Edgar Filing: CONOCOPHILLIPS

10-K

2014

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, 2014

[ ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934


For the transition period from				to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

01-0562944

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

600 North Dairy Ashford

Houston, TX 77079

(Address of principal executive offices) (Zip Code)

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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $85.73, was $105.4 billion.

The registrant had 1,231,461,668 shares of common stock outstanding at January 31, 2015.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2015 (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		6
	Canada		10
	Europe		12
	Asia Pacific and Middle East		14
	Other International		19
	Competition		22
	General		23
1A.	Risk Factors		24
1B.	Unresolved Staff Comments		26
3.	Legal Proceedings		26
4.	Mine Safety Disclosures		27
	Executive Officers of the Registrant		28

	PART II

5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30
6.	Selected Financial Data		31
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32
7A.	Quantitative and Qualitative Disclosures About Market Risk		71
8.	Financial Statements and Supplementary Data		74
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		170
9A.	Controls and Procedures		170
9B.	Other Information		170

	PART III

10.	Directors, Executive Officers and Corporate Governance		171
11.	Executive Compensation		171
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		171
13.	Certain Relationships and Related Transactions, and Director Independence		171
14.	Principal Accounting Fees and Services		171

	PART IV

15.	Exhibits, Financial Statement Schedules		172
	Signatures		180

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 70.

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.

In April 2012 the ConocoPhillips Board of Directors approved the separation of our downstream business into an independent, publicly traded energy company, Phillips 66. Each ConocoPhillips stockholder received one share of Phillips 66 stock for every two shares of ConocoPhillips stock held at the close of business on the record date of April 16, 2012. The separation was completed on April 30, 2012, and activities related to Phillips 66 have been treated as discontinued operations for all periods prior to the separation.

In 2012 we agreed to sell our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Nigeria and Algeria businesses (collectively, the “Disposition Group”). We sold our Nigeria business in the third quarter of 2014, and we sold Kashagan and our Algeria business in the fourth quarter of 2013. Results for the Disposition Group have been reported as discontinued operations in all periods presented. For additional information on all discontinued operations, see Note 2—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, 2014, ConocoPhillips employed approximately 19,100 people worldwide.

SEGMENT AND GEOGRAPHIC INFORMATION

For operating segment and geographic information, see Note 23—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, 2014, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

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 84 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	2014		2013		2012

Crude oil
Consolidated operations		2,605		2,659		2,684
Equity affiliates		103		90		95

Total Crude Oil		2,708		2,749		2,779


Natural gas liquids
Consolidated operations		662		699		646
Equity affiliates		53		45		48

Total Natural Gas Liquids		715		744		694


Natural gas
Consolidated operations		2,543		2,710		2,726
Equity affiliates		874		688		543

Total Natural Gas		3,417		3,398		3,269


Bitumen
Consolidated operations		598		579		506
Equity affiliates		1,468		1,451		1,394

Total Bitumen		2,066		2,030		1,900


Total consolidated operations		6,408		6,647		6,562
Total equity affiliates		2,498		2,274		2,080

Total company		8,906		8,921		8,642

Total production from continuing operations, including Libya, was 1,540 thousand barrels of oil equivalent per day (MBOED) in 2014, compared with 1,502 MBOED in 2013, an increase of 3 percent. Average liquids production increased 4 percent over the same period. The increase in total average production in 2014 primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada, and increased drilling programs, mostly in the Lower 48, western Canada and Norway. These increases were largely offset by normal field decline, higher planned downtime, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, and unfavorable market impacts. Excluding Libya, production from continuing operations was 1,532 MBOED in 2014, compared with 1,472 MBOED in 2013, an increase of 60 MBOED, or 4 percent.

Our total average realized price from continuing operations was $64.59 per BOE in 2014, a decrease of 4 percent compared with $67.62 per BOE in 2013, which reflected lower average realized prices for crude oil and natural gas liquids, partly offset by higher bitumen and natural gas prices. Our worldwide annual average crude oil sales price from continuing operations decreased 10 percent in 2014, from $103.32 per barrel in 2013 to $92.80 per barrel in 2014. Additionally, our worldwide average annual natural gas liquids prices from continuing operations decreased 6 percent, from $41.42 per barrel in 2013 to $38.99 per barrel in 2014. Our average annual worldwide natural gas sales price from continuing operations increased 8 percent, from $6.11 per thousand cubic feet in 2013 to $6.57 per thousand cubic feet in 2014. Average annual bitumen prices increased 3 percent, from $53.27 per barrel in 2013 to $55.13 per barrel in 2014.

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 2014. Approximately 0.4 million of these acres are located in the National Petroleum Reserve—Alaska (NPRA) and 0.3 million are located in the Chukchi Sea. In 2014 Alaska operations contributed 20 percent of our worldwide liquids production and 1 percent of our natural gas production.


				2014
	Interest		Operator		Liquids MBD	*	Natural Gas MMCFD	**	Total MBOED

Average Daily Net Production
Greater Prudhoe Area	36.1	%	BP		91		6		92
Greater Kuparuk Area	52.2–55.5		ConocoPhillips		52		-		52
Western North Slope	78.0		ConocoPhillips		32		1		32
Cook Inlet Area	33.3–100.0		ConocoPhillips		-		42		7

Total Alaska					175		49		183

*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 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. Development drilling at Kuparuk consists of rotary-drilled wells and horizontal multi-laterals from existing well bores utilizing coiled-tubing drilling.

The successful Shark Tooth delineation well extended the known Kuparuk accumulation to the southwestern area of the Kuparuk Field where construction of Drill Site 2S is progressing. The project was sanctioned in October 2014. First production is estimated in late 2015, with net peak production estimated at 5 MBOED in 2017.

In 2014 we received regulatory approvals to advance oil development targeting the West Sak reservoir in the Kuparuk River Unit. Pending a final investment decision, the development, 1H Northeast West Sak (NEWS), will include a nine-acre extension to an existing drill site allowing for new wells and associated facilities. We anticipate first production in 2017.

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 new drill site which will extend the Alpine reservoir west into 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. In 2014 we progressed development planning for the Greater Mooses Tooth #1 (GMT1) drill site. Delays in federal permitting and requirements, in addition to the current low commodity price environment, have resulted in deferral of the final investment decision. We plan to shoot seismic and continue engineering in 2015. 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. 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. Our share of production from the units is primarily sold to local utilities and is also used to supply feedstock to the Kenai LNG Plant.

The Kenai LNG Facility includes a 1.6 million-tons-per-year capacity plant, as well as docking and loading facilities for LNG tankers. LNG from the plant has historically been transported and sold to utility companies in Japan. The plant was idled in late-2012; however, due to a change in market conditions, including additional gas supplies, we were granted a two-year export license from the U.S. Department of Energy (DOE) in April 2014 to export up to 40 billion cubic feet of LNG from the facility. As a result, we shipped 5 cargoes of LNG from the Kenai Facility to Asia in 2014.

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).

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 liquefy and export 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.

The proposed AKLNG natural gas liquefaction plant and terminal would be located in the Nikiski area on the Kenai Peninsula, approximately 60 miles southwest of Anchorage, along the Cook Inlet. In January 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. During 2014 general legislation was enacted by the State of Alaska, and a joint venture agreement for the preliminary front-end engineering and design phase of the project was executed. The AKLNG Project will require many major federal permits, and in July 2014 an application for an LNG export license was filed with the U.S. DOE to export up to 20 million metric tons a year of LNG for 30 years. In November 2014 the U.S. DOE authorized the export of LNG to free trade agreement (FTA) countries, and authorization to export to non-FTA countries remains pending. In September 2014 the Federal Energy Regulatory Commission (FERC) accepted the project into pre-file status, which initiates the lengthy environmental and safety reviews required to design, permit, construct and operate the plants and pipeline.

Significant engineering, technical, regulatory, fiscal, commercial and permitting issues would need to be resolved prior to a final investment decision on the potential $45 billion to $65 billion (gross) project.

Exploration

In 2014 we drilled two exploration wells within the Greater Mooses Tooth Unit: the Rendezvous 3 and Flattop-1. Potential development of the Rendezvous 3 area is under evaluation. Flattop-1 encountered hydrocarbons but was expensed. The well is temporarily abandoned and available for testing in the future. In 2013 we drilled in the Cassin Prospect, located in the Bear Tooth Unit in the northeast NPRA, and we are continuing to evaluate development options. The Moraine Prospect, located on the western flank of the Kuparuk Field, was tested in 2013 and began producing in 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 charters third-party vessels as necessary. The tankers primarily deliver oil from Valdez, Alaska, to refineries on the west coast of the United States.

LOWER 48

The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico. The Lower 48 business is organized within four regions covering the Gulf Coast, Mid-Continent, Rockies and San Juan. As a result of increasing shale opportunities, we have directed our investments toward certain higher-margin, liquids-rich plays. We hold 15 million net onshore and offshore acres in the Lower 48. In 2014 the Lower 48 contributed 32 percent of our worldwide liquids production and 38 percent of our natural gas production.


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Eagle Ford		Various	%		Various		122		199		155
Gulf of Mexico		Various			Various		14		14		16
Gulf Coast—Other		Various			Various		9		213		45

Total Gulf Coast							145		426		216

Permian		Various			Various		38		119		58
Barnett		Various			Various		6		45		13
Anadarko Basin		Various			Various		7		119		27

Total Mid-Continent							51		283		98

Bakken		Various			Various		45		32		50
Wyoming/Uinta		Various			Various		1		96		17
Niobrara		Various			Various		2		1		2

Total Rockies							48		129		69

San Juan		Various			Various		41		653		150

Total U.S. Lower 48							285		1,491		533

Onshore

We hold 13 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:

•

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

•

619,000 net acres in the Bakken, located in North Dakota and Eastern Montana;

•

216,000 net acres in the Eagle Ford, located in South Texas;

•

186,000 net acres in the Permian, located in West Texas and southeastern New Mexico;

•

123,000 net acres in the Niobrara, located in northeastern Colorado;

•

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

•

578,000 net acres in other unconventional exploration plays.

The majority of our 2014 onshore production originated from the Eagle Ford, San Juan, Permian and Bakken. Onshore activities in 2014 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 2014 included the following:

•

Eagle Ford—The Eagle Ford transitioned into full field development in 2014, with the majority of the development program being drilled on multi-well pads. We operated 12 rigs throughout the majority of 2014, resulting in 196 operated wells drilled and 199 operated wells connected. In 2014 we also increased production by 30 percent compared with 2013, and we achieved net peak production of 179 MBOED, compared with 141 MBOED in 2013.

•

Bakken—The Bakken continued to experience a significant increase in activity in 2014, as we drilled 129 operated wells during the year and brought 137 operated wells online. We also operated 10 or more drilling rigs throughout the year and improved our efficiency with pad drilling. As a result, we achieved net peak production of more than 63 MBOED in 2014, compared with 43 MBOED in 2013.

•

San Juan Basin—The San Juan Basin includes significant conventional gas production, which yields approximately 30 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 select conventional development opportunities. This also includes approximately 900,000 net unconventional acres of lease rights.

•

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 should also identify new, unconventional plays across the region. We hold approximately 1.1 million net acres in the Permian, which includes 186,000 net unconventional acres.

Gulf of Mexico

At year-end 2014, 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

At December 31, 2014, we held approximately 2.1 million net acres in the deepwater Gulf of Mexico.

We own a 30 percent nonoperated working interest in the Shenandoah discovery. The results of the first Shenandoah appraisal well were announced in 2013 and confirmed Shenandoah as a significant oil discovery. The second Shenandoah down dip appraisal well was spud in 2014 and expensed as a dry hole. Planning is underway for the next appraisal well, which is expected to spud in the second quarter of 2015.

As of December 2014, we owned a 35 percent nonoperated interest in the Gila Prospect and a 100 percent interest in one Gibson Prospect block, both located in the Keathley Canyon area of the Gulf of Mexico. In January 2015 we entered into an exchange agreement with Chevron Corporation and BP p.l.c. to align working interests in order to progress a hub development. As a result, our interests in both the Gila and the Gibson prospects were adjusted to 30 percent. The Gila exploration well was announced as a discovery in 2013 and is currently being appraised.

Other ongoing drilling activities at the end of 2014 included a Tiber appraisal well, in which we own an 18 percent working interest.

The nonoperated Coronado wildcat and appraisal wells and the Deep Nansen wildcat well were declared dry holes in 2014.

In support of our Gulf of Mexico exploration program, we secured access to two new-build deepwater drillships. The first drillship commenced drilling on our operated Harrier Prospect in February 2015, and we anticipate delivery of the second drillship during 2015. Both will provide rig availability for our operated drilling program. We expect to drill two wells in 2015 utilizing the first drillship.

•

Unconventional Exploration

In 2014 we actively pursued the exploration and appraisal of our existing unconventional resource plays, including the Niobrara play in the Denver-Julesburg Basin, and the Wolfcamp and Bone Springs plays in the Delaware Basin. During 2014 we acquired approximately 13,000 net additional acres in various resource plays across the Lower 48, which included the Permian, Niobrara and Eagle Ford plays, maintaining our significant acreage position in Lower 48 shale plays of approximately 2.7 million net acres. During 2014 we drilled a total of 36 unconventional exploration wells in the Niobrara play and the Delaware Basin.

In 2015 we plan to continue to explore and appraise certain unconventional plays and assess new unconventional opportunities, but at a slower pace in anticipation of weak 2015 commodity prices.

Facilities

Freeport LNG Terminal

In July 2013 we agreed with Freeport LNG Development, L.P. to terminate our long-term agreement 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. The termination agreement was 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. These conditions were satisfied in the fourth quarter of 2014, and we paid Freeport LNG a termination fee of $522 million. Freeport LNG repaid the outstanding ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. These transactions, plus miscellaneous items, resulted in a one-time net cash outflow of $63 million for us. In addition, we recognized an after-tax charge to earnings of $540 million in the fourth quarter of 2014, and our terminal regasification capacity has been 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 costs over the next 18 years. For additional information, see Note 3—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, with a combined net book value of approximately $290 million at December 31, 2014. 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. Utilization of the terminal has been and is expected to be limited, as market conditions currently favor the flow of LNG to European and Asian markets. As a result, we are evaluating opportunities to optimize the value of the terminal facilities.

Great Northern Iron Ore Properties Trust

ConocoPhillips holds the reversionary interest in the Great Northern Iron Ore Properties trust (the Trust), a grantor trust that owns mineral interests in the Mesabi Iron Range in northeastern Minnesota and certain other personal property. Pursuant to the terms of the Trust Agreement, the Trust terminates on April 6, 2015. At the end of the wind-down period, documents memorializing ConocoPhillips’ ownership of certain Trust property, including all of the Trust’s mineral properties and active leases, will be delivered to ConocoPhillips. The Trustees currently anticipate the wind-down process, final distribution and dissolution of the Trust will be completed by the end of 2016. At that time, we expect to recognize the fair value of the Trust’s net assets transferred to us.

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.

•

Helena Condensate Processing Facility—We operate and own the Helena Condensate Processing Facility, a 90,000 barrel-per-day condensate processing plant located in Kenedy, Texas.

•

Sugarloaf Condensate Processing Facility—We operate and own an 87.5 percent interest in the Sugarloaf Condensate Processing Facility, a 30,000 barrel-per-day condensate processing plant located near Pawnee, Texas.

•

Bordovsky Condensate Processing Facility—We operate and own the Bordovsky Condensate Processing Facility, a 15,000 barrel-per-day condensate processing plant located in Kenedy, Texas.

•

Wingate Fractionator—We sold the Wingate Fractionator in 2014.

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 2014 operations in Canada contributed 19 percent of our worldwide liquids production and 18 percent of our natural gas production.


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Bitumen MBD		Total MBOED

Average Daily Net Production
Western Canada		Various	%		Various		36		711		-		155
Surmont		50.0			ConocoPhillips		-		-		12		12
Foster Creek		50.0			Cenovus		-		-		53		53
Christina Lake		50.0			Cenovus		-		-		64		64

Total Canada							36		711		129		284

Western Canada

Our operations in western Canada extend across Alberta, British Columbia and Saskatchewan. We operate or have ownership interests in approximately 80 natural gas processing plants in the region, and, as of December 31, 2014, held leasehold rights in 5.7 million net acres in western Canada. Our investments in 2014 were focused mainly on higher-margin, liquids-rich opportunities in the following three core development areas:

•

Deep Basin—We hold leasehold rights in 1.4 million net acres in the Deep Basin, located in northwest Alberta and northeast British Columbia. In 2014 Deep Basin achieved average net production of 44 MBOED, and we drilled 12 horizontal wells.

•

Kaybob-Edson—We hold leasehold rights in 0.9 million net acres in the Kaybob-Edson Area, located south of the Deep Basin in west-central Alberta. Net production for Kaybob-Edson averaged 41 MBOED in 2014, and we drilled 36 horizontal wells.

