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Cover and table of contents
10-K 1 d636257d10k.htm 10-K
Table of Contents
2018
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, 2018
OR
| [ ] | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-32395
ConocoPhillips
(Exact name of registrant as specified in its charter)
| Delaware | 01-0562944 | |
| (State or other jurisdiction of | (I.R.S. Employer | |
| incorporation or organization) | Identification No.) |
925 N. Eldridge Parkway
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 | |||
| 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 every Interactive Data File required to be submitted 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 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. [x]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer [x] Accelerated filer [ ] Non-accelerated filer [ ] Smaller reporting company [ ]
Emerging growth company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). [ ] Yes [x] No
The aggregate market value of common stock held by non-affiliates of the registrant on June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of $69.62, was $80.9 billion.
The registrant had 1,134,404,094 shares of common stock outstanding at January 31, 2019.
Documents incorporated by reference:
Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 14, 2019 (Part III)
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TABLE OF CONTENTS
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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 headings “Risk Factors” beginning on page 20 and “CAUTIONARY STATEMENT FOR THE PURPOSES OF THE ‘SAFE HARBOR’ PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995,” beginning on page 76.
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. Headquartered in Houston, Texas, we have operations and activities in 16 countries. Our diverse, low cost of supply portfolio includes resource-rich unconventional plays in North America; lower-risk conventional assets in North America, Europe, Asia and Australia; liquefied natural gas (LNG) developments; oil sands assets in Canada; and an inventory of global conventional and unconventional exploration prospects. At December 31, 2018, we employed approximately 10,800 people worldwide and had total assets of $70 billion.
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, ConocoPhillips completed the separation of the downstream business into an independent, publicly traded energy company, Phillips 66.
SEGMENT AND GEOGRAPHIC INFORMATION
For operating segment and geographic information, see Note 25—Segment Disclosures and Related Information, in the Notes to Consolidated Financial Statements, which is incorporated herein by reference.
We explore for, produce, transport and market crude oil, bitumen, natural gas, LNG and natural gas liquids on a worldwide basis. At December 31, 2018, our operations were producing in the United States, Norway, the United Kingdom, Canada, Australia, Timor-Leste, Indonesia, Malaysia, Libya, China and Qatar.
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. |
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| • | Net production of crude oil, natural gas liquids, natural gas and bitumen. |
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| • | Average sales prices of crude oil, natural gas liquids, natural gas and bitumen. |
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| • | Average production costs per barrel of oil equivalent (BOE). |
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| • | Net wells completed, wells in progress and productive wells. |
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| • | Developed and undeveloped acreage. |
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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 80 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 (MCF) 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 | 2018 | 2017 | 2016 | |||||||||
| Crude oil | ||||||||||||
| Consolidated operations | 2,533 | 2,322 | 2,047 | |||||||||
| Equity affiliates | 78 | 83 | 88 | |||||||||
| Total Crude Oil | 2,611 | 2,405 | 2,135 | |||||||||
| Natural gas liquids | ||||||||||||
| Consolidated operations | 349 | 354 | 457 | |||||||||
| Equity affiliates | 42 | 45 | 47 | |||||||||
| Total Natural Gas Liquids | 391 | 399 | 504 | |||||||||
| Natural gas | ||||||||||||
| Consolidated operations | 1,265 | 1,267 | 1,807 | |||||||||
| Equity affiliates | 760 | 717 | 730 | |||||||||
| Total Natural Gas | 2,025 | 1,984 | 2,537 | |||||||||
| Bitumen | ||||||||||||
| Consolidated operations | 236 | 250 | 159 | |||||||||
| Equity affiliates | - | - | 1,089 | |||||||||
| Total Bitumen | 236 | 250 | 1,248 | |||||||||
| Total consolidated operations | 4,383 | 4,193 | 4,470 | |||||||||
| Total equity affiliates | 880 | 845 | 1,954 | |||||||||
| Total company | 5,263 | 5,038 | 6,424 | |||||||||
Total production, including Libya, of 1,283 thousand barrels of oil equivalent per day (MBOED) decreased 7 percent in 2018 compared with 2017. The decrease in total average production primarily resulted from noncore asset dispositions, including the dispositions of our 50 percent nonoperated interest in the Foster Creek Christina Lake (FCCL) Partnership, as well as the majority of our western Canada gas assets, and our interest in the San Juan Basin in the Lower 48 in 2017; normal field decline; and higher unplanned downtime, including a third-party pipeline outage in Malaysia in 2018. The decrease in production was partly offset by growth from the Big 3 Unconventionals—Eagle Ford, Bakken and Delaware, development programs primarily in Europe and Alaska, and rampup of major projects in Asia Pacific.
Production excluding Libya was 1,242 MBOED in 2018 compared with 1,356 MBOED in 2017. The volume from closed dispositions was approximately 200 MBOED in 2017 and 15 MBOED in 2018. The volume from acquisitions was less than 10 MBOED in 2018. Our underlying production, which excludes the full-year impact of acquisitions, dispositions, and Libya, increased over 5 percent in 2018 compared with 2017.
