Edgar Filing: CONOCOPHILLIPS

10-K

2013

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


(Mark One)
[x]		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended December 31, 2013

		OR

[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
		OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)


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

600 North Dairy Ashford

Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class		Name of each exchange on which registered
Common Stock, $.01 Par Value		New York Stock Exchange
6.65% Debentures due July 15, 2018		New York Stock Exchange
7% Debentures due 2029		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

[x] Yes [ ] No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

[ ] Yes [x] No

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. [x] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

[x] Yes [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ]

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 Act). [ ] Yes [x] No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30, 2013, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $60.50, was $74.0 billion.

The registrant had 1,226,104,592 shares of common stock outstanding at January 31, 2014.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 13, 2014 (Part III)

TABLE OF CONTENTS


Item		Page

	PART I

1 and 2.	Business and Properties		1
	Corporate Structure		1
	Segment and Geographic Information		2
	Alaska		4
	Lower 48 and Latin America		7
	Canada		11
	Europe		13
	Asia Pacific and Middle East		16
	Other International		22
	Competition		25
	General		25
1A.	Risk Factors		27
1B.	Unresolved Staff Comments		29
3.	Legal Proceedings		29
4.	Mine Safety Disclosures		30
	Executive Officers of the Registrant		31

	PART II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
6.	Selected Financial Data		34
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		35
7A.	Quantitative and Qualitative Disclosures About Market Risk		72
8.	Financial Statements and Supplementary Data		75
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		172
9A.	Controls and Procedures		172
9B.	Other Information		172

	PART III

10.	Directors, Executive Officers and Corporate Governance		173
11.	Executive Compensation		173
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		173
13.	Certain Relationships and Related Transactions, and Director Independence		173
14.	Principal Accounting Fees and Services		173

	PART IV

15.	Exhibits, Financial Statement Schedules		174
	Signatures		181

PART I

Unless otherwise indicated, “the company,” “we,” “our,” “us” and “ConocoPhillips” are used in this report to refer to the businesses of ConocoPhillips and its consolidated subsidiaries. Items 1 and 2—Business and Properties, contain forward-looking statements including, without limitation, statements relating to our 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 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 71.

Items 1 and 2. BUSINESS AND PROPERTIES

CORPORATE STRUCTURE

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. ConocoPhillips was incorporated in the state of Delaware on November 16, 2001, in connection with, and in anticipation of, the merger between Conoco Inc. and Phillips Petroleum Company. The merger between Conoco and Phillips was consummated on August 30, 2002.

On April 30, 2012, we completed the separation of our downstream businesses into an independent, publicly traded company, Phillips 66. Our refining, marketing and transportation businesses, most of our Midstream segment, our Chemicals segment, as well as our power generation and certain technology operations included in our Emerging Businesses segment (collectively, our “Downstream business”), were transferred to Phillips 66. As a part of our asset disposition program, in the fourth quarter of 2013, we completed the sale of our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and the sale of our Algeria business, and we have agreements to sell our Nigeria business. Results of operations related to Phillips 66, Kashagan, Algeria and Nigeria have been classified as discontinued operations in all periods presented in this Annual Report on Form 10-K. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Headquartered in Houston, Texas, we have operations and activities in 27 countries. Our key focus areas include safely operating producing assets, executing major developments and exploring for new resources in promising areas. Our portfolio includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects.

At December 31, 2013, ConocoPhillips employed approximately 18,400 people worldwide.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

We explore for, produce, transport and market crude oil, bitumen, natural gas, liquefied natural gas (LNG) and natural gas liquids on a worldwide basis. At December 31, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

We manage our operations through six operating segments, which are defined by geographic region: Alaska, Lower 48 and Latin America, Canada, Europe, Asia Pacific and Middle East, and Other International.

The information listed below appears in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements and is incorporated herein by reference:

•

Proved worldwide crude oil, natural gas liquids, natural gas and bitumen reserves.

•

Net production of crude oil, natural gas liquids, natural gas and bitumen.

•

Average sales prices of crude oil, natural gas liquids, natural gas and bitumen.

•

Average production costs per barrel of oil equivalent (BOE).

•

Net wells completed, wells in progress and productive wells.

•

Developed and undeveloped acreage.

The following table is a summary of the proved reserves information included in the “Oil and Gas Operations” disclosures following the Notes to Consolidated Financial Statements. Approximately 83 percent of our proved reserves are located in politically stable countries that belong to the Organization for Economic Cooperation and Development. Natural gas reserves are converted to BOE based on a 6:1 ratio: six thousand cubic feet of natural gas converts to one BOE. See Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of factors that will enhance the understanding of the following summary reserves table.


	Millions of Barrels of Oil Equivalent
Net Proved Reserves at December 31	2013		2012		2011
Crude oil
Consolidated operations		2,659		2,684		2,617
Equity affiliates		90		95		124

Total Crude Oil		2,749		2,779		2,741


Natural gas liquids
Consolidated operations		699		646		670
Equity affiliates		45		48		51

Total Natural Gas Liquids		744		694		721


Natural gas
Consolidated operations		2,710		2,726		2,933
Equity affiliates		688		543		553

Total Natural Gas		3,398		3,269		3,486


Bitumen
Consolidated operations		579		506		530
Equity affiliates		1,451		1,394		909

Total Bitumen		2,030		1,900		1,439


Total consolidated operations		6,647		6,562		6,750
Total equity affiliates		2,274		2,080		1,637

Total company		8,921		8,642		8,387

Total production from continuing operations, including our share of equity affiliates, for 2013 averaged 1,502 thousand barrels of oil equivalent per day (MBOED), a 2 percent decrease compared with 1,527 MBOED in 2012. The decrease was mainly due to normal field decline, asset dispositions, shut-in Libya production, due to the closure of the Es Sider crude oil export terminal, and higher unplanned downtime. These decreases were partially offset by new production from major developments, mainly from shale plays in the Lower 48, the ramp-up of production from new phases at Christina Lake in Canada, and early production in Malaysia; higher production in China; and increased conventional drilling and well performance, mostly in the Lower 48, western Canada and Norway. Adjusted for dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 30 MBOED, or 2 percent, compared with 2012.

Our total realized price from continuing operations remained relatively flat in 2013, from $67.68 per BOE in 2012, compared with $67.62 per BOE in 2013. Our worldwide annual average crude oil sales price from continuing operations decreased 2 percent in 2013, from $105.72 per barrel in 2012 to $103.32 per barrel in 2013. Additionally, our worldwide average annual natural gas liquids prices from continuing operations decreased 11 percent, from $46.36 per barrel in 2012 to $41.42 per barrel in 2013. Our average annual worldwide natural gas sales price from continuing operations increased 11 percent, from $5.48 per thousand cubic feet in 2012 to $6.11 per thousand cubic feet in 2013. Average annual bitumen prices decreased 1 percent, from $53.91 per barrel in 2012 to $53.27 per barrel in 2013.

ALASKA

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. We are the largest crude oil and natural gas producer in Alaska and have major ownership interests in two of North America’s largest oil fields located on Alaska’s North Slope: Prudhoe Bay and Kuparuk. We also have a significant operating interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest owners of state and federal exploration leases, with approximately 0.9 million net undeveloped acres at year-end 2013. Approximately 0.5 million of these acres are located in the National Petroleum Reserve—Alaska (NPRA) and 0.3 million are located in the Chukchi Sea. In 2013, Alaska operations contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.


						2013

	Interest			Operator		Liquids MBD*		Natural Gas MMCFD**		Total MBOED

Average Daily Net Production
Greater Prudhoe Area		36.1	%		BP		101		5		102
Greater Kuparuk Area		52.2-55.5			ConocoPhillips		53		-		53
Western North Slope		78			ConocoPhillips		39		1		39
Cook Inlet Area		33.3-100			ConocoPhillips		-		37		6

Total Alaska							193		43		200

* Thousands of barrels per day.

** Millions of cubic feet per day.

Greater Prudhoe Area

The Greater Prudhoe Area includes the Prudhoe Bay Field and five satellite fields, as well as the Greater Point McIntyre Area fields. Prudhoe Bay, the largest oil field on Alaska’s North Slope, is the site of a large waterflood and enhanced oil recovery operation, as well as a gas processing plant which processes natural gas for reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven and Lisburne fields are part of the Greater Point McIntyre Area.

Greater Kuparuk Area

We operate the Greater Kuparuk Area, which consists of the Kuparuk Field and four satellite fields: Tarn, Tabasco, Meltwater and West Sak. Kuparuk is located 40 miles west of Prudhoe Bay. Field installations include three central production facilities which separate oil, natural gas and water, as well as a separate seawater treatment plant. New rotary-drilled wells and sidetracks from existing well bores utilizing coiled-tubing drilling are the primary means for development drilling at Kuparuk.

The successful Shark Tooth delineation well extended the known Kuparuk accumulation to the southwestern area of the Kuparuk Field. As a result, plans for the future development of Drill Site 2S are progressing, with project sanction targeted for late 2014 and first production estimated in late 2015.

Western North Slope

On the Western North Slope, we operate the Colville River Unit, which includes the Alpine Field and three satellite fields: Nanuq, Fiord and Qannik. Alpine is located 34 miles west of Kuparuk. Construction is progressing on Alpine West CD5, a drill site to access the western extension of the Alpine reservoir, in the NPRA. Initial production is anticipated in late 2015, with net peak production estimated at 10 MBOED in 2016.

The Greater Mooses Tooth Unit, the first unit established entirely within the NPRA, was formed in 2008. We are progressing development planning for the Greater Mooses Tooth #1 (GMT1) drill site in the Greater Mooses Tooth Unit. We filed permitting applications for GMT1 in July 2013, and project sanction is targeted for late 2014. GMT1 is planned to be connected by road to the CD5 drill site, and production will be

transported by pipeline to the existing Alpine facilities for processing. Construction is estimated to begin in 2016, with first production anticipated in late 2017. We are evaluating further exploration and development potential in the NPRA.

Cook Inlet Area

We operate the North Cook Inlet Unit, the Beluga River Unit, and the Kenai LNG Facility in the Cook Inlet Area. We have a 100 percent interest in the North Cook Inlet Unit and the Kenai LNG Facility, while we own 33.3 percent of the Beluga River Unit. Both units produce natural gas, and our share of production is currently sold to local utilities.

The Kenai LNG Facility includes a 1.3 million-tons-per-year capacity plant, which historically manufactured LNG for sale to utility companies in Japan, as well as docking and loading facilities, which enable the LNG to be transported by tanker. Although our LNG export license expired in March 2013, the plant is operational and in stand-by mode, maintaining the flexibility to resume limited operations. Due to a change in market conditions, including additional gas supplies, we submitted applications in December 2013 to the U.S. Department of Energy to resume LNG exports from the Kenai LNG Facility.

Point Thomson

We own a 5 percent interest in the Point Thomson Unit, which is located approximately 60 miles east of Prudhoe Bay. An initial production system is anticipated to be online by 2016, which is estimated to send 400 net BOED of condensate through the Trans-Alaska Pipeline System (TAPS).

More Alaska Production Act (MAPA)

Following the April 2013 enactment of revised oil tax legislation, MAPA, we have increased our exploration and development investments and activities on the North Slope by adding rigs and progressing new development opportunities. We will continue to work with co-owners to identify additional opportunities to increase our investments in Alaska.

Alaska LNG (AKLNG)

During 2012, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and TransCanada Corporation (collectively, the “AKLNG co-venturers”), began evaluating a potential LNG project which would export and liquefy natural gas from Alaska’s North Slope and deliver it to market. The AKLNG Project concept is an integrated LNG project consisting of a liquefaction plant, including marine terminal facilities and auxiliary marine vessels, located in south-central Alaska; a natural gas treatment plant, located on the North Slope; and an estimated 800-mile natural gas pipeline, which would connect the two plants.

In October 2013, the AKLNG co-venturers selected the Nikiski area on the Kenai Peninsula as the lead site for the proposed AKLNG natural gas liquefaction plant and terminal. On January 14, 2014, the AKLNG co-venturers, the Commissioners of the Alaska Departments of Revenue and Natural Resources, and the Alaska Gasline Development Corporation, a state-owned corporation, signed a Heads of Agreement (HOA) for the AKLNG Project. The HOA provides a roadmap of how the parties intend to progress the project, including proposed terms for participation by the State of Alaska as an equity owner, proposed fiscal and regulatory terms, and proposed terms for expansion of project components. One of the initial steps in the HOA is enactment of general legislation by the State of Alaska, as well as further commercial agreements, which would be subject to approval by the Alaska legislature. Significant engineering, technical, regulatory, fiscal, commercial and permitting issues would need to be resolved prior to a final investment decision on the potential 17 million-tons-per-year, $45 billion to $65 billion (gross) project. Following the enabling legislation, we anticipate commencing preliminary front-end engineering and development, currently estimated in the second quarter of 2014.

Exploration

In April 2013, we suspended our plans to drill an exploration well in the Chukchi Sea in 2014, in light of the uncertainties of evolving federal regulatory requirements and operational permitting standards. Once these requirements are clarified and better defined, we will re-evaluate plans for drilling in the Chukchi Sea.

In 2013, we drilled and flow-tested a new discovery at the Cassin prospect, located in the Bear Tooth Unit in the northeast NPRA, and we also tested the Moraine play on the western flank of the Kuparuk Field. The results for both wells are currently under evaluation. Additionally, we plan to drill two exploration wells within the Greater Mooses Tooth Unit in 2014: the Rendezvous 3, which is currently drilling, and Flattop-1, which is expected to be spud later in the first quarter of 2014.

Transportation

We transport the petroleum liquids produced on the North Slope to south-central Alaska through an 800-mile pipeline that is part of TAPS. We have a 29.1 percent ownership interest in TAPS, and we also have ownership interests in the Alpine, Kuparuk and Oliktok pipelines on the North Slope.

Our wholly owned subsidiary, Polar Tankers, Inc., manages the marine transportation of our North Slope production, using five company-owned, double-hulled tankers and chartering third-party vessels, as necessary. The tankers deliver oil from Valdez, Alaska, to refineries on the west coast of the United States.

LOWER 48 AND LATIN AMERICA

The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states, as well as exploration activities in the Gulf of Mexico and Colombia. As a result of increasing shale opportunities and a low natural gas price environment, we have directed our investments toward high-margin, liquids-rich plays, predominantly in the Lower 48.

Lower 48

We hold 15.3 million net onshore and offshore acres in the Lower 48. In 2013, the Lower 48 contributed 29 percent of our worldwide liquids production and 38 percent of our natural gas production.


				2013

	Interest		Operator		Liquids MBD	Natural Gas MMCFD	Total MBOED

Average Daily Net Production
Eagle Ford	Various	%	Various		94	147	119
Gulf of Mexico	Various		Various		13	14	15
Gulf Coast—Other	Various		Various		10	221	47

Total Gulf Coast					117	382	181

Permian	Various		Various		34	116	53
Barnett	Various		Various		7	51	16
Anadarko Basin	Various		Various		8	121	28

Total Mid-Continent					49	288	97

Bakken	Various		Various		29	25	33
Wyoming/Uinta	Various		Various		-	103	17
Rockies—Other	Various		Various		3	-	3

Total Rockies					32	128	53

San Juan	Various		Various		45	692	160

Total U.S. Lower 48					243	1,490	491

Onshore

We hold 13.1 million net acres of onshore conventional and unconventional acreage in the Lower 48, the majority of which is either held by production or owned by the Company. Our unconventional holdings total approximately 2.7 million net acres in the following areas:

•

620,000 net acres in the Bakken, located in North Dakota and Eastern Montana;

•

221,000 net acres in the Eagle Ford, located in South Texas;

•

240,000 net acres in the Permian, located in West Texas and southeastern New Mexico;

•

130,000 net acres in the Niobrara, located in northeastern Colorado;

•

900,000 net acres in the San Juan Basin, located in northwestern New Mexico and southwestern Colorado;

•

65,000 net acres in the Barnett, located in north central Texas; and

•

541,000 net acres in other unconventional exploration plays.

The majority of our 2013 onshore production originated from San Juan, Eagle Ford, Permian, Bakken, Anadarko, Lobo and Barnett. Onshore activities in 2013 were centered mostly on continued development and optimization of emerging and existing assets, with an emphasis on areas with higher-margin, liquids-rich production, particularly in growing unconventional plays. Our major focus areas in 2013 included the following:

•

Eagle Ford—Exploration and development continued in 2013 in the Eagle Ford. In 2013, we increased production by 70 percent, compared to 2012; drilled 164 exploration and development wells; connected 225 wells; and achieved net peak production of 141 MBOED, compared with 103 MBOED in 2012. We also had 11 operated rigs drilling throughout 2013.

•

Bakken—The Bakken experienced a significant increase in activity in 2013. We drilled 126 operated wells during the year, of which 85 were brought online. We also increased our operated rig count to 11 and improved our efficiency with pad drilling. As a result, we achieved net peak production of more than 40 MBOED in 2013, compared with approximately 25 MBOED in 2012.

•

San Juan Basin—The San Juan Basin includes significant conventional gas production, which yields approximately 35 percent natural gas liquids, as well as the majority of our U.S. coalbed methane (CBM) production. We hold approximately 1.3 million net acres of oil and gas leases by production in San Juan, where we continue to pursue conventional development opportunities. This also includes approximately 900,000 net unconventional acres of lease rights, where we are advancing the assessment of the Mancos shale play.

•

Permian Basin—the Permian Basin is another area where we are leveraging our conventional legacy position by utilizing new technology to improve the ultimate recovery and value from these fields. This technology will also identify new, unconventional plays across the region. We hold approximately 1.0 million net acres in the Permian, which includes 240,000 net unconventional acres.

Gulf of Mexico

At year-end 2013, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, including:

•

75 percent operated working interest in the Magnolia Field in Garden Banks Blocks 783 and 784.

•

15.9 percent nonoperated working interest in the unitized Ursa Field located in the Mississippi Canyon Area.

•

15.9 percent nonoperated working interest in the Princess Field, a northern, subsalt extension of the Ursa Field.

•

12.4 percent nonoperated working interest in the unitized K2 Field, comprised of seven blocks in the Green Canyon Area.

Exploration

•

Conventional Exploration

In the deepwater Gulf of Mexico, we added approximately 430,000 net acres to our position in 2013, bringing our total acreage position to 2.1 million acres at December 31, 2013. Since 2011, we have nearly doubled our acreage footprint in the deepwater Gulf of Mexico and currently rank in the top five deepwater leaseholders. In 2013, we announced two new oil discoveries in the deepwater Lower Tertiary play at Coronado and Gila, adding to the existing Shenandoah and Tiber discoveries made in 2009.

We own a 30 percent working interest in the Shenandoah discovery. The results of the Shenandoah appraisal well were announced in 2013 and confirmed Shenandoah as a significant oil discovery. The well encountered more than 1,000 feet of net pay in high-quality, Lower Tertiary-aged reservoirs. We plan to participate in further appraisal of Shenandoah in 2014. The Coronado exploration well encountered more than 400 feet of net pay and will require further appraisal. We hold a 35 percent working interest in Coronado. In 2013, we acquired a 20 percent interest in the Gila Prospect, located

in the Keathley Canyon section of the Gulf of Mexico. The Gila exploration well was announced as a discovery in 2013 and is expected to be appraised in 2014.

Ongoing drilling activities at the end of 2013 included a Tiber appraisal well, in which we own an 18 percent working interest, a Coronado appraisal well and the Deep Nansen exploration well. We hold a 12.5 percent interest in the Deep Nansen well. We plan to evaluate the results of these wells in the first half of 2014.

The nonoperated Ardennes wildcat well and the ConocoPhillips-operated Thorn wildcat well were declared dry holes in 2013.

In support of our intentions to grow our Gulf of Mexico exploration program, we secured access to two new-build deepwater drillships, which we anticipate will be delivered to the Gulf of Mexico in 2014 and 2015. The drillships will provide rig availability for our operated drilling program.

