of our 2010 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 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, 2010, we reported we had been notified of potential liability under CERCLA and comparable state laws at 73 sites around the United States. As of September 30, 2011, we were notified of six new sites, settled five sites and closed two sites, resulting in 72 unresolved sites with potential liability.

At September 30, 2011, our balance sheet included a total environmental accrual of $926 million, compared with $994 million at December 31, 2010. 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 on 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 (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 triggers 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 to determine the extent of climate change. Both of the above-referenced announcements are subject to pending legal challenges, and we continue to monitor these legal proceedings and other legislative and regulatory actions globally for potential impacts on our operations.

For other examples of legislation or precursors for possible regulation that do or could affect our operations, see the “Climate Change” section in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 59 and 60 of our 2010 Annual Report on Form 10-K.

NEW ACCOUNTING STANDARDS

OUTLOOK

Planned Separation of Downstream Businesses
On July 14, 2011, we announced approval by our Board of Directors to pursue the separation of our refining, marketing and transportation business into a stand-alone, publicly traded corporation via a tax-free distribution. We expect the new downstream company will also include most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations, to create an integrated downstream company. The separation would be accomplished by the pro rata distribution of one share of the new downstream company’s stock for every two shares of ConocoPhillips stock held by ConocoPhillips’ shareholders on the record date.

During October, we requested a private letter ruling from the U.S. Internal Revenue Service, which is expected to confirm the distribution will qualify as a tax-free reorganization for U.S. federal income tax purposes. In addition, we plan to file the new downstream company’s initial Form 10 registration statement with the SEC in mid-November.

The separation is subject to market conditions, customary regulatory approvals, the receipt of an affirmative Internal Revenue Service private letter ruling, execution of separation and intercompany agreements and final Board approval, and is expected to be completed in the second quarter of 2012.

Trainer Refinery
On September 27, 2011, we announced our intention to sell our 185,000 barrel-per-day refinery in Trainer, Pennsylvania, along with the associated pipelines and terminals. We have idled the facility and plan to permanently close the plant by the end of the first quarter of 2012 if a sales transaction is unsuccessful.

China — Bohai Bay Temporary Shut-in
On July 13, 2011, the State Oceanic Administration (SOA) in the People’s Republic of China instructed us to suspend production from Peng Lai Platforms B and C, as a result of two separate seepage incidents which occurred near the platforms. On September 2, 2011, the SOA ordered us to halt operations at the Peng Lai 19-3 Field, pending additional cleanup efforts and activities to ensure any residual seepage has stopped. The SOA also requires implementation of preventative measures to avoid recurrence, in addition to the filing of an updated environmental impact assessment and development plan for approval. The incidents resulted in a total release of approximately 700 barrels of oil into Bohai Bay and approximately 2,600 barrels of mineral oil-based drilling mud onto the seafloor. The mineral oil-based drilling mud was recovered and cleaned up from the seafloor. The sources of the seeps have been sealed and containment devices deployed as a preventative measure to capture any residue. The shut-down, combined with limited development and field optimization, is expected to reduce fourth quarter production from the field by approximately 40,000 net barrels of oil per day, compared to 2010 production levels. Future impacts on our business are not known at this time.

Libya
Our production operations in Libya and related oil exports continue to be temporarily suspended, although certain international sanctions have been lifted. We hold a 16.3 percent interest in the Waha concessions. For the year 2010, our net oil production averaged 46,000 barrels per day, and cash flow from operations was approximately $125 million. Future impacts are unknown at this time.

E&P Production
In E&P, we expect our 2011 production to be 1.61 million to 1.62 million BOE per day. Production in the fourth quarter of 2011 is expected to be 1.56 million to 1.58 million BOE per day.

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, refining and marketing margins and margins for our chemicals business.

	•		Potential failures or delays in achieving expected reserve or production levels from existing and future oil and gas development projects 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.

	•		Failure of new products and services to achieve market acceptance.

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

	•		Unexpected technological or commercial difficulties in manufacturing, refining or transporting our products, including chemicals products.

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

	•		Inability to timely obtain or maintain permits, including those necessary for construction of LNG terminals or regasification facilities, or refinery projects; 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, LNG, refinery and transportation projects.

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

	•		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, natural gas liquids or refined product 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 implement, our asset disposition plan.

	•		Inability to obtain economical financing for projects, construction or modification of facilities and general corporate purposes.

	•		The operation and financing of our midstream and chemicals joint ventures.

	•		The effect of restructuring or reorganization of business components.

	•		The factors generally described in Item 1A—Risk Factors in our 2010 Annual Report on Form 10-K and Item 1A-Risk Factors in this Quarterly Report on Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information about market risks for the nine months ended September 30, 2011, does not differ materially from that discussed under Item 7A in our 2010 Annual Report on Form 10-K.

Item 4. CONTROLS AND PROCEDURES

As of September 30, 2011, with the participation of our management, our Chairman and Chief Executive Officer (principal executive officer) and our Senior Vice President, Finance and Chief Financial Officer (principal financial officer) carried out an evaluation, pursuant to Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (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 Senior Vice President, Finance and Chief Financial Officer concluded that our disclosure controls and procedures were operating effectively as of September 30, 2011.

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 material developments with respect to matters previously reported in ConocoPhillips’ 2010 Annual Report on Form 10-K or first- or second-quarter 2011 Quarterly Report on Form 10-Q. We did not have any new matters that arose during the third quarter of 2011 to report. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings was 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’s (SEC) regulations.