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Our worldwide annual average realized price was $53.88 per BOE in 2018, an increase of 37 percent compared with $39.19 per BOE in 2017, reflecting stronger marker prices as well as a shift in our portfolio toward a higher mix of crude oil and less of bitumen and natural gas. Our worldwide annual average crude oil price increased 31 percent in 2018, from $51.96 per barrel in 2017 to $68.13 per barrel in 2018. Additionally, our worldwide annual average natural gas liquids prices increased 21 percent, from $25.22 per barrel in 2017 to $30.48 per barrel in 2018. Our worldwide annual average natural gas price increased 39 percent, from $4.07 per MCF in 2017 to $5.65 per MCF in 2018. Average annual bitumen prices decreased 2 percent, from $22.66 per barrel in 2017 to $22.29 per barrel in 2018.
ALASKA
The Alaska segment primarily explores for, produces, transports and markets crude oil, natural gas and natural gas liquids. We are the largest crude oil 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 100 percent interest in the Alpine Field, located on the Western North Slope. Additionally, we are one of Alaska’s largest owners of state, federal and fee exploration leases, with approximately 1.25 million net undeveloped acres at year-end 2018. Alaska operations contributed 23 percent of our worldwide liquids production and less than 1 percent of our natural gas production.
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | * | Natural Gas MMCFD | ** | Total MBOED | ||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Greater Prudhoe Area | 36.1 | % | BP | 85 | 5 | 86 | ||||||||||||||
| Greater Kuparuk Area*** | 91.4-94.7 | ConocoPhillips | 56 | 1 | 56 | |||||||||||||||
| Western North Slope*** | 100.0 | ConocoPhillips | 44 | - | 44 | |||||||||||||||
| Total Alaska | 185 | 6 | 186 | |||||||||||||||||
* Thousands of barrels per day.
**Millions of cubic feet per day.
*** Interest at December 31, 2018. See “Acquisitions” below for additional information.
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 to recover natural gas liquids before reinjection into the reservoir. Prudhoe Bay’s satellites are Aurora, Borealis, Polaris, Midnight Sun and Orion, while the Point McIntyre, Niakuk, Raven, Lisburne and North Prudhoe Bay State 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.
We completed a transaction in the fourth quarter of 2018 which increased our interest in the Greater Kuparuk Area by 39.2 percent. Further discussion of the transaction is included in the “Acquisitions” section below.
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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. In 2015, first oil was achieved at Alpine West CD5, a drill site which extends the Alpine reservoir west into the National Petroleum Reserve-Alaska (NPR-A). In 2018, we continued drilling additional wells using the available well slots on this pad.
The Greater Mooses Tooth Unit, the first unit established entirely within the NPR-A, was formed in 2008. In 2017, we began construction in the unit, which is currently planned to have two drill sites; Greater Mooses Tooth #1 (GMT-1) and Greater Mooses Tooth #2 (GMT-2). GMT-1 achieved first oil in the fourth quarter of 2018 and we expect first oil from GMT-2 in 2021.
We completed a transaction in the second quarter of 2018 to increase our interest in the Western North Slope from 78 percent to 100 percent. Further discussion of the transaction is included in the “Acquisitions” section below.
Alaska North Slope Gas
In 2016, we, along with affiliates of Exxon Mobil Corporation, BP p.l.c. and Alaska Gasline Development Corporation (AGDC), a state-owned corporation, completed preliminary front-end engineering and design (pre-FEED) technical work for a potential LNG project which would liquefy and export natural gas from Alaska’s North Slope and deliver it to market. In 2016, we, along with the affiliates of ExxonMobil and BP, indicated our intention not to progress into the next phase of the project due to changes in the economic environment. AGDC decided to continue progressing the project on its own and signed several Memorandums of Understanding with various potential LNG buyers in Asia. AGDC has also signed a Joint Development Agreement with Sinopec, CIC Capital and Bank of China, which was recently extended to June 30, 2019. In early January 2019, recently elected Governor Dunleavy appointed new members to AGDC’s board of directors who replaced AGDC’s president with an interim president. The Dunleavy administration has indicated they are interested in participation in the project by ConocoPhillips, ExxonMobil and BP. We remain willing to make our equity gas available for sale to the project at mutually agreed, commercially reasonable terms.
Exploration
Appraisal of the Willow Discovery, located in the northeast portion of the National Petroleum Reserve-Alaska, continued throughout 2018 with three appraisal wells. Additionally, the West Willow-1 exploration well, drilled in 2018, resulted in an oil discovery. In 2019, we will continue appraisal of the Willow and West Willow discoveries.
The Putu 2/2A and Stony Hill 1 wells were drilled in 2018 on state and federal leases, resulting in oil discoveries. In late 2018, we commenced appraisal of the Putu Discovery with a long reach well from existing Alpine CD4 infrastructure.
The Cairn 2S-315 Well was drilled in late 2018 from the 2S drill site on state leases in the Kuparuk River Unit. A flow test will commence in the first quarter of 2019.