•

Unconventional Exploration

In 2013, we actively pursued the exploration and appraisal of our existing unconventional resource plays, including the Eagle Ford in the Western Gulf Basin, the Bakken in the Williston Basin, the Barnett in the Fort Worth Basin, the Niobrara play in the Denver-Julesburg Basin, Wolfcamp and Bone Springs in the Delaware Basin, Wolfcamp in the Midland Basin, and the Mancos in the San Juan Basin. During 2013, we acquired approximately 61,000 net additional acres in various resource plays across the Lower 48, which included the Eagle Ford, Niobrara and Permian plays, further expanding our significant acreage position in Lower 48 shale plays to approximately 2.7 million net acres.

During 2013, we drilled a total of 25 unconventional wells in the Niobrara, Bone Springs and Wolfcamp plays. In 2014, we will continue to actively explore and appraise unconventional plays in the Lower 48, with a focus on Bone Springs, Wolfcamp and Niobrara. We will also continue to assess new opportunities in unconventional plays.

Facilities

Freeport LNG Terminal

We have a long-term agreement with Freeport LNG Development, L.P. to use 0.9 billion cubic feet per day of regasification capacity at Freeport’s 1.5-billion-cubic-feet-per-day LNG receiving terminal in Quintana, Texas. In July 2013, we agreed with Freeport LNG to terminate this agreement, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. Upon satisfaction of these conditions, currently expected to occur in the second half of 2014, we will pay Freeport LNG a termination fee of approximately $600 million. Freeport LNG will repay the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, will result in a one-time net cash outflow of approximately $80 million for us. When the agreement becomes effective, we also expect to recognize an after-tax charge to earnings of approximately $540 million. At that time, our terminal regasification capacity will be reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero. As a result of this transaction, we anticipate saving approximately $50 to $60 million per year in operating costs over the next 19 years. For additional information, see Note 4—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

Golden Pass LNG Terminal

We have a 12.4 percent ownership interest in the Golden Pass LNG Terminal and affiliated Golden Pass Pipeline. It is located adjacent to the Sabine-Neches Industrial Ship Channel northwest of Sabine Pass, Texas. The terminal became commercially operational in May 2011. We hold terminal and pipeline capacity for the receipt, storage and regasification of the LNG purchased from Qatargas 3 and the transportation of regasified LNG to interconnect with major interstate natural gas pipelines. Market conditions currently favor the flow of LNG to European and Asian markets; therefore, our near-to-mid-term utilization of the terminal is expected to be limited.

Other

•

San Juan Gas Plant—We operate and own a 50 percent interest in the San Juan Gas Plant, a 550 million cubic-feet-per-day capacity natural gas processing plant in Bloomfield, New Mexico.

•

Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a 313 million cubic-feet-per-day capacity natural gas processing facility in Lysite, Wyoming.

•

Wingate Fractionator—We operate and own the Wingate Fractionator, a 25,000 barrel-per-day capacity natural gas liquids fractionation plant located in Gallup, New Mexico.

•

Helena Stabilization Plant—We operate and own the Helena Stabilization Plant, a 60,000 barrel-per-day condensate stabilization facility located in Kenedy, Texas.

•

Bordovsky Stabilization Plant—We operate and own the Bordovsky Stabilization Plant, a 15,000 barrel-per-day condensate stabilization facility located in Kenedy, Texas.

•

Sugarloaf Stabilization Plant—We operate and own an 87.5 percent interest in the Sugarloaf Stabilization Plant, a 15,000 barrel-per-day condensate stabilization facility located near Pawnee, Texas.

Asset Dispositions

During 2013, we sold the majority of our producing zones in the Cedar Creek Anticline, located in southwestern North Dakota and eastern Montana; certain properties located in southwest Louisiana; and our 39 percent equity interest in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Colombia

Unconventional Exploration

During 2013, we entered into a farm-in agreement with Canacol Energy Ltd. to acquire a 70 percent working interest for deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. The first exploration well did not reach our planned La Luna Shale target and was expensed. Additional seismic acquisition and processing will continue in 2014. Additionally, we executed farm-in agreements to acquire 30 percent working interests in three blocks in the Middle Magdalena Basin, which cover approximately 116,000 net acres.

Venezuela

In September 2013, the World Bank’s International Centre for Settlement of Investment Disputes (ICSID) arbitration tribunal ruled Venezuela unlawfully expropriated ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. A separate arbitration phase will proceed to determine the amount of damages owed to ConocoPhillips for Venezuela’s actions. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Ecuador

In December 2012, an ICSID tribunal issued a decision on liability in favor of Burlington Resources, Inc., a wholly owned subsidiary of ConocoPhillips, finding that Ecuador’s seizure of Blocks 7 and 21 was an unlawful expropriation in violation of the Ecuador-U.S. Bilateral Investment Treaty. An additional arbitration phase is now proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

CANADA

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2013, operations in Canada contributed 17 percent of our worldwide liquids production and 20 percent of our natural gas production.


						2013

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Bitumen MBD		Total MBOED

Average Daily Net Production
Western Canada		Various	%		Various		38		775		-		167
Surmont		50.0			ConocoPhillips		-		-		13		13
Foster Creek		50.0			Cenovus		-		-		50		50
Christina Lake		50.0			Cenovus		-		-		46		46

Total Canada							38		775		109		276

Western Canada

Our operations in western Canada primarily consist of three core development areas: Deep Basin, Kaybob and Clearwater, which extend from central Alberta to northeastern British Columbia. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2013, held leasehold rights in 5.7 million net acres in western Canada.

Oil Sands

We hold approximately 0.9 million net acres of land in the Athabasca Region of northeastern Alberta. Our bitumen resources in Canada are produced via an enhanced thermal oil recovery method called steam-assisted gravity drainage (SAGD), whereby steam is injected into the reservoir, effectively liquefying the heavy bitumen, which is recovered and pumped to the surface for further processing.

•

Surmont

The Surmont oil sands leases are located approximately 35 miles south of Fort McMurray, Alberta. Surmont is a 50/50 joint venture with Total S.A. Surmont Phase 2 construction began in 2010, with production startup targeted for 2015. Following startup, Surmont’s gross production capacity is estimated to be 150 MBOED, with peak production anticipated by 2018.

•

FCCL

We have a 50/50 heavy oil business venture with Cenovus Energy Inc., FCCL Partnership, a Canadian upstream general partnership. FCCL’s assets, operated by Cenovus, include the Foster Creek, Christina Lake and Narrows Lake SAGD bitumen developments. FCCL continues to progress expansion plans which would potentially increase total gross production capacity to approximately 750 MBOED.

Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. There are five producing phases at Foster Creek, Phases A through E, with three more under construction: Phases F, G and H. First production for Phase F is expected in the third quarter of 2014, and first production for Phases G and H are anticipated in 2015 and 2016, respectively. These phases, in addition to planned optimization, will add approximately 125 MBOED of gross production capacity. An application for regulatory approval for an additional expansion, Phase J, was filed in 2013.

Christina Lake is located approximately 75 miles south of Fort McMurray, Alberta. There are five producing phases at Christina Lake, Phases A through E, with plans underway for three additional phases: Phases F, G and H. Gross production at Christina Lake increased more

than 55 percent in 2013, mostly as a result of Phase D reaching full capacity in the first quarter of 2013 and Phase E commencing production in the third quarter of 2013. Phase E added 40 MBOED of gross production capacity. During 2013, construction continued on Phase F, which is expected to commence production in 2016 and add another 50 MBOED of gross production capacity. Engineering work continued for Phase G, with first production anticipated for 2017. An application for Phase H was submitted for regulatory review in 2013. With the additional expansion phases and optimization work, total gross production capacity from Christina Lake has the potential to reach approximately 310 MBOED.

Narrows Lake is located near Christina Lake and is expected to have three phases of development. During 2013, plant construction began on Phase A, which is estimated to have 45 MBOED of gross production capacity. Initial production is anticipated in 2017.

Amauligak

We have a 55 percent operating interest in the Amauligak discovery, which lies approximately 30 miles offshore in shallow water in the Beaufort Sea. A range of development options are being evaluated.

Exploration

We hold exploration acreage in four areas of Canada: offshore eastern Canada, onshore western Canada, the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands. Our primary exploration focus is on liquids-rich unconventional plays in Alberta, British Columbia and the Northwest Territories.

•

Unconventional Exploration

We hold approximately 0.7 million net acres in the emerging Montney, Muskwa, Duvernay and Canol unconventional plays in Alberta, northeastern British Columbia and the Northwest Territories. During 2013, we drilled unconventional test wells in the Duvernay, located in Alberta; the Canol shale, located in the Northwest Territories; and the Montney play, which extends from British Columbia into Alberta. In 2014, exploration activities will continue in Duvernay, Canol and Montney. We also plan to continue delineating potential development opportunities in the oil sands.

Asset Dispositions

During 2013, we sold our Clyden undeveloped oil sands leasehold. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

EUROPE

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2013, operations in Europe contributed 14 percent of our worldwide liquids production and 11 percent of natural gas production.

Norway


						2013

						Liquids		Natural Gas		Total
	Interest			Operator		MBD		MMCFD		MBOED

Average Daily Net Production
Greater Ekofisk Area		35.1	%		ConocoPhillips		54		42		61
Alvheim		20			Marathon		12		13		14
Heidrun		24			Statoil		15		14		17
Other		Various			Various		14		74		27

Total Norway							95		143		119

The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway in the North Sea, and comprises four producing fields: Ekofisk, Eldfisk, Embla and Tor. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. In October 2013, we achieved first oil production from Ekofisk South, a development which includes the planned drilling of 35 new production and eight water injection wells. At year-end 2013, four production wells and the eight water injection wells had been drilled. A second development, Eldfisk II, is scheduled to start up by early 2015. Ekofisk South, along with Eldfisk II and other developments offshore Norway, are expected to add approximately 60 MBOED of net production within the next five years.

The Alvheim development is located in the northern part of the North Sea and consists of a floating production, storage and offloading (FPSO) vessel and subsea installations. Produced crude oil is exported via shuttle tankers, and natural gas is transported to the United Kingdom via a pipeline to the Beryl-Sage system.

The Heidrun Field is located in the Norwegian Sea. Produced crude oil is transported to Mongstad in Norway and Tetney in the United Kingdom by double-hulled shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of crude oil production, while the remainder is used as feedstock in a methanol plant in Norway, in which we own an 18.3 percent interest.

We also have varying ownership interests in five other producing fields in the Norway sector of the North Sea and in the Norwegian Sea, including the Aasta Hansteen development, a gas discovery with first gas scheduled for late 2017.

Exploration

During 2013, we participated in five nonoperated wells, of which three were discoveries. Also in 2013, we were awarded four new licenses in the 22^nd Licencing Round in the Norwegian Barents Sea: PL718, PL720, PL723 and PL615B. We plan to participate in two nonoperated wells in the Barents Sea in 2014. In January 2014, we were awarded one operatorship and an interest in one partnership license in the Predefined Areas gas licensing round for mature areas.

Transportation

We own a 35.1 percent interest in the Norpipe Oil Pipeline System, a 220-mile pipeline which carries crude oil from Ekofisk to a crude oil stabilization and natural gas liquids processing facility in Teesside, England. In addition, we own a 1.9 percent interest in Norwegian Continental Shelf Gas Transportation (Gassled), which owns most of the Norwegian gas transportation infrastructure.

United Kingdom


				2013

	Interest		Operator		Liquids MBD	Natural Gas MMCFD	Total MBOED

Average Daily Net Production
Britannia	58.7	%	Britannia		4	96	20
			Operator Ltd.
Britannia Satellites	75.0-83.5		ConocoPhillips		8	21	12
J-Area	32.5-36.5		ConocoPhillips		8	49	16
Southern North Sea	Various		Various		-	93	16
East Irish Sea	100		HRL		-	14	2
Other	Various		Various		4	-	4

Total United Kingdom					24	273	70

Britannia is one of the largest natural gas and condensate fields in the North Sea. In addition to our interest in the Britannia Field, we own 50 percent of Britannia Operator Limited, the operator of the field. Condensate is delivered through the Forties Pipeline to an oil stabilization and processing plant near the Grangemouth Refinery in Scotland, while natural gas is transported through Britannia’s line to St. Fergus, Scotland. The Britannia satellite fields, Callanish and Brodgar, produce via subsea manifolds and pipelines linked to the Britannia platform. A new mono-column design compression facility for the Britannia Platform is estimated to come on line in 2014 and increase Britannia’s natural gas production by approximately 90 MMCFD.

The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. Jasmine was discovered in 2006, and first production commenced in November 2013. The Jasmine development includes a 24-slot wellhead platform with a bridge-linked accommodation and utilities platform, a six-mile, 16-inch multi-phase pipeline bundle, and a riser and processing platform bridge-linked to the existing Judy Platform. The field is a high-pressure, high-temperature gas condensate reservoir located approximately six miles west of the Judy Platform. Jasmine is estimated to achieve average net production of 30 MBOED in 2014.

We have various ownership interests in 19 producing gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Our interests in the East Irish Sea include the Millom, Dalton and Calder fields, which are operated on our behalf by a third party.

We own a 24 percent interest in the Clair Field, located in the Atlantic Margin. Clair Ridge is the second phase of development for the Clair Field and is comprised of a 36-slot drilling and production facility with a bridge-linked accommodation and utilities platform. The new facilities will tie into existing oil and gas export pipelines to the Shetland Islands. Initial production for Clair Ridge is targeted for 2016.

Exploration

During 2013, we participated in two operated wells, Lacewing and Romeo, and three nonoperated wells in the Clair Field: HEXA, Segment 0 and Segment 5. The Lacewing well was deemed sub-commercial. All of the wells in the Greater Clair area were discoveries and are currently undergoing evaluation. The Romeo well is currently drilling and will be evaluated during 2014.

During 2013, we were awarded four licenses: three licenses in the Central Graben area of the North Sea, and one license in the Greater Clair area.

Transportation

We operate the Teesside oil and Theddlethorpe gas terminals in which we have 29.3 percent and 50 percent ownership interests, respectively. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party, in the United Kingdom. A project to replace the Acid Gas Plant at the Rivers Gas Terminal was completed in early 2014.

Asset Dispositions

We sold our 10 percent equity interest in the Interconnector Pipeline in the first quarter of 2013.

Poland

Exploration

We are participating in a shale gas venture in Poland and own a 70 percent equity interest in Lane Energy Poland. We operate three western Baltic Basin concessions, which encompass approximately 500,000 gross acres. Four wells have been drilled on these concessions, and further well tests and drilling are planned in 2014.

Greenland

Exploration

During 2013, we were awarded one non-operated license, Block 6, in the northeast area of Greenland.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and the Timor Sea; producing operations in Qatar; and exploration activities in Bangladesh and Brunei. In 2013, operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 30 percent of natural gas production.

Australia and Timor Sea


						2013

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Australia Pacific LNG		37.5	%		Origin Energy		-		114		19
Bayu-Undan		56.9			ConocoPhillips		22		227		60
Athena/Perseus		50			ExxonMobil		-		35		5

Total Australia and Timor Sea							22		376		84

Australia Pacific LNG

Australia Pacific LNG Pty Ltd (APLNG), our joint venture with Origin Energy Limited and China Petrochemical Corporation (Sinopec), is focused on producing CBM from the Bowen and Surat basins in Queensland, Australia, and converting the CBM into LNG. Natural gas is currently sold to domestic customers, while progress continues on the development of the LNG processing and export sales business. Origin operates APLNG’s upstream production and pipeline system, and we will operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland.

Two fully subscribed 4.5-million-tonnes-per-year LNG trains have been sanctioned. Approximately 3,900 net wells are ultimately envisioned to supply both the domestic gas market and the LNG sales contracts. The wells will be supported by gathering systems, central gas processing and compression stations, water treatment facilities, and a new export pipeline connecting the gas fields to the LNG facilities. First LNG is expected in mid-2015, under a sales agreement with Sinopec for up to 4.3 million metric tonnes of LNG per year for 20 years. Start-up of the second LNG train is expected to occur six-to-nine months following the startup of Train 1, under sales agreements with Sinopec and Japan-based Kansai Electric Power Co., Inc. The resulting LNG exports from Train 2 will commence shortly thereafter. Sinopec has agreed to purchase an additional 3.3 million metric tonnes of LNG per year through 2035, and Kansai has agreed to purchase approximately 1 million metric tonnes of LNG per year for 20 years.

In May 2012, APLNG executed project financing agreements for an $8.5 billion project finance facility and began drawing on the financing in October 2012. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility. Our guarantee of the project financing will be released upon meeting certain completion tests with milestones.

For additional information, see Note 4—Variable Interest Entities (VIEs), Note 7—Investments, Loans and Long-Term Receivables, and Note 13—Guarantees, in the Notes to Consolidated Financial Statements.

Bayu-Undan

The Bayu-Undan gas condensate field is located in the Timor Sea Joint Petroleum Development Area between Timor-Leste and Australia. We also operate and own a 56.9 percent interest in the associated Darwin LNG Facility, located at Wickham Point, Darwin.

The Bayu-Undan natural gas recycle facility processes wet gas; separates, stores and offloads condensate, propane and butane; and re-injects dry gas back into the reservoir. In addition, a 500-kilometer natural gas

pipeline connects the facility to the 3.5-million-tonnes-per-year capacity Darwin LNG Facility. Produced natural gas is piped to the Darwin LNG Plant, where it is converted into LNG before being transported to international markets. In 2013, we sold 167 billion gross cubic feet of LNG to utility customers in Japan.

The Bayu-Undan Phase Three Development was sanctioned in the third quarter of 2013, with development drilling anticipated to commence in the third quarter of 2014 and initial production estimated in the second quarter of 2015. The development will consist of two standalone, subsea horizontal wells tied back to the existing drilling, production, and processing (DPP) platform. In 2013, we secured a semi-submersible drilling rig, procured long-lead items and commenced planning and detailed engineering for subsea and DPP topsides installation. Planning and engineering activities will continue through 2014. The two wells are expected to produce over three to five years, with estimated average production of 150 MMCFD.

ConocoPhillips served a Notice of Arbitration on the Timor-Leste Minister of Finance in October 2012 for outstanding disputes related to a series of tax assessments. The arbitration process is currently underway. For additional information, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Athena/Perseus

The Athena production license (WA-17-L) is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA-1-L, an adjoining license area. Natural gas is produced from these licenses.

Greater Sunrise

We have a 30 percent interest in the Greater Sunrise gas and condensate field located in the Timor Sea. In May 2013, the Timor-Leste Government referred a dispute with the Australian Government relating to the treaty on Certain Maritime Arrangements in the Timor Sea (CMATS) to international arbitration. The CMATS arbitration does not directly impact our underlying interest in Sunrise; however, key challenges must be resolved before further commercial and technical work continues.

Exploration

•

Conventional Exploration

We operate three permits in the Browse Basin, offshore northwest Australia. In 2013, we reduced our interests in two permits in the Greater Poseidon Area, WA-315-P and WA-398-P, from 60 percent to 40 percent. We have a 10 percent interest in WA-314-P, which is outside the Greater Poseidon Area. Phase I of the 2009/2010 Browse Basin drilling campaign resulted in discoveries in the Greater Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the drilling campaign consists of six wells and commenced in 2012. The first two wells, Boreas-1 and Zephyros-1, discovered hydrocarbons and were completed, plugged and abandoned in 2012. The third well, Proteus-1, discovered hydrocarbons and was plugged and abandoned in 2013. The three wells were drilled in the Greater Poseidon Area. The fourth well, Grace-1, was drilled to satisfy a Year-5 permit obligation for WA-314-P. The Grace-1 was spud in late 2013, reached total depth in early 2014 and was declared a dry hole. The outcome does not affect our view of the overall Greater Poseidon Project.

In the Bonaparte Basin, offshore northern Australia, we operate the NT/RL5 and NT/RL6 permits. Our ownership interest in each of the permits is 37.5 percent. A three-well appraisal program is expected to commence in 2014 to further evaluate the field’s potential.

•

Unconventional Exploration

In 2013, we reduced our working interest in four exploration permits within the Canning Basin of Western Australia from 75 percent to 46 percent. These permits cover approximately 11 million gross acres. Phase I of a three-well drilling program commenced in 2012 with the drilling of the Nicolay-1 and the Gibb-Maitland-1 wells. Both were written off as dry holes in 2013. Phase I drilling is expected to resume in the second half of 2014.