•

Clearwater—Located in west-central Alberta, south of Kaybob-Edson, we hold 0.8 million net acres of leasehold rights. In 2014 average net production for Clearwater was 41 MBOED, and we drilled 39 horizontal wells.

Assets located outside the three core development areas are focused on production optimization and consist of 2.6 million net acres of leasehold rights. These assets averaged 29 MBOED of net production in 2014.

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 2 construction began in 2010, with first steam targeted for mid-2015. Following startup, Surmont’s gross production capacity is estimated to be 150 MBOED, with peak production anticipated by 2017.

•

FCCL— FCCL Partnership, a Canadian upstream general partnership, is a 50/50 heavy oil business venture with Cenovus Energy Inc. FCCL’s assets are operated by Cenovus and 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. In light of current market conditions for oil prices, FCCL plans to spread the capital investment in its oil sands projects over a longer period of time, which will slow the pace of certain developments.

Foster Creek

Foster Creek is located approximately 200 miles northeast of Edmonton, Alberta. There are six producing phases at Foster Creek, Phases A through F, with one more under construction, Phase G. First production for Phase F was achieved in the third quarter of 2014, and first production for Phase G is anticipated in 2016. Due to the substantial decline in crude oil prices, construction on Phase H has been deferred in order to preserve cash. Phases G and H are each expected to add 30 MBOED of gross production capacity, with an additional 50 MBOED from potential optimization. In the fourth quarter of 2014, regulatory approval was received for Phase J, which should add approximately 50 MBOED of gross production capacity. With the additional phases and potential optimization, Foster Creek has the potential to reach approximately 310 MBOED of total gross production capacity.

Christina Lake

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 Phase F. Gross production at Christina Lake increased approximately 40 percent in 2014, mostly as a result of Phase E reaching full capacity in the second quarter of 2014, in addition to strong facility uptime and strong well performance. During 2014 construction continued on Phases F and G. Phase F is expected to commence production in the second half of 2016 and add another 50 MBOED of gross production capacity. Further construction on Phase G has been deferred to preserve cash. 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

Narrows Lake is located near Christina Lake. Plant construction on Phase A continued in 2014; however, further work at Narrows Lake has been deferred to preserve cash. Narrows Lake is estimated to reach 130 MBOED of total gross production capacity.

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. In 2014 we decided not to pursue future development of the Amauligak discovery. Accordingly, we recorded a $109 million after-tax impairment of undeveloped leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties. We, however, remain committed to the potential of the area, should technology and commodity prices improve.

Exploration

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

•

Conventional Exploration

During 2014 we entered into a farm-in agreement to acquire a 30 percent nonoperated interest in six exploration licenses covering approximately five million gross acres in the deepwater Shelburne Basin, offshore Nova Scotia. Pending regulatory approval, we anticipate drilling will begin in the second half of 2015. In December 2014 we participated in a successful bid for one exploration license covering 0.7 million gross acres located in the Flemish Pass Basin, offshore Newfoundland. In January 2015 we were awarded the license, in which we hold a 30 percent nonoperated interest.

•

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 2014 we continued to drill 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.

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 the Barents Sea, offshore Norway; Central North Sea and west of Shetland, offshore United Kingdom; and Baffin Bay and Greenland Sea, offshore Greenland. In 2014 operations in Europe contributed 15 percent of our worldwide liquids production and 12 percent of natural gas production.

Norway


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Greater Ekofisk Area		35.1	%		ConocoPhillips		57		47		65
Alvheim		20.0			Det norske		11		13		13
Heidrun		24.0			Statoil		12		12		14
Other		Various			Various		14		66		25

Total Norway							94		138		117

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. Ekofisk South achieved first production in 2013 and continued to ramp up during 2014, while Eldfisk II achieved startup in January 2015. Ekofisk South, along with Eldfisk II and other developments offshore Norway, will contribute additional production over the coming years, as additional wells come online.

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, as well as the Aasta Hansteen development. The operator is targeting first gas for Aasta Hansteen by late 2017.

Exploration

During 2014 we participated in two nonoperated wildcat wells in the Barents Sea; both were declared dry holes. In the Visund area of the North Sea, we participated in the Helene/Methone nonoperated exploration well, which was a gas discovery and is currently being evaluated for development. We also participated in the

Barents Sea 3-D seismic group study over the recently opened southeast Barents area. In 2014 we were awarded two new North Sea licenses from the 2013 Awards in Pre-defined Areas licensing round: PL044B and PL736S, in which we will own a 41.88 percent operating interest and a 20 percent nonoperated interest, respectively.

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


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Britannia		58.7	%		Britannia		4		86		18
					Operator Ltd.
Britannia Satellites		75.0–83.5			ConocoPhillips		6		18		9
J-Area		32.5–36.5			ConocoPhillips		24		105		42
Southern North Sea		Various			Various		-		77		13
East Irish Sea		100.0			HRL		-		37		6
Other		Various			Various		6		-		6

Total United Kingdom							40		323		94

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. The Britannia Long-Term Compression Project, which consisted of a new mono-column design compression facility for the Britannia Platform, achieved startup in the third quarter of 2014 and has increased Britannia’s natural gas production by approximately 90 MMCFD gross.

The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The Jasmine Field is a high-pressure, high-temperature gas condensate reservoir located approximately six miles west of the Judy Platform. The 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. First production from Jasmine commenced in late-2013 and continued to ramp up during 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 2017.

Exploration

During 2014 the drilling and testing of three successful near-field prospects in the Greater Clair area was completed, and a fourth prospect is currently being tested. In the J-Area, well operations on the Jade South discovery, previously called the Romeo Prospect, were completed, and production was tied-in to the Jade Field during the second quarter of 2014. Additionally, a Jasmine exploration well was drilled and expensed as a dry hole in 2014, and a second well was spud in early 2015. We were also awarded three new licenses in the U.K. Continental Shelf 28^th Licensing Round, all of which are in proximity to existing acreage.

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.

Greenland

Exploration

In 2014 we conducted field-based, metocean studies in Baffin Bay in Block 2011/11 of our operated Qamut license. Additionally, we participated in a 2-D seismic acquisition program in Northeast Greenland, as part of our work program obligation in our nonoperated Avinngaq license.

ASIA PACIFIC AND MIDDLE EAST

The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia, Australia and Timor Leste; producing operations in Qatar; and exploration activities in Bangladesh, Brunei and Myanmar. In 2014 operations in the Asia Pacific and Middle East segment contributed 13 percent of our worldwide liquids production and 31 percent of natural gas production.

Australia and Timor Sea


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Australia Pacific LNG		37.5	%		Origin Energy		-		131		22
Bayu-Undan		56.9			ConocoPhillips		15		221		52
Athena/Perseus		50.0			ExxonMobil		-		34		5

Total Australia and Timor Sea							15		386		79

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 from Train 1. Following commissioning, the LNG will be sold to Sinopec under a 20-year sales agreement for up to 4.3 million metric tonnes of LNG per year. Startup of the second LNG train is expected to

occur six-to-nine months following the startup of Train 1. 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 Japan-based Kansai Electric Power Co., Inc. has agreed to purchase approximately 1 million metric tonnes of LNG per year for 20 years.

APLNG has an $8.5 billion project finance facility, of which $8.1 billion had been drawn from the facility at December 31, 2014. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility until the project achieves financial completion. For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 11—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 2014 we sold 154 billion gross cubic feet of LNG to utility customers in Japan.

The Bayu-Undan Phase Three Development consists of two standalone, subsea horizontal wells tied back to the existing drilling, production and processing platform. In 2014 we completed the fabrication and installation of platform risers, topsides piping, wellheads and trees. Development drilling commenced in the second half of 2014, with initial production estimated in the first quarter of 2015. The development is expected to average an additional 100 MMCFD gross over two years.

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 hearing was conducted in June 2014, and we are currently awaiting the Tribunal’s decision. For additional information, see Note 12—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. Following agreement between the governments in September 2014, this arbitration is currently suspended until March 2015. The CMATS arbitration does not directly impact our underlying interests in Sunrise; however, we and the Sunrise co-venturers are unable to commit to further commercial and technical work activities due to the uncertainty created by the lack of government alignment. Accordingly, current activities are restricted to compliance and social investment, as well as maintaining relationships and development options for Sunrise.

Exploration

•

Conventional Exploration

We operate two exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40 percent interest in permits WA-315-P and WA-398-P, of the Greater Poseidon Area. Phase I of the Browse Basin drilling campaign in 2009/2010 resulted in three discoveries in the Greater Poseidon Area: Poseidon-1, Poseidon-2 and Kronos-1. Phase II of the drilling campaign resulted in

five additional discoveries: Boreas-1, Zephyros-1, Proteus-1 SD2, Poseidon-North-1 and Pharos-1. All wells have been completed, plugged and abandoned. The Grace-1 well, drilled in permit WA-314-P, was declared a dry hole in early 2014, and the permit was subsequently relinquished in June 2014.

We operate two retention leases in the Bonaparte Basin, offshore northern Australia, where we own a 37.5 percent interest in leases NT/RL5 and NT/RL6. A three-well drilling campaign commenced in 2014 to further evaluate the field’s potential. The first two wells, Barossa-2 and Barossa-3, encountered hydrocarbons. The third well, Barossa-4, was spud in January 2015.

•

Unconventional Exploration

We own a 46 percent working interest in four exploration permits within the Canning Basin of Western Australia, which covers approximately 10 million gross acres. In October 2014 we exercised our right of withdrawal from the four permits, which is pending regulatory approval. The leases will expire in 2015.

Indonesia


						2014
	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
South Natuna Sea Block B		40.0	%		ConocoPhillips		9		117		29
South Sumatra		45.0–54.0			ConocoPhillips		2		344		59

Total Indonesia							11		461		88

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 Palangkaraya in central Kalimantan. 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 a 100 percent interest in the Palangkaraya PSC in central Kalimantan. Exploration drilling is scheduled to begin in the first quarter of 2015.

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


						2014

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Peng Lai		49.0	%		CNOOC		37		4		38
Panyu		24.5			CNOOC		13		-		13

Total China							50		4		51

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.

Effective July 1, 2014, operatorship of the Peng Lai fields transferred to China National Offshore Oil Corporation (CNOOC), in accordance with terms of the PSC. We retain a 49 percent nonoperated interest.

The Panyu development, located in Block 15/34 in the South China Sea, is comprised of three oil fields: Panyu 4-2, Panyu 5-1 and Panyu 11-6. The PSC for the block is scheduled to expire in September 2018, at which time we will relinquish all of our working interest in the block.

Exploration

•

Conventional Exploration

In 2014 we participated in four successful appraisal wells in the Peng Lai fields, which will be used to optimize our growth program.

•

Unconventional Exploration

In 2012 we entered into a joint study agreement (JSA) with Sinopec Southern Exploration Company over the Qijiang shale gas block, located in the Sichuan Basin. The Qijiang Block covers approximately one million acres. In February 2014 we were informed the majority of this area had been declared a military exclusion zone and would not be open for foreign cooperation. As a result, we are in the process of terminating the JSA.

In February 2013 we entered into a JSA with PetroChina over the 500,000-acre Neijiang-Dazu shale block, also located in the Sichuan Basin. In 2014 we decided not to pursue a PSC over the area.

Malaysia


						2014

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Gumusut		29.0	%		Shell		9		3		10
Siakap North-Petai		21.0			Murphy		4		-		4

Total Malaysia							13		3		14

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. Our fifth PSC, deepwater Block 3E, is located off the Malaysian state of Sarawak.

Block G

We have a 21 percent interest in the unitized Siakap North-Petai oil field, which began producing in the first quarter of 2014. Estimated net annual peak production of 6 MBOED is anticipated in 2015. Development of the Malikai oil field is underway with first production anticipated in 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 drilled in 2013 and resulted in an oil discovery. Development options are being evaluated.

Block J

First production for Gumusut occurred from an early production system in 2012. Production from a permanent, semi-submersible floating production vessel was achieved in October 2014, with estimated net annual peak production of 26 MBOED anticipated in 2016. Unitization of the Gumusut Field with Brunei was recorded in 2014 and reduced our ownership interest from 33 percent to 29 percent.

KBBC

We own a 30 percent interest in the KBBC PSC. Development of the KBB gas field commenced in 2011, and first production was achieved in November 2014; however, gas sales have not yet commenced due to ongoing repairs on a third-party pipeline. We anticipate the repairs will be completed in the second half of 2015. Estimated net annual peak production of 28 MBOED is expected in 2016. Kamunsu East is being evaluated for development options.

Exploration

We own a 40 percent operating interest in SB-311, an exploration block encompassing 259,000 gross acres offshore Sabah. We plan to commence drilling in 2015 under a two-well commitment program.

We own an 85 percent operating interest in deepwater Block 3E, which encompasses approximately 480,000 gross acres offshore Sarawak. Seismic acquisition and reprocessing occurred in 2014, and drilling is planned for 2016-2017.

Bangladesh

Exploration

In 2014 we relinquished the PSC for two deepwater blocks in the Bay of Bengal, Blocks 10 and 11. We were the high bidder on adjoining Deepwater Blocks 12, 16 and 21 in 2014 and are awaiting finalization of the PSC.

Brunei

Exploration

We have a 6.25 percent working interest in the deepwater Block CA-2 PSC, which has an exploration period through December 2018. Exploration has been ongoing since September 2011. The Kempas-1 well was declared a dry hole in January 2014.

Myanmar

Exploration

In 2014 we were awarded deepwater Block AD-10 in the 2013 Myanmar offshore oil and gas bidding round. Finalization of the PSC is anticipated to occur in early 2015.

Qatar


						2014

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Qatargas 3		30.0	%		Qatargas Operating Co.		23		374		85

Total Qatar							23		374		85

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 Colombia, Poland, Angola, Senegal and Azerbaijan. During 2014 operations in Other International contributed 1 percent of our worldwide liquids production.

In 2014 we completed the sale of our Nigeria business. Results of operations for Nigeria have been reported as discontinued operations for all periods presented. For additional information, see Note 2—Discontinued Operations, in the Notes to Consolidated Financial Statements.

Libya


						2014

	Interest			Operator		Liquids MBD		Natural Gas MMCFD		Total MBOED

Average Daily Net Production
Waha Concession		16.3	%		Waha Oil Co.		8		3		8

Total Libya							8		3		8

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. The Es Sider Terminal briefly reopened in the third quarter of 2014 and production and liftings resumed temporarily; however, further disruptions occurred in December 2014, and production is shut in again. The 2015 drilling program remains uncertain as a result of the ongoing civil unrest.

Exploration

During 2014 we completed drilling four appraisal wells. No decision has been made regarding the 2015 drilling program.

Russia


						2014

	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 gross acres. We have secured a rig for a four-well commitment program and commenced drilling in the second quarter of 2014. In November 2014 we plugged and abandoned the Kamoxi-1 exploration well as a dry hole. Kamoxi-1 is located in Block 36 offshore Angola. We subsequently spud the Omosi-1 well in adjacent Block 37, which is the second wildcat in our planned four-well exploration program in the Kwanza Basin.

Senegal

Exploration

We have a 35 percent working interest in three exploration blocks offshore Senegal. In October 2014 we discovered a working petroleum system at the FAN-1 exploration well. In addition, in November 2014 we confirmed oil was discovered in the SNE-1 well, the second of the two-well program. Further evaluation of both wells is required to determine commerciality. We have the option to become operator of the project if it advances to development.

Azerbaijan

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.

Poland

Exploration

We are participating in a shale gas venture in Poland and own a 100 percent interest in Lane Energy Poland. We operate three western Baltic Basin concessions, which encompass approximately 500,000 gross acres. A horizontal well was drilled and completed in 2014, and further evaluation continues.

Colombia

Unconventional Exploration

We have a 70 percent nonoperated working interest for deep rights in the Santa Isabel Block in the Middle Magdalena Basin, which covers approximately 71,000 net acres. During 2014 work continued on the environmental impact assessment for an area of the Santa Isabel block in preparation for future drilling.

We also hold 30 percent nonoperated working interests in three blocks in the Middle Magdalena Basin, which cover approximately 116,000 net acres. Exploration drilling commenced in October 2014 at the Picoplata-1 well, located on the VMM3 Block, with completion targeted during the first quarter of 2015.

Venezuela

In October 2014 we filed for arbitration under the rules of the International Chamber of Commerce (ICC) against Petroleos de Venezuela (PDVSA), the Venezuela state oil company, for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects. The ICC arbitration is a separate and independent legal action from the investment treaty arbitration against the government of Venezuela, which is currently proceeding before an arbitral tribunal under the World Bank’s International Centre for Settlement for Investment Disputes (ICSID). ICSID is determining the damages owed to ConocoPhillips as a result of Venezuela’s unlawful expropriation of ConocoPhillips’ significant oil investments in the Petrozuata and Hamaca heavy crude oil projects and the offshore Corocoro development project in June 2007. For additional information, see Note 12—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 currently proceeding to determine the damages owed to ConocoPhillips for Ecuador’s actions and to address Ecuador’s counterclaims. For additional information, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Discontinued Operations

Nigeria

In July 2014 we sold our Nigeria business. Production from discontinued operations for Nigeria averaged 21 MBOED in 2014.