A 3-D seismic survey was completed in 2018 over a 250-mile area on state lands. We are currently processing this data.
We were successful in the federal lease sale on the North Slope in the fourth quarter of 2018, where we were the high bidder on five tracts for a total of approximately 48,000 net acres.
Acquisitions
During the second quarter of 2018, we obtained regulatory approvals and completed a transaction we entered into with Anadarko Petroleum Corporation to acquire its 22 percent nonoperated interest in the Western North Slope of Alaska, as well as its interest in the Alpine Transportation Pipeline. In 2018, our Alaska segment net production included 7 MBOED associated with the additional interest acquired.
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During the fourth quarter of 2018, we completed a transaction with BP to acquire their 39.2 percent nonoperated interest in the Greater Kuparuk Area, including their 38 percent interest in the Kuparuk Transportation Company in Alaska (Kuparuk Assets), and to sell a ConocoPhillips subsidiary to BP, which held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom. In 2018, our Alaska segment net production included 1 MBOED associated with the additional interest acquired in the Greater Kuparuk Area.
See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to Consolidated Financial Statements, for additional information.
Transportation
We transport the petroleum liquids produced on the North Slope to south central Alaska through an 800-mile pipeline that is part of Trans-Alaska Pipeline System (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 deliver oil from Valdez, Alaska, primarily to refineries on the west coast of the United States.
LOWER 48
The Lower 48 segment consists of operations located in the contiguous United States and the Gulf of Mexico. The Lower 48 business is organized within two regions covering the Gulf Coast and Great Plains. As a result of tight oil opportunities, we have directed our investments toward certain shorter cycle time, low cost of supply plays. We disposed of several noncore assets within the Lower 48 in 2018, including our interests in the Barnett and certain conventional assets in the Permian Basin. In 2017, we disposed of our interest in the San Juan Basin. We hold 10.3 million net onshore and offshore acres in the Lower 48. In 2018, the Lower 48 contributed 36 percent of our worldwide liquids production and 21 percent of our natural gas production.
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Eagle Ford | Various | % | Various | 151 | 212 | 186 | ||||||||||||||
| Gulf of Mexico | Various | Various | 12 | 9 | 14 | |||||||||||||||
| Gulf Coast—Other | Various | Various | 3 | 8 | 4 | |||||||||||||||
| Total Gulf Coast | 166 | 229 | 204 | |||||||||||||||||
| Bakken | Various | Various | 72 | 72 | 84 | |||||||||||||||
| Permian | Various | Various | 46 | 126 | 66 | |||||||||||||||
| Anadarko Basin | Various | Various | 4 | 59 | 14 | |||||||||||||||
| Wyoming/Uinta | Various | Various | - | 78 | 13 | |||||||||||||||
| Barnett | * | Various | 3 | 25 | 8 | |||||||||||||||
| Niobrara | Various | Various | 7 | 7 | 8 | |||||||||||||||
| Total Great Plains | 132 | 367 | 193 | |||||||||||||||||
| Total U.S. Lower 48 | 298 | 596 | 397 | |||||||||||||||||
*See “Dispositions” below for additional information.
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Onshore
We hold 10.3 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 1.6 million net acres in the following areas:
| • | 620,000 net acres in the Bakken, located in North Dakota and eastern Montana. |
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| • | 225,000 net acres in central Louisiana. |
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| • | 200,000 net acres in the Eagle Ford, located in South Texas. |
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| • | 145,000 net acres in the Permian, located in West Texas and southeastern New Mexico. |
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| • | 98,000 net acres in the Niobrara, located in northeastern Colorado. |
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| • | 340,000 net acres in other areas with unconventional potential. |
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The majority of our 2018 onshore production originated from the Big 3—Eagle Ford, Bakken and the Delaware in the Permian Basin. Onshore activities in 2018 were centered mostly on continued development of assets, with an emphasis on areas with low cost of supply, particularly in growing unconventional plays. Our major focus areas in 2018 included the following:
| • | Eagle Ford—The Eagle Ford continued full-field development in 2018. We operated seven rigs on average in 2018, resulting in 166 operated wells drilled and 149 operated wells brought online. Production increased 40 percent in 2018 compared with 2017, averaging 186 MBOED and 133 MBOED, respectively. |
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| • | Bakken—We operated an average of three rigs during the year in the Bakken. We continued our pad drilling with 51 operated wells drilled during the year and 85 operated wells brought online. Production increased 29 percent in 2018 compared with 2017, averaging 84 MBOED and 65 MBOED, respectively. |
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| • | Permian Basin—The Permian Basin is an area where we are leveraging our conventional legacy position by utilizing new technology to improve the ultimate recovery and value from these fields. We hold approximately 800,000 net acres in the Permian, which includes 145,000 net unconventional acres. The Permian Basin produced 66 MBOED in 2018, increasing 6 percent compared to 2017, including 28 MBOED of unconventional production from the Delaware. We disposed of several noncore conventional assets throughout the year. |
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Dispositions
We completed the sale of our interests in the Barnett in the fourth quarter of 2018. Combined with the sale of several noncore conventional assets in the Permian Basin, production from the assets sold was 10 MBOED, approximately 3 percent of total Lower 48 production in 2018. For additional information on our asset dispositions, see Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.