Asset Dispositions

During 2013, we sold 20 percent of our working interest in the Greater Poseidon Area permits in the Browse Basin and 29 percent of our working interest in the Goldwyer Shale in the Canning Basin permits. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Indonesia


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
South Natuna Sea Block B		40.0	%		ConocoPhillips		9		107		27
South Sumatra		45.0-54.0			ConocoPhillips		2		335		58

Total Indonesia							11		442		85

We operate five production sharing contracts (PSCs) in Indonesia: the offshore South Natuna Sea Block B and four onshore PSCs, the Corridor Block and South Jambi “B”, both located in South Sumatra, Warim in Papua, and we acquired Palangkaraya in Kalimantan in 2013. Our producing assets are primarily concentrated in two core areas: South Natuna Sea and onshore South Sumatra.

South Natuna Sea Block B

The offshore South Natuna Sea Block B PSC has 3 producing oil fields and 16 natural gas fields in various stages of development. Natural gas production is sold under international sales agreements to Malaysia and Singapore, and liquefied petroleum gas is sold locally for domestic consumption.

South Sumatra

The Corridor PSC consists of five oil fields and seven natural gas fields in various stages of development. Natural gas is supplied from the Grissik and Suban gas processing plants to the Duri steamflood in central Sumatra and to markets in Singapore, Batam and West Java. Production from the South Jambi “B” PSC has reached depletion and field development has been suspended. We are evaluating options related to the future of this PSC.

Exploration

We own and operate an 80 percent interest in the Warim onshore exploration PSC in Papua. In 2013, we signed an amendment to the PSC, which enables us to continue exploration activities for the next five years and, if there are commercial discoveries, to continue development and production activities until 2032.

In January 2013, we signed a farm-in agreement to acquire a 49 percent interest in the Palangkaraya PSC. In November 2013, we completed the acquisition of Vela Energy Limited, which increased our interest in the Palangkaraya PSC to 100 percent. The Palangkaraya PSC consists of approximately 1.9 million net acres and is located in a frontier exploration area in central Kalimantan.

Transportation

We are a 35 percent owner of a consortium company that has a 40 percent ownership in PT Transportasi Gas Indonesia, which owns and operates the Grissik to Duri and Grissik to Singapore natural gas pipelines.

China


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Peng Lai		49.0	%		ConocoPhillips		40		4		41
Panyu		24.5			CNOOC		13		-		13

Total China							53		4		54

The Peng Lai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from the Phase I development of the PL 19-3 Field began in 2002. The Phase II development includes six drilling and production platforms and an FPSO vessel used to accommodate production from all the fields.

Crude oil production at the Peng Lai 19-3 Field in Bohai Bay was curtailed in 2011, as a result of two separate seepage incidents which occurred near Platforms B and C. In February 2013, we received approval from China’s State Oceanic Administration (SOA) to resume normal production operations.

During 2012, we reached agreements with China’s Ministry of Agriculture and the SOA to resolve claims related to these seepage incidents. In the third quarter of 2013, we recognized an after-tax charge of $116 million for amounts previously paid by ConocoPhillips as operator. We do not anticipate further significant charges related to the 2011 seepage incidents.

Under the terms of the PSC, operatorship of the Peng Lai fields will transfer to our co-venturer on July 1, 2014, and we will maintain our interest as a non-operator.

The Panyu development, located in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. During 2012, a production platform was added to each of the Panyu 4-2 and Panyu 5-1 fields. Production from the new platforms began in September 2012.

Exploration

•

Unconventional Exploration

In 2012, we entered into a joint study agreement with Sinopec Southern Exploration Company over the Qijiang shale gas block, located in the Sichuan Basin. The Qijiang Block covers approximately 1 million acres. The study, which will be carried out over two years and includes seismic and drilling obligations, will be an important step in evaluating the potential for shale gas exploration in the area.

In February 2013, we entered into a joint study agreement with PetroChina over the 500,000-acre Neijiang-Dazu shale block, also located in the Sichuan Basin. The study is for 19 months and encompasses a desktop study and drilling preparation.

Malaysia


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Gumusut		33.0	%		Shell		6		1		6

Total Malaysia							6		1		6

We own interests in five deepwater PSCs in Malaysia. Four are located off the eastern Malaysian state of Sabah: Block G, Block J, the Kebabangan Cluster (KBBC) and SB-311. In 2013, we executed our fifth PSC, deepwater Block 3E, located off the Malaysian state of Sarawak.

Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which is expected to begin producing in the first quarter of 2014, with estimated net annual peak production of 6 MBOED in 2015. Development of the Malikai oil field is underway with first production anticipated in the first half of 2017. Estimated net annual peak production of 19 MBOED is expected in 2018. We own a 35 percent interest in the Malikai, Pisagan, Ubah and Limbayong oil discoveries. The Limbayong-2 appraisal well, located approximately seven miles from Gumusut, was suspended as an oil discovery in the fourth quarter of 2013.

Block J

First production for Gumusut occurred from an early production system in the fourth quarter of 2012. Production from a permanent, semi-submersible floating production vessel is expected in the second quarter of 2014, with estimated net annual peak production of 30 MBOED anticipated in 2015.

KBBC

We own a 30 percent interest in the KBBC PSC. Development of the KBB gas field commenced in 2011, with first production anticipated in late 2014. Estimated net annual peak production of 28 MBOED is expected in 2015. The Kamunsu East-2 appraisal well, located approximately seven miles northwest of the KBB gas field, was suspended as a gas discovery in the third quarter of 2013.

Exploration

We own a 40 percent operating interest in SB-311, an exploration block encompassing 259,000 acres offshore Sabah. Seismic reprocessing and acquisition occurred in 2013, and initial exploration drilling is anticipated in 2015.

In November 2013, we acquired an 85 percent operating interest in deepwater Block 3E, which encompasses approximately 480,000 acres offshore Sarawak. The PSC carries a four-year exploration term during which we plan to drill two wells.

Bangladesh

Exploration

We hold 100 percent interests in two deepwater blocks in the Bay of Bengal, Blocks 10 and 11. In 2013, we performed 2-D seismic activities and are currently evaluating the results. Additionally, we were the high bidder on adjoining Shelf Block 7 in 2013 and are awaiting finalization of the PSC.

Brunei

Exploration

We have a 6.25 percent working interest in deepwater Block CA-2, where exploration drilling has been ongoing since September 2011. Natural gas was discovered at the Kelidang NE well and the Keratau well in 2013. We are currently evaluating the results. Additionally, the Kempas #1 well was spud in late 2013 and declared a dry hole in January 2014.

Qatar


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Qatargas 3		30.0	%		Qatargas Operating Co.		22		367		83

Total Qatar							22		367		83

Qatargas 3 (QG3) is an integrated development jointly owned by Qatar Petroleum (68.5 percent), ConocoPhillips (30 percent) and Mitsui & Co., Ltd. (1.5 percent). QG3 consists of upstream natural gas production facilities, which produce approximately 1.4 billion gross cubic feet per day of natural gas from Qatar’s North Field over a 25 year life, in addition to a 7.8-million-gross-tonnes-per-year LNG facility. LNG is shipped in leased LNG carriers destined for sale globally.

QG3 executed the development of the onshore and offshore assets as a single integrated development with Qatargas 4 (QG4), a joint venture between Qatar Petroleum and Royal Dutch Shell plc. This included the joint development of offshore facilities situated in a common offshore block in the North Field, as well as the construction of two identical LNG process trains and associated gas treating facilities for both the QG3 and QG4 joint ventures. Production from the LNG trains and associated facilities are combined and shared.

OTHER INTERNATIONAL

The Other International segment includes exploration and producing operations in Libya and Russia, as well as exploration activities in Angola, Senegal and Azerbaijan. In 2013, we completed the sale of our Algeria business and the sale of our interest in the Republic of Kazakhstan’s North Caspian Sea Production Sharing Agreement (Kashagan), and we have agreements to sell our Nigeria business. Accordingly, results of these operations have been reclassified to discontinued operations for all periods presented. During 2013, operations in Other International contributed 4 percent of our worldwide liquids production.

Libya


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Waha Concession		16.3	%		Waha Oil Co.		26		25		30

Total Libya							26		25		30

The Waha Concession consists of multiple concessions and encompasses nearly 13 million gross acres in the Sirte Basin. Our production operations in Libya and related oil exports were interrupted in mid-2013, as a result of the shutdown of the Es Sider crude oil export terminal at the end of July 2013. Production remains shut-in, as the Es Sider Terminal shutdown has continued into the first quarter of 2014.

Exploration

We continued to participate in the ongoing exploration and appraisal programs within the Waha Concession in 2013. We completed drilling six appraisal wells and are currently drilling four appraisal wells. During 2014, we plan to drill six additional exploration and appraisal wells.

Russia


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Polar Lights		50.0	%		Polar Lights Co.		4		-		4

Total Russia							4		-		4

Polar Lights

Polar Lights Company is an entity which has developed several fields in the Timan-Pechora Basin in northern Russia.

Angola

Exploration

We have a 50 percent operating interest in Block 36 and a 30 percent operating interest in Block 37, both of which are located in Angola’s subsalt play trend. The two blocks total approximately 2.5 million acres. We have secured a rig for a four-well commitment program and plan to commence drilling in the second quarter of 2014.

Senegal

Exploration

In 2013, we farmed into three exploration blocks in offshore Senegal with a 35 percent working interest. We have secured a rig for a two-well program and expect to begin drilling in the first half of 2014.

Kazakhstan

Exploration

We disposed of our interest in the N Block, located offshore Kazakhstan, in January 2013.

Azerbaijan

Exploration

During 2013, we acquired an onshore 2-D seismic survey as part of a joint study with the State Oil Company of the Republic of Azerbaijan (SOCAR).

Transportation

The Baku-Tbilisi-Ceyhan (BTC) Pipeline transports crude oil from the Caspian Region through Azerbaijan, Georgia and Turkey for tanker loadings at the port of Ceyhan. We have a 2.5 percent interest in BTC.

Discontinued Operations

Nigeria


						2013
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production*
OMLs 60, 61, 62, 63		20.0	%		Eni		12		129		34

Total Nigeria							12		129		34

*Reclassified to discontinued operations.

We have an interest in four onshore Oil Mining Leases (OMLs). Natural gas is sourced from our proved reserves in the OMLs and provides fuel for a 480-megawatt gas-fired power plant in Kwale, Nigeria. We have a 20 percent interest in this power plant, which supplies electricity to Nigeria’s national electricity supplier. In 2013, the plant consumed 11 million net cubic feet per day of natural gas.

We have a 17 percent equity interest in Brass LNG Limited, which plans to construct an LNG facility in the Niger Delta.

In December 2012, we entered into agreements to sell our Nigeria business, which includes its upstream affiliates and Brass LNG. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Algeria

In November 2013, we sold our Algeria business. Production from discontinued operations for Algeria averaged 9 MBOED in 2013.

Kazakhstan

In October 2013, we sold our 8.4 percent interest in Kashagan.

For additional information on the Algeria and Kashagan dispositions, see Note 3—Discontinued Operations and Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

OTHER

Marketing Activities

Our Commercial organization manages our worldwide commodity portfolio, which mainly includes natural gas, crude oil, bitumen, natural gas liquids and LNG. Marketing activities are performed through offices in the United States, Canada, Europe and Asia. In marketing our production, we attempt to minimize flow disruptions, maximize realized prices and manage credit-risk exposure. Commodity sales are generally made at prevailing market prices at the time of sale. We also purchase third-party volumes to better position the Company to fully utilize transportation and storage capacity and satisfy customer demand.

Natural Gas

Our natural gas production, along with third-party purchased gas, is primarily marketed in the United States, Canada, Europe and Asia. Our natural gas is sold to a diverse client portfolio which includes local distribution companies; gas and power utilities; large industrials; independent, integrated or state-owned oil and gas companies; as well as marketing companies. To reduce our market exposure and credit risk, we also transport natural gas via firm and interruptible transportation agreements to major market hubs.

Crude Oil, Bitumen and Natural Gas Liquids

Our crude oil, bitumen and natural gas liquids revenues are derived from production in the United States, Canada, Australia, Asia, Africa and Europe. These commodities are primarily sold under contracts with prices based on market indices, adjusted for location, quality and transportation.

Energy Partnerships

Marine Well Containment Company

We are a founding member of the Marine Well Containment Company (MWCC), a non-profit organization formed in 2010, which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC developed an interim containment system, which meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico. To advance this capability, MWCC continues to develop an expanded containment system with significantly increased capacity. The expanded containment system should be available by the end of 2014.

Subsea Well Response Project

In 2011, we, along with several leading oil and gas companies, launched the Subsea Well Response Project (SWRP), a non-profit organization based in Stavanger, Norway, which was created to enhance the industry’s capability to respond to international subsea well control incidents. Through collaboration with Oil Spill Response Limited, a non-profit organization in the United Kingdom, subsea well intervention equipment is available for the industry to use in the event of a subsea well incident. This complements the work being undertaken in the United States by MWCC.

Technology

Our Technology organization has several technology programs, which focus on areas to support our business growth plans: developing unconventional reservoirs, producing oil sands and heavy oil economically with fewer emissions, advancing our competitiveness in deepwater development capabilities, improving the economic efficiency of our LNG and other gas solutions technologies, increasing recoveries from our legacy fields, and implementing sustainability measures.

Our Optimized Cascade^® LNG liquefaction technology business continues to grow with the demand for new LNG plants. The technology has been applied in 10 LNG trains around the world, with 12 more under construction and several feasibility studies ongoing.

RESERVES

We have not filed any information with any other federal authority or agency with respect to our estimated total proved reserves at December 31, 2013. No difference exists between our estimated total proved reserves for year-end 2012 and year-end 2011, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2013.

DELIVERY COMMITMENTS

We sell crude oil and natural gas from our producing operations under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Our Commercial organization also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be the spot market or a combination of our reserves and the spot market. Worldwide, we are contractually committed to deliver approximately 4 trillion cubic feet of natural gas, including approximately 600 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 200 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2028. We expect to fulfill the majority of these delivery commitments with proved developed reserves. In addition, we anticipate using proved undeveloped reserves and spot market purchases to fulfill any remaining commitments. See the disclosure on “Proved Undeveloped Reserves” in the “Oil and Gas Operations” section following the Notes to Consolidated Financial Statements, for information on the development of proved undeveloped reserves.

COMPETITION

We compete with private, public and state-owned companies in all facets of the E&P business. Some of our competitors are larger and have greater resources. Each of our segments is highly competitive, with no single competitor, or small group of competitors, dominating.

We compete with numerous other companies in the industry, including state-owned companies, to locate and obtain new sources of supply and to produce oil, bitumen, natural gas liquids and natural gas in an efficient, cost-effective manner. Based on statistics published in the September 2, 2013, issue of the Oil and Gas Journal, we had the third-largest worldwide liquids and natural gas reserves for U.S.-based oil and gas companies in 2012. We deliver our production into the worldwide commodity markets. Principal methods of competing include geological, geophysical and engineering research and technology; experience and expertise; economic analysis in connection with portfolio management; and safely operating oil and gas producing properties.

GENERAL

At the end of 2013, we held a total of 811 active patents in 55 countries worldwide, including 336 active U.S. patents. During 2013, we received 40 patents in the United States and 50 foreign patents. Our products and processes generated licensing revenues of $128 million in 2013. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.

Company-sponsored research and development activities charged against earnings were $258 million, $221 million and $193 million in 2013, 2012 and 2011, respectively.

Health, Safety and Environment

Our Health, Safety and Environment (HSE) organization provides tools and support to our business units and staff groups to help them ensure world class health, safety and environmental performance. The framework through which we safely manage our operations, the HSE Management System Standard, emphasizes process safety, risk management, emergency preparedness and environmental performance, with an intense focus on occupational safety. In support of the goal of zero incidents, our HSE Excellence Process requires the business

units to measure performance and drive continuous improvement. Assessments are conducted annually to capture progress and set new targets. We also have detailed processes in place to address sustainable development in our economic, environmental and social performance. Our processes, related tools and requirements focus on water, biodiversity and climate change, as well as social and stakeholder issues.

The environmental information contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations on pages 63 through 66 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2013 and those expected for 2014 and 2015.

Website Access to SEC Reports

Our internet website address is www.conocophillips.com. Information contained on our internet website is not part of this report on Form 10-K.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available on our website, free of charge, as soon as reasonably practicable after such reports are filed with, or furnished to, the U.S. Securities and Exchange Commission (SEC). Alternatively, you may access these reports at the SEC’s website at www.sec.gov.

Item 1A. RISK FACTORS

You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.

Our operating results, our future rate of growth and the carrying value of our assets are exposed to the effects of changing commodity prices.

Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our crude oil, bitumen, natural gas, natural gas liquids and LNG. The factors influencing these prices are beyond our control. Lower crude oil, bitumen, natural gas, natural gas liquids and LNG prices may have a material adverse effect on our revenues, operating income and cash flows and may reduce the amount of these commodities we can produce economically.

Unless we successfully add to our existing proved reserves, our future crude oil, bitumen, natural gas and natural gas liquids production will decline, resulting in an adverse impact to our business.

The rate of production from upstream fields generally declines as reserves are depleted. Except to the extent that we conduct successful exploration and development activities, or, through engineering studies, optimize production performance or identify additional or secondary recovery reserves, our proved reserves will decline materially as we produce crude oil, bitumen, natural gas and natural gas liquids. Accordingly, to the extent we are unsuccessful in replacing the crude oil, bitumen, natural gas and natural gas liquids we produce with good prospects for future production, our business will experience reduced cash flows and results of operations.

Any material change in the factors and assumptions underlying our estimates of crude oil, bitumen, natural gas and natural gas liquids reserves could impair the quantity and value of those reserves.

Our proved reserve information included in this annual report has been derived from engineering estimates prepared by our personnel. Future reserve revisions could also result from changes in, among other things, governmental regulation. Reserve estimation is a process that involves estimating volumes to be recovered from underground accumulations of crude oil, bitumen, natural gas and natural gas liquids that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Any significant future price changes could have a material effect on the quantity and present value of our proved reserves. Any material changes in the factors and assumptions underlying our estimates of these items could result in a material negative impact to the volume of reserves reported.

We expect to continue to incur substantial capital expenditures and operating costs as a result of our compliance with existing and future environmental laws and regulations. Likewise, future environmental laws and regulations may impact or limit our current business plans and reduce demand for our products.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment. These laws and regulations continue to increase in both number and complexity and affect our operations with respect to, among other things:

•

The discharge of pollutants into the environment.

•

Emissions into the atmosphere, such as nitrogen oxides, sulfur dioxide, and mercury and greenhouse gas emissions.

•

Carbon taxes.

•

The handling, use, storage, transportation, disposal and cleanup of hazardous materials and hazardous and nonhazardous wastes.

•

The dismantlement, abandonment and restoration of our properties and facilities at the end of their useful lives.

•

Exploration and production activities in certain areas, such as offshore environments, arctic fields, oil sands reservoirs and shale plays.

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our business, financial condition, results of operations and cash flows in future periods could be materially adversely affected.

Although our business operations are designed and operated to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.

In addition, in response to the Deepwater Horizon incident, the United States, as well as other countries where we do business, may make changes to their laws or regulations governing offshore operations that could have a material adverse effect on our business.

Domestic and worldwide political and economic developments could damage our operations and materially reduce our profitability and cash flows.

Actions of the U.S., state, local and foreign governments, through tax and other legislation, executive order and commercial restrictions, could reduce our operating profitability both in the United States and abroad. In certain locations, governments have imposed or proposed restrictions on our operations; special taxes or tax assessments; and payment transparency regulations that could require us to disclose competitively sensitive information or might cause us to violate non-disclosure laws of other countries. U.S. federal, state and local legislative and regulatory agencies’ initiatives regarding the hydraulic fracturing process could result in operating restrictions or delays in the completion of our oil and gas wells.

The U.S. government can also prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in, or gain access to, opportunities in various countries. Actions by host governments have affected operations significantly in the past, such as the expropriation of our oil assets by the Venezuelan government, and may continue to do so in the future. Changes in domestic and international regulations may affect our ability to obtain or maintain permits, including those necessary for drilling and development of wells or for construction of LNG terminals or regasification facilities in various locations.