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. In January 2015 MWCC announced acceptance of its expanded containment system (ECS). The ECS complements the capabilities and capacities put into place with its interim containment system, which the

industry has been relying on since 2011. Equipment from both systems have been combined to form MWCC’s containment system, which meet 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.

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 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, 2014. No difference exists between our estimated total proved reserves for year-end 2013 and year-end 2012, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2014.

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 3 trillion cubic feet of natural gas, including approximately 500 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 1, 2014, issue of the Oil and Gas Journal, we were the third-largest U.S.-based oil and gas company in worldwide liquids and natural gas production and reserves in 2013. 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 2014, we held a total of 912 active patents in 56 countries worldwide, including 367 active U.S. patents. During 2014 we received 51 patents in the United States and 74 foreign patents. Our products and processes generated licensing revenues of $46 million in 2014. 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 $263 million, $258 million and $221 million in 2014, 2013 and 2012, 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 59 through 62 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2014 and those expected for 2015 and 2016.

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.

Prices for crude oil, bitumen, natural gas, natural gas liquids and LNG can fluctuate widely. 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, cash flows and liquidity and may reduce the amount of our reserves we can produce economically. Significant reductions in crude oil, bitumen, natural gas, natural gas liquids and LNG prices could require us to reduce our capital expenditures or impair the carrying value of our assets.

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. 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. Future reserve revisions could also result from changes in, among other things, governmental regulation.

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, 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.

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 2014, and 56 percent of our proved reserves, as of December 31, 2014, 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, bitumen, natural gas 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, bitumen, natural gas 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 services or infrastructure required to develop, produce, process or transport our production, such as contract labor, drilling rigs, 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 has 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. As cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure security vulnerabilities.

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 2014, as well as matters previously reported in our 2013 Form 10-K and our first-, second- and third-quarter 2014 Form 10-Qs that were not resolved prior to the fourth quarter of 2014. 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 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 a Notice of Violation (NOV) to ConocoPhillips alleging failure to comply with two air emission monitoring requirements at the East Vacuum Liquid Recovery/CO2 Plant in southeastern New Mexico. The Plant has corrected these issues and has resolved this NOV by paying a penalty of $34,003.

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 July 2014 Phillips 66 resolved the consent decree issues and is working with the LDEQ to resolve the remaining allegations.

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 October 15, 2012, the Bay Area Air Quality Management District (Bay Area AQMD) 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 WRB 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.

On July 7, 2014, the Phillips 66 WRB Wood River Refinery received a NOV from the U.S. EPA alleging various flaring-related violations between 2009 and 2013.

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

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

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

EXECUTIVE OFFICERS OF THE REGISTRANT


Name	Position Held	Age*

Ellen R. DeSanctis	Vice President, Investor Relations and Communications	58

Sheila Feldman	Vice President, Human Resources, Real Estate and Facilities Services	60

Matt J. Fox	Executive Vice President, Exploration and Production	54

Alan J. Hirshberg	Executive Vice President, Technology and Projects	53

Janet L. Kelly	Senior Vice President, Legal, General Counsel and Corporate Secretary	57

Ryan M. Lance	Chairman of the Board of Directors and Chief Executive Officer	52

Andrew D. Lundquist	Senior Vice President, Government Affairs	54

Glenda M. Schwarz	Vice President and Controller	49

Jeff W. Sheets	Executive Vice President, Finance and Chief Financial Officer	57

Don E. Wallette, Jr.	Executive Vice President, Commercial, Business Development and Corporate Planning	56

*On February 15, 2015.

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 12, 2015. 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, Real Estate and Facilities Services in May 2014. Prior to that, she served as Vice President, Human Resources since 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.

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.

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.

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.

Jeff W. Sheets was appointed Executive Vice President, Finance and Chief Financial Officer in May 2012, having previously served as Senior Vice President, Finance and Chief Financial Officer since 2010.

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

2014
First	$	70.99		62.74		0.69
Second		86.43		69.33		0.69
Third		87.09		75.92		0.73
Fourth		76.52		60.84		0.73


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


Closing Stock Price at December 31, 2014					$	69.06
Closing Stock Price at January 31, 2015					$	62.98
Number of Stockholders of Record at January 31, 2015*						53,653

*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


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


December 1-31, 2014	318		$	70.10	-	$	-

Total fourth-quarter 2014	318		$	70.10	-	$	-

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

Item 6.

SELECTED FINANCIAL DATA


	Millions of Dollars Except Per Share Amounts
		2014	2013	2012	2011	2010

Sales and other operating revenues	$	52,524	54,413	57,967	64,196	56,215
Income from continuing operations		5,807	8,037	7,481	7,188	10,305
Per common share
Basic		4.63	6.47	5.95	5.18	6.93
Diluted		4.60	6.43	5.91	5.14	6.88
Income from discontinued operations		1,131	1,178	1,017	5,314	1,112
Net income		6,938	9,215	8,498	12,502	11,417
Net income attributable to ConocoPhillips		6,869	9,156	8,428	12,436	11,358
Per common share
Basic		5.54	7.43	6.77	9.04	7.68
Diluted		5.51	7.38	6.72	8.97	7.62
Total assets		116,539	118,057	117,144	153,230	156,314
Long-term debt		22,383	21,073	20,770	21,610	22,656
Joint venture acquisition obligation—long-term		-	-	2,810	3,582	4,314
Cash dividends declared per common share		2.84	2.70	2.64	2.64	2.15

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, and the sales of our Algeria and Nigeria businesses. Total assets for 2011 and prior years includes assets for the downstream business. For additional information, see Note 2—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 70.

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

BUSINESS ENVIRONMENT AND EXECUTIVE OVERVIEW

ConocoPhillips is the world’s largest independent exploration and production (E&P) company, based on proved reserves and production of liquids and natural gas. Headquartered in Houston, Texas, we have operations and activities in 27 countries. At December 31, 2014, we employed approximately 19,100 people worldwide and had total assets of $117 billion. Our stock is listed on the New York Stock Exchange under the symbol “COP.”

Basis of Presentation

Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Results of operations for the Lower 48, Europe and Other International segments have been revised for all periods presented. There was no impact on our consolidated financial results, and the impact on our segment presentation was immaterial. For additional information, see Note 23—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements.

Overview

We are an independent E&P company focused on exploring for, developing and producing crude oil and natural gas globally. Our asset base reflects our legacy as a major company with a strategic focus on higher-margin developments. Our diverse portfolio primarily includes resource-rich North American shale and oil sands assets; lower-risk legacy assets in North America, Europe, Asia and Australia; several major international developments; and a growing inventory of global conventional and unconventional exploration prospects. Since the separation of the downstream business in 2012, our value proposition to our shareholders has been to deliver 3 to 5 percent production and 3 to 5 percent cash margin growth, normalized for changes in commodity prices, pay a competitive dividend, improve financial returns, and maintain our fundamental commitment to safety, operating excellence and environmental stewardship. This value proposition was predicated on capital expenditures of approximately $16 billion annually.

We achieved our value proposition in 2014 and met our strategic objectives; however, in response to a significant downturn in commodity prices beginning in the second half of 2014, we have elected to reduce our 2015 capital program to $11.5 billion. At this level of capital, we expect to achieve 2 to 3 percent production growth in 2015. The dividend remains our top priority, and we anticipate cash flow neutrality (cash from continuing operations sufficient to fund our dividend and capital program) in 2017. We continue to monitor the environment and will exercise additional capital reductions or balance sheet flexibility, as appropriate, to withstand this cycle.

Key Operating and Financial Highlights

Significant highlights during 2014 included the following:

•

Achieved 4 percent full-year production growth from continuing operations, excluding Libya.

•

Realized 8 percent price-normalized cash margin per BOE growth.

•

Achieved annual organic reserve replacement of 124 percent from reserve additions of approximately 0.7 billion BOE.

•

Completed the asset disposition program with sale of Nigerian business for $1.4 billion.

•

Achieved a combined 35 percent year-over-year production increase in the Eagle Ford and Bakken.

•

Commenced production from five major projects at Siakap North-Petai, Foster Creek Phase F, Britannia Long-Term Compression, Gumusut and Kebabangan, as well as first production from Eldfisk II in January 2015.

•

Discovered oil in two new plays offshore Senegal.

•

Ended the year with $5.1 billion of cash and cash equivalents.

We accomplished several strategic milestones in 2014. Through major project startups, development drilling and increased investment in higher-margin areas, we achieved 4 percent production growth from continuing operations, excluding Libya. Our net income attributable to ConocoPhillips per barrel of oil equivalent (BOE) decreased 27 percent in 2014 compared with 2013. This reduction mainly resulted from lower gains from dispositions and higher impairments. Our cash margin per BOE, normalized based on 2013 prices, increased 8 percent over the same period, which reflects an underlying portfolio shift to liquids and more favorable fiscal regimes. For additional information on the calculations for Net Income Attributable to ConocoPhillips per BOE and Price Normalized Cash Margin per BOE, see “Non-GAAP Reconciliation: Price Normalized Cash Margin per BOE,” beginning on page 63.

In 2014 we achieved production of 1,561 thousand barrels of oil equivalent per day (MBOED), including production from discontinued operations of 21 MBOED. Excluding Libya, our production from continuing operations was 1,532 MBOED, compared with 1,472 MBOED in 2013. The startup of several major projects in 2014 and continued success in shale plays enabled us to achieve our volume growth target. With the startup of Eldfisk II in early 2015, anticipated startups at Australia Pacific LNG (APLNG) and Surmont 2 in 2015, and ongoing development program activity, we believe we can achieve production growth of 2 to 3 percent in 2015.

Consistent with our commitment to offer our shareholders a competitive dividend, in July 2014 our Board of Directors increased our quarterly dividend by 5.8 percent to $0.73 per share. During 2014 we generated $16.6 billion in cash from continuing operations, which included a one-time $1.3 billion distribution from our 50 percent owned FCCL Partnership, and we generated $1.6 billion in proceeds from dispositions of non-core assets. We also paid dividends on our common stock of $3.5 billion and ended the year with $5.1 billion in cash and cash equivalents.

We funded a $17.1 billion capital program in 2014, which yielded a strong, annual organic reserve replacement ratio of 124 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.

In December 2014 we announced a capital budget of $13.5 billion for 2015, a reduction of 21 percent compared with actual capital spending of $17.1 billion in 2014. In January 2015 we further reduced the capital budget by $2.0 billion, due to the ongoing decline in commodity prices. The $5.6 billion reduction primarily reflects the deferral of spending on certain North American unconventional plays, lower spending on major projects, several of which are nearing completion, and the deferral of some exploration programs. Capital spending on several major projects has peaked, such as APLNG, Surmont 2 and Eldfisk II, and we will realize the benefit of production growth from these projects over the next few years. This lower level of investment associated with major projects allows us to have increasing flexibility with our capital program.

Our 2015 capital budget of $11.5 billion will target our diverse portfolio of global opportunities and will be directed predominantly toward high-quality developments already underway in the United States, Canada, Europe and Asia; the completion of major projects, such as APLNG and Surmont 2; as well as exploration opportunities in the Gulf of Mexico and offshore West Africa which will continue to build our inventory for the future.

Business Environment

In the first half of 2014, the energy industry experienced strong prices for crude oil, driven by geopolitical tensions impacting supplies, as well as global oil demand growth. This was followed by an abrupt decline in prices during the fourth quarter of 2014 to near five-year lows, as surging production growth from U.S. shale and the decision by the Organization of Petroleum Exporting Countries (OPEC) to maintain current production outweighed fears of supply disruptions. This, combined with lower forecasts for global oil demand growth, caused crude oil prices to plummet to the $60-per-barrel-range at the end of 2014. More recently, prices for WTI and Brent have continued to decrease to the mid-$40-per-barrel-range, less than half of June 2014 prices.

The energy industry has periodically experienced this type of extreme volatility due to fluctuating supply-and-demand conditions, which have impacted our operations and profitability and are largely due to factors beyond our control. Commodity prices are the most significant factor impacting our profitability and related reinvestment of operating cash flows into our business. Other dynamics which have influenced world energy markets and commodity prices included 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. Additionally, 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. In order to navigate through a volatile market, our strategy is to maintain a strong balance sheet with a diverse and flexible portfolio of assets which will provide the financial flexibility to withstand challenging business cycles.

Operating and Financial Priorities

Other 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 2014 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.

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, 2014, our organic reserve replacement was 143 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, which often experiences long lead times from the time an investment decision is made to the time an asset is operational and generates cash flow. 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 natural gas. As investments bring more liquids production online, we have experienced a corresponding shift in our production mix. In 2014 our average liquids production from continuing operations, excluding Libya, increased 7 percent compared with 2013. In 2013 our average liquids production from continuing operations, excluding Libya, increased 2 percent compared with 2012.

Our 2015 capital budget is $11.5 billion, a reduction of 33 percent compared with our actual 2014 capital spend of $17.1 billion. The decrease mainly reflects a slower pace of development on North American unconventional plays, the elimination of peak spending on major capital projects due to their anticipated startup in 2015, and the deferral of certain exploration programs. Our capital budget will be allocated toward maintenance of our legacy base portfolio; higher-margin development drilling programs, primarily in the Eagle Ford and Bakken; sanctioned major developments, specifically the completion of APLNG and Surmont 2; and our worldwide exploration and appraisal program, which will target conventional activity in the U.S. Gulf of Mexico, offshore West Africa and Nova Scotia, as well as unconventional activity in North America.

In response to weakening commodity prices, we plan to slow the pace of certain investments, such as in the Eagle Ford and the Bakken, as well as emerging unconventional plays in the Permian, Niobrara, Montney and Duvernay. We retain the flexibility to increase or decrease investment activity and may reassess our near-term investment decisions as necessary.

•

Portfolio optimization. We continue to optimize our asset portfolio by focusing on assets which offer the highest returns and growth potential, while selling nonstrategic assets. In 2012 we announced plans to sell $8–$10 billion of noncore assets through the end of 2013. We completed this disposition program with the July 2014 sale of our Nigeria upstream affiliates. As part of this program, we generated $14.0 billion in proceeds from asset dispositions through December 31, 2014.

Although we have completed the asset disposition program, we will continue to evaluate our assets to determine whether they fit our strategic direction. We will optimize the portfolio as necessary and direct our capital investments to areas we expect will achieve our strategic objectives.

•

Controlling costs and expenses. Controlling operating and overhead costs, without compromising 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. Managing operating and overhead costs is critical to maintaining a competitive position in our industry.

•

Applying technical capability. We 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. In 2014 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. We offer 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 graph depicts the average benchmark prices for West Texas Intermediate (WTI) crude oil, Dated Brent crude oil and U.S. Henry Hub natural gas:

LOGO

Brent crude oil prices averaged $76.27 per barrel in the fourth quarter of 2014, a decrease of 30 percent compared with $109.27 per barrel in the fourth quarter of 2013. December 2014 prices for Brent crude oil averaged $62.53 per barrel, a decline of 44 percent compared with June 2014 average prices of $111.65 per barrel. Industry crude prices for WTI averaged $73.41 per barrel in the fourth quarter of 2014, a decrease of 25 percent compared with $97.38 in the same quarter of 2013. WTI prices in December 2014 averaged $59.50 per barrel, a 43 percent decrease compared with June 2014 average prices of $105.24 per barrel. Crude oil prices have continued to rapidly decline in the first quarter of 2015 to their lowest levels in the past six years to the mid-$40-per-barrel-range, driven downward by rising production, particularly from U.S. shale oil and reduced disruptions from Middle East production, OPEC’s decision to maintain current production and weaker-than-expected demand in Europe and Asia.

Henry Hub natural gas prices averaged $4.04 per thousand cubic feet (MCF) in the fourth quarter of 2014, an increase of 12 percent compared with the same period in 2013. Average Henry Hub prices were relatively strong in 2014, as prices averaged $4.43 per MCF in 2014 compared with $3.65 in 2013. This was the result of a cold start to 2014; however, natural gas prices softened later in the year due to very strong production growth, particularly from the northeast United States, and a mild start to the 2014/2015 heating season.

Domestic natural gas liquids prices experienced a similar decline to crude oil prices in the fourth quarter of 2014, as our domestic realized natural gas liquids prices averaged $24.93 per barrel in the fourth quarter of 2014, a decrease of 27 percent compared with $34.33 per barrel in the same quarter of 2013. 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.

Declining global crude oil prices have resulted in the Western Canada Select benchmark price experiencing a 50 percent decline from June 2014 to December 2014, from $86.55 per barrel to $43.24 per barrel. Consequently, our realized bitumen price experienced a significant decrease in the second half of 2014.