Gulf of Mexico
At year-end 2018, our portfolio of producing properties in the Gulf of Mexico primarily consisted of one operated field and three fields operated by co-venturers, totaling approximately 68,000 net acres, including:
| • | 75 percent operated working interest in the Magnolia Field in Garden Banks Blocks 783 and 784. |
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| • | 15.9 percent nonoperated working interest in the unitized Ursa Field located in the Mississippi Canyon Area. |
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| • | 15.9 percent nonoperated working interest in the Princess Field, a northern subsalt extension of the Ursa Field. |
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| • | 12.4 percent nonoperated working interest in the unitized K2 Field, comprised of seven blocks in the Green Canyon Area. |
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Exploration
| • | Conventional Exploration |
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In December 2017, we elected to withdraw from our Shenandoah leases. The withdrawal was effective February 17, 2018, substantially completing our exit from deepwater Gulf of Mexico.
| • | Unconventional Exploration |
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Our onshore focus areas include the Niobrara in the Denver-Julesburg Basin, the Delaware in the Permian Basin, as well as several emerging plays such as the Louisiana Austin Chalk. We began acquiring early life-cycle acreage in the Austin Chalk in the fourth quarter of 2017, and currently hold approximately 225,000 net acres. We spud our first Austin Chalk well in late 2018 and plan to drill additional wells in 2019.
Facilities
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 $235 million at December 31, 2018. 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 Qatar Liquefied Gas Company Limited (3) (QG3) 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. In January 2019, we entered into agreements to sell our 12.4 percent ownership interest in Golden Pass LNG Terminal and the affiliated Golden Pass Pipeline. We have also entered into agreements to amend our contractual obligations for remaining use of the facilities. Completion of the sale is subject to regulatory approval.
Other
| • | Lost Cabin Gas Plant—We operate and own a 46 percent interest in the Lost Cabin Gas Plant, a 246 million cubic-feet-per-day capacity natural gas processing facility in Lysite, Wyoming. The Plant is currently operating at less than capacity due to a fire in December 2018. Restoration efforts are ongoing and anticipated to continue throughout 2019. The expected production loss in 2019 is approximately 7 MBOED. |
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| • | Helena Condensate Processing Facility—We operate and own the Helena Condensate Processing Facility, a 110,000 barrel-per-day condensate processing plant located in Kenedy, Texas. |
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| • | 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. |
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| • | 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. |
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CANADA
Our Canadian operations mainly consist of an oil sands development in the Athabasca Region of northeastern Alberta and a liquids-rich unconventional play in western Canada. In 2018, operations in Canada contributed 8 percent of our worldwide liquids production and less than 1 percent of our natural gas production.
| 2018 | ||||||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Bitumen MBD | Total MBOED | |||||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||||||
| Surmont | 50.0 | % | ConocoPhillips | - | - | 66 | 66 | |||||||||||||||||
| Montney | 100.0 | ConocoPhillips | 2 | 12 | - | 4 | ||||||||||||||||||
| Total Canada | 2 | 12 | 66 | 70 | ||||||||||||||||||||
On May 17, 2017, we completed the sale of our 50 percent nonoperated interest in the FCCL Partnership, as well as the majority of our western Canada gas assets to Cenovus Energy. Production from the assets sold was 103 MBOED, approximately 62 percent of the total Canada segment production in 2017. For additional information on our asset dispositions, see Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions, in the Notes to Consolidated Financial Statements.
Oil Sands
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. We hold approximately 0.6 million net acres of land in the Athabasca Region of northeastern Alberta.
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. The second phase of the Surmont project achieved first production in 2015 and reached peak production in 2018. We are focused on structurally lowering costs, reducing greenhouse gas intensity and optimizing asset performance.
Exploration
We hold exploration acreage in three areas of Canada: onshore western Canada, the Mackenzie Delta/Beaufort Sea Region and the Arctic Islands. Our primary exploration focus is on unconventional plays in western Canada.
We hold approximately 145,000 net acres in the emerging unconventional Montney play in northeast British Columbia and 207,000 net acres in Canol Northwest Territories. Our Montney activity in 2018 included drilling 13 horizontal wells, completing two horizontal wells and acquiring approximately 37,000 additional net acres. Appraisal drilling and completions activity will continue in 2019 to further explore the area’s resource potential.
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EUROPE AND NORTH AFRICA
The Europe and North Africa segment consists of operations and exploration activities in Norway, the United Kingdom and Libya. In 2018, operations in Europe and North Africa contributed 19 percent of our worldwide liquids production and 18 percent of natural gas production.