Local political and economic factors in international markets could have a material adverse effect on us. Approximately 54 percent of our hydrocarbon production from continuing operations was derived from production outside the United States in 2013, and 56 percent of our proved reserves, as of December 31, 2013, was located outside the United States. We are subject to risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas, bitumen, natural gas liquids or LNG pricing and taxation, other political, economic or diplomatic developments, changing political conditions and international monetary fluctuations.

Changes in governmental regulations may impose price controls and limitations on production of crude oil, natural gas, bitumen, and natural gas liquids.

Our operations are subject to extensive governmental regulations. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil, natural gas, bitumen and natural gas liquids wells below actual production capacity. Because legal requirements are frequently changed and subject to interpretation, we cannot predict the effect of these requirements.

Our investments in joint ventures decrease our ability to manage risk.

We conduct many of our operations through joint ventures in which we may share control with our joint venture partners. There is a risk our joint venture participants may at any time have economic, business or legal interests or goals that are inconsistent with those of the joint venture or us, or our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone. Failure by us, or an entity in which we have a joint venture interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and, in turn, our business and operations.

We do not insure against all potential losses; therefore, we could be harmed by unexpected liabilities and increased costs.

We maintain insurance against many, but not all, potential losses or liabilities arising from operating risks. As such, our insurance coverage may not be sufficient to fully cover us against potential losses arising from such risks. Uninsured losses and liabilities arising from operating risks could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations present hazards and risks that require significant and continuous oversight.

The scope and nature of our operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, crude oil spills, severe weather, geological events, labor disputes, civil unrest or cyber attacks. Our operations may be adversely affected by unavailability, interruptions or accidents involving infrastructure required to process or transport our production, such as pipelines, railcars, tankers, barges or other infrastructure. Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks. Activities in deepwater areas may pose incrementally greater risks because of complex subsurface conditions such as higher reservoir pressures, water depths and metocean conditions. All such hazards could result in loss of human life, significant property and equipment damage, environmental pollution, impairment of operations, substantial losses to us and damage to our reputation.

Our technologies, systems and networks may be subject to cybersecurity breaches. Although we have experienced occasional, actual or attempted breaches of our cybersecurity, none of these breaches have had a material effect on our business, operations or reputation. If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business systems compromised, our proprietary information altered, lost or stolen, or our business operations disrupted.

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

The following is a description of reportable legal proceedings, including those involving governmental authorities under federal, state and local laws regulating the discharge of materials into the environment for this reporting period. The following proceedings include those matters that arose during the fourth quarter of 2013, as well as matters previously reported in our 2012 Form 10-K and our
first-, second- and third-quarter 2013 Form 10-Qs that were not resolved prior to the fourth quarter of 2013. Material developments to the previously reported matters have been included in the descriptions below. While it is not possible to accurately predict the final outcome of these pending proceedings, if any one or more of such proceedings were to be decided adversely to ConocoPhillips, we expect there would be no material effect on our consolidated financial position. Nevertheless, such proceedings are reported pursuant to the SEC regulations.

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

Matters Previously Reported – ConocoPhillips

The New Mexico Environment Department has issued 4 Notices of Violation (NOVs) to ConocoPhillips alleging a total of 16 individual violations for failure to comply with air emission recordkeeping, reporting and testing requirements at various natural gas compression operations in northwestern New Mexico. These violations are alleged to have occurred between 2006 and 2012. The agency is seeking a penalty of over $100,000. We are working with the agency to resolve these matters.

Matters Previously Reported – Phillips 66

In October 2007, ConocoPhillips received a Complaint from the EPA alleging violations of the Clean Water Act related to a 2006 oil spill at the Phillips 66 Bayway Refinery and proposing a penalty of $156,000.

On May 19, 2010, the Phillips 66 Lake Charles Refinery received a Consolidated Compliance Order and Notice of Potential Penalty from the Louisiana Department of Environmental Quality (LDEQ) alleging various violations of applicable air emission regulations, as well as certain provisions of the consent decree in Civil Action No. H-01-4430.

In October 2011, ConocoPhillips was notified by the Attorney General of the State of California that it was conducting an investigation into possible violations of the regulations relating to the operation of underground storage tanks at gas stations in California. On January 3, 2013, the California Attorney General filed a lawsuit notice that alleges such violations.

On March 7, 2012, the Bay Area Air Quality Management District (District) in California issued a $302,500 demand to settle five NOVs issued between 2008 and 2010. The NOVs allege non-compliance with the District rules and/or facility permit conditions at the Phillips 66 Rodeo Refinery.

On September 19, 2012, the District issued a $213,500 demand to settle 14 NOVs issued in 2009 and 2010 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

On October 15, 2012, the District issued a $313,000 demand to settle 13 other NOVs issued in 2010 and 2011 with respect to alleged violations of regulatory and/or permit requirements at the Phillips 66 Rodeo Refinery.

In May 2012, the Illinois Attorney General’s office filed and notified ConocoPhillips of a complaint with respect to operations at the Phillips 66 Wood River Refinery alleging violations of the Illinois groundwater standards and a third-party’s hazardous waste permit. The complaint seeks as relief remediation of area groundwater; compliance with the hazardous waste permit; enhanced pipeline and tank integrity measures; additional spill reporting; and yet-to-be specified amounts for fines and penalties.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT


Name	Position Held	Age*

Ellen R. DeSanctis	Vice President, Investor Relations and Communications	57

Sheila Feldman	Vice President, Human Resources	59

Matt J. Fox	Executive Vice President, Exploration and Production	53

Alan J. Hirshberg	Executive Vice President, Technology and Projects	52

Janet L. Kelly	Senior Vice President, Legal, General Counsel and Corporate Secretary	56

Ryan M. Lance	Chairman of the Board of Directors and Chief Executive Officer	51

Andrew D. Lundquist	Senior Vice President, Government Affairs	53

Glenda M. Schwarz	Vice President and Controller	48

Jeff W. Sheets	Executive Vice President, Finance and Chief Financial Officer	56

Don E. Wallette, Jr.	Executive Vice President, Commercial, Business Development and Corporate Planning	55

*On February 15, 2014.

There are no family relationships among any of the officers named above. Each officer of the Company is elected by the Board of Directors at its first meeting after the Annual Meeting of Stockholders and thereafter as appropriate. Each officer of the Company holds office from the date of election until the first meeting of the directors held after the next Annual Meeting of Stockholders or until a successor is elected. The date of the next annual meeting is May 13, 2014. Set forth below is information about the executive officers.

Ellen R. DeSanctis was appointed Vice President, Investor Relations and Communications in May 2012. She was previously employed by Petrohawk Energy Corp. and served as Senior Vice President, Corporate Communications since 2010. Prior to that she was employed by Rosetta Resources Inc. and served as Executive Vice President of Strategy and Development from 2008 to 2010.

Sheila Feldman was appointed Vice President, Human Resources in May 2012. She was previously employed by Arch Coal, Inc. and served as Vice President, Human Resources since 2003.

Matt J. Fox was appointed Executive Vice President, Exploration and Production in May 2012. Prior to that, he was employed by Nexen, Inc. and served as Executive Vice President, International since 2010. He was previously employed by ConocoPhillips and served as President, ConocoPhillips Canada from 2009 to 2010 and Senior Vice President, Oil Sands and Canadian Arctic from 2007 to 2009.

Alan J. Hirshberg was appointed Executive Vice President, Technology and Projects in May 2012. Prior to that, he served as Senior Vice President, Planning and Strategy since 2010. He was previously employed by Exxon Mobil Corporation and served as Vice President, Worldwide Deepwater and Africa Projects since 2009; and Vice President, Worldwide Deepwater Projects from 2008 to 2009.

Janet L. Kelly was appointed Senior Vice President, Legal, General Counsel and Corporate Secretary in 2007.

Ryan M. Lance was appointed Chairman of the Board of Directors and Chief Executive Officer in May 2012, having previously served as Senior Vice President, Exploration and Production—International since May 2009. Prior to that, he served as President, Exploration and Production—Asia, Africa, Middle East and Russia/Caspian since April 2009; and President, Exploration and Production— Europe, Asia, Africa and the Middle East from 2007 to 2009.

Andrew D. Lundquist was appointed Senior Vice President, Government Affairs in 2013. Prior to that, he served as managing partner of BlueWater Strategies LLC, since 2002.

Glenda M. Schwarz was appointed Vice President and Controller in 2009. She previously served as General Auditor and Chief Ethics Officer from 2008 to 2009.

Jeff W. Sheets was appointed Executive Vice President, Finance and Chief Financial Officer in May 2012. Prior to that, he served as Senior Vice President, Finance and Chief Financial Officer since 2010 and Senior Vice President, Planning and Strategy since 2008.

Don E. Wallette, Jr. was appointed Executive Vice President, Commercial, Business Development and Corporate Planning in May 2012. Prior to that, he served as President, Asia Pacific since 2010 and President, Russia/Caspian from 2006 to 2010.

PART II

Item 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Quarterly Common Stock Prices and Cash Dividends Per Share

ConocoPhillips’ common stock is traded on the New York Stock Exchange, under the symbol “COP.”


	Stock Price
		High	Low		Dividends

2013
First	$	62.05	56.78		0.66
Second		64.77	56.38		0.66
Third		71.09	60.73		0.69
Fourth		74.59	68.23		0.69


2012
First	$	78.29	68.00		0.66
Second		77.31	50.62		0.66
Third		58.90	52.84		0.66
Fourth		59.65	53.95		0.66


Closing Stock Price at December 31, 2013				$	70.65
Closing Stock Price at January 31, 2014				$	64.95
Number of Stockholders of Record at January 31, 2014*					54,896

*In determining the number of stockholders, we consider clearing agencies and security position listings as one stockholder for each agency listing.

Issuer Purchases of Equity Securities

Our share repurchase program announced on December 2, 2011, to repurchase up to $10 billion of common stock expired on December 2, 2013. Approximately $5.1 billion of shares were repurchased under the program since its inception.

Item 6. SELECTED FINANCIAL DATA


	Millions of Dollars Except Per Share Amounts
	2013		2012		2011		2010		2009


Sales and other operating revenues	$	54,413		57,967		64,196		56,215		47,879
Income from continuing operations		8,037		7,481		7,188		10,305		3,737
Per common share
Basic		6.47		5.95		5.18		6.93		2.46
Diluted		6.43		5.91		5.14		6.88		2.44
Income from discontinued operations		1,178		1,017		5,314		1,112		755
Net income		9,215		8,498		12,502		11,417		4,492
Net income attributable to ConocoPhillips		9,156		8,428		12,436		11,358		4,414
Per common share
Basic		7.43		6.77		9.04		7.68		2.96
Diluted		7.38		6.72		8.97		7.62		2.94
Total assets		118,057		117,144		153,230		156,314		152,138
Long-term debt		21,073		20,770		21,610		22,656		26,925
Joint venture acquisition obligation—long-term		-		2,810		3,582		4,314		5,009
Cash dividends declared per common share		2.70		2.64		2.64		2.15		1.91

Many factors can impact the comparability of this information, such as:

•

Net income and Net income attributable to ConocoPhillips for all periods presented includes income from discontinued operations as a result of the separation of the Downstream business, the sale of our interest in Kashagan, the sale of our Algeria business, and the intention to sell our Nigeria business. Total assets for 2011 and prior years includes assets for the Downstream business. For additional information, see Note 3—Discontinued Operations, in the Notes to Consolidated Financial Statements.

•

The financial data for 2010 includes the impact of $5,563 million before-tax ($4,463 million after-tax) related to gains from asset dispositions and LUKOIL share sales.

See Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Notes to Consolidated Financial Statements for a discussion of factors that will enhance an understanding of this data.

Item 7.

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, and supplemental oil and gas disclosures included elsewhere in this report. 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 71.

Due to discontinued operations reporting, as more fully described below, income (loss) from continuing operations is more representative of ConocoPhillips’ earnings. The terms “earnings” and “loss” as used in Management’s Discussion and Analysis refer to income (loss) from continuing operations.

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 27 countries. At December 31, 2013, we had approximately 18,400 employees worldwide and total assets of $118 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Discontinued Operations

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects. Our value proposition to our shareholders is to deliver production and cash margin growth, competitive returns on capital, and a compelling dividend, while keeping our fundamental commitment to safety, operating excellence and environmental stewardship. We expect to achieve this value proposition through optimizing our portfolio, investing in high-margin developments, applying technical capability and maintaining financial flexibility.

We achieved several strategic milestones in 2013. We delivered on our non-core asset sales, advanced our growth programs, achieved exploration success and increased shareholder distributions. These accomplishments will position us to meet our goal of 3 to 5 percent annual production and margin growth beginning in 2014.

During 2013, we generated $15.8 billion in cash from continuing operations, paid dividends on our common stock of $3.3 billion and generated $10.2 billion in proceeds from dispositions of non-core assets. This brings the total proceeds received to $12.4 billion for the 2012–2013 program, which has exceeded our goal of raising $8–$10 billion in proceeds from disposition of non-strategic assets during 2012 and 2013. Consistent with our commitment to offer our shareholders a compelling dividend, in July 2013, our Board of Directors increased our quarterly dividend by 4.5 percent to $0.69 per share.

In 2013, we achieved production of 1,545 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 43 MBOED. With the startup of major projects at Christina Lake Phase E, Ekofisk South and Jasmine in 2013, final preparations underway for full-field startup at Gumusut and Siakap North-Petai, and a portfolio of high-margin opportunities, we have the momentum to begin delivering our volume growth goals in 2014.

We funded a $16.9 billion capital program in 2013 and fully prepaid a $2.8 billion joint venture acquisition obligation to our 50 percent owned FCCL Partnership. Our 2013 capital program yielded a strong organic reserve replacement, as our annual organic reserve replacement ratio was 179 percent. The organic reserve additions represent a continuing portfolio shift to higher-value liquids and reflect increased levels of activity in our development programs and major projects.

Our 2014 capital budget of $16.7 billion will target our diverse portfolio of global opportunities, with approximately 55 percent of the budget allocated toward North America and 45 percent toward Europe, Asia Pacific and other international businesses. Our investments will be directed predominantly toward high-quality developments already underway in the United States, Canada, the United Kingdom, the Norwegian North Sea, Malaysia and Australia, as well as exploration opportunities which will continue to build our inventory for the future.

Key Operating and Financial Highlights

Significant highlights during 2013 included the following:

•

Achieved annual organic reserve replacement of 179 percent from reserve additions of approximately 1.1 billion barrels of oil equivalent.

•

Achieved annual production of 1,545 MBOED, including continuing operations of 1,502 MBOED and discontinued operations of 43 MBOED, and generated earnings of $8.0 billion.

•

Increased quarterly dividend by 4.5 percent.

•

Generated $10.2 billion in proceeds from asset dispositions.

•

Announced two deepwater Gulf of Mexico discoveries at Coronado and Gila, adding to the existing Shenandoah and Tiber discoveries in 2009.

•

Eagle Ford and Bakken production increased 60 percent in 2013 compared with 2012.

•

Commenced production from major projects at Christina Lake Phase E, Ekofisk South and Jasmine, with preparations underway for full-field startup at Gumusut and Siakap North-Petai in 2014.

Business Environment

The business environment for the energy industry has historically experienced many challenges which have influenced our operations and profitability, largely due to factors beyond our control, such as the global financial crisis and recession which began in 2008; supply disruptions or fears thereof caused by civil unrest or military conflicts; environmental laws; tax regulations; governmental policies; and weather-related disruptions. Recently, North America’s energy landscape has been transformed from resource scarcity to an abundance of

supply, as a result of advances in technology responsible for the rapid growth of shale production, successful exploration and development in the deepwater Gulf of Mexico and rising production from the Canadian oil sands. These dynamics generally influence world energy markets and commodity prices. The most significant factor impacting our profitability and related reinvestment of our operating cash flows into our business is commodity prices, which can be very volatile; therefore, our strategy is to maintain a strong balance sheet with a diverse portfolio of assets, which we believe will provide the financial flexibility to withstand challenging business cycles.

Operating and Financial Priorities

Important factors we must continue to manage well in order to be successful include:

•

Maintaining a relentless focus on safety and environmental stewardship. Safety and environmental stewardship, including the operating integrity of our assets, remain our highest priorities, and we are committed to protecting the health and safety of everyone who has a role in our operations and the communities in which we operate. We strive to conduct our business with respect and care for both the local and global environment and systematically manage risk to drive sustainable business growth. Our sustainability efforts in 2013 focused on updating action plans for climate change, biodiversity, water and human rights, as well as revamping public reporting to be more informative, searchable and responsive to common questions.

There has been heightened public focus on the safety of the oil and gas industry as a result of the 2010 Deepwater Horizon incident in the Gulf of Mexico. We are a founding member of the Marine Well Containment Company LLC (MWCC), a non-profit organization formed in 2010 to improve industry spill response in the U.S. Gulf of Mexico. MWCC developed a containment system, which meets the U.S. Bureau of Safety and Environmental Enforcement requirements for a subsea well containment system that can respond to a deepwater well control incident in the U.S. Gulf of Mexico. To complement this work internationally, we and several leading oil and gas companies established the Subsea Well Response Project in Norway, which enhances the oil industry’s ability to respond to subsea well-control incidents in international waters.

•

Adding to our proved reserve base. We primarily add to our proved reserve base in three ways:

Successful exploration, exploitation and development of new and existing fields.

Application of new technologies and processes to improve recovery from existing fields.

Acquisition of existing fields.

Through a combination of the methods listed above, we have been successful in adding to our proved reserve base, and we anticipate being able to do so in the future. In the five years ended December 31, 2013, our organic reserve replacement was 145 percent, excluding LUKOIL and the impact of sales and purchases.

Access to additional resources has become increasingly difficult as direct investment is prohibited in some nations, while fiscal and other terms in other countries can make projects uneconomic or unattractive. In addition, political instability, competition from national oil companies, and lack of access to high-potential areas due to environmental or other regulation may negatively impact our ability to increase our reserve base. As such, the timing and level at which we add to our reserve base may, or may not, allow us to replace our production over subsequent years.

•

Disciplined investment approach. We participate in a capital-intensive industry. As a result, we must invest significant capital dollars to explore for new oil and gas fields, develop newly discovered fields, maintain existing fields, and construct pipelines and liquefied natural gas (LNG) facilities. We use a disciplined approach to select the appropriate projects which will provide the most attractive investment opportunities, with a continued focus on organic growth in volumes and margins through higher-margin oil, condensate and LNG projects and limited investment in North American

conventional natural gas. As investments bring more liquids production online, we expect a corresponding shift in our production mix. However, there are often long lead times from the time we make an investment decision to the time the asset is operational and generates financial returns.

Our actual capital program for 2013 was $16.9 billion, excluding a $2.8 billion prepayment to FCCL for the remaining balance of our joint venture acquisition obligation. Our capital budget for 2014 is $16.7 billion. Approximately 13 percent of the 2014 capital budget is allocated toward maintenance of our legacy base portfolio, including planned turnarounds; 39 percent is allocated to high-margin development drilling programs, mostly in North America, which is intended to offset natural field decline from our producing assets; 35 percent is focused on sanctioned major developments, such as Australia Pacific LNG (APLNG) and Surmont Phase 2; and 13 percent is planned for our worldwide exploration and appraisal program, which will target both conventional and unconventional plays.

•

Portfolio optimization. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling nonstrategic holdings. In 2012, we announced plans to sell $8–$10 billion of noncore assets through the end of 2013. During 2013, we received proceeds from dispositions of approximately $10.2 billion, which primarily resulted from:

The disposition of our 8.4 percent interest in Kashagan, located in Kazakhstan.

The sale of our Algeria business.

The sale of the majority of our producing zones in the Cedar Creek Anticline, located in North Dakota and Montana.

The sale of our Clyden undeveloped oil sands leasehold, located in Canada.

The disposition of our 39 percent equity investment in Phoenix Park Gas Processors Limited, located in Trinidad and Tobago.

The disposition of a portion of our working interests in the Poseidon discovery in the Browse Basin and the Goldwyer Shale in the Canning Basin.

The disposition of certain properties located in southwest Louisiana.