In recent years, the use of hydraulic fracturing and horizontal drilling in shale natural gas formations has led to increased industry actual and forecasted crude oil and natural gas production in the United States. Although providing significant short- and long-term growth opportunities for our Company, the increased abundance of crude oil and natural gas due to development of shale plays could also have adverse financial implications to us, including: an extended period of low commodity prices; production curtailments; delay of plans to develop areas such as unconventional fields or 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. For additional information on our impairments in 2014, 2013 and 2012, see Note 8—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 or significantly curtailed 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

The company expects to deliver 2 to 3 percent production growth in 2015 from continuing operations, excluding Libya. First-quarter 2015 production from continuing operations is expected to be 1,570 MBOED to 1,610 MBOED, excluding Libya.

Operating Segments

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

Corporate and Other represents costs not directly associated with an operating segment, such as most interest expense, corporate overhead, costs related to the separation of Phillips 66 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	2014			2013			2012


Alaska	$	2,041			2,274			2,276
Lower 48		(22	)		754			745
Canada		940			718			(684	)
Europe		804			1,229			1,517
Asia Pacific and Middle East		3,008			3,591			3,996
Other International		(90	)		291			624
Corporate and Other		(874	)		(820	)		(993	)

Income from continuing operations	$	5,807			8,037			7,481

2014 vs. 2013

Earnings for ConocoPhillips decreased 28 percent in 2014. The decrease was mainly due to:

•

Lower crude oil prices.

•

Lower gains from asset sales. Gains realized in 2014 were approximately $70 million after-tax, compared with gains realized in 2013 of $1,132 million after-tax.

•

Higher operating expenses, which included the 2014 recognition of a $540 million after-tax loss resulting from the Freeport LNG termination agreement.

•

Higher impairments. Non-cash impairments in 2014 totaled $662 million after-tax, compared with $289 million after-tax in 2013.

•

Higher depreciation, depletion and amortization (DD&A) expenses, mainly due to higher volumes in the Lower 48 and the United Kingdom, partly offset by lower unit-of-production rates in Canada related to reserve bookings.

•

Higher exploration expenses.

These reductions to earnings were partially offset by higher volumes; lower production taxes, which mainly resulted from higher capital spending, lower prices and lower production volumes in Alaska; and higher natural gas and LNG prices.

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 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.

Income Statement Analysis

2014 vs. 2013

Sales and other operating revenues decreased 3 percent in 2014, mainly as a result of lower crude oil prices, partly offset by higher crude oil and bitumen volumes and higher natural gas prices.

Equity in earnings of affiliates increased 14 percent in 2014, primarily as a result of higher earnings from FCCL Partnership due to higher bitumen volumes and prices. This increase was partially offset by lower earnings from APLNG, mostly as a result of higher operating expenses and DD&A.

Gain on dispositions decreased $1,144 million in 2014. Gains realized in 2014 mostly resulted from the disposition of certain properties in western Canada. For additional information on gains realized in prior years, see Note 5—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements.

Production and operating expenses increased 23 percent in 2014, largely due to the $849 million charge resulting from the Freeport LNG termination agreement. Higher drilling and maintenance activity, mostly in the Lower 48, Australia, Alaska and Europe, in addition to the absence of the 2013 benefit of a $142 million accrual reduction 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), also contributed to the increase. These increases were partly offset by the absence of a $155 million charge in 2013 related to Bohai Bay. For additional information on the Freeport LNG transaction, see Note 3—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.

Selling, general and administrative (SG&A) expenses decreased 14 percent in 2014, mainly due to the absence of pension settlement expenses.

Exploration expenses increased 66 percent in 2014, mainly as a result of higher impairments of undeveloped leasehold costs, primarily in the Lower 48 and Canada, and higher dry hole costs, mostly associated with the Gulf of Mexico and Angola. For additional information on the leasehold impairments, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

DD&A increased 12 percent in 2014. This increase was mostly associated with higher production volumes in the United Kingdom and the Lower 48, partly offset by lower unit-of-production rates in Canada associated with year-end 2013 price-related reserve revisions and lower natural gas production volumes.

Impairments increased 62 percent in 2014. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Taxes other than income taxes decreased 28 percent in 2014, mainly due to lower production taxes, which resulted from higher capital spending, lower crude oil prices and lower production volumes in Alaska.

Interest and debt expense increased 6 percent in 2014, primarily due to lower capitalized interest on projects, partly offset by lower interest expense from lower average debt levels and a $28 million benefit associated with interest on a favorable tax settlement.

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

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 5—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 12—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 $142 million accrual reduction associated with FERC approval of pooling agreements with the TAPS owners.

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 17—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 and mainly consisted of increases in the asset retirement obligation 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.

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

Summary Operating Statistics


		2014	2013	2012

Average Net Production
Crude oil (MBD)*		595	581	595
Natural gas liquids (MBD)		159	156	156
Bitumen (MBD)		129	109	93
Natural gas (MMCFD)**		3,943	3,939	4,096


Total Production (MBOED)***		1,540	1,502	1,527


		Dollars Per Unit

Average Sales Prices
Crude oil (per barrel)	$	92.80	103.32	105.72
Natural gas liquids (per barrel)		38.99	41.42	46.36
Bitumen (per barrel)		55.13	53.27	53.91
Natural gas (per thousand cubic feet)		6.57	6.11	5.48


		Millions of Dollars

Worldwide Exploration Expenses
General and administrative; geological and geophysical; and lease rentals	$	879	789	626
Leasehold impairment		562	175	719
Dry holes		604	268	155

	$	2,045	1,232	1,500

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, 2014, our continuing operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, China, Malaysia, Qatar, Libya and Russia.

Total production from continuing operations, including Libya, increased 3 percent in 2014, while average liquids production increased 4 percent. The increase in total average production in 2014 primarily resulted from additional production from major developments, mainly from shale plays in the Lower 48 and the ramp up of production from Jasmine in the United Kingdom and Christina Lake in Canada, and increased drilling programs, mostly in the Lower 48, western Canada and Norway. These increases were largely offset by normal field decline, higher planned downtime, shut-in Libya production due to the closure of the Es Sider crude oil export terminal, and unfavorable market impacts. Adjusted for Libya, production from continuing operations increased by 60 MBOED, or 4 percent, compared with 2013.

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 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 Libya, production grew by 30 MBOED, or 2 percent, compared with 2012.

Alaska


		2014	2013	2012


Income from Continuing Operations (millions of dollars)	$	2,041	2,274	2,276


Average Net Production
Crude oil (MBD)		162	178	188
Natural gas liquids (MBD)		13	15	16
Natural gas (MMCFD)		49	43	55


Total Production (MBOED)		183	200	213


Average Sales Prices
Crude oil (per barrel)	$	97.68	107.83	109.62
Natural gas (per thousand cubic feet)		5.42	4.35	4.22

The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas liquids, natural gas and LNG. In 2014 Alaska contributed 20 percent of our worldwide liquids production and 1 percent of our natural gas production.

2014 vs. 2013

Alaska earnings decreased 10 percent in 2014 compared with 2013 earnings. The decrease was largely due to lower crude oil prices and volumes; the absence of a $97 million after-tax benefit associated with a FERC ruling in 2013, more fully described below; higher operating expenses; and a $36 million after-tax impairment related to a cancelled project. These reductions to earnings were partly offset by lower production taxes, which resulted from higher 2014 capital spending and lower crude oil prices and volumes. Higher LNG sales volumes and prices also partially offset the decrease in 2014 earnings.

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

Average production decreased 9 percent in 2014 compared with 2013, mainly as a result of normal field decline and higher planned maintenance, partly offset by lower unplanned downtime.

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 FERC ruling discussed above.

Average production decreased 6 percent in 2013 compared with 2012, primarily due to normal field decline, partially offset by lower planned downtime.

Lower 48


		2014		2013	2012


Income (Loss) from Continuing Operations (millions of dollars)	$	(22	)	754	745


Average Net Production
Crude oil (MBD)		188		152	123
Natural gas liquids (MBD)		97		91	85
Natural gas (MMCFD)		1,491		1,490	1,493


Total Production (MBOED)		533		491	457


Average Sales Prices
Crude oil (per barrel)	$	84.18		93.79	91.67
Natural gas liquids (per barrel)		30.74		31.48	35.45
Natural gas (per thousand cubic feet)		4.29		3.50	2.67

The Lower 48 segment consists of operations located in the U.S. Lower 48 states and exploration activities in the Gulf of Mexico. During 2014 the Lower 48 contributed 32 percent of our worldwide liquids production and 38 percent of our natural gas production.

2014 vs. 2013

The Lower 48 reported a loss of $22 million after-tax in 2014, compared with earnings of $754 million after-tax in 2013. The decrease in earnings was primarily attributable to:

•

Higher operating expenses, which included the $545 million after-tax charge to earnings due to the Freeport LNG termination agreement.

•

Lower crude oil prices.

•

Higher DD&A, mostly due to higher crude oil production.

•

Higher impairments. Earnings in 2014 were impacted by impairments of approximately $290 million after-tax. Property impairments were not material in 2013. For additional information, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

•

Higher dry hole costs. Dry hole costs in 2014 were approximately $180 million after-tax, primarily for the nonoperated Coronado wildcat and appraisal wells, the Shenandoah appraisal well and the Deep Nansen wildcat well, all located in the Gulf of Mexico. Dry hole costs in 2013 were approximately $130 million after-tax and mainly consisted of the Ardennes and Thorn wells, also located in the Gulf of Mexico.

•

An $83 million after-tax loss recognized upon the release of underutilized transportation and storage capacity at rates below our contractual rates.

These reductions to earnings were partially offset by higher crude oil and natural gas liquids volumes, higher natural gas prices and a benefit to earnings of approximately $150 million after-tax from marketing third-party natural gas volumes.

Rising U.S. production and an increase in pipeline capacity to the Gulf Coast have put downward pressure on Gulf Coast crude oil prices. Prices for Permian Basin crude oil production have been impacted by production increases exceeding pipeline offtake additions. Our average realized prices in the Lower 48 have historically correlated with WTI prices; however, beginning in the second half of 2013, our Lower 48 crude differential versus WTI began to widen. In 2014 our average realized crude oil price of $84.18 per barrel was 10 percent below the WTI price of $93.17 per barrel.

Total average production in the Lower 48 increased 9 percent in 2014, while average crude oil production increased 24 percent. The increase was mainly attributable to new production, primarily from the Eagle Ford and Bakken, and improved drilling and well performance, partially offset by normal field decline.

2013 vs. 2012

Lower 48 earnings increased 1 percent in 2013 compared with 2012. Earnings in 2013 largely benefitted from higher crude oil and natural gas liquids volumes, 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, higher operating expenses, higher exploration expenses, which mainly resulted from the Thorn and Ardennes dry holes, and lower natural gas liquids prices.

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.

Canada


		2014	2013	2012

Income (Loss) from Continuing Operations (millions of dollars)	$	940	718	(684)


Average Net Production
Crude oil (MBD)		13	13	13
Natural gas liquids (MBD)		23	25	24
Bitumen (MBD)
Consolidated operations		12	13	12
Equity affiliates		117	96	81

Total bitumen		129	109	93


Natural gas (MMCFD)		711	775	857


Total Production (MBOED)		284	276	273


Average Sales Prices
Crude oil (per barrel)	$	77.87	79.73	78.26
Natural gas liquids (per barrel)		46.23	47.19	48.64
Bitumen (dollars per barrel)
Consolidated operations		60.03	55.25	57.58
Equity affiliates		54.62	53.00	53.39
Total bitumen		55.13	53.27	53.91
Natural gas (per thousand cubic feet)		4.13	2.92	2.13

Our Canadian operations mainly consist of natural gas fields in western Canada and oil sands developments in the Athabasca Region of northeastern Alberta. In 2014 Canada contributed 19 percent of our worldwide liquids production and 18 percent of our natural gas production.

2014 vs. 2013

Canada earnings increased 31 percent in 2014 compared with 2013, primarily as a result of higher natural gas and bitumen prices, lower DD&A from western Canada and higher bitumen volumes. The lower DD&A mainly resulted from lower unit-of-production rates related to year-end 2013 price-related reserve revisions

and lower natural gas production volumes. Earnings in 2014 also included a $47 million tax benefit resulting from a favorable tax settlement. These increases were partly offset by lower gains from asset sales, mainly as a result of the $461 million after-tax gain from the disposition of our Clyden undeveloped oil sands leasehold in 2013, as well as the 2013 recognition of a $224 million tax benefit, related to the favorable tax resolution associated with the sale of certain western Canada properties in a prior year. Lower natural gas volumes also partially offset the increase in 2014 earnings.

In addition, earnings in 2014 benefitted from lower impairments. Impairments in 2014 were $138 million after-tax and consisted primarily of the $109 million after-tax impairment of undeveloped leasehold costs associated with the offshore Amauligak discovery, Arctic Islands and other Beaufort properties. Impairments in 2013 consisted of the $162 million after-tax impairment of mature natural gas assets in western Canada.

For additional information on prior year asset sales, see Note 5—Assets Held for Sale or Sold, and for additional information on impairments, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Total average production increased 3 percent in 2014 compared with 2013, while bitumen production increased 18 percent over the same period. The continued ramp-up of production from Christina Lake Phase E in FCCL and improved drilling and well performance were partly offset by normal field decline and higher royalty impacts.

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 Clyden gain on disposition and lower impairments. Impairments in 2013 consisted of the $162 million after-tax impairment of mature natural gas assets in western Canada, and 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, and the $224 million favorable tax resolution also benefitted 2013 earnings.

Average production in Canada increased 1 percent in 2013, while bitumen production increased 17 percent over the same period. 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.

Europe


		2014	2013	2012

Income from Continuing Operations (millions of dollars)	$	804	1,229	1,517


Average Net Production
Crude oil (MBD)		126	113	135
Natural gas liquids (MBD)		8	6	7
Natural gas (MMCFD)		461	416	516


Total Production (MBOED)		211	189	228


Average Sales Prices
Crude oil (dollars per barrel)	$	99.56	110.56	113.08
Natural gas liquids (per barrel)		52.65	58.36	61.53
Natural gas (per thousand cubic feet)		9.29	10.68	9.76

The Europe segment consists of operations principally located in the Norwegian and U.K. sectors of the North Sea, as well as exploration activities in Greenland. In 2014 our Europe operations contributed 15 percent of our worldwide liquids production and 12 percent of our natural gas production.

2014 vs. 2013

Earnings for Europe decreased 35 percent in 2014 compared with 2013. The reduction in earnings was primarily due to higher DD&A, which mainly resulted from increased production volumes from Jasmine, lower crude oil and natural gas prices, higher taxes and higher impairments. Impairments in 2014 were $192 million after-tax, compared with impairments in 2013 of $118 million after-tax. Lower gains from asset dispositions, mostly due to the absence of the $83 million after-tax gain on the disposition of our interest in the Interconnector Pipeline in 2013, also contributed to the decrease in 2014 earnings. These decreases were partly offset by higher volumes and a $48 million after-tax benefit from a pension-related settlement.

For additional information on the impairments, see Note 8—Impairments, in the Notes to Consolidated Financial Statements.

Average production increased 12 percent in 2014, mostly due to the continued ramp-up of production from Jasmine, the Rivers Acid Plant in the East Irish Sea and Ekofisk South, improved drilling and well performance in Norway and lower planned downtime. These increases were partly offset by normal field decline and higher unplanned downtime.

2013 vs. 2012

Europe earnings decreased 19 percent in 2013 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 Interconnector Pipeline gain in 2013. These decreases were partly offset by the absence of the recognition of $192 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. Additionally, major planned maintenance at Greater Ekofisk, higher unplanned downtime, mostly in the East Irish Sea, and asset dispositions 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.

Asia Pacific and Middle East


		2014	2013	2012


Income from Continuing Operations (millions of dollars)	$	3,008	3,591	3,996


Average Net Production
Crude oil (MBD)
Consolidated operations		79	80	68
Equity affiliates		15	15	15

Total crude oil		94	95	83


Natural gas liquids (MBD)
Consolidated operations		10	12	16
Equity affiliates		8	7	8

Total natural gas liquids		18	19	24


Natural gas (MMCFD)
Consolidated operations		723	709	672
Equity affiliates		505	481	485

Total natural gas		1,228	1,190	1,157


Total Production (MBOED)		317	312	300


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	95.32	104.78	108.20
Equity affiliates		99.01	105.44	108.07
Total crude oil		95.92	104.88	108.18
Natural gas liquids (dollars per barrel)
Consolidated operations		69.36	73.82	79.26
Equity affiliates		67.20	73.31	77.30
Total natural gas liquids		68.46	73.63	78.64
Natural gas (dollars per thousand cubic feet)
Consolidated operations		9.80	10.61	10.63
Equity affiliates		9.79	8.98	8.54
Total natural gas		9.80	9.95	9.75

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

2014 vs. 2013

Asia Pacific and Middle East earnings decreased 16 percent in 2014 compared with 2013. The reduction in earnings was largely due to lower crude oil and natural gas prices; higher operating expenses, mostly as a result of major planned maintenance at our Bayu-Undan Field and Darwin LNG facility in Australia; lower equity earnings, mainly due to increased activity at APLNG in preparation for startup in mid-2015; and lower sales volumes, primarily crude oil and LNG. These decreases were partially offset by higher LNG prices, higher natural gas volumes and lower taxes. The 2014 benefits from the absence of the $116 million after-tax charge in 2013 related to Bohai Bay and a $30 million after-tax legal settlement in 2014 were offset by the absence of a $146 million after-tax insurance settlement received in 2013, also associated with the Bohai Bay seepage incidents.