Norway
| 2018 | ||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||
| Average Daily Net Production | ||||||||||||
| Greater Ekofisk Area | 35.1 | % | ConocoPhillips | 53 | 45 | 60 | ||||||
| Heidrun | 24.0 | Equinor | 12 | 25 | 16 | |||||||
| Alvheim | 20.0 | Aker BP | 11 | 11 | 13 | |||||||
| Visund | 9.1 | Equinor | 5 | 44 | 12 | |||||||
| Troll | 1.6 | Equinor | 2 | 60 | 12 | |||||||
| Other | Various | Equinor | 8 | 9 | 10 | |||||||
| Total Norway | 91 | 194 | 123 | |||||||||
The Greater Ekofisk Area is located approximately 200 miles offshore Stavanger, Norway, in the North Sea, and comprises three producing fields: Ekofisk, Eldfisk and Embla. Crude oil is exported to Teesside, England, and the natural gas is exported to Emden, Germany. The Ekofisk and Eldfisk fields consist of several production platforms and facilities, including the Ekofisk South and Eldfisk II developments which achieved first production in 2013 and 2015, respectively. Continued development drilling in the Greater Ekofisk Area will contribute additional production over the coming years, as additional wells come online.
The Heidrun Field is located in the Norwegian Sea. Produced crude oil is stored in a floating storage unit and exported via shuttle tankers. Part of the natural gas is currently injected into the reservoir for optimization of crude oil production, some gas is transported for use as feedstock in a methanol plant in Norway, in which we own an 18 percent interest, and the remainder is transported to Europe via gas processing terminals in Norway.
The Alvheim Field is located in the northern part of the North Sea near the border with the U.K. sector, 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 Scottish Area Gas Evacuation (SAGE) Terminal at St. Fergus, Scotland, through the SAGE Pipeline.
Visund is an oil and gas field located in the North Sea and consists of a floating drilling, production and processing unit, and subsea installations. Crude oil is transported by pipeline to a nearby third-party field for storage and export via tankers. The natural gas is transported to a gas processing plant at Kollsnes, Norway, through the Gassled transportation system.
The Troll Field lies in the northern part of the North Sea and consists of the Troll A, B and C platforms. The natural gas from Troll A is transported to Kollsnes, Norway. Crude oil from floating platforms Troll B and Troll C is transported to Mongstad, Norway, for storage and export.
We also have varying ownership interests in two other producing fields in the Norway sector of the North Sea, as well as the Aasta Hansteen development in the Norwegian Sea, which achieved first production in December 2018.
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Exploration
In 2018, we participated in the Gekko appraisal well and sidetrack in the Alvheim Area of the North Sea and encountered hydrocarbons. The Gekko Discovery is currently under evaluation as a future tie-in to the Alvheim Facility. In 2018, we were awarded six new exploration licenses; PL911, PL912, PL917, PL919, PL935 and PL938; and one acreage addition, PL775B.
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.
United Kingdom
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Britannia | 58.7 | % | ConocoPhillips | 3 | 74 | 15 | ||||||||||||||
| Britannia Satellites | 26.3–93.8 | * | ConocoPhillips | 12 | 92 | 27 | ||||||||||||||
| J-Area | 32.5–36.5 | ConocoPhillips | 9 | 57 | 19 | |||||||||||||||
| Clair | 7.5 | ** | BP | 6 | 1 | 6 | ||||||||||||||
| East Irish Sea | 100.0 | Spirit Energy | - | 30 | 5 | |||||||||||||||
| Southern North Sea | Various | ConocoPhillips | - | 22 | 4 | |||||||||||||||
| Other | Various | Various | - | 5 | 1 | |||||||||||||||
| Total United Kingdom | 30 | 281 | 77 | |||||||||||||||||
| *Includes the Chevron-operated Alder Field, ConocoPhillips equity interest is 26.3 percent. **See dispositions below for additional information. |
Britannia is one of the largest natural gas and condensate fields in the North Sea. 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, Brodgar, Enochdhu and Alder, produce via subsea manifolds and pipelines linked to the Britannia Platform.
The J-Area consists of the Judy/Joanne, Jade and Jasmine fields, located in the U.K. Central North Sea. The J-Area gas is processed on the Judy Platform and transported through the Central Area Transmission System Pipeline, while liquids are transported to Teesside through the Norpipe system. Continued development drilling in the J-Area will provide additional volumes in the coming years as wells are brought online.
We have various ownership interests in several gas fields in the Rotliegendes and Carboniferous areas of the Southern North Sea. Production ceased in August 2018, and decommissioning activity in the Southern North Sea is ongoing. 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 7.5 percent interest in the Clair Field, located in the Atlantic Margin. We completed the sale of a subsidiary holding a 16.5 percent interest in the Clair Field in December 2018 to BP. See the “Disposition” section below for more information. 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 tie into existing oil and gas export pipelines to the Shetland Islands. First production for Clair Ridge was achieved in November 2018.
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Exploration
In 2018, we drilled the Jasmine 2A exploration well. The well encountered insufficient hydrocarbons and was expensed as a dry hole. In 2018, we were awarded two new exploration licenses in the J-Area, P2399 and P2456.