Our U.S. refineries are implementing two separate consent decrees regarding alleged violations of the Federal Clean Air Act with the U.S. Environmental Protection Agency (EPA), six states and one local air pollution agency. Some of the requirements and limitations contained in the decrees provide for stipulated penalties for violations. Stipulated penalties under the decrees are not automatic, but must be requested by one of the agency signatories. As part of periodic reports under the decrees or other reports required by permits or regulations, we occasionally report matters that could be subject to a request for stipulated penalties. If a specific request for stipulated penalties meeting the reporting threshold set forth in SEC rules is made pursuant to these decrees based on a given reported exceedance, we will separately report that matter and the amount of the proposed penalty.

Matters Previously Reported

In February 2011, we reported to the EPA two instances of potential non-compliance with federal air regulations at the company’s Ute Compressor Station in Southwest Colorado. This matter was resolved with a penalty payment of $198,000.

Item 1A. RISK FACTORS

You should carefully consider the following risk factor, in addition to the risk factors disclosed in Item 1A of our 2010 Annual Report on Form 10-K.

The proposed separation of our downstream businesses is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.

We expect the separation will be effective in the second quarter of 2012. Our ability to timely effect the separation is subject to several conditions, including, among others, the receipt of a favorable private letter ruling from the IRS, an independent tax opinion that the separation will qualify as tax-free for U.S. federal income tax purposes, and the SEC declaring effective a registration statement relating to the securities of the separated entity. We cannot assure that we will be able to complete the separation in a timely fashion, if at all. For these and other reasons, the separation may not be completed on the terms or timeline contemplated. Further, if the separation is completed, it may not achieve the intended results. Any such difficulties could adversely affect our business, results of operations or financial condition.

There have been no other material changes from the risk factors disclosed in Item 1A of our 2010 Annual Report on Form 10-K.

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

Issuer Purchases of Equity Securities


							Millions of Dollars
					Total Number of		Approximate Dollar
					Shares Purchased		Value of Shares
					as Part of Publicly		that May Yet Be
	Total Number of		Average Price Paid		Announced Plans		Purchased Under the
Period	Shares Purchased*		per Share		or Programs**		Plans or Programs

July 1-31, 2011		13,272,242	$	75.30		13,271,248	$	5,350
August 1-31, 2011		17,170,822		66.96		17,168,893		4,200
September 1-30, 2011		15,976,999		65.71		15,976,550		3,150

Total		46,420,063	$	68.92		46,416,691

* Includes the repurchase of common shares from company employees in connection with the company’s broad-based employee incentive plans.

** On March 24, 2010, we announced plans to repurchase up to $5 billion of our common stock through 2011. Repurchase of shares under this authorization was completed during the first quarter of 2011. On February 11, 2011, we announced plans to repurchase up to $10 billion of our common stock over the subsequent two years. Acquisitions for the share repurchase program are made at management’s discretion, at prevailing prices, subject to market conditions and other factors. Repurchases may be increased, decreased or discontinued at any time without prior notice. Shares of stock repurchased under the plan are held as treasury shares.

Item 6. EXHIBITS


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)

November 1, 2011

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Financial Statementsprint Note 1 Interim Financial Informationprint Note 2 Variable Interest Entities (vies)print Note 3 Inventoriesprint Note 4 Investments, Loans and Long-term Receivablesprint Note 5 Assets Held For Sale Or Soldprint Note 6 Properties, Plants and Equipmentprint Note 7 Suspended Wellsprint Note 8 Impairmentsprint Note 9 Debtprint Note 10 Joint Venture Acquisition Obligationprint Note 11 Noncontrolling Interestsprint Note 12 Guaranteesprint Note 13 Contingencies and Commitmentsprint Note 14 Financial Instruments and Derivative Contractsprint Note 15 Comprehensive Income (loss)print Note 16 Cash Flow Informationprint Note 17 Employee Benefit Plansprint Note 18 Related Party Transactionsprint Note 19 Segment Disclosures and Related Informationprint Note 20 Income Taxesprint Note 21 New Accounting Standardsprint Note 22 Planned Separation Of Downstream Businessesprint Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 6. Exhibitsprint

Exhibits

EX-12 EX-31.1 EX-31.2 EX-32

Customer name	Ticker
Adams Resources & Energy, Inc.	AE
Avery Dennison Corporation	AVY
CMS Energy Corporation	CMS
Cooper Tire & Rubber Company	CTB
EQT Corporation	EQT
FirstEnergy Corp.	FE
FMC Corporation	FMC
First Trust New Opportunities MLP & Energy Fund	FPL
The Goodyear Tire & Rubber Company	GT
H.B. Fuller Company	FUL
Johnson Controls International plc	JCI
NiSource Inc.	NI
Olin Corporation	OLN
ONEOK, Inc.	OKE
PPL Corporation	PPL

Supplier name	Ticker
Thermo Fisher Scientific Inc.	TMO
Xcel Energy Inc.	XEL
Air Products and Chemicals, Inc.	APD
Exxon Mobil Corporation	XOM
Raytheon Technologies Corporation	RTX
Chevron Corporation	CVX
Danaher Corporation	DHR
Canaan Inc.	CAN

COP 10-Q Quarter ended Sept. 30, 2011

Exhibits