Average production increased 2 percent in 2014 compared with 2013. Increased production, mainly from Indonesia, China and Malaysia, was largely offset by normal field decline and major planned maintenance at Bayu-Undan and Darwin LNG.

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 Bohai Bay.

•

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 and 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.

Other International


		2014		2013	2012

Income (Loss) from Continuing Operations (millions of dollars)	$	(90	)	291	624


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

Total crude oil		12		30	53


Natural gas (MMCFD)		3		25	18


Total Production (MBOED)		12		34	56


Average Sales Prices
Crude oil (dollars per barrel)
Consolidated operations	$	86.71		107.21	110.75
Equity affiliates		64.14		72.43	96.50
Total crude oil		77.36		101.91	107.56
Natural gas (dollars per thousand cubic feet)		3.40		5.38	5.55

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

2014 vs. 2013

Other International operations reported a loss of $90 million in 2014, compared with earnings of $291 million in 2013. The decrease was primarily due to the lower gains from asset dispositions, mainly from the absence of the $288 million after-tax gain recognized on the 2013 disposition of our equity investment in Phoenix Park Processors Limited, located in Trinidad and Tobago; higher dry hole expenses, mostly due to the $136 million after-tax charge for the Kamoxi-1 exploration well, located offshore Angola; and lower volumes from Libya. These reductions were partially offset by the recognition of other income of $154 million after-tax associated with the favorable resolution of a contingent liability.

Average production decreased 65 percent in 2014 compared with 2013, primarily due to the shutdown of the Es Sider crude oil export terminal in Libya, which began at the end of July 2013. The Es Sider Terminal briefly reopened in the third quarter of 2014 and production and liftings resumed temporarily; however, further disruptions occurred in December 2014, and production is shut in again. The 2015 drilling program remains uncertain as a result of the ongoing civil unrest.

2013 vs. 2012

Earnings from Other International decreased 53 percent in 2013 compared with 2012 earnings. The reduction was mainly due to the absence of the 2012 favorable resolution of the PDVSA ICC arbitration, more fully described, below, and lower gains from asset dispositions. Gains realized in 2013 primarily included the $288 million after-tax Phoenix Park disposition, and gains realized in 2012 mostly consisted of the $443 million after-tax gain on disposition of our interest in Naryanmarneftegaz (NMNG) in Russia. Additionally, lower volumes from Libya contributed to the reduction in earnings. 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.

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.

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.

Venezuela Arbitration

In October 2014 we filed for arbitration under the rules of the ICC against PDVSA, the Venezuela state oil company, for contractual compensation related to the Petrozuata and Hamaca heavy crude oil projects. The ICC arbitration is a separate and independent legal action from the investment treaty arbitration against the government of Venezuela, which is pending before an arbitral tribunal under ICSID. For additional information, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Asset Dispositions

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

Corporate and Other


	Millions of Dollars
		2014	2013	2012

Income (Loss) from Continuing Operations
Net interest	$	(502)	(530)	(648)
Corporate general and administrative expenses		(194)	(213)	(313)
Technology		(93)	(6)	(4)
Separation costs		-	-	(84)
Other		(85)	(71)	56

	$	(874)	(820)	(993)

2014 vs. 2013

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 5 percent in 2014 compared with 2013, primarily as a result of a $93 million tax benefit associated with the election of the fair market value method of apportioning interest expense in the United States, as well as a $28 million after-tax benefit associated with interest on a favorable tax settlement. These improvements were largely offset by lower capitalized interest on projects sold or completed.

Corporate general and administrative expenses decreased 9 percent in 2014, mainly due to lower pension settlement expense, partly offset by higher benefit-related expenses. Pension settlement expense incurred in 2013 was $41 million after-tax. We did not incur pension settlement expense in 2014.

Technology includes our investment in new technologies or businesses, as well as licensing revenues received. Activities are focused on heavy oil and oil sands, unconventional reservoirs, LNG, and subsurface, arctic and deepwater technologies, with an underlying commitment to environmental responsibility. Losses from Technology were $93 million in 2014, compared with losses of $6 million in 2013. The reduction in earnings primarily resulted from lower licensing revenues and higher research and development expenses.

The category “Other” includes certain foreign currency transaction gains and losses, environmental costs associated with sites no longer in operation, and other costs not directly associated with an operating segment.

2013 vs. 2012

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 arbitration, see Note 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

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.

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

“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.

CAPITAL RESOURCES AND LIQUIDITY

Financial Indicators


	Millions of Dollars
	Except as Indicated
		2014		2013	2012

Net cash provided by continuing operating activities	$	16,592		15,801	13,458
Net cash provided by discontinued operations		143		286	464
Cash and cash equivalents		5,062		6,246	3,618
Short-term debt		182		589	955
Total debt		22,565		21,662	21,725
Total equity		52,273		52,492	48,427
Percent of total debt to capital*		30	%	29	31
Percent of floating-rate debt to total debt**		5	%	8	9

*Capital includes total debt and total equity.

**Includes effect of interest rate swaps in 2013 and 2012.

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 2014 we received $1,603 million in proceeds from asset sales and issued $2,994 million of new low-interest notes. The primary uses of our available cash were $17,085 million to support our ongoing capital expenditures and investments; $3,525 million to pay dividends on our common stock; and $2,014 million to repay debt. During 2014 cash and cash equivalents decreased by $1,184 million, to $5,062 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 2014 cash provided by continuing operating activities was $16,592 million, a 5 percent increase from 2013. Cash flows from operating activities benefited from the $1.3 billion distribution from FCCL in the first quarter of 2014. The distribution from FCCL resulted from our $2.8 billion prepayment of the remaining joint venture acquisition obligation in 2013, which substantially increased the financial flexibility of our 50 percent owned FCCL Partnership. We do not expect this individually significant distribution to recur in the future under current economic conditions. Cash flows from investing activities were also impacted by the $0.5 billion payment of the fee resulting from our termination agreement with Freeport LNG, which was largely offset by the receipt of the Freeport LNG loan repayment. During 2013 cash provided by continuing operations was $15,801 million, compared with $13,458 million in 2012.

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. During 2014 and 2013 we benefited from favorable crude oil and natural gas prices, although these prices deteriorated significantly in the fourth quarter of 2014. 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 absolute production volumes, as well as product and location mix, impacts our cash flows. Our 2014 production from continuing operations, excluding Libya, averaged 1,532 MBOED. We expect 2015 production to grow 2 to 3 percent, excluding Libya. 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; acquisition and disposition of fields; field production decline rates; new technologies; operating efficiencies; timing of startups and major turnarounds; political instability; weather-related disruptions; and the addition of proved reserves through exploratory success and their timely and cost-effective development. While we actively manage these factors, production levels can cause variability in cash flows, although generally this variability has not been as significant as that caused by commodity prices.

To maintain or grow our production volumes, we must continue to add to our proved reserve base. Our total reserve replacement in 2014 was 97 percent. Excluding the impact of sales and purchases, the organic reserve replacement was 124 percent of 2014 production. Over the five-year period ended December 31, 2014, our reserve replacement was 55 percent (including 78 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 138 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 2014, 2013 and 2012, 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 2014 were $1.6 billion, primarily from the sale of our Nigeria upstream affiliates for net proceeds of $1.4 billion, after customary adjustments, inclusive of deposits previously received. This compares with proceeds of $10.2 billion in 2013, 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 interest in Browse and Canning basins. For additional information, see Note 2—Discontinued Operations and Note 5—Assets Held for Sale or Sold, in the Notes to Consolidated Financial Statements. We continue to evaluate opportunities to further optimize the portfolio.

Commercial Paper and Credit Facilities

In June 2014 we refinanced our revolving credit facility from a total of $7.5 billion to $7.0 billion, with a new expiration date of June 2019. Our revolving credit facility may be used for direct bank borrowings, for the issuance of letters of credit totaling up to $500 million, or as support for our commercial paper programs. The revolving credit facility is broadly syndicated among financial institutions and does not contain any material adverse change provisions or any covenants requiring maintenance of specified financial ratios or credit ratings. The facility agreement contains a cross-default provision relating to the failure to pay principal or interest on other debt obligations of $200 million or more by ConocoPhillips or any of its consolidated subsidiaries.

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

Our primary funding source for short-term working capital needs is the ConocoPhillips $6.1 billion commercial paper program. Commercial paper maturities are generally limited to 90 days. We also have the ConocoPhillips Qatar Funding Ltd. $900 million commercial paper program, which is used to fund commitments relating to QG3. At both December 31, 2014 and 2013, 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 $860 million of commercial paper outstanding at December 31, 2014, compared with $961 million at December 31, 2013. Since we had $860 million of commercial paper outstanding and had issued no letters of credit, we had access to $6.1 billion in borrowing capacity under our revolving credit facility at December 31, 2014.

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 $7.0 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, 2014 and December 31, 2013, we had direct bank letters of credit of $802 million and $827 million, respectively, which secured performance obligations related to various purchase commitments incident to the ordinary conduct of business.

Shelf Registration

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

Off-Balance Sheet Arrangements

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

For information about guarantees, see Note 11—Guarantees, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.

Capital Requirements

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

Our debt balance at December 31, 2014, was $22.6 billion, an increase of $903 million from the balance at December 31, 2013. Our short-term debt balance at December 31, 2014, decreased $407 million compared with December 31, 2013, primarily as a result of the timing of scheduled maturities. During 2014 we repaid notes at maturity totaling $400 million. In November 2014 we redeemed the outstanding $1.5 billion of 4.60% Notes due January 2015 and issued $3.0 billion of new low-interest notes. For more information, see Note 10—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. 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.

In October 2014 we announced a dividend of 73 cents per share. The dividend was paid December 1, 2014, to stockholders of record at the close of business on October 14, 2014. Additionally, on February 4, 2015, we announced a dividend of 73 cents per share. The dividend will be paid March 2, 2015, to stockholders of record at the close of business on February 17, 2015.

Contractual Obligations

The following table summarizes our aggregate contractual fixed and variable obligations of our continuing operations as of December 31, 2014:


		Millions of Dollars

		Payments Due by Period

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


Debt obligations (a)	$	21,707	123	2,309		3,843		15,432
Capital lease obligations (b)		858	59	95		102		602

Total debt		22,565	182	2,404		3,945		16,034

Interest on debt and other obligations		16,007	1,169	2,216		1,943		10,679
Operating lease obligations (c)		2,949	568	1,235		515		631
Purchase obligations (d)		17,450	7,099	3,119		1,878		5,354
Other long-term liabilities
Pension and postretirement benefit contributions (e)		1,690	294	558		838		-
Asset retirement obligations (f)		10,939	592	1,506		1,529		7,312
Accrued environmental costs (g)		344	48	59		34		203
Unrecognized tax benefits (h)		53	53	(h	)	(h	)	(h)

Total	$	71,997	10,005	11,097		10,682		40,213

(a)	Includes $372 million of net unamortized premiums and discounts. See Note 10—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 $6,573 million.

Purchase obligations of $7,778 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 2015 through 2019. For additional information related to expected benefit payments subsequent to 2019, see Note 17—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 $389 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
		2014	2013	2012

Alaska	$	1,564	1,140	828
Lower 48		6,054	5,210	5,249
Canada		2,340	2,232	2,184
Europe		2,521	3,078	2,844
Asia Pacific and Middle East		3,877	3,382	2,430
Other International		539	313	433
Corporate and Other		190	182	204

Capital expenditures and investments from continuing operations		17,085	15,537	14,172

Discontinued operations in Kashagan, Nigeria and Algeria		59	609	817
Joint venture acquisition obligation (principal)—Canada*		-	772	733

Capital Program	$	17,144	16,918	15,722

*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, 2014, totaled $46.8 billion. The 2014 expenditures supported key exploration and developments, primarily:

•

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

•

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

•

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

•

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

•

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

•

Exploration and appraisal drilling in deepwater Gulf of Mexico.

•

Continued development in Malaysia and Indonesia and ongoing exploration, appraisal and development activity offshore Australia and China.

•

Exploration activities in Angola and Senegal.

2015 CAPITAL BUDGET

In anticipation of weak commodity prices in 2015, our capital budget was further reduced in January 2015 from the previously announced $13.5 billion to $11.5 billion, a decrease of 33 percent, compared with our actual 2014 capital spend of $17.1 billion. The reduction in capital relative to 2014 primarily reflects deferral of spending on North American unconventional plays, as well as lower spending on major projects, several of which are nearing completion.

We are planning to allocate approximately:

•

30 percent of our 2015 capital expenditures budget to development drilling programs. The 2015 Lower 48 development program capital will continue to target the Eagle Ford and Bakken, with investments being deferred in emerging plays like the Permian and Niobrara. We retain the flexibility to ramp up or down activity in the unconventionals.

•

40 percent of our 2015 capital expenditures budget to major projects. These funds will focus on completion of APLNG and Surmont 2, as well as multiple projects in Alaska, Europe and Malaysia.

•

15 percent of our 2015 capital expenditures budget to exploration and appraisal. This spending will focus on conventional activity in the U.S. Gulf of Mexico, offshore West Africa and Nova Scotia, as well as unconventional activity in North America.

•

15 percent of our 2015 capital expenditures budget to maintain base production.

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 12—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.

Legal and Tax Matters

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

Our legal organization applies its knowledge, experience and professional judgment to the specific characteristics of our cases, employing a litigation management process to manage and monitor the legal proceedings against us. Our process facilitates the early evaluation and quantification of potential exposures in individual cases. This process also enables us to track those cases that have been scheduled for trial and/or mediation. Based on professional judgment and experience in using these litigation management tools and available information about current developments in all our cases, our legal organization regularly assesses the adequacy of current accruals and determines if adjustment of existing accruals, or establishment of new accruals, is required. See Note 18—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:

•

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

•

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

•

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

•

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.

•

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

•

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.

•

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.

•

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

•

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.

•

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 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, 2013, we reported we had been notified of potential liability under CERCLA and comparable state laws at 15 sites around the United States. At December 31, 2014, there was no change in the number of 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 $573 million in 2014 and are expected to be about $560 million per year in 2015 and 2016. Capitalized environmental costs were $497 million in 2014 and are expected to be about $450 million per year in 2015 and 2016.

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, 2014, our balance sheet included total accrued environmental costs of $344 million, compared with $348 million at December 31, 2013, 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:

•

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 2014 was approximately $3 million (net share pre-tax).

•

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 2014 was approximately $6 million.

•

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.

•

The U.S. 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.

•

The U.S. EPA’s announcement on January 14, 2015, outlining a series of steps it plans to take to address methane and smog-forming volatile organic compound emissions from the oil and gas industry. The current U.S. administration has established a goal of reducing the 2012 levels in methane emissions from the oil and gas industry by 40 to 45 percent by 2025.

•

Carbon taxes in certain jurisdictions. Our cost of compliance with Norwegian carbon tax legislation in 2014 was approximately $41 million (net share pre-tax). Our cost of compliance with the Australian Clean Energy Legislation carbon tax (repealed in July 2014) in 2014 was approximately $3 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:

•

Whether and to what extent legislation is enacted.

•

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

•

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

•

The GHG reductions required.

•

The price and availability of offsets.

•

The amount and allocation of allowances.

•

Technological and scientific developments leading to new products or services.

•

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

•

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:

•

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.

•

Reducing GHG emissions—In 2013 the Company reduced or avoided GHG emissions by approximately 1,200,000 metric tonnes by carrying out a range of programs across a number of business units.

•

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.

•

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 $7 to $47 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 offsets to the tax consequences of future taxable income.

NON-GAAP RECONCILIATION: PRICE NORMALIZED CASH MARGIN PER BOE

Our financial information includes information prepared in conformity with U.S. generally accepted accounting principles (GAAP), as well as non-GAAP information. Management believes this non-GAAP measure is useful to investors because it enhances understanding of our consolidated financial information by facilitating comparisons of Company operating performance across time periods. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. The non-GAAP measure is presented along with the corresponding GAAP measure in order not to imply more emphasis should be placed on the non-GAAP measure. The non-GAAP financial information presented may be determined or calculated differently by other companies.

Cash margin is a performance measure we calculate as a ratio, the numerator of which is net income adjusted for the special items included in the following reconciliation; depreciation, depletion and amortization; dry hole costs; impairments; and corporate and other segment earnings. The denominator is production for the stated time period. This performance measure represents the amount of cash generated per BOE of production. Normalized for changes in commodity prices across time periods, changes in this performance measure demonstrate an underlying portfolio shift to liquids and more favorable fiscal regimes.