Transportation
We operate the Teesside oil and Theddlethorpe gas terminals in which we have 40.25 percent and 50 percent ownership interests, respectively. Decommissioning activity is ongoing at the Theddlethorpe gas terminal following cessation of production in the Southern North Sea. We also have a 100 percent ownership interest in the Rivers Gas Terminal, operated by a third party.
Disposition
In the fourth quarter of 2018, we completed a transaction to sell a ConocoPhillips subsidiary, which held 16.5 percent of our 24 percent interest in the BP-operated Clair Field in the United Kingdom to BP, and acquire their nonoperated interest in the Kuparuk Assets in Alaska. In 2018, our Europe and North Africa segment net production associated with the disposed 16.5 percent interest in the Clair Field was approximately 5 MBOED. See Note 5—Assets Held for Sale, Sold or Acquired and Other Planned Dispositions in the Notes to Consolidated Financial Statements, for additional information.
Libya
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Waha Concession | 16.3 | % | Waha Oil Co. | 36 | 28 | 41 | ||||||||||||||
| Total Libya | 36 | 28 | 41 | |||||||||||||||||
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 have periodically been interrupted over the last several years due to the shutdown of the Es Sider crude oil export terminal. In 2018, we had 21 crude liftings from Es Sider. We expect a gradual, continued rampup in activity.
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ASIA PACIFIC AND MIDDLE EAST
The Asia Pacific and Middle East segment has exploration and production operations in China, Indonesia, Malaysia and Australia and producing operations in Qatar and Timor-Leste. In 2018, operations in the Asia Pacific and Middle East segment contributed 14 percent of our worldwide liquids production and 60 percent of natural gas production.
Australia and Timor Sea
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Australia Pacific LNG | 37.5 | % | ConocoPhillips/ Origin Energy | - | 660 | 110 | ||||||||||||||
| Bayu-Undan | 56.9 | ConocoPhillips | 7 | 240 | 47 | |||||||||||||||
| Athena/Perseus | 50.0 | ExxonMobil | - | 35 | 6 | |||||||||||||||
| Total Australia and Timor Sea | 7 | 935 | 163 | |||||||||||||||||
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 coalbed methane (CBM) from the Bowen and Surat basins in Queensland, Australia, to supply the domestic gas market and convert the CBM into LNG for export. Origin operates APLNG’s upstream production and pipeline system, and we operate the downstream LNG facility, located on Curtis Island near Gladstone, Queensland, as well as the LNG export sales business.
Two fully subscribed 4.5-million-metric-tonnes-per-year LNG trains have been completed. Approximately 3,900 net wells are ultimately expected to supply both the domestic gas market and the LNG sales contracts. The wells are supported by gathering systems, central gas processing and compression stations, water treatment facilities, and an export pipeline connecting the gas fields to the LNG facilities. The first APLNG Train 1 cargo sailed in January 2016, and APLNG Train 2 achieved first production in the third quarter of 2016. The LNG is being sold to Sinopec under 20-year sales agreements for 7.6 million metric tonnes of LNG per year, and Japan-based Kansai Electric Power Co., Inc. under a 20-year sales agreement for approximately 1 million metric tonnes of LNG per year.
APLNG has an $8.5 billion project finance facility, which was fully drawn down and had an outstanding balance of $7.2 billion at December 31, 2018. In September 2018, APLNG successfully refinanced $1.4 billion of the project finance facility for a lower cost United States Private Placement (USPP) bond facility. Project finance interest payments are bi-annual, concluding September 2030.
For additional information, see Note 3—Variable Interest Entities (VIEs), Note 6—Investments, Loans and Long-Term Receivables, and Note 12—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 310-mile natural gas pipeline connects the facility to the 3.5-million-metric-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 2018, we sold 157 billion gross cubic feet of LNG primarily to utility customers in Japan.
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A continuation of the Bayu-Undan Phase Three Development consisting of one subsea and two platform wells was completed with all three wells producing by November 2018.
Athena/Perseus
The Athena production license (WA-17-L) in which ConocoPhillips has a 50 percent working interest is located offshore Western Australia and contains part of the Perseus Field which straddles the boundary with WA-1-L, an adjoining license area. The production entitlement to natural gas produced from WA-17-L is forecast to end in the fourth quarter of 2019.
Greater Sunrise
In the fourth quarter of 2018, we entered into an agreement to sell our 30 percent interest in the Greater Sunrise Fields to the government of Timor-Leste for $350 million, subject to customary adjustments. The transaction is conditional on the funding approval from the Timor-Leste government as well as regulatory approvals.
Exploration
We operate three exploration permits in the Browse Basin, offshore northwest Australia, in which we own a 40 percent interest in permits WA-315-P, WA-398-P and TP 28, of the Greater Poseidon Area. The TP 28 Western Australia State exploration permit was granted for five years from January 2017, with a 40 percent working interest and was excised from the existing permits as agreed between state and federal regulators. 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 plugged and abandoned.