The sale of our 10 percent interest in the Interconnector Pipeline, located in Europe.

As previously announced, we entered into agreements to sell our Nigeria business, which includes its upstream affiliates and Brass LNG. The upstream sale is anticipated to close in the first quarter of 2014 and generate proceeds of approximately $1.5 billion, after customary adjustments. We have received deposits to date of $500 million, with the remainder of approximately $1.0 billion due at closing. The buyer has until March 31, 2014, to close on Brass LNG. The sale of Brass LNG would generate proceeds of approximately $0.16 billion, after customary adjustments.

During 2012, we received proceeds of $2.1 billion from the sale of our Vietnam business, the Statfjord and Alba fields in the North Sea, our investment in Naryanmarneftegaz (NMNG) in Russia, and the additional dilution of our interest in APLNG from 42.5 percent to 37.5 percent.

Although we are near completion of the 2012–2013 asset disposition program, we will continue to evaluate our assets to determine whether they fit our strategic direction. We will prune the portfolio as necessary and direct our capital investments to areas which will achieve our strategic objectives.

•

Controlling costs and expenses. Since we cannot control the prices of the commodity products we sell, controlling operating and overhead costs, within the context of our commitment to safety and environmental stewardship, is a high priority. We monitor these costs using various methodologies that are reported to senior management monthly, on both an absolute-dollar basis and a per-unit basis. As managing operating and overhead costs is critical to maintaining competitive positions in our industry, cost control is a component of our variable compensation programs. Operating and overhead costs increased 4 percent in 2013 compared with 2012, primarily as a result of higher operating expenses in the Lower 48 associated with increased production.

•

Applying technical capability. We focus on ways to leverage our knowledge and technology to create value and safely deliver on our plans. Technical strength is part of our heritage, and we are evolving our technical approach to optimally apply best practices where they matter most. In 2013, we tested new technology as a means to provide remote monitoring capability, as well as new methods that could increase production and reduce water usage and emissions from assets, such as the oil sands and unconventional reservoirs. Companywide, we continue to evaluate potential solutions to leverage knowledge of technological successes across all of our operations. Such innovations enable us to economically convert additional resources to reserves, achieve greater operating efficiencies and reduce our environmental impact.

•

Developing and retaining a talented work force. We strive to attract, train, develop and retain individuals with the knowledge and skills to implement our business strategy and who support our values and ethics. As part of our future workforce planning, we are committed to increasing student interest in energy industry professions by awarding scholarships in science, technology, engineering, mathematics, accounting and finance, as well as providing university internships to attract the best talent. We also recruit experienced hires to maintain a broad range of skills and experience. Career development is an important investment in our employees and our future, so we focus on continued learning, development and technical training through structured development programs designed to accelerate technical and functional skills of our employees.

Other significant factors that can affect our profitability include:

•

Commodity prices. Our earnings generally correlate with industry price levels for crude oil and natural gas. These are commodity products, the prices of which are subject to factors external to our company and over which we have no control. The following table depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:


	Dollars Per Unit
	2013		2012		2011

Market Indicators
WTI (per barrel)	$	97.90		94.16		95.05
Dated Brent (per barrel)		108.65		111.58		111.27
U.S. Henry Hub first of month (per million British thermal units)		3.65		2.79		4.04

Brent crude oil prices decreased 3 percent in 2013, compared with 2012, to average $108.65 per barrel, as disruptions to the Organization of Petroleum Exporting Countries (OPEC) supplies were more than offset by non-OPEC production growth. Global oil demand grew 1 percent, or about 1.2 million barrels per day, to 91.2 million barrels per day. The fiscal uncertainties that plagued many developed countries, while not completely resolved, subsided enough to help restore confidence and growth in real economic activity in 2013.

WTI crude oil prices increased 4 percent in 2013, compared with 2012, as new infrastructure helped to alleviate the glut at Cushing, Oklahoma, by increasing the movement of physical barrels toward U.S. Gulf Coast refining centers. As a result, the WTI discount to Brent decreased by 38 percent to average $10.75. U.S. crude oil production grew 16 percent to reach an average of 7.5 million barrels per day. The growth was led by shale oil developments such as Bakken, Eagle Ford and Permian. U.S. oil demand increased by 2 percent in 2013, as economic growth strengthened.

Henry Hub natural gas prices increased 31 percent in 2013 compared with 2012. Strong weather-driven demand growth outweighed production growth and drew down high storage inventories. U.S. natural gas consumption rose 2 percent, or 1.5 billion cubic feet per day, to an all-time high of

71.2 billion cubic feet per day. U.S. dry gas production increased 1 percent, by 0.8 billion cubic feet per day, to reach 66.5 billion cubic feet per day, as growth from the Marcellus shale gas play more than offset declines in other areas.

The expansion in shale production has also helped boost supplies of natural gas liquids, resulting in downward pressure on natural gas liquids prices in the United States. As a result, our domestic realized natural gas liquids price declined 11 percent in 2013 compared with 2012. Our realized bitumen price remained relatively flat in 2013.

In recent years, the use of hydraulic fracturing and horizontal drilling in shale natural gas formations has led to increased industry actual and forecasted natural gas production in the United States. Although providing significant short- and long-term growth opportunities for our company, the increased abundance of natural gas due to development of shale plays could also have adverse financial implications to us, including: an extended period of low natural gas and natural gas liquids prices; production curtailments on properties that produce primarily natural gas; delay of plans to develop Alaska North Slope natural gas fields; and underutilization of LNG regasification facilities. Should one or more of these events occur, our revenues would be reduced and additional impairments might be possible.

•

Impairments. As mentioned above, we participate in capital-intensive industries. At times, our properties, plants and equipment and investments become impaired when, for example, our reserve estimates are revised downward, commodity prices decline significantly for long periods of time, or a decision to dispose of an asset leads to a write-down to its fair value. We may also invest large amounts of money in exploration which, if exploratory drilling proves unsuccessful, could lead to a material impairment of leasehold values. Before-tax impairments in 2013 totaled $0.5 billion and mainly resulted from impairments of various properties in Europe, which have ceased production or are nearing the end of their useful lives, and mature natural gas properties in Canada. Before-tax impairments in 2012 totaled $1.2 billion and primarily resulted from the impairments of the Mackenzie Gas Project and associated leaseholds in Canada; Cedar Creek Anticline in the Lower 48; various properties in Europe, which have ceased production or are nearing the end of their useful lives; and the N Block in the Caspian Sea. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

•

Effective tax rate. Our operations are located in countries with different tax rates and fiscal structures. Accordingly, even in a stable commodity price and fiscal/regulatory environment, our overall effective tax rate can vary significantly between periods based on the “mix” of pretax earnings within our global operations.

•

Fiscal and regulatory environment. Our operations can be affected by changing economic, regulatory and political environments in the various countries in which we operate, including the United States. Civil unrest or strained relationships with governments may impact our operations or investments. These changing environments have generally negatively impacted our results of operations, and further changes to government fiscal take could have a negative impact on future operations. Our production operations in Libya and related oil exports have been suspended since July 2013 due to the closure of the Es Sider crude oil export terminal, and they were also suspended in 2011 during Libya’s period of civil unrest. In the United Kingdom, the government enacted tax legislation in both 2012 and 2011, which increased our U.K. corporate tax rate. Our assets in Venezuela and Ecuador were expropriated in 2007 and 2009, respectively. Our management carefully considers these events when evaluating projects or determining the level of activity in such countries.

Outlook

Due to the ongoing shutdown of the Es Sider Terminal in Libya, we intend to exclude Libya from our future production outlooks. Production from continuing operations for 2013 was 1,502 MBOED, or 1,472 MBOED adjusted for Libya. Full-year 2014 production from continuing operations is expected to be approximately 1,550 MBOED, excluding Libya. First-quarter 2014 production from continuing operations is expected to be 1,490 to 1,530 MBOED, excluding Libya. Our Corporate and Other segment earnings are expected to be an after-tax loss of approximately $1.0 billion for the full-year 2014.

Freeport LNG Terminal

Operating Segments

The LUKOIL Investment segment represents our prior investment in the ordinary shares of OAO LUKOIL, which was sold in the first quarter of 2011.

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs related to the separation and certain technology activities, as well as licensing revenues received.

Our key performance indicators, shown in the statistical tables provided at the beginning of the operating segment sections that follow, reflect results from our continuing operations, including commodity prices and production.

RESULTS OF OPERATIONS

Consolidated Results

A summary of the company’s income (loss) from continuing operations by business segment follows:


	Millions of Dollars
Years Ended December 31	2013			2012			2011


Alaska	$	2,274			2,276			1,984
Lower 48 and Latin America		1,081			1,029			1,288
Canada		718			(684	)		91
Europe		1,199			1,498			1,830
Asia Pacific and Middle East		3,591			3,996			3,093
Other International		(6	)		359			(377)
LUKOIL Investment		-			-			239
Corporate and Other		(820	)		(993	)		(960)

Income from continuing operations	$	8,037			7,481			7,188

2013 vs. 2012

Earnings for ConocoPhillips increased 7 percent in 2013. The increase was mainly due to:

•

Lower impairments. Non-cash impairments in 2013 totaled $289 million after-tax, compared with $900 million after-tax in 2012.

•

Higher natural gas prices.

•

A higher proportion of production in higher-margin areas and a continued portfolio shift toward liquids.

•

Lower production taxes, primarily as a result of lower production volumes and prices, and higher capital spending in Alaska.

These items were partially offset by:

•

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

•

Lower gains from asset sales. In 2013, gains from asset dispositions were $1,132 million after-tax, compared with gains of $1,567 million after-tax in 2012.

•

Higher operating expenses.

•

Lower crude oil and natural gas liquids prices.

2012 vs. 2011

Earnings for ConocoPhillips increased 4 percent in 2012. The increase was mainly due to:

•

Higher gains from asset sales. In 2012, gains from asset dispositions were $1,567 million after-tax, compared with gains in 2011 from asset dispositions and LUKOIL share sales of $141 million after-tax.

•

Higher LNG and crude oil prices.

•

Lower production taxes, mainly as a result of lower volumes.

•

The benefit from the realization of a tax loss carryforward of $236 million.

•

The favorable resolution of pending claims and settlements of $235 million after-tax.

These items were partially offset by:

•

Lower volumes, largely due to dispositions and reduced production in China.

•

Lower natural gas, natural gas liquids and bitumen prices.

•

Higher operating and selling, general and administrative (SG&A) expenses, which included pension settlement expenses of $87 million after-tax and separation costs of $84 million after-tax.

•

Higher impairments. Non-cash impairments in 2012 totaled $900 million after-tax, compared with impairments in 2011 of $698 million after-tax.

Income Statement Analysis

2013 vs. 2012

Sales and other operating revenues decreased 6 percent in 2013, mainly due to lower natural gas volumes and lower crude oil prices, partly offset by higher natural gas prices.

Equity in earnings of affiliates increased 16 percent in 2013. The increase primarily resulted from higher earnings from FCCL Partnership, mainly as a result of higher bitumen volumes.

Gain on dispositions decreased 25 percent in 2013. For additional information, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Other income decreased 20 percent in 2013, primarily due to the absence of the 2012 benefit which resulted from the favorable resolution of the Petróleos de Venezuela S.A. (PDVSA) International Chamber of Commerce (ICC) arbitration. The decrease was partly offset by a $150 million insurance settlement in 2013 associated with the Bohai Bay seepage incidents. For information on a separate PDVSA arbitration with the World Bank’s International Centre for Settlement of Investment Disputes (ICSID), see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Purchased commodities decreased 10 percent in 2013, largely as a result of lower purchased natural gas volumes, partly offset by higher natural gas prices.

Production and operating expenses increased 7 percent in 2013, primarily due to increased drilling activity and production volumes, mostly in the Lower 48, in addition to a charge related to a settlement in Asia Pacific and Middle East. These increases were partly offset by the reduction of an accrual related to the Federal Energy Regulatory Commission (FERC) approval of cost allocation (pooling) agreements with the remaining owners of the Trans-Alaska Pipeline System (TAPS).

SG&A expenses decreased 23 percent in 2013, primarily due to the absence of separation costs, lower pension settlement expense and lower costs related to compensation and benefit plans. For additional information on pension settlement expense, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

Exploration expenses decreased 18 percent in 2013, largely due to lower leasehold impairment costs. Exploration costs in 2012 included the $481 million impairment of undeveloped leasehold costs associated with the Mackenzie Gas Project, as a result of the indefinite suspension of the project. Increased 2013 exploration activity and higher dry hole costs, mostly in the Lower 48, partly offset the reduction.

DD&A increased 13 percent in 2013. The increase was mostly associated with higher production volumes in the Lower 48. Higher production volumes in China partly contributed to the increase.

Impairments decreased 22 percent in 2013. Impairments in 2013 mainly consisted of increases in the asset retirement obligation (ARO) for properties located in the United Kingdom, which have ceased production or are nearing the end of their useful lives, and mature natural gas properties in Canada. Impairments in 2012 consisted of impairments of capitalized development costs associated with the Mackenzie Gas Project, the disposition of Cedar Creek Anticline and impairments of late-life U.K. properties. For additional information, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 19 percent in 2013, mainly due to lower production taxes as a result of lower crude oil production volumes and prices, and higher capital spending in Alaska.

Interest and debt expense decreased 14 percent in 2013, mostly as a result of lower interest expense from lower average 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.

2012 vs. 2011

Sales and other operating revenues decreased 10 percent in 2012, mainly due to lower natural gas and natural gas liquids prices, partly offset by higher LNG prices.

Equity in earnings of affiliates increased 54 percent in 2012. The increase primarily resulted from:

•

Improved earnings from Qatar Liquefied Gas Company Limited (3) (QG3), mainly due to higher LNG prices, partly offset by lower volumes.

•

Lower impairments from NMNG. In 2011, equity earnings included a $395 million impairment of our equity investment.

Gain on dispositions increased $1,287 million in 2012. Gains in 2012 primarily resulted from the disposition of our Vietnam business, our equity investment in NMNG and the Statfjord and Alba fields in the North Sea, partly offset by the loss on further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent. Gains in 2011 mainly consisted of the divestiture of our remaining LUKOIL shares and the disposition of certain properties located in the Lower 48 and Canada, partially offset by the loss on the initial dilution of our equity interest in APLNG from 50 percent to 42.5 percent.

Other income increased 78 percent in 2012, mostly as a result of the favorable resolution of the PDVSA ICC arbitration.

Purchased commodities decreased 15 percent in 2012, largely as a result of lower U.S. natural gas prices, partly offset by higher purchased volumes.

Production and operating expenses increased 6 percent in 2012, mostly due to major turnaround expenses at our Bayu-Undan Field and Darwin LNG facility and higher operating expenses in the Lower 48.

SG&A expenses increased 28 percent in 2012, primarily due to pension settlement expense and costs associated with the separation of Phillips 66.

Exploration expenses increased 45 percent in 2012, mostly due to the Mackenzie Gas Project impairment.

Impairments increased 112 percent in 2012. Impairments in 2012 included the impairment of capitalized development costs associated with the Mackenzie Gas Project, the disposition of Cedar Creek Anticline, and impairments of various late-life properties, mostly located in the United Kingdom. Impairments in 2011 consisted of various North American natural gas properties.

Taxes other than income taxes decreased 11 percent in 2012, mostly due to lower production taxes as a result of lower crude oil production volumes.

Interest and debt expense decreased 26 percent in 2012, primarily due to higher capitalized interest on projects and lower interest expense due to lower average 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.

Summary Operating Statistics


	2013		2012		2011


Average Net Production
Crude oil (MBD)*		581		595		622
Natural gas liquids (MBD)		156		156		145
Bitumen (MBD)		109		93		67
Natural gas (MMCFD)**		3,939		4,096		4,359


Total Production (MBOED)***		1,502		1,527		1,561


	Dollars Per Unit
Average Sales Prices
Crude oil (per barrel)	$	103.32		105.72		105.52
Natural gas liquids (per barrel)		41.42		46.36		55.73
Bitumen (per barrel)		53.27		53.91		62.56
Natural gas (per thousand cubic feet)		6.11		5.48		5.80


	Millions of Dollars
Worldwide Exploration Expenses
General and administrative; geological and geophysical; and lease rentals	$	789		626		569
Leasehold impairment		175		719		159
Dry holes		268		155		310

	$	1,232		1,500		1,038

Excludes discontinued operations.

*Thousands of barrels per day.

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

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

We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2013, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

In 2013, average production from continuing operations decreased 2 percent compared with 2012, mainly due to normal field decline, asset dispositions, shut-in Libya production, due to the closure of the Es Sider crude oil export terminal, and higher unplanned downtime. These decreases were partially offset by new production from major developments, mainly from shale plays in the Lower 48, the ramp-up of production from new phases at Christina Lake in Canada, and early production in Malaysia; higher production in China; and increased conventional drilling and well performance, mostly in the Lower 48, western Canada and Norway. Adjusted for dispositions, downtime and the impact from the closure of the Es Sider Terminal in Libya, production grew by 30 MBOED, or 2 percent, compared with 2012.

In 2012, average production from continuing operations decreased 2 percent compared with 2011, primarily as a result of normal field decline, the impact from asset dispositions and higher planned and unplanned downtime. These decreases were largely offset by additional production from major developments, mainly from shale plays in the Lower 48 and ramp-up of new phases at FCCL, the resumption of production in Libya following a period of civil unrest in 2011, and increased drilling programs in the Lower 48.

Alaska


	2013		2012		2011


Income from Continuing Operations (millions of dollars)	$	2,274		2,276		1,984


Average Net Production
Crude oil (MBD)		178		188		200
Natural gas liquids (MBD)		15		16		15
Natural gas (MMCFD)		43		55		61


Total Production (MBOED)		200		213		225


Average Sales Prices
Crude oil (per barrel)	$	107.83		109.62		105.95
Natural gas (per thousand cubic feet)		4.35		4.22		4.56

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2013, Alaska contributed 23 percent of our worldwide liquids production and 1 percent of our natural gas production.

2013 vs. 2012

Alaska earnings in 2013 were flat compared with 2012 earnings. Earnings in 2013 were mainly impacted by lower crude oil volumes and lower crude oil prices. These decreases to earnings were mostly offset by lower production taxes, which resulted from lower prices, higher 2013 capital spending and lower crude oil production volumes. Additionally, 2013 earnings benefitted from the impact of a ruling by the FERC.

In 2012, the major owners of TAPS filed a proposed settlement with FERC to resolve pooling disputes prior to August 2012 and establish a voluntary pooling agreement to pool costs prospectively from August 2012. In July 2013, the FERC approved the proposed settlement and pooling agreement without modification. Under the terms of the agreements, we paid the other remaining owners of TAPS $355 million, including interest, in the third quarter of 2013. As a result of FERC approval of these agreements, we reduced a related accrual in the second quarter of 2013, which decreased our production and operating expenses by $97 million after-tax. The FERC ruling approving these agreements has been appealed by certain parties to the Court of Appeals for the District of Columbia.

Production averaged 200 MBOED in 2013, a decrease of 6 percent compared with 2012. This decrease was mainly due to normal field decline, partially offset by lower planned downtime.

2012 vs. 2011

Alaska earnings in 2012 increased 15 percent compared with earnings in 2011. The increase in earnings was primarily due to higher crude oil prices, lower production taxes as a result of lower crude oil production volumes, the absence of the $54 million after-tax write-off of our investment associated with the cancellation of the Denali gas pipeline project in 2011, and lower DD&A. These increases were partly offset by lower crude oil sales volumes and higher operating expenses.

Production averaged 213 MBOED in 2012, a decrease of 5 percent compared with 2011. This decrease was mainly due to normal field decline, partially offset by lower unplanned downtime.

Lower 48 and Latin America


	2013		2012		2011


Income from Continuing Operations (millions of dollars)	$	1,081		1,029		1,288


Average Net Production
Crude oil (MBD)		152		123		94
Natural gas liquids (MBD)		91		85		74
Natural gas (MMCFD)		1,490		1,493		1,556


Total Production (MBOED)		491		457		428


Average Sales Prices
Crude oil (per barrel)	$	93.79		91.67		92.79
Natural gas liquids (per barrel)		31.48		35.45		50.55
Natural gas (per thousand cubic feet)		3.50		2.67		3.99

During 2013, Lower 48 and Latin America contributed 29 percent of our worldwide liquids production and 38 percent of our natural gas production. The Lower 48 and Latin America segment primarily consists of operations located in the U.S. Lower 48 states, as well as exploration activities in the Gulf of Mexico and Colombia.