Non-GAAP Price Normalized Cash Margin Reconciliation


	Millions of Dollars Except as Indicated
	2014			2013


Net Income Attributable to ConocoPhillips	$	6,869			9,156
Adjustment to exclude special items⁽¹⁾		(260	)		(2,095)

Adjusted earnings		6,609			7,061
Adjusted loss for Corporate and Other (non-GAAP)⁽²⁾		963			781
Operating segment depreciation, depletion and amortization (non-GAAP)⁽³⁾		8,225			7,338
Operating segment impairments (non-GAAP)⁽⁴⁾		29			27
Adjusted dry hole costs and leasehold impairments (non-GAAP)⁽⁵⁾		782			443
Price adjustment⁽⁶⁾		755			-

Price Normalized Cash Margin	$	17,363			15,650


Per BOE Calculation
Production from continuing operations (MBOED)		1,540			1,502
Production from continuing operations (MMBOE)		562			548


Net Income Attributable to ConocoPhillips per BOE	$	12.22			16.70
Percentage decrease		(27	)%

Price Normalized Cash Margin per BOE	$	30.89			28.55
Percentage increase		8	%


		Millions of Dollars Except as Indicated
		2014			2013

(1)	Adjustment to Exclude Special Items*
	Special items, pre-tax
	Net gain on asset sales	$	(51	)		(1,142)
	Special items impairments (including leasehold impairment)**		1,214			498
	Loss on capacity agreements		130			-
	Qatar depreciation adjustment		28			-
	Freeport LNG termination		846			-
	Pension settlement expense		-			66
	Pending claims and settlements		(208	)		(137)
	FCCL international financial reporting standards depreciation adjustment		-			(44)
	Income from discontinued operations		(1,147	)		(1,461)

	Special items, pre-tax	$	812			(2,220)


	Special items, after-tax
	Net gain on asset sales	$	(38	)		(1,075)
	Special items impairments (including leasehold impairment)**		641			269
	Loss on capacity agreements		83			-
	Deferred tax adjustment		(59	)		-
	Qatar depreciation adjustment		28			-
	Tax benefit on interest expense		(61	)		-
	Pension settlement expense		-			41
	Freeport LNG termination		545			-
	Pending claims and settlements		(268	)		(118)
	Tax loss carryforward realization		-			(1)
	FCCL international financial reporting standards depreciation adjustment		-			(33)
	Income from discontinued operations		(1,131	)		(1,178)

	Special items, after-tax	$	(260	)		(2,095)

*Generally, the threshold for special items is $25 million after-tax per event. The special items tax impacts were primarily calculated using the statutory rates in effect for each jurisdiction.
**Includes 2014 impairment related exploration expense of $6 million pre-tax and $4 million after-tax.

(2)	Adjusted loss for Corporate and Other
	Corporate and Other loss	$	874			820
	Exclude Corporate and Other special items		89			(39)

	Adjusted loss for Corporate and Other (non-GAAP)	$	963			781


(3)	Operating Segment Depreciation, Depletion and Amortization (non-GAAP)
	Depreciation, depletion and amortization	$	8,329			7,434
	Exclude Corporate and Other depreciation, depletion and amortization		(104	)		(96)

	Operating segment depreciation, depletion and amortization (non-GAAP)	$	8,225			7,338


(4)	Operating Segment Impairments (non-GAAP)
	Impairments	$	856			529
	Exclude impairments special items		(824	)		(498)
	Exclude Corporate and Other impairments		(3	)		(4)

	Operating segment impairments (non-GAAP)	$	29			27


		Millions of Dollars Except as Indicated
		2014			2013


(5)	Adjusted Dry Hole Costs and Leasehold Impairments (non-GAAP)
	Dry hole costs and leasehold impairments	$	1,166			443
	Exclude leasehold impairment special items		(384	)		-

	Adjusted dry hole costs and leasehold impairments (non-GAAP)	$	782			443


(6)	Price Adjustment*
	Average Industry prices
	Dated Brent (dollars per barrel)	$	98.99			108.65
	WTI (dollars per barrel)		93.17			97.90
	Western Canada Select (dollars per barrel)		73.60			72.77
	Weighted Average Mt Belvieu natural gas liquids (dollars per barrel)		37.51			38.85
	U.S. Henry Hub - first of month (dollars per thousand cubic feet)		4.43			3.65
	UK Gas - National Balancing Point (dollars per thousand cubic feet)		8.51			10.45


	Net income adjustment**
	Dated Brent	$	821			-
	WTI		177			-
	Western Canada Select		(29	)		-
	Weighted Average Mt Belvieu natural gas liquids		17			-
	U.S. Henry Hub - first of month		(328	)		-
	UK Gas - National Balancing Point		97			-

	Price adjustments*	$	755			-

*Based on published sensitivities.
**Represents the difference in industry prices multiplied by the midpoint of the Annualized Net Income Sensitivities, below.

Annualized Net Income Sensitivities

The following sensitivities were published during the 2014 ConocoPhillips Analyst Meeting:

•

Crude oil

Brent/Alaska North Slope: $80–90 million change for $1 per barrel change ($85 million midpoint).

West Texas Intermediate: $35–40 million change for $1 per barrel change ($37.5 million midpoint).

Western Canada Select: $30–40 million change for $1 per barrel change ($35 million midpoint). Western Canada Select price represents a volumetric weighted average of Shorcan and Net Energy indices.

•

North American natural gas liquids

Representative blend: $10–15 million change for $1 per barrel change ($13.5 million midpoint).

•

Natural gas

Henry Hub: $100–110 million change for $0.25 per thousand cubic feet change ($105 million midpoint).

International gas: $10–15 million change for $0.25 per thousand cubic feet change ($12.5 million midpoint).

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 relatively small individual leasehold acquisition costs, 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 with 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 2014, 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 $1,275 million and the accumulated impairment reserve was $433 million. The weighted-average judgmental percentage probability of ultimate failure was approximately 69 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, pre-tax leasehold impairment expense in 2015 would increase by approximately $22 million. At year-end 2014, the remaining $6,612 million of net 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 $4 billion is concentrated in 10 major development areas, the majority of which are not expected to move to proved properties in 2015.

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 expected return on investment.

At year-end 2014, total suspended well costs were $1,299 million, compared with $994 million at year-end 2013. For additional information on suspended wells, including an aging analysis, see Note 7—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 geosciences and 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 an asset 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. Generally, our proved reserves decrease as prices decline and increase as prices rise.

Our proved reserves include estimated quantities related to production sharing contracts, reported under the “economic interest” method, as well as variable-royalty regimes, 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. We would expect reserves from these contracts to decrease when product prices rise and increase when prices 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 2014, the net book value of productive properties, plants and equipment (PP&E) subject to a unit-of-production calculation was approximately $64 billion and the DD&A recorded on these assets in 2014 was approximately $7.9 billion. The estimated proved developed reserves for our consolidated operations were 4.9 billion BOE at the end of 2013 and 4.6 billion BOE at the end of 2014. If the estimates of proved reserves used in the unit-of-production calculations had been lower by 5 percent across all calculations, pre-tax DD&A in 2014 would have increased by an estimated $420 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 pre-tax 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 8—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. Since quoted market prices are usually not available, the fair value is typically 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-governed 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. Projected benefit obligations are particularly sensitive to the discount rate assumption. A 1 percent decrease in the discount rate assumption would increase projected benefit obligations by $1,400 million. 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 $130 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 17—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:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

International monetary conditions and exchange controls.

•

Substantial investment or reduced demand for products as a result of existing or future environmental rules and regulations, use of competing energy sources or the development of alternative energy sources.

•

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

•

Liability resulting from litigation.

•

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

•

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

•

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

•

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

•

The operation and financing of our joint ventures.

•

The factors generally described in Item 1A—Risk Factors in 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, 2014, 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, 2014 and 2013, 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, 2014 and 2013, was also immaterial to our consolidated 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.


	Millions of Dollars Except as Indicated
	Debt
Expected Maturity Date	Fixed Rate Maturity		Average Interest Rate			Floating Rate Maturity		Average Interest Rate

Year-End 2014
2015	$	-		-	%	$	107		0.18	%
2016		1,273		5.52			-		-
2017		1,001		1.06			-		-
2018		797		5.74			-		-
2019		2,250		5.75			753		0.18
Remaining years		14,871		5.81			283		0.04

Total	$	20,192				$	1,143

Fair value	$	24,048				$	1,143


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

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, 2014 and 2013, 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, 2014, or 2013, exchange rates. The notional and fair market values of these positions at December 31, 2014 and 2013, were as follows:


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

	2014		2013		2014			2013

Sell U.S. dollar, buy Canadian dollar	USD	7		-		(1	)		-
Buy U.S. dollar, sell Norwegian krone	USD	44		-		-			-
Buy U.S. dollar, sell Canadian dollar	USD	-		6		-			-
Buy British pound, sell euro	GBP	20		17		1			-

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

**Denominated in U.S. dollars.

For additional information about our use of derivative instruments, see Note 13—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		75

Reports of Independent Registered Public Accounting Firm		76

Consolidated Income Statement for the years ended December 31, 2014, 2013 and 2012		78

Consolidated Statement of Comprehensive Income for the years ended December 31, 2014, 2013 and 2012		79

Consolidated Balance Sheet at December 31, 2014 and 2013		80

Consolidated Statement of Cash Flows for the years ended December 31, 2014, 2013 and 2012		81

Consolidated Statement of Changes in Equity for the years ended December 31, 2014, 2013 and 2012		82

Notes to Consolidated Financial Statements		83

Supplementary Information

Oil and Gas Operations		136

Selected Quarterly Financial Data		163

Condensed Consolidating Financial Information		164

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, 2014. 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 (2013). Based on our assessment, we believe the company’s internal control over financial reporting was effective as of December 31, 2014.

Ernst & Young LLP has issued an audit report on the company’s internal control over financial reporting as of December 31, 2014, 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 24, 2015

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, 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, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 24, 2015, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2015

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, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 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 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, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2014 consolidated financial statements of ConocoPhillips and our report dated February 24, 2015, expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Houston, Texas

February 24, 2015



Consolidated Income Statement		ConocoPhillips

Years Ended December 31
	Millions of Dollars

		2014	2013	2012

Revenues and Other Income
Sales and other operating revenues	$	52,524	54,413	57,967
Equity in earnings of affiliates		2,529	2,219	1,911
Gain on dispositions		98	1,242	1,657
Other income		366	374	469

Total Revenues and Other Income		55,517	58,248	62,004


Costs and Expenses
Purchased commodities		22,099	22,643	25,232
Production and operating expenses		8,909	7,238	6,793
Selling, general and administrative expenses		735	854	1,106
Exploration expenses		2,045	1,232	1,500
Depreciation, depletion and amortization		8,329	7,434	6,580
Impairments		856	529	680
Taxes other than income taxes		2,088	2,884	3,546
Accretion on discounted liabilities		484	434	394
Interest and debt expense		648	612	709
Foreign currency transaction (gains) losses		(66)	(58)	41

Total Costs and Expenses		46,127	43,802	46,581

Income from continuing operations before income taxes		9,390	14,446	15,423
Provision for income taxes		3,583	6,409	7,942

Income From Continuing Operations		5,807	8,037	7,481
Income from discontinued operations*		1,131	1,178	1,017

Net income		6,938	9,215	8,498
Less: net income attributable to noncontrolling interests		(69)	(59)	(70)

Net Income Attributable to ConocoPhillips	$	6,869	9,156	8,428


Amounts Attributable to ConocoPhillips Common Shareholders:
Income from continuing operations	$	5,738	7,978	7,413
Income from discontinued operations		1,131	1,178	1,015

Net Income	$	6,869	9,156	8,428


Net Income Attributable to ConocoPhillips Per Share of Common Stock (dollars)
Basic
Continuing operations	$	4.63	6.47	5.95
Discontinued operations		0.91	0.96	0.82

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	5.54	7.43	6.77

Diluted
Continuing operations	$	4.60	6.43	5.91
Discontinued operations		0.91	0.95	0.81

Net Income Attributable to ConocoPhillips Per Share of Common Stock	$	5.51	7.38	6.72


Dividends Paid Per Share of Common Stock (dollars)	$	2.84	2.70	2.64


Average Common Shares Outstanding (in thousands)
Basic		1,237,325	1,230,963	1,243,799
Diluted		1,245,863	1,239,803	1,253,093

*Net of provision for income taxes on discontinued operations of:	$	16	283	745

See Notes to Consolidated Financial Statements.



Consolidated Statement of Comprehensive Income		ConocoPhillips

Years Ended December 31	Millions of Dollars

	2014		2013		2012


Net Income	$	6,938		9,215		8,498
Other comprehensive income (loss)
Defined benefit plans
Prior service credit (cost) arising during the period		(3)		1		2
Reclassification adjustment for amortization of prior service credit included in net income		(6)		(5)		(5)

Net change		(9)		(4)		(3)

Net actuarial gain (loss) arising during the period		(840)		688		(704)
Reclassification adjustment for amortization of net actuarial losses included in net income		131		294		430

Net change		(709)		982		(274)
Nonsponsored plans*		-		10		8
Income taxes on defined benefit plans		281		(387)		132

Defined benefit plans, net of tax		(437)		601		(137)

Foreign currency translation adjustments		(3,539)		(2,705)		929
Reclassification adjustment for gain included in net income		-		(4)		(155)
Income taxes on foreign currency translation adjustments		72		23		(16)

Foreign currency translation adjustments, net of tax		(3,467)		(2,686)		758

Hedging activities		-		-		6
Income taxes on hedging activities		-		-		-

Hedging activities, net of tax		-		-		6

Other Comprehensive Income (Loss), Net of Tax		(3,904)		(2,085)		627

Comprehensive Income		3,034		7,130		9,125
Less: comprehensive income attributable to noncontrolling interests		(69)		(59)		(70)

Comprehensive Income Attributable to ConocoPhillips	$	2,965		7,071		9,055

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

See Notes to Consolidated Financial Statements.



Consolidated Balance Sheet		ConocoPhillips

At December 31	Millions of Dollars

	2014		2013

Assets
Cash and cash equivalents	$	5,062		6,246
Short-term investments*		-		272
Accounts and notes receivable (net of allowance of $5 million in 2014 and $8 million in 2013)		6,675		8,273
Accounts and notes receivable—related parties		132		214
Inventories		1,331		1,194
Prepaid expenses and other current assets		1,868		2,824

Total Current Assets		15,068		19,023
Investments and long-term receivables		24,335		23,907
Loans and advances—related parties		804		1,357
Net properties, plants and equipment (net of accumulated depreciation, depletion and amortization of $70,786 million in 2014 and $65,321 million in 2013)		75,444		72,827
Other assets		888		943

Total Assets	$	116,539		118,057


Liabilities
Accounts payable	$	7,982		9,250
Accounts payable—related parties		44		64
Short-term debt		182		589
Accrued income and other taxes		1,051		2,713
Employee benefit obligations		878		842
Other accruals		1,400		1,671

Total Current Liabilities		11,537		15,129
Long-term debt		22,383		21,073
Asset retirement obligations and accrued environmental costs		10,647		9,883
Deferred income taxes		15,070		15,220
Employee benefit obligations		2,964		2,459
Other liabilities and deferred credits		1,665		1,801

Total Liabilities		64,266		65,565


Equity
Common stock (2,500,000,000 shares authorized at $.01 par value)
Issued (2014—1,773,583,368 shares; 2013—1,768,169,906)
Par value		18		18
Capital in excess of par		46,071		45,690
Treasury stock (at cost: 2014—542,230,673; 2013—542,230,673)		(36,780)		(36,780)
Accumulated other comprehensive income (loss)		(1,902)		2,002
Retained earnings		44,504		41,160

Total Common Stockholders’ Equity		51,911		52,090
Noncontrolling interests		362		402

Total Equity		52,273		52,492

Total Liabilities and Equity	$	116,539		118,057

*Includes marketable securities of:	$	-		135

See Notes to Consolidated Financial Statements.