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, containing the Barossa and Caldita discoveries. A 3-D seismic survey was completed over the Barossa and Caldita fields in 2016. The drilling of the Barossa-5A and Barossa-6 appraisal wells was completed in 2017 with good quality, gas-bearing reservoir intersected at both. Additionally, the retention lease over the Barossa Field was renewed during 2017. In April 2018, Barossa entered the front-end engineering and design (FEED) phase of development which will continue through 2019. During the FEED phase, costs and the technical definition for the project will be finalized, gas and condensate sales agreements progressed, and access arrangements negotiated with the owners of the Darwin LNG Facility and Bayu-Darwin Pipeline.
Indonesia
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| South Sumatra | 45.0–54.0 | % | ConocoPhillips | 2 | 309 | 53 | ||||||||||||||
| Total Indonesia | 2 | 309 | 53 | |||||||||||||||||
We operate three production sharing contracts (PSC) in Indonesia: The Corridor Block and South Jambi “B,” both located in South Sumatra, and Kualakurun in Central Kalimantan. Currently, there is production from the Corridor Block.
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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. This PSC will expire in January 2020.
Exploration
We have a 60 percent working interest in the Kualakurun PSC, located in Central Kalimantan, which was signed in May 2015. This block has an area of approximately 1.4 million gross acres. Technical evaluation is on-going to determine the block’s potential.
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
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Penglai | 49.0 | % | CNOOC | 30 | - | 30 | ||||||||||||||
| Panyu | 24.5 | CNOOC | 6 | - | 6 | |||||||||||||||
| Total China | 36 | - | 36 | |||||||||||||||||
The Penglai 19-3, 19-9 and 25-6 fields are located in Bohai Bay Block 11/05. Production from Phase 1 development of the Penglai 19-3 Field began in 2002. Phase 2, which included six additional wellhead platforms and an FPSO vessel, was fully operational by 2009.
As part of further development of the Penglai 19-9 Field, the new wellhead platform J Project, which anticipates 62 wells, is progressing according to schedule, with 36 wells completed and brought online through December 2018.
The Penglai 19-3/19-9 Phase 3 Project was sanctioned in December 2015. This project consists of three new wellhead platforms and a central processing platform. First oil from Phase 3 was achieved in 2018.
In December 2018, we sanctioned the Penglai 25-6 Phase 4A Project. This project consists of one new wellhead platform and anticipates 62 new wells. First production is expected in 2021.
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 production period for Panyu 4-2, 5-1 and 11-6 will expire in 2019.
Exploration
In 2018, we participated in one successful appraisal well in the Bohai Penglai Field. We continued the Penglai full-field 3-D seismic program, covering existing and future development opportunities. The program is expected to complete in 2019.
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Malaysia
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Siakap North-Petai | 21.0 | % | Murphy | 2 | 1 | 2 | ||||||||||||||
| Gumusut | 29.0 | Shell | 25 | - | 25 | |||||||||||||||
| KBB | 30.0 | KPOC | 1 | 41 | 8 | |||||||||||||||
| Malikai | 35.0 | Shell | 19 | - | 19 | |||||||||||||||
| Total Malaysia | 47 | 42 | 54 | |||||||||||||||||
We own interests in six PSCs in Malaysia. Three are located off the eastern Malaysian state of Sabah: Block G, Block J and the Kebabangan Cluster (KBBC). Three other blocks, Block SK304, Block SK313 and Block WL4-00 are located off the eastern 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.
We own a 35 percent interest in Malikai. The field achieved first production in December 2016, ramping to peak production in 2018. The KMU-1 exploration well was completed and started producing in 2018.
Block J
First production from the Gumusut Field occurred from an early production system in 2012. Production from a permanent, semi-submersible floating production vessel was achieved in October 2014. Our ownership in the Gumusut Field is currently at 29 percent following the finalization of the Malaysia-Brunei unitization and a redetermination of the Block J and Block K Malaysia Unit, both in 2017. The drilling of the Gemilang-1 exploration well in Block J is complete and the results are under review. Gumusut Phase 2 infill drilling and first oil from Phase 2 are expected in 2019.
KBBC
We have 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. Production in 2018 was impacted by unplanned downtime related to the rupture of a third-party pipeline which carries gas production from the Kebabangan gas field to market. Development options for the Kamunsu East gas field are being evaluated.
Exploration
In the fourth quarter of 2016, we entered into a farm-in agreement to acquire a 50 percent interest in Block SK 313, a 1.4 million gross-acre exploration block, effective January 2017. Following completion of the Sadok-1 exploration well in January 2017, we assumed operatorship of the block from PETRONAS.
We were awarded Block WL4-00, which encompasses 0.6 million gross acres, in January 2017. We have a 50 percent operated interest in this block which includes the Salam-1 oil discovery.
We completed a 3-D seismic survey in Block SK 313 and Block WL4-00 in 2017. Two wells were drilled in Block WL4-00 in 2018 and discovered hydrocarbons. Further exploration drilling is expected to occur in 2019.
We were awarded Block SK304 in May 2018, which encompasses 2.1 million gross acres. We completed a 3-D seismic survey in this block in 2018.
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Brunei
Exploration
In October 2018, we assigned our 6.25 percent working interest in the deepwater Block CA-2 PSC to Brunei National Petroleum Company Sendirian Berhad.