2013 vs. 2012

Lower 48 and Latin America earnings increased 5 percent in 2013 compared with 2012. Earnings in 2013 largely benefitted from higher crude oil and NGL volumes, higher gains from asset dispositions, mostly as a result of the $288 million after-tax gain on disposition of our equity investment in Phoenix Park, higher natural gas and crude oil prices and lower impairments. These increases were partially offset by higher DD&A, as a result of higher crude oil production, as well as the absence of the 2012 realization of a tax loss carryforward of $236 million and the 2012 favorable resolution of the PDVSA ICC arbitration, as more fully described below. Higher operating expenses, higher exploration expenses, which mainly resulted from the Thorn and Ardennes dry holes in the Gulf of Mexico, and lower NGL prices also partially offset the increase in 2013 earnings. For additional information on asset sales, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

In November 2012, based on an ICC arbitration tribunal ruling, PDVSA paid ConocoPhillips $68 million for pre-expropriation breaches of the Petrozuata project agreements, which resulted in a $61 million after-tax earnings increase. The Company also recognized additional income of $173 million after-tax associated with the reversal of a related contingent liability accrual. These amounts included interest of $33 million after-tax, which was reflected in the Corporate and Other segment. For information on a separate PDVSA ICSID arbitration, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Average production in the Lower 48 increased 7 percent in 2013, while average crude oil production increased 24 percent in the same period. New production, primarily from the Eagle Ford and Bakken areas, and improved drilling and well performance more than offset normal field decline and the impact from dispositions.

2012 vs. 2011

Lower 48 and Latin America earnings decreased 20 percent in 2012 compared with 2011. The decrease in earnings was primarily the result of substantially lower natural gas and natural gas liquids prices; higher DD&A, mostly due to higher crude oil and natural gas liquids production; lower gains from asset dispositions; higher operating expenses and higher impairments. These decreases were partially offset by higher crude oil

and natural gas liquids volumes. Earnings in 2012 also benefitted from the realization of a tax loss carryforward of $236 million, and the favorable resolution of the PDVSA ICC arbitration.

Average production increased 7 percent in 2012, while average crude oil production increased 31 percent over the same period. New production, primarily from the Eagle Ford, Bakken and Permian areas, and improved drilling and well performance more than offset normal field decline. In addition, higher unplanned downtime during 2012 partly offset the increase in production.

Canada


	2013		2012			2011


Income (Loss) from Continuing Operations (millions of dollars)	$	718		(684	)		91


Average Net Production
Crude oil (MBD)		13		13			12
Natural gas liquids (MBD)		25		24			26
Bitumen (MBD)
Consolidated operations		13		12			10
Equity affiliates		96		81			57

Total bitumen		109		93			67


Natural gas (MMCFD)		775		857			928


Total Production (MBOED)		276		273			260


Average Sales Prices
Crude oil (per barrel)	$	79.73		78.26			86.04
Natural gas liquids (per barrel)		47.19		48.64			56.84
Bitumen (dollars per barrel)
Consolidated operations		55.25		57.58			55.16
Equity affiliates		53.00		53.39			63.93
Total bitumen		53.27		53.91			62.56
Natural gas (per thousand cubic feet)		2.92		2.13			3.46

Our Canadian operations are mainly comprised of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2013, Canada contributed 17 percent of our worldwide liquids production and 20 percent of our natural gas production.

2013 vs. 2012

Canada operations reported earnings of $718 million in 2013, an increase of $1,402 million, compared with a loss of $684 million in 2012. The increase in 2013 earnings was largely due to:

•

The $461 million after-tax gain on disposition of our Clyden undeveloped oil sands leasehold.

•

Lower impairments. Impairments in 2013 consisted of the $162 million after-tax impairment of mature natural gas assets in western Canada. Impairments in 2012 mainly resulted from the $520 million after-tax impairment of the Mackenzie Gas Project and associated undeveloped leaseholds.

•

Higher bitumen volumes, primarily at Christina Lake.

•

The recognition of additional income of $224 million related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year.

For additional information on asset sales, see Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements. For additional information on impairments, see Note 9—Impairments, in the Notes to Consolidated Financial Statements.

Average production in Canada increased 1 percent in 2013, while average liquids production increased 13 percent in the same period, primarily from the oil sands. Normal field decline was more than offset by the ramp-up of production from Christina Lake Phases D and E in FCCL and improved drilling and well performance from western Canada.

2012 vs. 2011

Canada operations reported a loss of $684 million in 2012, a reduction of $775 million, compared with earnings of $91 million in 2011. The decrease in earnings was largely due to significantly lower natural gas prices, lower bitumen prices and higher impairments, mainly as a result of the Mackenzie Gas Project impairment in 2012. These decreases were partially offset by significantly higher bitumen volumes from FCCL and lower DD&A from our western Canadian gas assets, primarily due to asset dispositions and curtailments. Equity earnings from FCCL were also impacted by higher operating and DD&A expenses, mostly as a result of higher production volumes.

Average production in Canada increased 5 percent in 2012, while average liquids production increased 24 percent over the same period. Normal field decline and the impact from asset dispositions were more than offset by new production from Christina Lake Phases C and D and improved well performance from Foster Creek in FCCL.

Europe


	2013		2012		2011


Income from Continuing Operations (millions of dollars)	$	1,199		1,498		1,830


Average Net Production
Crude oil (MBD)		113		135		164
Natural gas liquids (MBD)		6		7		11
Natural gas (MMCFD)		416		516		626


Total Production (MBOED)		189		228		279


Average Sales Prices
Crude oil (dollars per barrel)	$	110.56		113.08		111.82
Natural gas liquids (per barrel)		58.36		61.53		59.19
Natural gas (per thousand cubic feet)		10.68		9.76		9.26

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Poland and Greenland. In 2013, our Europe operations contributed 14 percent of our worldwide liquids production and 11 percent of our natural gas production.

2013 vs. 2012

Europe operations reported a 20 percent decrease in 2013 earnings compared with 2012, primarily due to lower volumes and lower gains from asset dispositions. Gains realized in 2012 included the $287 million after-tax gain on sale of our interests in the Statfjord and Alba fields, compared with the $83 million after-tax gain on sale of our interest in the Interconnector Pipeline in 2013. These decreases were partly offset by the absence of

the recognition of $170 million in additional income tax expense in 2012, as a result of legislation enacted in the United Kingdom, which restricted corporate tax relief on decommissioning costs to 50 percent. The additional tax expense resulted from the revaluation of deferred tax balances.

Average production decreased 17 percent in 2013, primarily due to normal field decline. Major planned maintenance at Greater Ekofisk, higher unplanned downtime, mostly in the East Irish Sea, and asset dispositions also contributed to the decrease. These decreases were partially offset by improved drilling and well performance in Norway and new production from Jasmine and Ekofisk South.

2012 vs. 2011

Earnings from Europe decreased 18 percent in 2012 compared with 2011, mainly as a result of lower volumes, higher impairments and the U.K. tax increase. These decreases to earnings were partly offset by the gain on disposition of Statfjord and Alba and lower DD&A. Additionally, earnings in 2011 included a $316 million increase in U.K. corporate income tax expense due to legislation enacted in 2011. This additional tax expense consisted of $106 million for the revaluation of deferred tax liabilities and $210 million to reflect the higher tax rates from the effective date of the legislation, March 24, 2011, through December 31, 2011.

Production decreased 18 percent in 2012, mostly due to normal field decline, dispositions and higher unplanned downtime in the United Kingdom.

Asia Pacific and Middle East


	2013		2012		2011


Income from Continuing Operations (millions of dollars)	$	3,591		3,996		3,093


Average Net Production
Crude oil (MBD)
Consolidated operations		80		68		99
Equity affiliates		15		15		16

Total crude oil		95		83		115


Natural gas liquids (MBD)
Consolidated operations		12		16		12
Equity affiliates		7		8		7

Total natural gas liquids		19		24		19


Natural gas (MMCFD)
Consolidated operations		709		672		695
Equity affiliates		481		485		492

Total natural gas		1,190		1,157		1,187


Total Production (MBOED)		312		300		332


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	104.78		108.20		109.84
Equity affiliates		105.44		108.07		106.96
Total crude oil		104.88		108.18		109.46
Natural gas liquids (dollars per barrel)
Consolidated operations		73.82		79.26		72.87
Equity affiliates		73.31		77.30		70.62
Total natural gas liquids		73.63		78.64		71.98
Natural gas (dollars per thousand cubic feet)
Consolidated operations		10.61		10.63		9.82
Equity affiliates		8.98		8.54		5.93
Total natural gas		9.95		9.75		8.21

The Asia Pacific and Middle East segment has producing operations in China, Indonesia, Malaysia, Australia, Timor-Leste and Qatar, as well as exploration activities in Bangladesh and Brunei. During 2013, Asia Pacific and Middle East contributed 13 percent of our worldwide liquids production and 30 percent of our natural gas production.

2013 vs. 2012

Asia Pacific and Middle East earnings decreased 10 percent in 2013 compared with 2012. The decrease in earnings was largely due to:

•

Lower gains from asset dispositions. Amounts realized from dispositions in 2012 included the $937 million after-tax gain on sale of our Vietnam business, in addition to the $133 million after-tax loss on further dilution of our equity interest in APLNG from 42.5 percent to 37.5 percent.

•

Higher DD&A, mostly due to increased production in China.

•

A $116 million after-tax charge associated with a settlement.

•

Lower crude oil prices.

•

Higher operating expenses and production taxes.

•

The absence of a $72 million tax-related charge in 2012.

These decreases to earnings were partially offset by:

•

Higher crude oil and LNG volumes.

•

A $146 million after-tax insurance settlement associated with the Bohai Bay seepage incidents.

•

The absence of an $89 million after-tax charge related to the Bohai Bay settlement with the China State Oceanic Administration in 2012.

•

Higher equity earnings, mainly due to an $85 million tax benefit from foreign currency exchange rate movements.

Average production increased 4 percent in 2013. The improvement was largely due to:

•

Increased production in Bohai Bay, China.

•

New production from Panyu in the South China Sea.

•

The continued ramp-up of production in Malaysia.

•

Lower planned downtime, mainly from our Bayu-Undan Field and Darwin LNG facility.

These increases were partly offset by normal field decline and the Vietnam disposition.

2012 vs. 2011

Asia Pacific and Middle East earnings increased 29 percent in 2012 compared with 2011. Earnings in 2012 primarily benefitted from higher gains from asset dispositions, significantly higher LNG prices, higher equity earnings due to lower DD&A and operating expenses from QG3, and lower Bohai Bay expenses incurred in 2012. Amounts realized from dispositions in 2012 consisted of the Vietnam gain and the APLNG loss on further dilution from 42.5 percent to 37.5 percent, compared with a $279 million after-tax loss on the initial dilution of our interest in APLNG from 50 percent to 42.5 percent in 2011. The increase in 2012 earnings was partly offset by lower crude oil volumes, mainly as a result of the Bohai Bay seepage incidents and the Vietnam disposition, lower LNG volumes and higher production taxes.

Average production decreased 10 percent in 2012. The decrease was largely due to the disposition of our Vietnam business, normal field decline, planned maintenance at our Bayu-Undan Field and Darwin LNG Facility in 2012, as well as lower production in China.

Other International


	2013			2012		2011


Income (Loss) from Continuing Operations (millions of dollars)	$	(6	)		359		(377)


Average Net Production
Crude oil (MBD)
Consolidated operations		26			40		8
Equity affiliates		4			13		29

Total crude oil		30			53		37


Natural gas (MMCFD)		25			18		1


Total Production (MBOED)		34			56		37


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	107.21			110.75		98.30
Equity affiliates		72.43			96.50		101.62
Total crude oil		101.91			107.56		101.14
Natural gas (dollars per thousand cubic feet)		5.38			5.55		0.09

The Other International segment includes producing operations in Libya and Russia, as well as exploration activities in Angola, Senegal and Azerbaijan. During 2013, Other International contributed 4 percent of our worldwide liquids production.

2013 vs. 2012

Other International operations reported a loss of $6 million in 2013, compared with earnings of $359 million in 2012. The decrease in earnings was mainly due to the absence of the $443 million after-tax gain on disposition of our interest in NMNG in 2012. Lower volumes from Libya also contributed to the reduction. These decreases were partially offset by lower impairments. Earnings in 2012 included a $108 million after-tax impairment associated with the N Block in the Caspian Sea.

Average production decreased 39 percent in 2013, largely as a result of the shutdown of the Es Sider crude oil export terminal in Libya at the end of July 2013 and the disposition of our interest in NMNG in 2012. These decreases were partially offset by higher production from Libya during the first six months of 2013, compared with the ramp-up of production in 2012 following their period of civil unrest. Libya production remains shut-in, as the Es Sider Terminal closure has continued into the first quarter of 2014.

2012 vs. 2011

Other International earnings were $359 million in 2012, a $736 million increase compared with 2011. Earnings in 2012 primarily benefitted from the NMNG disposition, the absence of a $395 million after-tax impairment of our investment in NMNG in 2011, and higher earnings from Libya, as a result of the resumption of production following a period of civil unrest in 2011. These increases were partially offset by the N Block impairment.

Average production increased 51 percent in 2012, mainly due to the resumption of production in Libya, partly offset by field decline in Russia and the disposition of our interest in NMNG.

Asset Dispositions

In 2013, we sold our 8.4 percent interest in Kashagan for $5.4 billion, and we sold our Algeria business for $1.65 billion. We also have agreements to sell our Nigeria business, which includes its upstream affiliates and Brass LNG. Results of operations related to Kashagan, Algeria and Nigeria have been classified as discontinued operations in all periods presented in this Form 10-K. For additional information, see Note 3—Discontinued Operations and Note 6—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

LUKOIL Investment


	Millions of Dollars

	2013		2012		2011


Income from Continuing Operations	$	-		-		239

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.

Corporate and Other


	Millions of Dollars

	2013			2012			2011


Income (Loss) from Continuing Operations
Net interest	$	(530	)		(648	)		(710)
Corporate general and administrative expenses		(213	)		(313	)		(190)
Technology		(6	)		(4	)		15
Separation costs		-			(84	)		(25)
Other		(71	)		56			(50)

	$	(820	)		(993	)		(960)

2013 vs. 2012

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 18 percent in 2013, compared with 2012, primarily due to the absence of a $68 million after-tax premium on early debt retirement in 2012 and lower interest expense on lower average debt levels. These improvements were partially offset by the absence of the $33 million after-tax interest benefit from the 2012 favorable resolution of the PDVSA ICC arbitration. For additional information on the ICC arbitration, see the Results of Operations for Lower 48 and Latin America.

Corporate general and administrative expenses decreased 32 percent in 2013, mainly due to lower pension settlement expense and lower costs related to compensation and benefit plans. Pension settlement expense incurred in 2013 was $41 million after-tax, compared with $87 million after-tax in 2012.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands; unconventional reservoirs; subsurface technology; liquefied natural gas; and arctic, deepwater and sustainability technology.

Separation costs consist of expenses related to the separation of our Downstream business into a stand-alone, publicly traded company, Phillips 66.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment. “Other” expenses increased $127 million in 2013, primarily as a result of higher tax-related adjustments, the absence of a $39 million after-tax settlement which benefitted 2012 and higher foreign currency transaction losses.

2012 vs. 2011

Net interest decreased 9 percent in 2012 compared with 2011, mostly due to higher capitalized interest, lower interest expense due to lower average debt levels, higher interest income and the $33 million after-tax interest benefit from the favorable resolution of the PDVSA arbitration. These improvements were partly offset by a $68 million after-tax premium on early debt retirement.

Corporate general and administrative expenses increased 65 percent in 2012, mainly due to $87 million of after-tax pension settlement expense and higher costs related to compensation and benefit plans.

Technology reported a loss of $4 million in 2012, compared to earnings of $15 million in 2011, primarily as a result of lower licensing revenues.

Separation costs increased $59 million in 2012 and mainly included costs related to compensation and benefit plans.

The improvement in “Other” in 2012 was largely due to various tax-related adjustments, including a $39 million after-tax settlement. These improvements were partially offset by higher environmental expenses and foreign currency transaction losses.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars Except as Indicated

	2013			2012		2011


Net cash provided by continuing operating activities	$	15,801			13,458		13,953
Net cash provided by discontinued operations		286			464		5,693
Cash and cash equivalents		6,246			3,618		5,780
Short-term debt		589			955		1,013
Total debt		21,662			21,725		22,623
Total equity		52,492			48,427		65,749
Percent of total debt to capital*		29	%		31		26
Percent of floating-rate debt to total debt**		8	%		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 continuing operating activities is the primary source of funding. In addition, during 2013, we received $10,220 million in proceeds from asset sales. We used the remaining $748 million of our restricted cash balance, received in connection with the separation of Phillips 66, solely to pay dividends. During 2013, the primary uses of our available cash were $15,537 million to support our ongoing capital expenditures and investments; $3,334 million to pay dividends on our common stock; $2,810 million to prepay the remaining balance of our joint venture acquisition obligation with our 50 percent owned FCCL Partnership; and $946 million to repay debt. During 2013, cash and cash equivalents increased by $2,628 million, to $6,246 million.

In addition to cash flows from continuing 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 our current cash balance 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 expenditures and investments, dividend payments and required debt payments.

Significant Sources of Capital

Operating Activities

During 2013, cash provided by continuing operating activities was $15,801 million, a 17 percent increase from 2012. The increase was primarily related to lower income taxes due to a greater proportion of volumes in areas with more favorable fiscal regimes. During 2012, cash provided by continuing operations was $13,458 million, compared with $13,953 million in 2011.

While the stability of our cash flows from operating activities benefits from geographic diversity, our short- and long-term operating cash flows are highly dependent upon prices for crude oil, bitumen, natural gas, LNG and natural gas liquids. Prices and margins in our industry 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 generally this variability has not been as significant as that caused by commodity prices.

Our 2013 production from continuing operations averaged 1,502 MBOED. Future production is subject to numerous uncertainties, including, among others, the volatile crude oil and natural gas price environment, which may impact investment decisions; the effects of price changes on production sharing and variable-royalty contracts; timing of startups and major turnarounds; and weather-related disruptions. Our production from continuing operations in 2014 is expected to be 1,550 MBOED, excluding Libya.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2013 was 147 percent. Excluding the impact of sales and purchases, the organic reserve replacement was 179 percent of 2013 production. Over the five-year period ended December 31, 2013, our reserve replacement was 69 percent (including 95 percent from consolidated operations) reflecting the disposition of our interest in LUKOIL and the impact of asset dispositions. Excluding these items and purchases, our five-year organic reserve replacement was 145 percent. The total reserve replacement amount above is based on the sum of our net additions (revisions, improved recovery, purchases, extensions and discoveries, and sales) divided by our production, as shown in our reserve table disclosures. For additional information about our proved reserves, including both developed and undeveloped reserves, see the “Oil and Gas Operations” section of this report.

As discussed in the “Critical Accounting Estimates” section, engineering estimates of proved reserves are imprecise; therefore, each year reserves may be revised upward or downward due to the impact of changes in commodity prices or as more technical data becomes available on reservoirs. In 2013, 2012 and 2011, revisions increased reserves. It is not possible to reliably predict how revisions will impact reserve quantities in the future.

Asset Sales

Proceeds from asset sales in 2013 were $10,220 million, primarily from the sale of our 8.4 percent equity interest in Kashagan, the sale of our Algeria business, the sale of the majority of our producing zones in the Cedar Creek Anticline, the sale of our interest in the Clyden undeveloped oil sands leasehold, the sale of our 39 percent equity interest in Phoenix Park and the sale of a portion of our working interests in Browse and Canning basins. This compares with proceeds of $2,132 million in 2012, primarily from the sale of our Vietnam business, the sale of our equity interest in NMNG and the sale of our interest in the Statfjord and Alba fields in the North Sea.