Consolidated Statement of Cash Flows		ConocoPhillips

Years Ended December 31	Millions of Dollars

		2014	2013	2012

Cash Flows From Operating Activities
Net income	$	6,938	9,215	8,498
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization		8,329	7,434	6,580
Impairments		856	529	680
Dry hole costs and leasehold impairments		1,166	443	874
Accretion on discounted liabilities		484	434	394
Deferred taxes		709	1,311	1,397
Undistributed equity earnings		77	(822)	(596)
Gain on dispositions		(98)	(1,242)	(1,657)
Income from discontinued operations		(1,131)	(1,178)	(1,017)
Other		(233)	(371)	(456)
Working capital adjustments
Decrease (increase) in accounts and notes receivable		1,227	744	(1,866)
Decrease (increase) in inventories		(193)	(278)	210
Decrease (increase) in prepaid expenses and other current assets		(190)	(83)	513
Increase (decrease) in accounts payable		(783)	183	1,103
Decrease in taxes and other accruals		(566)	(518)	(1,199)

Net cash provided by continuing operating activities		16,592	15,801	13,458
Net cash provided by discontinued operations		143	286	464

Net Cash Provided by Operating Activities		16,735	16,087	13,922


Cash Flows From Investing Activities
Capital expenditures and investments		(17,085)	(15,537)	(14,172)
Proceeds from asset dispositions		1,603	10,220	2,132
Net sales (purchases) of short-term investments		253	(263)	597
Collection of advances/loans—related parties		603	145	114
Other		(446)	(212)	821

Net cash used in continuing investing activities		(15,072)	(5,647)	(10,508)
Net cash used in discontinued operations		(59)	(604)	(1,119)

Net Cash Used in Investing Activities		(15,131)	(6,251)	(11,627)


Cash Flows From Financing Activities
Issuance of debt		2,994	-	1,996
Repayment of debt		(2,014)	(946)	(2,565)
Special cash distribution from Phillips 66		-	-	7,818
Change in restricted cash		-	748	(748)
Issuance of company common stock		35	20	138
Repurchase of company common stock		-	-	(5,098)
Dividends paid		(3,525)	(3,334)	(3,278)
Other		(64)	(3,621)	(725)

Net cash used in continuing financing activities		(2,574)	(7,133)	(2,462)
Net cash used in discontinued operations		-	-	(2,019)

Net Cash Used in Financing Activities		(2,574)	(7,133)	(4,481)


Effect of Exchange Rate Changes on Cash and Cash Equivalents		(214)	(75)	24


Net Change in Cash and Cash Equivalents		(1,184)	2,628	(2,162)
Cash and cash equivalents at beginning of period		6,246	3,618	5,780

Cash and Cash Equivalents at End of Period	$	5,062	6,246	3,618

See Notes to Consolidated Financial Statements.

Consolidated Statement of Changes in Equity

ConocoPhillips


	Millions of Dollars

	Attributable to ConocoPhillips

	Common Stock

	Par Value		Capital in Excess of Par		Treasury Stock			Accum. Other Comprehensive Income (Loss)			Unearned Employee Compensation			Retained Earnings			Non- Controlling Interests			Total

December 31, 2011	$	17		44,725		(31,787	)		3,246			(11	)		49,049			510			65,749
Net income															8,428			70			8,498
Other comprehensive income									627												627
Dividends paid															(3,278	)					(3,278)
Repurchase of company common stock						(5,098	)														(5,098)
Distributions to noncontrolling interests and other																		(109	)		(109)
Distributed under benefit plans		1		599		105															705
Recognition of unearned compensation												11									11
Separation of downstream business									214						(18,880	)		(31	)		(18,697)
Other															19						19

December 31, 2012	$	18		45,324		(36,780	)		4,087			-			35,338			440			48,427
Net income															9,156			59			9,215
Other comprehensive loss									(2,085	)											(2,085)
Dividends paid															(3,334	)					(3,334)
Distributions to noncontrolling interests and other																		(97	)		(97)
Distributed under benefit plans				366																	366

December 31, 2013	$	18		45,690		(36,780	)		2,002			-			41,160			402			52,492
Net income															6,869			69			6,938
Other comprehensive loss									(3,904	)											(3,904)
Dividends paid															(3,525	)					(3,525)
Distributions to noncontrolling interests and other																		(109	)		(109)
Distributed under benefit plans				381																	381

December 31, 2014	$	18		46,071		(36,780	)		(1,902	)		-			44,504			362			52,273

See Notes to Consolidated Financial Statements.


Notes to Consolidated Financial Statements		ConocoPhillips

Note 1—Accounting Policies

Consolidation Principles and Investments—Our consolidated financial statements include the accounts of majority-owned, controlled subsidiaries and variable interest entities where we are the primary beneficiary. The equity method is used to account for investments in affiliates in which we have the ability to exert significant influence over the affiliates’ operating and financial policies. When we do not have the ability to exert significant influence, the investment is either classified as available-for-sale if fair value is readily determinable, or the cost method is used if fair value is not readily determinable. Undivided interests in oil and gas joint ventures, pipelines, natural gas plants and terminals are consolidated on a proportionate basis. Other securities and investments are generally carried at cost.

As a result of the separation of Phillips 66 on April 30, 2012, the results of operations for our former refining, marketing and transportation businesses; most of our former Midstream segment; our former Chemicals segment; and our power generation and certain technology operations included in our former Emerging Businesses segment (collectively, our “Downstream business”), have been classified as discontinued operations for all periods presented. In addition, the results of operations for our interest in the North Caspian Sea Production Sharing Agreement (Kashagan) and our Algeria and Nigeria businesses have been classified as discontinued operations for all periods presented. See Note 2—Discontinued Operations, for additional information.

We manage our operations through six operating segments, defined by geographic region: Alaska, Lower 48, Canada, Europe, Asia Pacific and Middle East, and Other International. Effective April 1, 2014, the Other International segment was restructured to focus on enhancing our capability to operate in emerging and new country business units. As a result, we moved the Latin America and Poland businesses from the historically presented Lower 48 and Latin America segment and the Europe segment to the Other International segment. Certain financial information has been revised for all prior periods presented to reflect the change in the composition of our operating segments. For additional information, see Note 23—Segment Disclosures and Related Information. Unless indicated otherwise, the information in the Notes to the Consolidated Financial Statements relates to our continuing operations.

Foreign Currency Translation—Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in accumulated other comprehensive income in common stockholders’ equity. Foreign currency transaction gains and losses are included in current earnings. Most of our foreign operations use their local currency as the functional currency.

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of contingent assets and liabilities. Actual results could differ from these estimates.

Revenue Recognition—Revenues associated with sales of crude oil, bitumen, natural gas, liquefied natural gas (LNG), natural gas liquids and other items are recognized when title passes to the customer, which is when the risk of ownership passes to the purchaser and physical delivery of goods occurs, either immediately or within a fixed delivery schedule that is reasonable and customary in the industry.

Revenues associated with producing properties in which we have an interest with other producers are recognized based on the actual volumes we sold during the period. Any differences between volumes sold and entitlement volumes, based on our net working interest, which are deemed to be nonrecoverable through remaining production, are recognized as accounts receivable or accounts payable, as appropriate. Cumulative differences between volumes sold and entitlement volumes are generally not significant.

Revenues associated with transactions commonly called buy/sell contracts, in which the purchase and sale of inventory with the same counterparty are entered into “in contemplation” of one another, are combined and reported net (i.e., on the same income statement line).

Shipping and Handling Costs—We include shipping and handling costs in production and operating expenses for production activities. Transportation costs related to marketing activities are recorded in purchased commodities. Freight costs billed to customers are recorded as a component of revenue.

n	Cash Equivalents—Cash equivalents are highly liquid, short-term investments that are readily convertible to known amounts of cash and have original maturities of 90 days or less from their date of purchase. They are carried at cost plus accrued interest, which approximates fair value.

Short-Term Investments—Investments in bank time deposits and marketable securities (commercial paper and government obligations) with original maturities of greater than 90 days but less than one year are classified as short-term investments. See Note 13—Derivative and Financial Instruments, for additional information on these held-to-maturity financial instruments.

Inventories—We have several valuation methods for our various types of inventories and consistently use the following methods for each type of inventory. Commodity-related inventories are valued at the lower of cost or market in the aggregate, primarily on the last-in, first-out (LIFO) basis. Any necessary lower-of-cost-or-market write-downs at year end are recorded as permanent adjustments to the LIFO cost basis. LIFO is used to better match current inventory costs with current revenues. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location, but not unusual/nonrecurring costs or research and development costs. Materials, supplies and other miscellaneous inventories, such as tubular goods and well equipment, are valued using various methods, including the weighted-average-cost method, and the first-in, first-out (FIFO) method, consistent with industry practice.

Fair Value Measurements—We categorize assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are observable inputs other than quoted prices included within Level 1 for the asset or liability, either directly or indirectly through market-corroborated inputs. Level 3 inputs are unobservable inputs for the asset or liability reflecting significant modifications to observable related market data or our assumptions about pricing by market participants.

Derivative Instruments—Derivative instruments are recorded on the balance sheet at fair value. If the right of offset exists and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the balance sheet and the collateral payable or receivable is netted against derivative assets and derivative liabilities, respectively.

Recognition and classification of the gain or loss that results from recording and adjusting a derivative to fair value depends on the purpose for issuing or holding the derivative. Gains and losses from derivatives not accounted for as hedges are recognized immediately in earnings. For derivative instruments that are designated and qualify as a fair value hedge, the gains or losses from adjusting the derivative to its fair value will be immediately recognized in earnings and, to the extent the hedge is effective, offset the concurrent recognition of changes in the fair value of the hedged item. Gains or losses from derivative instruments that are designated and qualify as a cash flow hedge or hedge of a net investment in a foreign entity are recognized in other comprehensive income and appear on the balance sheet in accumulated other comprehensive income until the hedged transaction is recognized in earnings; however, to the extent the change in the value of the derivative exceeds the change in the anticipated cash flows of the hedged transaction, the excess gains or losses will be recognized immediately in earnings.

n	Oil and Gas Exploration and Development—Oil and gas exploration and development costs are accounted for using the successful efforts method of accounting.

Property Acquisition Costs—Oil and gas leasehold acquisition costs are capitalized and included in the balance sheet caption properties, plants and equipment (PP&E). Leasehold impairment is recognized based on exploratory experience and management’s judgment. Upon achievement of all conditions necessary for reserves to be classified as proved, the associated leasehold costs are reclassified to proved properties.

Exploratory Costs—Geological and geophysical costs and the costs of carrying and retaining undeveloped properties are expensed as incurred. Exploratory well costs are capitalized, or “suspended,” on the balance sheet pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. 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. 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 all required approvals and permits have been obtained, the projects are moved into the development phase, and the oil and gas resources are designated as proved reserves.

Development Costs—Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized.

Depletion and Amortization—Leasehold costs of producing properties are depleted using the unit-of-production method based on estimated proved oil and gas reserves. Amortization of intangible development costs is based on the unit-of-production method using estimated proved developed oil and gas reserves.

Capitalized Interest—Interest from external borrowings is capitalized on major projects with an expected construction period of one year or longer. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manner as the underlying assets.

Depreciation and Amortization—Depreciation and amortization of PP&E on producing hydrocarbon properties and certain pipeline assets (those which are expected to have a declining utilization pattern), are determined by the unit-of-production method. Depreciation and amortization of all other PP&E are determined by either the individual-unit-straight-line method or the group-straight-line method (for those individual units that are highly integrated with other units).

Impairment of Properties, Plants and Equipment—PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate a possible significant deterioration in the 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 pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down to estimated fair value through additional amortization or depreciation provisions and reported as impairments in the periods in which the determination of the

impairment is made. Individual assets are grouped for impairment purposes at 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. Long-lived assets committed by management for disposal within one year are accounted for at the lower of amortized cost or fair value, less cost to sell, with fair value determined using a binding negotiated price, if available, or present value of expected future cash flows as previously described.

The expected future cash flows used for impairment reviews and related fair value calculations are based on estimated future production volumes, prices and costs, considering all available evidence at the date of review. The impairment review includes cash flows from proved developed and undeveloped reserves, including any development expenditures necessary to achieve that production. Additionally, when probable and possible reserves exist, an appropriate risk-adjusted amount of these reserves may be included in the impairment calculation.

Impairment of Investments in Nonconsolidated Entities—Investments in nonconsolidated entities are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred and annually following updates to corporate planning assumptions. When such a condition is judgmentally determined to be other than temporary, the carrying value of the investment is written down to fair value. The fair value of the impaired investment is based on quoted market prices, if available, or upon 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.

n	Maintenance and Repairs—Costs of maintenance and repairs, which are not significant improvements, are expensed when incurred.

Property Dispositions—When complete units of depreciable property are sold, the asset cost and related accumulated depreciation are eliminated, with any gain or loss reflected in the “Gain on dispositions” line of our consolidated income statement. When less than complete units of depreciable property are disposed of or retired, the difference between asset cost and salvage value is charged or credited to accumulated depreciation.

Asset Retirement Obligations and Environmental Costs—The fair value of legal obligations to retire and remove long-lived assets are recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, we capitalize this cost by increasing the carrying amount of the related PP&E. If, in subsequent periods, our estimate of this liability changes, we will record an adjustment to both the liability and PP&E. Over time the liability is increased for the change in its present value, and the capitalized cost in PP&E is depreciated over the useful life of the related asset. For additional information, see Note 9—Asset Retirement Obligations and Accrued Environmental Costs.

Environmental expenditures are expensed or capitalized, depending upon their future economic benefit. Expenditures relating to an existing condition caused by past operations, and those having no future economic benefit, are expensed. Liabilities for environmental expenditures are recorded on an undiscounted basis (unless acquired in a purchase business combination) when environmental assessments or cleanups are probable and the costs can be reasonably estimated. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is probable and estimable.

Guarantees—The fair value of a guarantee is determined and recorded as a liability at the time the guarantee is given. The initial liability is subsequently reduced as we are released from exposure under the guarantee. We amortize the guarantee liability over the relevant time period, if one exists, based on the facts and circumstances surrounding each type of guarantee. In cases where the guarantee term is indefinite, we reverse the liability when we have information indicating the liability is essentially relieved or amortize it over an appropriate time period as the fair value of our guarantee exposure declines over time. We amortize the guarantee liability to the related income statement line item based on the nature of the guarantee. When it becomes probable that we will have to perform on a guarantee, we accrue a separate liability if it is reasonably estimable, based on the facts and circumstances at that time. We reverse the fair value liability only when there is no further exposure under the guarantee.

Share-Based Compensation—We recognize share-based compensation expense over the shorter of the service period (i.e., the stated period of time required to earn the award) or the period beginning at the start of the service period and ending when an employee first becomes eligible for retirement. We have elected to recognize expense on a straight-line basis over the service period for the entire award, whether the award was granted with ratable or cliff vesting.

Income Taxes—Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial reporting basis and the tax basis of our assets and liabilities, except for deferred taxes on income and temporary differences related to the cumulative translation adjustment considered to be permanently reinvested in certain foreign subsidiaries and foreign corporate joint ventures. Allowable tax credits are applied currently as reductions of the provision for income taxes. Interest related to unrecognized tax benefits is reflected in interest and debt expense, and penalties related to unrecognized tax benefits are reflected in production and operating expenses.

n	Taxes Collected from Customers and Remitted to Governmental Authorities—Sales and value-added taxes are recorded net.

Net Income Per Share of Common Stock—Basic net income per share of common stock is calculated based upon the daily weighted-average number of common shares outstanding during the year, including unallocated shares held by the stock savings feature of the ConocoPhillips Savings Plan. Also, this calculation includes fully vested stock and unit awards that have not yet been issued as common stock, along with an adjustment to net income for dividend equivalents paid on unvested unit awards that are considered participating securities. Diluted net income per share of common stock includes unvested stock, unit or option awards granted under our compensation plans and vested but unexercised stock options, but only to the extent these instruments dilute net income per share, primarily under the treasury-stock method. Treasury stock and shares held by grantor trusts are excluded from the daily weighted-average number of common shares outstanding in both calculations. The earnings per share impact of the participating securities is immaterial.

Note 2—Discontinued Operations

Separation of Downstream Business

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, Phillips 66 distributed approximately $7.8 billion to us in a special cash distribution. The principal funds from the special cash distribution were designated solely to pay dividends, repurchase common stock, repay debt, or a combination of the foregoing, within twelve months following the distribution. At December 31, 2014 and 2013, no balance remained from the cash distribution. We also entered into several agreements with Phillips 66 in order to effect the separation and govern our relationship with Phillips 66.

Sales and other operating revenues and income from discontinued operations related to Phillips 66 during 2012 were as follows:


	Millions of Dollars

Sales and other operating revenues from discontinued operations	$	62,109


Income from discontinued operations before-tax	$	1,768
Income tax expense		534

Income from discontinued operations	$	1,234

Income from discontinued operations after-tax includes transaction, information systems and other costs incurred to effect the separation of $70 million for the year ended December 31, 2012. No separation costs were incurred in 2014 and 2013.

Prior to the separation, commodity sales to Phillips 66 were $4,973 million for the year ended December 31, 2012. Commodity purchases from Phillips 66 prior to the separation were $166 million for the year ended December 31, 2012. Prior to May 1, 2012, commodity sales and related costs were eliminated in consolidation between ConocoPhillips and Phillips 66. Beginning May 1, 2012, these revenues and costs represent third-party transactions with Phillips 66.

Other Discontinued Operations

As part of our asset disposition program, we agreed to sell our interest in Kashagan and our Algeria and Nigeria businesses (collectively, the “Disposition Group”). The Disposition Group was previously part of the Other International operating segment. We completed the sales of Kashagan and our Algeria business in the fourth quarter of 2013. We sold our Nigeria business in the third quarter of 2014, which completed the asset disposition program.