Qatar
| 2018 | ||||||||||||||||||||
| Interest | Operator | Liquids MBD | Natural Gas MMCFD | Total MBOED | ||||||||||||||||
| Average Daily Net Production | ||||||||||||||||||||
| Qatargas Operating | ||||||||||||||||||||
| QG3 | 30.0 | % | Company Limited | 21 | 371 | 83 | ||||||||||||||
| Total Qatar | 21 | 371 | 83 | |||||||||||||||||
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 is combined and shared.
OTHER INTERNATIONAL
The Other International segment includes exploration activities in Colombia and Chile.
Colombia
Exploration
We have an 80 percent operated interest in the Middle Magdalena Basin Block VMM-3. The block extends over approximately 67,000 net acres and contains the Picoplata-1 Well, which completed drilling in 2015 and testing in 2017. Plug and abandonment activity started during 2018 and is expected to continue into 2019. In addition, we have an 80 percent working interest in the VMM-2 Block which extends over approximately 58,000 net acres and is contiguous to the VMM-3 Block. Community engagement and environmental permitting activities are expected to continue in 2019.
Chile
Exploration
We have a 49 percent interest in the Coiron Block located in the Magallanes Basin in southern Chile.
Argentina
Exploration
We received government approval in January 2019 for a 50 percent nonoperated interest in the El Turbio Este Block in the Austral Basin.
Venezuela and Ecuador
For discussion of our contingencies in Venezuela and Ecuador, see Note 13—Contingencies and Commitments, in the Notes to Consolidated Financial Statements.
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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 and sell third-party volumes to better position the company to satisfy customer demand while fully utilizing transportation and storage capacity.
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.
LNG
LNG marketing efforts are focused on equity LNG production facilities located in Australia and Qatar. LNG is primarily sold under long-term contracts with prices based on market indices.
Energy Partnerships
Marine Well Containment Company (MWCC)
We are a founding member of the MWCC, a non-profit organization formed in 2010, which provides well containment equipment and technology in the deepwater U.S. Gulf of Mexico. MWCC’s containment system 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. For additional information, see Note 3—Variable Interest Entities (VIEs), in the Notes to Consolidated Financial Statements.
Subsea Well Response Project (SWRP)
In 2011, we, along with several leading oil and gas companies, launched the 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 and provides well capping and containment capability outside the United States.
Oil Spill Response Removal Organizations (OSROs)
We maintain memberships in several OSROs across the globe as a key element of our preparedness program in addition to internal response resources. Many of the OSROs are not-for-profit cooperatives owned by the member companies wherein we may actively participate as a member of the board of directors, steering committee, work group or other supporting role. Globally, our primary OSRO is Oil Spill Response Ltd. based in the United Kingdom, with facilities in several other countries and the ability to respond anywhere in the world. In North America, our primary OSROs include the Marine Spill Response Corporation for the continental United States and Alaska Clean Seas and Ship Escort/Response Vessel System for the Alaska North Slope and Prince William Sound, respectively. Internationally, we maintain memberships in various regional OSROs including the Norwegian Clean Seas Association for Operating Companies, Australian Marine Oil Spill Center and Petroleum Industry of Malaysia Mutual Aid Group.
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Technology
We have several technology programs that improve our ability to develop unconventional reservoirs, produce heavy oil economically with fewer emissions, improve the efficiency of our company’s exploration program, increase recoveries from our legacy fields, and implement sustainability measures.
Our Optimized Cascade® LNG liquefaction technology business continues to be successful with the demand for new LNG plants. The technology has been licensed for use in 26 LNG trains around the world, with feasibility studies ongoing for additional trains.
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, 2018. No difference exists between our estimated total proved reserves for year-end 2017 and year-end 2016, which are shown in this filing, and estimates of these reserves shown in a filing with another federal agency in 2018.
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 1.5 trillion cubic feet of natural gas, including approximately 243 billion cubic feet related to the noncontrolling interests of consolidated subsidiaries, and 73 million barrels of crude oil in the future. These contracts have various expiration dates through the year 2029. 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 3, 2018, issue of the Oil and Gas Journal, we were the third-largest U.S.-based oil and gas company in worldwide natural gas and liquids production and worldwide liquids reserves in 2017. 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.
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GENERAL
At the end of 2018, we held a total of 814 active patents in 50 countries worldwide, including 333 active U.S. patents. During 2018, we received 29 patents in the United States and 67 foreign patents. Our products and processes generated licensing revenues of $53 million related to activity in 2018. The overall profitability of any business segment is not dependent on any single patent, trademark, license, franchise or concession.
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 process and occupational safety. In support of the goal of zero incidents, HSE milestones and criteria are established annually to drive strong safety performance. Progress toward these milestones and criteria are measured and reported. HSE audits are conducted on business functions periodically, and improvement actions are established and tracked to completion. 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 65 through 69 under the captions “Environmental” and “Climate Change” is incorporated herein by reference. It includes information on expensed and capitalized environmental costs for 2018 and those expected for 2019 and 2020.
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.