We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

At December 31, 2013, we had a revolving credit facility totaling $7.5 billion expiring in August 2016. Our revolving credit facility 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 facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips, or 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. $1.15 billion commercial paper program, which is used to fund commitments relating to QG3. At both December 31, 2013 and 2012, we had no direct outstanding borrowings or letters of credit issued under the revolving credit facility. In addition, under the ConocoPhillips Qatar Funding Ltd. commercial paper program, there was $961 million of commercial paper outstanding at December 31, 2013, compared with $1,055 million at December 31, 2012. Since we had $961 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.5 billion in borrowing capacity under our revolving credit facility at December 31, 2013.

Our senior long-term debt is rated “A1” by Moody’s Investors Service and “A” by both Standard and Poor’s Rating Service and Fitch. We do not have any ratings triggers on any of our corporate debt that would cause an automatic default, and thereby impact our access to liquidity, in the event of a downgrade of our credit rating. If our credit rating were to deteriorate to a level prohibiting us from accessing the commercial paper market, we would still be able to access funds under our $7.5 billion revolving credit facility.

Certain of our project-related contracts and derivative instruments contain provisions requiring us to post collateral. Many of these contracts and instruments permit us to post either cash or letters of credit as collateral. At December 31, 2013 and December 31, 2012, we had direct bank letters of credit of $827 million and $852 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

Shelf Registration

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

Off-Balance Sheet Arrangements

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

For information about guarantees, see Note 13—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 both December 31, 2013 and December 31, 2012, was $21.7 billion. During 2013, we repaid bonds at maturity totaling $850 million. In June 2013, we incurred a capital lease obligation of $906 million. For more information, see Note 11—Debt, in the Notes to Consolidated Financial Statements.

We were obligated to contribute $7.5 billion, plus interest, over a 10-year period that began in 2007, to our 50 percent owned FCCL Partnership. Quarterly principal and interest payments of $237 million began in the second quarter of 2007. The principal portion of these payments totaled $772 million in 2013. In December 2013, we paid the remaining balance of the obligation, which totaled $2,810 million and is included in the “Other” line in the financing activities section of our consolidated statement of cash flows.

This $2,810 million prepayment substantially increases the FCCL Partnership’s ability to make distributions to its partners or fund future capital requirements without contributions from the partners. Interest accrued 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.

In July 2013, we announced a 4.5 percent increase in the quarterly dividend rate to 69 cents per share. Additionally, on February 5, 2014, we announced a dividend of 69 cents per share. The dividend will be paid March 3, 2014, to stockholders of record at the close of business on February 18, 2014.

In February 2014, the $400 million 4.75% Notes due 2014 were repaid at maturity.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations of our continuing operations as of December 31, 2013:


	Millions of Dollars

		Payments Due by Period

	Total		Up to 1 Year		Years 2-3			Years 4-5			After 5 Years


Debt obligations (a)	$	20,740		514		3,678			1,838			14,710
Capital lease obligations (b)		922		75		100			108			639

Total debt		21,662		589		3,778			1,946			15,349

Interest on debt and other obligations		15,259		1,137		2,076			1,900			10,146
Operating lease obligations (c)		2,749		602		1,002			500			645
Purchase obligations (d)		23,338		10,008		3,548			2,368			7,414
Other long-term liabilities
Pension and postretirement benefit contributions (e)		2,117		560		737			820			-
Asset retirement obligations (f)		10,076		489		1,333			805			7,449
Accrued environmental costs (g)		348		50		61			40			197
Unrecognized tax benefits (h)		144		144		(h	)		(h	)		(h)

Total	$	75,693		13,579		12,535			8,379			41,200

(a)	Includes $404 million of net unamortized premiums and discounts. See Note 11—Debt, in the Notes to Consolidated Financial Statements, for additional information.

(b)	Capital lease obligations are presented on a discounted basis.

(c)	Operating lease obligations are presented on an undiscounted basis.

(d)	Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms, presented on an undiscounted basis. Does not include purchase commitments for jointly owned fields and facilities where we are not the operator.

The majority of the purchase obligations are market-based contracts related to our commodity business. Product purchase commitments with third parties totaled $9,610 million.

Purchase obligations of $10,538 million are related to agreements to access and utilize the capacity of third-party equipment and facilities, including pipelines and LNG and product terminals, to transport, process, treat and store commodities. The remainder is primarily our net share of purchase commitments for materials and services for jointly owned fields and facilities where we are the operator.

(e)	Represents contributions to qualified and nonqualified pension and postretirement benefit plans for the years 2014 through 2018. For additional information related to expected benefit payments subsequent to 2018, see Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements.

(f)	Represents estimated discounted costs to retire and remove long-lived assets at the end of their operations.

(g)	Represents estimated costs for accrued environmental expenditures presented on a discounted basis for costs acquired in various business combinations and an undiscounted basis for all other accrued environmental costs.

(h)

Excludes unrecognized tax benefits of $511 million because the ultimate disposition and timing of any payments to be made with regard to such amounts are not reasonably estimable. Although unrecognized tax benefits are not a contractual obligation, they are presented in this table because they represent potential demands on our liquidity.

Capital Spending


	Millions of Dollars


	2013		2012		2011


Alaska	$	1,140		828		774
Lower 48 and Latin America		5,234		5,251		3,882
Canada		2,232		2,184		1,761
Europe		3,115		2,860		2,222
Asia Pacific and Middle East		3,382		2,430		2,325
Other International		252		415		8
Corporate and Other		182		204		242

Capital expenditures and investments from continuing operations		15,537		14,172		11,214

Discontinued operations in Kashagan, Nigeria and Algeria		609		817		1,038
Joint venture acquisition obligation (principal)—Canada*		772		733		695

Capital Program	$	16,918		15,722		12,947

*Excludes $2,810 million prepayment in the fourth quarter of 2013.

Our capital expenditures and investments from continuing operations for the three-year period ended December 31, 2013, totaled $40.9 billion. The expenditures over this period supported key exploration and developments, primarily:

•

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

•

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

•

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

•

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

•

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

•

Exploration leases and wells in deepwater Gulf of Mexico.

•

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

2014 CAPITAL BUDGET

Our 2014 capital budget is $16.7 billion, essentially flat compared with our 2013 capital program.

We are directing approximately 55 percent of our 2014 capital expenditures budget for continuing operations to North America. These funds are expected to be directed toward:

•

Increased investment in the Company’s successful development drilling programs in the Eagle Ford, Bakken and Permian.

•

Higher allocation of capital to Alaska compared to 2013, reflecting increased spending on the CD5 development and higher activity resulting from improved fiscal terms from the passage of the More Alaska Production Act.

•

Increased exploration and appraisal activity in several North American unconventional plays, including the Permian, Niobrara, Canol and Duvernay.

•

Higher levels of spending at Surmont Phase 2, in anticipation of first production in 2015.

•

Increased conventional exploration drilling in the deepwater Gulf of Mexico.

We are directing approximately 45 percent of our 2014 capital expenditures budget for continuing operations to Europe, Asia Pacific and other international businesses. These funds are expected to be directed toward:

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Peak spending at the APLNG Project, in anticipation of first LNG sales.

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Conventional exploration drilling offshore Angola, Senegal and the Browse Basin.

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Investments in Eldfisk II, Britannia Long-term Compression and Clair Ridge.

For information on proved undeveloped reserves and the associated costs to develop these reserves, see the “Oil and Gas Operations” section.

Contingencies

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

Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures. Estimates particularly sensitive to future changes include contingent liabilities recorded for environmental remediation, tax and legal matters. Estimated future environmental remediation costs are subject to change due to such factors as the uncertain magnitude of cleanup costs, the unknown time and extent of such remedial actions that may be required, and the determination of our liability in proportion to that of other responsible parties. Estimated future costs related to tax and legal matters are subject to change as events evolve and as additional information becomes available during the administrative and litigation processes. For information on other contingencies, see Note 14—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal and Tax 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, are required. See Note 20—Income Taxes, in the Notes to Consolidated Financial Statements, for additional information about income-tax-related contingencies.

Environmental

We are subject to the same numerous international, federal, state and local environmental laws and regulations as other companies in our industry. The most significant of these environmental laws and regulations include, among others, the:

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U.S. Federal Clean Air Act, which governs air emissions.

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U.S. Federal Clean Water Act, which governs discharges to water bodies.

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European Union Regulation for Registration, Evaluation, Authorization and Restriction of Chemicals (REACH).

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U.S. Federal Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), which imposes liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur.

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U.S. Federal Resource Conservation and Recovery Act (RCRA), which governs the treatment, storage and disposal of solid waste.

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U.S. Federal Oil Pollution Act of 1990 (OPA90), under which owners and operators of onshore facilities and pipelines, lessees or permittees of an area in which an offshore facility is located, and owners and operators of vessels are liable for removal costs and damages that result from a discharge of oil into navigable waters of the United States.

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U.S. Federal Emergency Planning and Community Right-to-Know Act (EPCRA), which requires facilities to report toxic chemical inventories with local emergency planning committees and response departments.

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U.S. Federal Safe Drinking Water Act, which governs the disposal of wastewater in underground injection wells.

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U.S. Department of the Interior regulations, which relate to offshore oil and gas operations in U.S. waters and impose liability for the cost of pollution cleanup resulting from operations, as well as potential liability for pollution damages.

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European Union Trading Directive resulting in European Emissions Trading Scheme.

These laws and their implementing regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. These permits can require an applicant to collect substantial information in connection with the application process, which can be expensive and time consuming. In addition, there can be delays associated with notice and comment periods and the agency’s processing of the application. Many of the delays associated with the permitting process are beyond the control of the applicant.

Many states and foreign countries where we operate also have, or are developing, similar environmental laws and regulations governing these same types of activities. While similar, in some cases these regulations may impose additional, or more stringent, requirements that can add to the cost and difficulty of marketing or transporting products across state and international borders.

The ultimate financial impact arising from environmental laws and regulations is neither clearly known nor easily determinable as new standards, such as air emission standards, water quality standards and stricter fuel regulations, continue to evolve. However, environmental laws and regulations, including those that may arise

to address concerns about global climate change, are expected to continue to have an increasing impact on our operations in the United States and in other countries in which we operate. Notable areas of potential impacts include air emission compliance and remediation obligations in the United States and Canada.

An example is the use of hydraulic fracturing, an essential completion technique that facilitates production of oil and natural gas otherwise trapped in lower permeability rock formations. A range of local, state, federal or national laws and regulations currently govern hydraulic fracturing operations, with hydraulic fracturing currently prohibited in some jurisdictions. Although hydraulic fracturing has been conducted for many decades, a number of new laws, regulations and permitting requirements are under consideration by the U.S. Environmental Protection Agency (EPA), the U.S. Department of the Interior, and others which could result in increased costs, operating restrictions, operational delays and/or limit the ability to develop oil and natural gas resources. Governmental restrictions on hydraulic fracturing could impact the overall profitability or viability of certain of our oil and natural gas investments. We have adopted operating principles that incorporate established industry standards designed to meet or exceed government requirements. Our practices continually evolve as technology improves and regulations change.

We also are subject to certain laws and regulations relating to environmental remediation obligations associated with current and past operations. Such laws and regulations include CERCLA and RCRA and their state equivalents. Longer-term expenditures are subject to considerable uncertainty and may fluctuate significantly.

We occasionally receive requests for information or notices of potential liability from the EPA and state environmental agencies alleging that we are a potentially responsible party under 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, 2012, we reported we had been notified of potential liability under CERCLA and comparable state laws at 11 sites around the United States. At December 31, 2013, we had been notified of 4 new sites, bringing the number of unresolved sites with potential liability to 15 sites.

For most Superfund sites, our potential liability will be significantly less than the total site remediation costs because the percentage of waste attributable to us, versus that attributable to all other potentially responsible parties, is relatively low. Although liability of those potentially responsible is generally joint and several for federal sites and frequently so for state sites, other potentially responsible parties at sites where we are a party typically have had the financial strength to meet their obligations, and where they have not, or where potentially responsible parties could not be located, our share of liability has not increased materially. 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 site conditions, apportion responsibility and determine the appropriate remediation. In some instances, we may have no liability or attain a settlement of liability. Actual cleanup costs generally occur after the parties obtain EPA or equivalent state agency approval. There are relatively few sites where we are a major participant, and given the timing and amounts of anticipated expenditures, neither the cost of remediation at those sites nor such costs at all CERCLA sites, in the aggregate, is expected to have a material adverse effect on our competitive or financial condition.

Expensed environmental costs were $546 million in 2013 and are expected to be about $580 million per year in 2014 and 2015. Capitalized environmental costs were $357 million in 2013 and are expected to be about $480 million per year in 2014 and 2015.

Accrued liabilities for remediation activities are not reduced for potential recoveries from insurers or other third parties and are not discounted (except those assumed in a purchase business combination, which we do record on a discounted basis).

Many of these liabilities result from CERCLA, RCRA and similar state or international laws that require us to undertake certain investigative and remedial activities at sites where we conduct, or once conducted,

operations or at sites where ConocoPhillips-generated waste was disposed. The accrual also includes a number of sites we identified that may require environmental remediation, but which are not currently the subject of CERCLA, RCRA or other agency enforcement activities. If applicable, we accrue receivables for probable insurance or other third-party recoveries. In the future, we may incur significant costs under both CERCLA and RCRA.

Remediation activities vary substantially in duration and cost from site to site, depending on the mix of unique site characteristics, evolving remediation technologies, diverse regulatory agencies and enforcement policies, and the presence or absence of potentially liable third parties. Therefore, it is difficult to develop reasonable estimates of future site remediation costs.

At December 31, 2013, our balance sheet included total accrued environmental costs of $348 million, compared with $364 million at December 31, 2012, for remediation activities in the U.S. and Canada. We expect to incur a substantial amount of these expenditures within the next 30 years.

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

Climate Change

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

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European Emissions Trading Scheme (ETS), the program through which many of the European Union (EU) member states are implementing the Kyoto Protocol. Our cost of compliance with the EU ETS in 2013 was approximately $2 million (net share pre-tax).

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A regulation issued by the Alberta government in 2007 under the Climate Change and Emissions Act. The regulation requires any existing facility with emissions equal to or greater than 100,000 metric tonnes of carbon dioxide or equivalent per year to reduce the net emissions intensity beginning July 1, 2007 by 12 percent. New facilities must reduce 2 percent per year until they reach the maximum target of 12 percent. We also incur a carbon tax for emissions from fossil fuel combustion in our British Columbia operations. The total cost of compliance with these Canadian regulations in 2013 was approximately $6 million.

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The U.S. Supreme Court decision in Massachusetts v. EPA, 549 U.S. 497, 127 S.Ct. 1438 (2007), confirming that the EPA has the authority to regulate carbon dioxide as an “air pollutant” under the Federal Clean Air Act.

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The EPA’s announcement on March 29, 2010 (published as “Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 75 Fed. Reg. 17004 (April 2, 2010)), and the EPA’s and U.S. Department of Transportation’s joint promulgation of a Final Rule on April 1, 2010, that 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.

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Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation in 2013 was approximately $44 million (net share pre-tax).

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Cap and trade programs in certain jurisdictions, including the Australian Clean Energy Legislation, which took effect in July 2012. Our cost of compliance with the Australian Clean Energy Legislation in 2013 was approximately $10 million (net share pre-tax).

In the United States, some additional form of regulation may be forthcoming in the future at the federal and state levels with respect to GHG emissions. Such regulation could take any of several forms that may result in the creation of additional costs in the form of taxes, the restriction of output, investments of capital to maintain compliance with laws and regulations, or required acquisition or trading of emission allowances. We are working to continuously improve operational and energy efficiency through resource and energy conservation throughout our operations.

Compliance with changes in laws and regulations that create a GHG emission trading scheme or GHG reduction policies could significantly increase our costs, reduce demand for fossil energy derived products, impact the cost and availability of capital and increase our exposure to litigation. Such laws and regulations could also increase demand for less carbon intensive energy sources, including natural gas. The ultimate impact on our financial performance, either positive or negative, will depend on a number of factors, including but not limited to:

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Whether and to what extent legislation is enacted.

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The nature of the legislation (such as a cap and trade system or a tax on emissions).

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The price placed on GHG emissions (either by the market or through a tax).

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The GHG reductions required.

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The price and availability of offsets.

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The amount and allocation of allowances.

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Technological and scientific developments leading to new products or services.

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Any potential significant physical effects of climate change (such as increased severe weather events, changes in sea levels and changes in temperature).

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Whether, and the extent to which, increased compliance costs are ultimately reflected in the prices of our products and services.

The Company has responded by putting in place a corporate Climate Change Action Plan, together with individual business unit climate change management plans in order to undertake actions in four major areas:

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Equipping the Company for a low emission world, for example by integrating GHG forecasting and reporting into company procedures; utilizing GHG pricing in planning economics; developing systems to handle GHG market transactions.

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Reducing GHG emissions—In 2012 the Company reduced GHG emissions by approximately 1,000,000 metric tonnes by carrying out a range of programs across a number of business units.

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Evaluating business opportunities such as the creation of offsets and allowances; carbon capture and storage; the use of low carbon energy and the development of low carbon technologies.

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Engaging externally—The Company is a sponsor of MIT’s Joint Program on the Science and Policy of Global Change; constructively engages in the development of climate change legislation and regulation; and discloses our progress and performance through the Carbon Disclosure Project and the Dow Jones Sustainability Index.

The Company uses an estimated market cost of GHG emissions in the range of $6 to $46 per tonne depending on the timing and country or region to evaluate future opportunities.

Other

We have deferred tax assets related to certain accrued liabilities, loss carryforwards and credit carryforwards. Valuation allowances have been established to reduce these deferred tax assets to an amount that will, more likely than not, be realized. Based on our historical taxable income, our expectations for the future, and available tax-planning strategies, management expects the net deferred tax assets will be realized as offsets to reversing deferred tax liabilities and as reductions in future taxable income.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in conformity with generally accepted accounting principles requires management to select appropriate accounting policies and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. See Note 1—Accounting Policies, in the Notes to Consolidated Financial Statements, for descriptions of our major accounting policies. Certain of these accounting policies involve judgments and uncertainties to such an extent there is a reasonable likelihood materially different amounts would have been reported under different conditions, or if different assumptions had been used. These critical accounting estimates are discussed with the Audit and Finance Committee of the Board of Directors at least annually. We believe the following discussions of critical accounting estimates, along with the discussions of contingencies and of deferred tax asset valuation allowances in this report, address all important accounting areas where the nature of accounting estimates or assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change.

Oil and Gas Accounting

Accounting for oil and gas exploratory activity is subject to special accounting rules unique to the oil and gas industry. The acquisition of geological and geophysical seismic information, prior to the discovery of proved reserves, is expensed as incurred, similar to accounting for research and development costs. However, leasehold acquisition costs and exploratory well costs are capitalized on the balance sheet pending determination of whether proved oil and gas reserves have been discovered on the prospect.

Property Acquisition Costs

For individually significant leaseholds, management periodically assesses for impairment based on exploration and drilling efforts to date. For leasehold acquisition costs that individually are relatively small, management exercises judgment and determines a percentage probability that the prospect ultimately will fail to find proved oil and gas reserves and pools that leasehold information with others in the geographic area. For prospects in areas that have had limited, or no, previous exploratory drilling, the percentage probability of ultimate failure is normally judged to be quite high. This judgmental percentage is multiplied by the leasehold acquisition cost, and that product is divided by the contractual period of the leasehold to determine a periodic leasehold impairment charge that is reported in exploration expense.

This judgmental probability percentage is reassessed and adjusted throughout the contractual period of the leasehold based on favorable or unfavorable exploratory activity on the leasehold or on adjacent leaseholds, and leasehold impairment amortization expense is adjusted prospectively. At year-end 2013, the book value of the pools of property acquisition costs that individually are relatively small and thus subject to the above-described periodic leasehold impairment calculation was $1,830 million and the accumulated impairment reserve was $558 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 56 percent, and the weighted-average amortization period was approximately three years. If that judgmental percentage were to be raised by 5 percent across all calculations, pretax leasehold impairment expense in 2014 would increase by approximately $39 million. At year-end 2013, the remaining $6,708 million of gross capitalized unproved property costs consisted primarily of individually significant leaseholds, mineral rights held in perpetuity by title ownership, exploratory wells currently being drilled, suspended exploratory wells, and capitalized interest. Management periodically assesses individually significant leaseholds for impairment based on the results of exploration and drilling efforts and the outlook for commercialization. Of this amount, approximately $3 billion is concentrated in 10 major development areas, the majority of which are not expected to move to proved properties in 2014.