On November 26, 2012, we notified government authorities in Kazakhstan and co-venturers of our intent to sell the Company’s 8.4 percent interest in Kashagan to ONGC Videsh Limited (OVL). On July 2, 2013, we received notification from the government of Kazakhstan indicating it was exercising its right to pre-empt the proposed sale to OVL and designating KazMunayGas (KMG) as the entity to acquire the interest. On October 31, 2013, we completed the transaction with KMG for total proceeds of $5,392 million and recognized a pre-tax gain of $22 million, which is included in the “Income from discontinued operations” line on the consolidated income statement. We recorded pre-tax impairments of $43 million and $606 million in the first quarter of 2013 and the fourth quarter of 2012, respectively. At the time of disposition, the carrying value of the net assets related to our interest in Kashagan was $5,370 million, which included $212 million of other current assets, $239 million of long-term receivables, $5,149 million of PP&E, $144 million of other current liabilities, and $86 million of asset retirement obligations (ARO).

On December 18, 2012, we entered into an agreement with Pertamina to sell our wholly owned subsidiary, ConocoPhillips Algeria Ltd. On November 27, 2013, we completed the transaction with Pertamina, resulting in proceeds of $1,652 million, which included a $175 million deposit received in December 2012. We recognized a pre-tax gain of $938 million, which is included in the “Income from discontinued operations” line on the consolidated income statement. At the time of disposition, the net carrying value of our Algerian assets was $714 million, which included $48 million of other current assets, $883 million of PP&E, $41 million of other current liabilities, $37 million of ARO, and $139 million of deferred taxes.

On December 20, 2012, we entered into agreements with affiliates of Oando PLC to sell our Nigeria business. The transaction originally included our upstream affiliates and Phillips (Brass) Limited, which owned a 17 percent interest in the Brass LNG Project. On July 30, 2014, we completed the sale of the upstream affiliates for $1,359 million, inclusive of $550 million deposits previously received. The deposits had been included in the “Other accruals” line on our consolidated balance sheet and in the “Other” line of cash flows

from investing activities on our consolidated statement of cash flows. The deposits received included $435 million in 2012, $15 million in 2013, and $100 million in 2014. At closing we also received a $33 million short-term promissory note. We recognized a before-tax gain of $1,052 million, which is included in the “Income from discontinued operations” line on the consolidated income statement. At the time of disposition, the net carrying value of the upstream assets was $307 million, which included $233 million of other current assets, $1,211 million of PP&E, $298 million of other current liabilities, $14 million of ARO, and $825 million of deferred taxes.

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

At December 31, 2013, we classified $7 million of loans and advances to related parties in the “Accounts and notes receivable—related parties” line and $1,215 million of noncurrent assets in the “Prepaid expenses and other current assets” line of our consolidated balance sheet. In addition, we classified $765 million of noncurrent deferred income taxes in the “Accrued income and other taxes” line and $14 million of ARO in the “Other accruals” line of our consolidated balance sheet. The carrying amounts of the major classes of assets and liabilities associated with the Disposition Group as of December 31, 2013, were as follows:


	Millions of Dollars
Assets
Accounts and notes receivable	$	376
Inventories		9
Prepaid expenses and other current assets		72

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

Total assets of discontinued operations	$	1,679


Liabilities
Accounts payable	$	419
Accrued income and other taxes		72

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

Total liabilities of discontinued operations	$	1,270

Sales and other operating revenues and income (loss) from discontinued operations related to the Disposition Group during 2014, 2013 and 2012 were as follows:


	Millions of Dollars
	2014		2013		2012

Sales and other operating revenues from discontinued operations	$	480		1,185		1,369


Income (loss) from discontinued operations before-tax	$	1,147		1,461		(6)
Income tax expense		16		283		211

Income (loss) from discontinued operations	$	1,131		1,178		(217)

Note 3—Variable Interest Entities (VIEs)

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

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

Through November 2014 we had an agreement with Freeport LNG to participate in a liquefied natural gas (LNG) receiving terminal in Quintana, Texas. We have no ownership in Freeport LNG; however, we own a 50 percent interest in Freeport LNG GP, Inc. (Freeport GP), which serves as the general partner managing the venture. We entered into a credit agreement with Freeport LNG, whereby we agreed to provide loan financing for the construction of the terminal. We also entered into a long-term agreement with Freeport LNG to use 0.9 billion cubic feet per day of regasification capacity, which expires in 2033. When the terminal became operational in June 2008, we began making payments under the terminal use agreement. Freeport LNG began making loan repayments in September 2008.

In July 2013 we reached an agreement with Freeport LNG to terminate our long-term agreement at the Freeport LNG Terminal, subject to Freeport LNG obtaining regulatory approval and project financing for an LNG liquefaction and export facility in Texas, in which we are not a participant. These conditions were satisfied in the fourth quarter of 2014 and we paid Freeport LNG a termination fee of $522 million. Freeport LNG repaid the outstanding $454 million ConocoPhillips loan used by Freeport LNG to partially fund the original construction of the terminal. The payment made to Freeport LNG to terminate our long-term agreement is included in cash flows from operating activities on our consolidated statement of cash flows, while the receipt of the funds from Freeport LNG to repay the outstanding loan is included in cash flows from investing activities. These transactions, plus miscellaneous items, including the disposal of our 50 percent interest in Freeport GP, resulted in a one-time net cash outflow of $63 million for us. In addition, we recognized an after-tax charge to earnings of $540 million in the fourth quarter of 2014, and our terminal regasification capacity has been reduced from 0.9 billion cubic feet per day to 0.4 billion cubic feet per day, until July 1, 2016, at which time it will be reduced to zero.

Freeport LNG is a VIE because the limited partners of Freeport LNG do not have any substantive decision making ability. Since we do not have the unilateral power to direct the key activities which most significantly impact its economic performance, we are not the primary beneficiary of Freeport LNG. These key activities primarily involve or relate to operating and maintaining the terminal.

Australia Pacific LNG Pty Ltd (APLNG)

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

As of December 31, 2014, we have not provided any financial support to APLNG other than amounts previously contractually required. Unless we elect otherwise, we have no requirement to provide liquidity or purchase the assets of APLNG. See Note 6—Investments, Loans and Long-Term Receivables, and Note 11—Guarantees, for additional information.

Note 4—Inventories

Inventories at December 31 were:


	Millions of Dollars
	2014		2013


Crude oil and natural gas	$	538		452
Materials, supplies and other		793		742

	$	1,331		1,194

Inventories valued on the LIFO basis totaled $440 million and $343 million at December 31, 2014 and 2013, respectively. The estimated excess of current replacement cost over LIFO cost of inventories was approximately $6 million at December 31, 2014, and $160 million at December 31, 2013. In 2014 liquidation of LIFO inventory values decreased net income from continuing operations by $2 million.

Note 5—Assets Held for Sale or Sold

Assets Sold

All gains or losses are reported before-tax and are included net in the “Gain on dispositions” line on the consolidated income statement.

2014

For information on the sale of our Nigeria business, which is included in the “Income from discontinued operations” line on the consolidated income statement, see Note 2—Discontinued Operations.

2013

In March 2013 we sold the majority of our producing zones in the Cedar Creek Anticline for $994 million and recognized a loss on disposition of $43 million. At the time of the disposition, the carrying value of our interest, which was included in the Lower 48 segment, was $1,037 million, which included primarily $1,066 million of PP&E and $28 million of ARO.

In June 2013 we sold a portion of our working interests in the Browse and Canning basins for $402 million. Because we retain a working interest in the unproved properties, proceeds were treated as a reduction of the carrying value of PP&E with no gain or loss on disposition recognized. Prior to the partial disposition, the carrying value of the PP&E associated with our interests, included in our Asia Pacific and Middle East segment, was $486 million.

In August 2013 we sold our interest in the Clyden undeveloped oil sands leasehold for $724 million and recognized a gain on disposition of $614 million. At the time of the disposition, the carrying value of our interest in Clyden, which was included in the Canada segment, was $110 million and was primarily classified as PP&E.

In August 2013 we also sold our 39 percent interest in Phoenix Park Gas Processors Limited for $593 million and recognized a gain on disposition of $417 million. At the time of the disposition, the carrying value of our equity investment in Phoenix Park, which was included in our Other International segment, was $176 million.

For information on the Kashagan and Algeria sales, which are included in the “Income from discontinued operations” line on the consolidated income statement, see Note 2—Discontinued Operations.

2012

In March 2012 we sold our Vietnam business for $1,095 million and recognized a gain on disposition of $931 million. At the time of the disposition, the net carrying value of the business, which was included in the Asia Pacific and Middle East segment, was approximately $164 million, which included $352 million of PP&E, $69 million of ARO and $145 million of deferred income taxes.

In April 2012 we sold our interest in the Statfjord Field and associated satellites, all of which are located in the North Sea, for $228 million and recognized a gain of $429 million. At the time of disposition, the carrying value of our interest, which was included in the Europe segment, was negative $201 million, which included $205 million of PP&E and $445 million of ARO.

In May 2012 we sold our interest in the North Sea Alba Field for $220 million, and recognized a gain of $155 million. At the time of disposition, the carrying value of our interest, which was included in the Europe segment, was $65 million, which included $160 million of PP&E and $86 million of ARO.

In August 2012 we sold our 30 percent interest in Naryanmarneftegaz (NMNG) and certain related assets for $450 million, and recognized a gain of $206 million. At the time of the disposition, the carrying value of our equity investment in NMNG, which was included in the Other International segment, was $244 million.

Note 6—Investments, Loans and Long-Term Receivables

Components of investments, loans and long-term receivables at December 31 were:


	Millions of Dollars
	2014		2013


Equity investments	$	23,426		22,980
Loans and advances—related parties		804		1,357
Long-term receivables		444		470
Other investments		465		457

	$	25,139		25,264

Equity Investments

Affiliated companies in which we had a significant equity investment at December 31, 2014, included:

•

APLNG—37.5 percent owned joint venture with Origin Energy (37.5 percent) and Sinopec (25 percent)—to develop coalbed methane production from the Bowen and Surat basins in Queensland, Australia, as well as process and export LNG.

•

FCCL Partnership—50 percent owned business venture with Cenovus Energy Inc.—produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend.

•

Qatar Liquefied Gas Company Limited (3) (QG3)—30 percent owned joint venture with affiliates of Qatar Petroleum (68.5 percent) and Mitsui & Co., Ltd. (1.5 percent)—produces and liquefies natural gas from Qatar’s North Field, as well as exports LNG.

Summarized 100 percent earnings information for equity method investments in affiliated companies, combined, was as follows (information includes equity investments disposed of in connection with the separation of the Downstream business until the date of the separation):


	Millions of Dollars
	2014		2013		2012


Revenues	$	19,243		18,035		17,903
Income before income taxes		6,746		6,384		5,986
Net income		6,630		6,125		5,767

Summarized 100 percent balance sheet information for equity method investments in affiliated companies, combined, was as follows:


	Millions of Dollars
	2014		2013


Current assets	$	4,512		9,073
Noncurrent assets		58,570		51,674
Current liabilities		3,346		3,416
Noncurrent liabilities		20,210		13,850

Our share of income taxes incurred directly by an equity company is reported in equity in earnings of affiliates, and as such is not included in income taxes in our consolidated financial statements.

At December 31, 2014, retained earnings included $1,377 million related to the undistributed earnings of affiliated companies. Dividends received from affiliates were $2,648 million, $1,425 million and $1,351 million in 2014, 2013 and 2012, respectively.

APLNG

APLNG is focused on coalbed methane production from the Bowen and Surat basins in Queensland, Australia, and LNG processing and export sales. Our investment in APLNG gives us access to coalbed methane resources in Australia and enhances our LNG position with the expected creation of an additional LNG hub targeting the Asia Pacific markets. Origin Energy, an integrated Australian energy company, is the operator of APLNG’s production and pipeline system, while we will operate the LNG facility.

In 2011 Sinopec subscribed for a 15 percent equity interest in APLNG, which diluted both our ownership interest and Origin’s ownership interest to 42.5 percent. In July 2012 Sinopec subscribed to additional shares in APLNG, which increased its equity interest from 15 percent to 25 percent. As a result, on July 12, 2012, both our ownership interest and Origin’s ownership interest diluted from 42.5 percent to 37.5 percent. We recorded a before- and after-tax loss of $133 million from the dilution in the third quarter of 2012. The book value of our investment in APLNG was reduced by $453 million, and we reduced the foreign currency translation adjustment associated with our investment by $320 million.

In addition, APLNG executed project financing agreements for an $8.5 billion project finance facility during the third quarter of 2012. The $8.5 billion project finance facility is composed of financing agreements executed by APLNG with the Export-Import Bank of the United States for approximately $2.9 billion, the Export-Import Bank of China for approximately $2.7 billion, and a syndicate of Australian and international commercial banks for approximately $2.9 billion. At December 31, 2014, $8.1 billion had been drawn from the facility. In connection with the execution of the project financing, we provided a completion guarantee for our pro-rata share of the project finance facility which will be released upon meeting certain completion milestones. See Note 11—Guarantees, for additional information.

APLNG is considered a VIE, as it has entered into certain contractual arrangements that provide it with additional forms of subordinated financial support. See Note 3—Variable Interest Entities (VIEs) for additional information.

At December 31, 2014, the book value of our equity method investment in APLNG was $12,159 million, which includes $121 million of cumulative translation effects due to a strengthening Australian dollar relative to the U.S. dollar over time. The historical cost basis of our 37.5 percent share of net assets on the books of APLNG under U.S. generally accepted accounting principles was $7,101 million, resulting in a basis difference of $5,058 million on our books. The amortizable portion of the basis difference, $3,662 million associated with PP&E, has been allocated on a relative fair value basis to individual exploration and production license areas owned by APLNG, most of which are not currently in production. Any future additional payments are expected to be allocated in a similar manner. Each exploration license area will periodically be reviewed for any indicators of potential impairment, which, if required, would result in

acceleration of basis difference amortization. As the joint venture produces natural gas from each license, we amortize the basis difference allocated to that license using the unit-of-production method. Included in net income attributable to ConocoPhillips for 2014, 2013 and 2012 was after-tax expense of $24 million, $16 million and $19 million, respectively, representing the amortization of this basis difference on currently producing licenses.

FCCL

FCCL Partnership, a Canadian upstream 50/50 general partnership with Cenovus Energy Inc., produces bitumen in the Athabasca oil sands in northeastern Alberta and sells the bitumen blend. We account for our investment in FCCL under the equity method of accounting, with the operating results of our investment in FCCL converted to reflect the use of the successful efforts method of accounting for oil and gas exploration and development activities.

At December 31, 2014, the book value of our investment in FCCL was $9,484 million. FCCL’s operating assets consist of the Foster Creek and Christina Lake steam-assisted gravity drainage bitumen projects, both located in the eastern flank of the Athabasca oil sands in northeastern Alberta. Cenovus is the operator and managing partner of FCCL.

We were obligated to contribute $7.5 billion, plus accrued interest, to FCCL over a 10-year period that began in 2007. In December 2013 we repaid 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. 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 the first quarter of 2014, we received a $1.3 billion distribution from FCCL, which is included in the “Undistributed equity earnings” line on our consolidated statement of cash flows.

QG3

QG3 is a joint venture that owns an integrated large-scale LNG project located in Qatar. We provided project financing, with a current outstanding balance of $909 million as described below under “Loans and Long-Term Receivables.” At December 31, 2014, the book value of our equity method investment in QG3, excluding the project financing, was $966 million. We have terminal and pipeline use agreements with Golden Pass LNG Terminal and affiliated Golden Pass Pipeline near Sabine Pass, Texas, in which we have a 12.4 percent interest, intended to provide us with terminal and pipeline capacity for the receipt, storage and regasification of LNG purchased from QG3. However, currently the LNG from QG3 is being sold to markets outside of the United States.

Loans and Long-Term Receivables

As part of our normal ongoing business operations and consistent with industry practice, we enter into numerous agreements with other parties to pursue business opportunities. Included in such activity are loans and long-term receivables to certain affiliated and non-affiliated companies. Loans are recorded when cash is transferred or seller financing is provided to the affiliated or non-affiliated company pursuant to a loan agreement. The loan balance will increase as interest is earned on the outstanding loan balance and will decrease as interest and principal payments are received. Interest is earned at the loan agreement’s stated interest rate. Loans and long-term receivables are assessed for impairment when events indicate the loan balance may not be fully recovered.

At December 31, 2014, significant loans to affiliated companies include $909 million in project financing to QG3. We own a 30 percent interest in QG3, for which we use the equity method of accounting. The other participants in the project are affiliates of Qatar Petroleum and Mitsui. QG3 secured project financing of $4.0 billion in December 2005, consisting of $1.3 billion of loans from export credit agencies (ECA), $1.5 billion from