Exploratory Costs

For exploratory wells, drilling costs are temporarily capitalized, or “suspended,” on the balance sheet, pending a determination of whether potentially economic oil and gas reserves have been discovered by the drilling effort to justify completion of the find as a producing well.

If exploratory wells encounter potentially economic quantities of oil and gas, the well costs remain capitalized on the balance sheet as long as sufficient progress assessing the reserves and the economic and operating viability of the project is being made. The accounting notion of “sufficient progress” is a judgmental area, but the accounting rules do prohibit continued capitalization of suspended well costs on the expectation future market conditions will improve or new technologies will be found that would make the development economically profitable. Often, the ability to move into the development phase and record proved reserves is dependent on obtaining permits and government or co-venturer approvals, the timing of which is ultimately beyond our control. Exploratory well costs remain suspended as long as we are actively pursuing such approvals and permits, and believe they will be obtained. Once all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas reserves are designated as proved reserves. For complex exploratory discoveries, it is not unusual to have exploratory wells remain suspended on the balance sheet for several years while we perform additional appraisal drilling and seismic work on the potential oil and gas field or while we seek government or co-venturer approval of development plans or seek environmental permitting. Once a determination is made the well did not encounter potentially economic oil and gas quantities, the well costs are expensed as a dry hole and reported in exploration expense.

Management reviews suspended well balances quarterly, continuously monitors the results of the additional appraisal drilling and seismic work, and expenses the suspended well costs as a dry hole when it determines the potential field does not warrant further investment in the near term. Criteria utilized in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected development costs, ability to apply existing technology to produce the reserves, fiscal terms, regulations or contract negotiations, and our required return on investment.

At year-end 2013, total suspended well costs were $994 million, compared with $1,038 million at year-end 2012. For additional information on suspended wells, including an aging analysis, see Note 8—Suspended Wells, in the Notes to Consolidated Financial Statements.

Proved Reserves

Engineering estimates of the quantities of proved reserves are inherently imprecise and represent only approximate amounts because of the judgments involved in developing such information. Reserve estimates are based on geological and engineering assessments of in-place hydrocarbon volumes, the production plan, historical extraction recovery and processing yield factors, installed plant operating capacity and approved operating limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons.

Despite the inherent imprecision in these engineering estimates, accounting rules require disclosure of “proved” reserve estimates due to the importance of these estimates to better understand the perceived value and future cash flows of a company’s operations. There are several authoritative guidelines regarding the engineering criteria that must be met before estimated reserves can be designated as “proved.” Our reservoir engineering organization has policies and procedures in place consistent with these authoritative guidelines. We have trained and experienced internal engineering personnel who estimate our proved reserves held by consolidated companies, as well as our share of equity affiliates.

Proved reserve estimates are adjusted annually in the fourth quarter and during the year if significant changes occur, and take into account recent production and subsurface information about each field. Also, as required by current authoritative guidelines, the estimated future date when a field will be permanently shut down for economic reasons is based on 12-month average prices and current costs. This estimated date when production will end affects the amount of estimated reserves. Therefore, as prices and cost levels change from year to year, the estimate of proved reserves also changes.

Our proved reserves include estimated quantities related to production sharing contracts, which are reported under the “economic interest” method and are subject to fluctuations in commodity prices; recoverable operating expenses; and capital costs. If costs remain stable, reserve quantities attributable to recovery of costs will change inversely to changes in commodity prices. For example, if prices increase, then our applicable reserve quantities would decline. The estimation of proved developed reserves also is important to the income

statement because the proved developed reserve estimate for a field serves as the denominator in the unit-of-production calculation of the DD&A of the capitalized costs for that asset. At year-end 2013, the net book value of productive properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $59 billion and the DD&A recorded on these assets in 2013 was approximately $7.0 billion. The estimated proved developed reserves for our consolidated operations were 4.9 billion BOE at the end of 2012 and 4.9 billion BOE at the end of 2013. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pretax DD&A in 2013 would have increased by an estimated $370 million.

Impairments

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in future cash flows expected to be generated by an asset group and annually in the fourth quarter following updates to corporate planning assumptions. If there is an indication the carrying amount of an asset may not be recovered, the asset is monitored by management through an established process where changes to significant assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the undiscounted pretax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value. Individual assets are grouped for impairment purposes based on a judgmental assessment of the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets—generally on a field-by-field basis for exploration and production assets. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, or based on a multiple of operating cash flow validated with historical market transactions of similar assets where possible. The expected future cash flows used for impairment reviews and related fair value calculations are based on judgmental assessments of future production volumes, commodity prices, operating costs and capital decisions, considering all available information at the date of review. See Note 9—Impairments, in the Notes to Consolidated Financial Statements, for additional information.

Investments in nonconsolidated entities accounted for under the equity method are reviewed for impairment when there is evidence of a loss in value and annually following updates to corporate planning assumptions. Such evidence of a loss in value might include our inability to recover the carrying amount, the lack of sustained earnings capacity which would justify the current investment amount, or a current fair value less than the investment’s carrying amount. When it is determined such a loss in value is other than temporary, an impairment charge is recognized for the difference between the investment’s carrying value and its estimated fair value. When determining whether a decline in value is other than temporary, management considers factors such as the length of time and extent of the decline, the investee’s financial condition and near-term prospects, and our ability and intention to retain our investment for a period that will be sufficient to allow for any anticipated recovery in the market value of the investment. When quoted market prices are not available, the fair value is usually based on the present value of expected future cash flows using discount rates believed to be consistent with those used by principal market participants, plus market analysis of comparable assets owned by the investee, if appropriate. Differing assumptions could affect the timing and the amount of an impairment of an investment in any period.

Asset Retirement Obligations and Environmental Costs

Under various contracts, permits and regulations, we have material legal obligations to remove tangible equipment and restore the land or seabed at the end of operations at operational sites. Our largest asset removal obligations involve plugging and abandonment of wells, removal and disposal of offshore oil and gas platforms around the world, as well as oil and gas production facilities and pipelines in Alaska. The fair values of obligations for dismantling and removing these facilities are recorded as a liability and an increase to PP&E at the time of installation of the asset based on estimated discounted costs. Estimating future asset removal costs is difficult. Most of these removal obligations are many years, or decades, in the future and the contracts and regulations often have vague descriptions of what removal practices and criteria must be met when the removal event actually occurs. Asset removal technologies and costs, regulatory and other compliance

considerations, expenditure timing, and other inputs into valuation of the obligation, including discount and inflation rates, are also subject to change.

Normally, changes in asset removal obligations are reflected in the income statement as increases or decreases to DD&A over the remaining life of the assets. However, for assets at or nearing the end of their operations, as well as previously sold assets for which we retained the asset removal obligation, an increase in the asset removal obligation can result in an immediate charge to earnings, because any increase in PP&E due to the increased obligation would immediately be subject to impairment, due to the low fair value of these properties.

In addition to asset removal obligations, under the above or similar contracts, permits and regulations, we have certain environmental-related projects. These are primarily related to remediation activities required by Canada and various states within the United States at exploration and production sites. Future environmental remediation costs are difficult to estimate because they 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.

Projected Benefit Obligations

Determination of the projected benefit obligations for our defined benefit pension and postretirement plans are important to the recorded amounts for such obligations on the balance sheet and to the amount of benefit expense in the income statement. The actuarial determination of projected benefit obligations and company contribution requirements involves judgment about uncertain future events, including estimated retirement dates, salary levels at retirement, mortality rates, lump-sum election rates, rates of return on plan assets, future health care cost-trend rates, and rates of utilization of health care services by retirees. Due to the specialized nature of these calculations, we engage outside actuarial firms to assist in the determination of these projected benefit obligations and company contribution requirements. For Employee Retirement Income Security Act-qualified pension plans, the actuary exercises fiduciary care on behalf of plan participants in the determination of the judgmental assumptions used in determining required company contributions into the plan. Due to differing objectives and requirements between financial accounting rules and the pension plan funding regulations promulgated by governmental agencies, the actuarial methods and assumptions for the two purposes differ in certain important respects. Ultimately, we will be required to fund all promised benefits under pension and postretirement benefit plans not funded by plan assets or investment returns, but the judgmental assumptions used in the actuarial calculations significantly affect periodic financial statements and funding patterns over time. Benefit expense is particularly sensitive to the discount rate and return on plan assets assumptions. A 1 percent decrease in the discount rate assumption would increase annual benefit expense by $120 million, while a 1 percent decrease in the return on plan assets assumption would increase annual benefit expense by $60 million. In determining the discount rate, we use yields on high-quality fixed income investments matched to the estimated benefit cash flows of our plans. We are also exposed to the possibility that lump sum retirement benefits taken from pension plans during the year could exceed the total of service and interest components of annual pension expense and trigger accelerated recognition of a portion of unrecognized net actuarial losses and gains. These benefit payments are based on decisions by plan participants and are therefore difficult to predict. See Note 19—Employee Benefit Plans, in the Notes to Consolidated Financial Statements, for additional information.

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:

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

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

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

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

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

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

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

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

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International monetary conditions and exchange controls.

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Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations.

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

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Liability resulting from litigation.

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

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

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

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

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

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The operation and financing of our joint ventures.

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The factors generally described in Item 1A—Risk Factors in this report.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Financial Instrument Market Risk

We and certain of our subsidiaries hold and issue derivative contracts and financial instruments that expose our cash flows or earnings to changes in commodity prices, foreign currency exchange rates or interest rates. We may use financial and commodity-based derivative contracts to manage the risks produced by changes in the prices of natural gas, crude oil and related products; fluctuations in interest rates and foreign currency exchange rates; or to capture market opportunities.

Our use of derivative instruments is governed by an “Authority Limitations” document approved by our Board of Directors that prohibits the use of highly leveraged derivatives or derivative instruments without sufficient liquidity. The Authority Limitations document also establishes the Value at Risk (VaR) limits for the company, and compliance with these limits is monitored daily. The Chief Financial Officer monitors risks resulting from foreign currency exchange rates and interest rates and reports to the Chief Executive Officer. The Executive Vice President of Commercial, Business Development and Corporate Planning monitors commodity price risk and also reports to the Chief Executive Officer. The Commercial organization manages our commercial marketing, optimizes our commodity flows and positions, and monitors risks.

Commodity Price Risk

Our Commercial organization uses futures, forwards, swaps and options in various markets to accomplish the following objectives:

—

Meet customer needs. Consistent with our policy to generally remain exposed to market prices, we use swap contracts to convert fixed-price sales contracts, which are often requested by natural gas consumers, to floating market prices.

—

Enable us to use market knowledge to capture opportunities such as moving physical commodities to more profitable locations and storing commodities to capture seasonal or time premiums. We may use derivatives to optimize these activities.

We use a VaR model to estimate the loss in fair value that could potentially result on a single day from the effect of adverse changes in market conditions on the derivative financial instruments and derivative commodity instruments we hold or issue, including commodity purchases and sales contracts recorded on the balance sheet at December 31, 2013, as derivative instruments. Using Monte Carlo simulation, a 95 percent confidence level and a one-day holding period, the VaR for those instruments issued or held for trading purposes at December 31, 2013 and 2012, was immaterial to our consolidated cash flows and net income attributable to ConocoPhillips. The VaR for instruments held for purposes other than trading at December 31, 2013 and 2012, was also immaterial to our cash flows and net income attributable to ConocoPhillips.

Interest Rate Risk

The following table provides information about our financial instruments that are sensitive to changes in U.S. interest rates. The debt portion of the table presents principal cash flows and related weighted-average interest rates by expected maturity dates. Weighted-average variable rates are based on effective rates at the reporting date. The carrying amount of our floating-rate debt approximates its fair value. The fair value of the fixed-rate financial instruments is estimated based on quoted market prices. The joint venture acquisition obligation portion of the table presents principal cash flows of the fixed-rate 5.3 percent joint venture acquisition obligation owed to FCCL Partnership. The fair value of the obligation at year-end 2012 was estimated based on the net present value of the future cash flows, discounted at an effective yield rate of 0.7 percent. The discount rate was based on yields of U.S. Treasury securities of a similar average duration, adjusted for ConocoPhillips’ average credit risk spread and the amortizing nature of the obligation principal. In December 2013, we paid the remaining balance of the obligation, which totaled $2,810 million.


	Millions of Dollars Except as Indicated
	Debt										Joint Venture Acquisition Obligation
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate			Floating Rate Maturity		Average Interest Rate			Fixed Rate Maturity		Average Interest Rate
Year-End 2013
2014	$	400		4.75	%	$	100		0.21	%	$	-		-	%
2015		1,500		4.60			-		-			-		-
2016		1,273		5.52			861		0.02			-		-
2017		1,001		1.06			-		-			-		-
2018		797		5.74			-		-			-		-
Remaining years		14,121		6.27			283		0.05			-		-

Total	$	19,092				$	1,244				$	-

Fair value	$	22,309				$	1,244				$	-


Year-End 2012
2013	$	850		5.75	%	$	91		0.25	%	$	772		5.30	%
2014		400		4.75			-		-			814		5.30
2015		1,500		4.60			-		-			858		5.30
2016		1,273		5.52			964		0.25			904		5.30
2017		1,001		1.06			-		-			234		5.30
Remaining years		14,918		6.25			283		0.19			-		5.30

Total	$	19,942				$	1,338				$	3,582

Fair value	$	25,011				$	1,338				$	3,968

Foreign Currency Exchange Risk

We have foreign currency exchange rate risk resulting from international operations. We do not comprehensively hedge the exposure to currency exchange rate changes 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.

At December 31, 2013 and 2012, we held foreign currency exchange forwards hedging cross-border commercial activity and foreign currency exchange swaps for purposes of mitigating our cash related exposures. Although these forwards and swaps hedge exposures to fluctuations in exchange rates, we elected not to utilize hedge accounting. As a result, the change in the fair value of these foreign currency exchange derivatives is recorded directly in earnings. Since the gain or loss on the swaps is offset by the gain or loss from remeasuring the related cash balances, and since our aggregate position in the forwards was not material, there would be no material impact to our income from an adverse hypothetical 10 percent change in the December 31, 2013, or 2012, exchange rates. The notional and fair market values of these positions at December 31, 2013 and 2012, were as follows:


	In Millions
Foreign Currency Exchange Derivatives	Notional*						Fair Market Value**
			2013		2012		2013		2012


Sell U.S. dollar, buy British pound		USD		-		2,573		-		31
Buy U.S. dollar, sell euro		USD		-		7		-		-
Buy U.S. dollar, sell Norwegian krone		USD		-		90		-		-
Buy U.S. dollar, sell Canadian dollar		USD		6		43		-		(2)
Buy euro, sell British pound		EUR		-		96		-		-
Buy British pound, sell euro		GBP		17		-		-		-

* Denominated in U.S. dollars (USD), euro (EUR), and British pound (GBP).

** Denominated in U.S. dollars.

For additional information about our use of derivative instruments, see Note 15—Derivative and Financial Instruments, in the Notes to Consolidated Financial Statements.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CONOCOPHILLIPS

INDEX TO FINANCIAL STATEMENTS


	Page
Report of Management		76

Reports of Independent Registered Public Accounting Firm		77

Consolidated Income Statement for the years ended December 31, 2013, 2012 and 2011		79

Consolidated Statement of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011		80

Consolidated Balance Sheet at December 31, 2013 and 2012		81

Consolidated Statement of Cash Flows for the years ended December 31, 2013, 2012 and 2011		82

Consolidated Statement of Changes in Equity for the years ended December 31, 2013, 2012 and 2011		83

Notes to Consolidated Financial Statements		84

Supplementary Information

Oil and Gas Operations		138

Selected Quarterly Financial Data		165

Condensed Consolidating Financial Information		166

Report of Management

Management prepared, and is responsible for, the consolidated financial statements and the other information appearing in this annual report. The consolidated financial statements present fairly the company’s financial position, results of operations and cash flows in conformity with accounting principles generally accepted in the United States. In preparing its consolidated financial statements, the company includes amounts that are based on estimates and judgments management believes are reasonable under the circumstances. The company’s financial statements have been audited by Ernst & Young LLP, an independent registered public accounting firm appointed by the Audit and Finance Committee of the Board of Directors and ratified by stockholders. Management has made available to Ernst & Young LLP all of the company’s financial records and related data, as well as the minutes of stockholders’ and directors’ meetings.

Assessment of Internal Control Over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. ConocoPhillips’ internal control system was designed to provide reasonable assurance to the company’s management and directors regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Management assessed the effectiveness of the company’s internal control over financial reporting as of December 31, 2013. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control—Integrated Framework (1992). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2013.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2013, and their report is included herein.


/s/ Ryan M. Lance				/s/ Jeff W. Sheets

Ryan M. Lance				Jeff W. Sheets
Chairman and				Executive Vice President, Finance
Chief Executive Officer				and Chief Financial Officer

February 25, 2014

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

ConocoPhillips

We have audited the accompanying consolidated balance sheets of ConocoPhillips as of December 31, 2013 and 2012, and the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended December 31, 2013. Our audits also included the related condensed consolidating financial information listed in the Index at Item 8 and financial statement schedule listed in Item 15(a). These financial statements, condensed consolidating financial information, and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements, condensed consolidating financial information, and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of ConocoPhillips at December 31, 2013 and 2012, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related condensed consolidating financial information and financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ConocoPhillips’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated February 25, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 25, 2014

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

ConocoPhillips

We have audited ConocoPhillips’ internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). ConocoPhillips’ management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included under the heading “Assessment of Internal Control Over Financial Reporting” in the accompanying “Report of Management.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, ConocoPhillips maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2013 consolidated financial statements of ConocoPhillips and our report dated February 25, 2014, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 25, 2014


Consolidated Income Statement			ConocoPhillips


Years Ended December 31	Millions of Dollars
		2013		2012		2011

Revenues and Other Income
Sales and other operating revenues	$	54,413		57,967		64,196
Equity in earnings of affiliates		2,219		1,911		1,239
Gain on dispositions		1,242		1,657		370
Other income		374		469		264

Total Revenues and Other Income		58,248		62,004		66,069


Costs and Expenses
Purchased commodities		22,643		25,232		29,797
Production and operating expenses		7,238		6,793		6,426
Selling, general and administrative expenses		854		1,106		865
Exploration expenses		1,232		1,500		1,038
Depreciation, depletion and amortization		7,434		6,580		6,827
Impairments		529		680		321
Taxes other than income taxes		2,884		3,546		3,999
Accretion on discounted liabilities		434		394		422
Interest and debt expense		612		709		954
Foreign currency transaction (gains) losses		(58	)	41		24

Total Costs and Expenses		43,802		46,581		50,673

Income from continuing operations before income taxes		14,446		15,423		15,396
Provision for income taxes		6,409		7,942		8,208

Income From Continuing Operations		8,037		7,481		7,188
Income from discontinued operations*		1,178		1,017		5,314

Net income		9,215		8,498		12,502
Less: net income attributable to noncontrolling interests		(59	)	(70	)	(66)

Net Income Attributable to ConocoPhillips	$	9,156		8,428		12,436


Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	7,978		7,413		7,127
Income from discontinued operations		1,178		1,015		5,309

Net Income	$	9,156		8,428		12,436


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	6.47		5.95		5.18
Discontinued operations		0.96		0.82		3.86

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	7.43		6.77		9.04

Diluted
Continuing operations	$	6.43		5.91		5.14
Discontinued operations		0.95		0.81		3.83

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	7.38		6.72		8.97


Dividends Paid Per Share of Common Stock (dollars)	$	2.70		2.64		2.64


Average Common Shares Outstanding (in thousands)
Basic		1,230,963		1,243,799		1,375,035
Diluted		1,239,803		1,253,093		1,387,100

*Net of provision for income taxes on discontinued operations of:	$	*283*